The abstracts of the GEO 2004 Conference presentations (March 7-10, 2004, Bahrain) are published in alphabetical order based on the last name of the first author. Only those abstracts that were accepted by the GEO 2004 Program Committee are published here. Abstracts were submitted online and were subsequently edited by GeoArabia Editors and proof-read by the first author. The names of companies and institutions to which authors are affiliated have been abbreviated. For convenience, all subsidiary companies are listed as the parent company. A list of the organization abbreviations is on page 148.

(345-Poster) Characterizing sealing faults in carbonates of onshore Abu Dhabi

Abd El-Sattar, Mohamed M. (ADCO - msattar@adco.co.ae), Rafael Rosell (ADCO), Saleh Bin Sumaidaa (ADCO), Naema Al-Zaabi (ADCO), Jean F. Dervieux (ADCO) and Marie-Odile T. Bockel-Rebelle (ADCO)

There has been increasing interest in the role of faults in the relatively gently deformed reservoirs of southeast Abu Dhabi, where fault-dependant plays were recognized. Evidence for sealing on faults includes differences in hydrocarbon pressure, viscosity and water-contact heights across some faults, as well as seismic amplitude and impedance differences. There has been little published work so far on the understanding of fault seal potential in carbonate rocks, which is the situation in onshore Abu Dhabi. Much seismic, well and production data are available from the Abu Dhabi fields, this data made it possible to go from observations to prediction of fault-seal mechanisms. Faulting and sealing mechanisms in the petroleum systems of Abu Dhabi have complicated movement histories. Also it is strongly influenced by the lithological nature of the sequence offset by the fault. Therefore, to fully assess fault-seal potential it is necessary to examine the evolution of faults through time and the stress history. Extensive databases of all relevant information have been constructed. It involved painstaking integration between structural geology, sedimentology, geochemistry, geophysics, petrophysics, and reservoir engineering, which allowed many types of analyses to be carried out. This study also reviews fault-sealing mechanisms and fault seal risk analysis. Fault characterization showed that they are segmented horizontally and vertically in an echelon arrangement and featured by small throws. In such an environment, the concept of juxtaposition or fault membrane do not exist. Diagenesis/cementation seal should be the working mechanism. Almost all faults – even those beyond seismic resolution – form a deformation zone/band (mainly fractures/fracture corridors) which is more continouos than the fault segments. This study introduces a new sealing mechanism, which is “Cemented Damages Zone” (CDZ), where dissolution and re-precipitation of calcite in the fault zone and in wall rocks caused the cementation of the damage zone. This framework and database provides an understanding of fault-sealed play risk that allows the comparison of success and failure scenarios in our future exploration.

(327-Oral) Maturity and geothermal history of the Silurian, Triassic and Jurassic source rocks, Saudi Arabia

Abdelbagi, Sami T. (Saudi Aramco - sami.abdelbagi@aram co.com) and Mahdi A. Abu-Ali (Saudi Aramco)

Organic microscopic analysis were carried out on over 400 samples of black shale, siltstones, and marls from over seventy wells in eastern and central Saudi Arabia to determine maximum paleotemperature and thermal maturity of different source rocks. The results indicate that the organic components consist of liptinites, alginite of marine origin and vitrinite. Inertnites predominate in the Silurian section. Vitrinite reflectance (% Ro) data suggest that source rocks in the deepest part of the basin are gas prone while the oil-generating potential increases from west to east and in the younger strata. At present, the Silurian source rock in the deeper parts of all basins has passed the oil window and is in the gas-expulsion maturity phase. The wet gas is confined to basinal areas with depths equivalent to % Ro (1.2-2.0). At the west margin of the basinal area the Silurian source is immature or has attained early maturity (% Ro = 0.45-0.50). The least mature Triassic source rock occurs along the western margin and its maturity gradually increases eastwards. To the east, this source is at the peak oil maturity (% Ro = 0.7-0.9). In the north and in the Rub’ Al-Khali the main kitchen is mostly at wet and dry gas maturity (% Ro > 1.3). The Upper Jurassic source rock in the Rub’ Al-Khali Basin is at peak dry gas and wet gas generation. The central and eastern reaches of the Jurassic source are at peak-oil expulsion. The northern part of the ‘kitchen’ shows early to peak-oil maturities (% Ro = 0.5-0.9). This data has allowed better modeling of the burial and hydrocarbon generation histories of the Saudi Arabian basins. It has provided a good calibration tool to better predict geothermal histories and hydrocarbon occurrences in undrilled locations.

(222-Poster) Facies architecture and porosity/permeability patterns in Wajid Sandstone

Abdullatif, Osman M. (KFUPM - osmanabd@kfupm.edu.sa) and Fadhel Al-Khalifa (KFUPM)

Facies architectural analysis and porosity/permeability determination were carried out on two-dimensional outcrops of Wajid Sandstone in southwest Saudi Arabia. The facies are dominated by medium to large scale cross-stratified sandstone. Channel and basal lag conglomerate and mudstone facies occur in minor percentages. The sandstone is characterized by stacked fining-upwards sequences, tabular geometry and many reactivation surfaces. Facies architectural elements recognized include mainly sandy channels, sandy bedforms, laminated sand sheets, and proximal overbank fines. The facies in the Wajid Sandstone suggest mostly proximal to medial depositional setting with laterally shifting low-sinuosity channels and bar sequences. The study revealed that stacked, layered, and compartmentallized sandstone body geometries are characteristic in Wajid Sandstone. Facies heterogeneity and porosity/permeability development at macro- and microscale reflect depositional environmental control, as well as post-depositional diagenetic changes. The evaluation of Wajid Sandstone heterogeneity at outcrop analog scale is important for facies and petrophysical modeling as well as fluid simulation studies.

(365-Oral) Paleozoic petroleum system of Kuwait

Abdulmalek, Salah A. (KOC - smalek@kockw.com), Swapan K. Bhattacharya (KOC), Riyasat Husain (KOC), Abdul Aziz A. Sajer (KOC), Adel M.H. Ebaid (KOC) and Jim Russel (KOC)

The Paleozoic petroleum system and its elements are established in most parts of the Arabian Peninsula, but is poorly understood in Kuwait due to the paucity of exploration data. Recent drilling information and direct gas indications in the NW Raudhatain area have provided valuable leads for understanding the Paleozoic petroleum system in Kuwait. Although several regional Paleozoic petroleum systems exist in the Arabian Peninsula, the available exploration data suggests that a likely system in Kuwait is the Qusaiba–Unayzah (.) system. The existence of this system is indicated by the results of drilling, however no commercial production from this system has been established. The Lower Silurian Qusaiba ‘hot’ shale, the likely source for this system, is expected to be mature for gas and might have entered the gas window by about 115 Ma. Tectonic activity associated with Late Cretaceous closure of the Neo-Tethys Ocean (marked as an unconformity on the top of Mishrif Formation) probably corresponds to the critical time of this system. The Permo-Carboniferous Unayzah Formation is expected to act as the major reservoir rock. Khuff and Sudair carbonates are envisaged as the minor reservoir rocks. While the anhydrites and shale interbeds, at different levels within the Khuff, Sudair and lower part of Jilh formations, can act as local seals for this system, a major salt unit in the middle part of the Jilh Formation is expected to be the regional seal partitioning the Paleozoic petroleum system from the Mesozoic one. The stratigraphic limit of the system lies below the Jilh salt down to the basement. Geographically it covers most of the onland areas of Kuwait. This petroleum system is poorly explored and so far reserves are not established.

(468-Poster) Effective integration of reservoir heterogeneities, fracture networks and fault communication and their challenges in Bahrain’s Awali field simulation models

Abdulwahab, Ayda Essa (Bapco - ayda_wahab@bapco.net), Kandaswamy Kumar (Bapco) and Ali Ebrahim Al-Muftah (Bapco)

Bahrain’s Awali field is an asymmetrical NS-trending anticline that was discovered in 1932. The field is a multistack of carbonate and sandstone reservoirs, most of them oil-bearing. The fluids range from tarry oil in the Aruma zone, to dry gas in the Khuff zones. The geology of the field is extremely complex with a large number of faults, especially in the Wasia Group formations, which contain the major oil reservoirs in the field. These reservoirs are at different stages of the production cycle. Following a 3-D seismic acquisition campaign in the year 2000, Bapco took up an integrated study to develop numerical models as the main tool to assess alternative production mechanisms. This integrated study faced a significant number of challenges, which had to be overcome with innovative ideas. The challenges included representing communication between reservoirs through faults, complex rock and fluid distribution from heavy oil to gas condensate, gas injection, aquifer encroachment and fracture intensity. Although the hardware required for handling the large simulation models was meticulously selected based on benchmark data of the various machines, the geological complexities posed serious problems while running the simulation models. This poster describes the effective integration of the reservoir heterogeneities, fracture networks and fault communication in the simulation models built for different zones of the field. It also highlights the challenges faced during the history matching process and the approaches adopted to overcome these challenges.

(387-oral) Integration of regional petroleum system elements and exploration play fairway maps using GIS

Abu-Ali, Mahdi A. (Saudi Aramco - mahdi.abuali@aramc o.com), AbdalHadi Al-Khalifa (Saudi Aramco), Jay Fares (Saudi Aramco) and John Griffiths (Saudi Aramco)

Geographic Information System (GIS) is a powerful tool to visualize and integrate geographic and geologic information on a single platform. A GIS application was successfully used to not only display information geographically, but more significantly, to enable the interactive over-laying of maps from multiple sources to derive a play fairway map. The application has facilitated the integration of maps into a single visualization platform due to its ease of accessibility, flexibility, excellent resolution of maps and features and ability to overlay multiple maps simultaneously. The geo-data originated from different sources; such as: Z-Map, Petrosys, shape files, vector datasets, CAD maps, and scanned maps. Initially, much of the data had to be reformatted to various file formats compatible with the GIS, but newer releases of the underlying GIS software allowed the transfer of all the data into the corporate database. The process of data transfer was a major task. Grids were converted to raster data with associated contours, faults and control datasets as vector data. Scanned maps were geo-referenced and pertinent information extracted where appropriate, by vectorization. The underlying GIS software was customized to allow easy access to the data and their associated meta-data and display definitions. Regional petroleum system maps that include structure, source rock thermal maturity, well tests and hydrocarbon show data, structural growth history, paleogeography and reservoir isopach grids were generated for three petroleum systems: (1) Permo-Carboniferous Unayzah; (2) Devonian Jauf; and (3) Jurassic Arab-D formations. These three integrated petroleum systems maps were combined with migration pathways and structural growth history maps to generate regional play fairway concepts that can be used to help assess future exploration plays.

(423-Oral) Influence of sequence-boundary duration and facies on porosity evolution, Early Cretaceous, Saudi Arabia

Adams, Roy D. (Saudi Aramco - roy.adams@aramco.com), G. Wyn Hughes (Saudi Aramco), Nassir S. Alnaji (Saudi Aramco) and Mokhtar M. Al-Khalid (Saudi Aramco)

Core and outcrop provide excellent data on two sequence boundaries that extend from the Tuwaiq Escarpment, near Riyadh, to the Gulf. These sequence boundaries approximately coincide with formational contacts between the Sulaiy and Yamama formations, and between the Yamama and Buwaib formations. Although the Yamama-Buwaib sequence boundary is well established, the Sulaiy-Yamama sequence boundary is subtle, possibly due to a relatively brief period of sea-level fall and subaerial exposure. The Sulaiy-Yamama sequence boundary probably represents no more than a few hundred thousand years of missing time and produced some karsting. Evidence of caverns is found within 20 feet of the boundary and includes cave-sediment fill and collapse breccia. In contrast, the Yamama-Buwaib sequence boundary represents several million years of missing time. This extensive exposure produced a heavily karsted surface and intense vadose dissolution that extended more than 200 ft below the sequence boundary. With burial, extremely vuggy intervals collapsed, creating extensive fracture networks. Producing reservoirs beneath these two sequence boundaries differ, primarily due to differences in duration of exposure associated with the overlying sequence boundary. Porosity beneath the Sulaiy-Yamama sequence boundary is predominantly inter- and intra-particle. Porosity beneath the Yamama-Buwaib sequence boundary is predominately fracture porosity related to intense vadose dissolution and subsequence collapse. Depositional facies provide a secondary control on porosity development in the Sulaiy Formation: better porosity development correlates with coral- and Lithocodium-rich, shallow-shelf, depositional facies. Depositional facies have less influence on porosity development in the Yamama Formation, due to pervasive and intense vadose dissolution.

(144-Poster) Field studies of deformed carbonates in northern Oman: implications for modeling structural permeability in carbonate reservoirs

Agar, Susan M. (ExxonMobil - susan.agar@exxonmobil. com), Jerry J. Kendall (ExxonMobil) and Rolf V. Ackermann (Beicip-Franlab)

Cretaceous outcrops in northern Oman provide an opportunity to investigate the different processes that accommodate strain variations in carbonates and the factors that influence their timing and distribution. Such knowledge is critical for predicting the impact of structures on carbonate reservoir performance. Preliminary field observations in the Jebel Akhdar region emphasize several important factors for flow modeling in deformed carbonates. Mechanical stratigraphy is an important control on fracture heights and densities. However, fractures confined to individual beds may not impact reservoir flow as much as higher-order fractures that have longer vertical extents and wider spacing. Stratal stacking patterns as well as the mechanical properties of individual beds are important controls on these distinct fracture populations. Our observations of fractures in gently folded strata indicate that curvature does not always provide a suitable proxy for fracture densities or orientations. The folding mechanism and the timing of fracture formation relative to folding are key controls on fracture density gradients around some folds. Fracture corridors and discrete, low-displacement faults are also potential fluid-flow conduits. Preliminary estimates of the displacement-height scaling relations for the very tall but narrow faults indicate that faulting mechanisms in carbonates may differ from those in clastics. Such differences could impact the reliability of sub-seismic fault prediction in carbonates. Seismic imaging is also unlikely to resolve these faults, which may therefore be omitted from flow simulations. These observations, combined with the style and scale of strain partitioning and variable fault zone characteristics are key considerations for representing structural permeability in flow simulations of deformed carbonate reservoirs.

(302-Oral) Hydrocarbon source rock correlations of the Saudi Arabian petroleum systems

Ahmed, Abdelghayoum (Saudi Aramcoabdelghayoum. ahmed@aramco.com), Mahdi A. Abu-Ali (Saudi Aramco), Adnan A. Hajji (Saudi Aramco), Peter D. Jenden (Saudi Aramco) and Michael J. Moldowan (Stanford U)

Saudi Arabia’s Eastern Province holds the greater part of the Arabian Basin which is the world’s major oil producing province. Three major petroleum systems are confined to the Paleozoic and Mesozoic sections. These systems are discussed with respect to source rock potential and their hydrocarbon genetic relationships. The Paleozoic petroleum system consists of the Early Silurian Qusaiba shales of the Qalibah Formation as the principal source rock, particularly the basal ‘hot’ shale unit. Biomarker and isotope data have established the genetic link between the basal Qusaiba ‘hot’ shale and the reservoired hydrocarbons. This system is dominated by the non-associated gas and sweet extra light oil, essentially in Central Arabia. The Jurassic petroleum system includes: (1) argillaceous carbonates of the Tuwaiq Mountain and Lower Hanifa formations in the Arabian Basin; (2) Hanifa-equivalent deposited in relatively open marine, clay-rich source environment in the Rub’ Al-Khali Basin; and (3) Sargelu/Najmah carbonates in the Gotnia Basin. The Cretaceous petroleum system comprises of the Wasia Formation in the Rub’ Al-Khali Basin, and both the Wasia and Sulaiy formations and their equivalents are indispensable source facies offshore Arabia. To address hydrocarbon origin and preservation (oil cracking), several Saudi Arabian oils were analyzed by high-resolution geochemical methods using diamondoids and compound specific isotope analysis of biomarkers. Diamondoids indicated some samples were thermally altered (‘cracked’), some were mixtures of cracked and non-cracked oil, and others were composed entirely of normal oil. Biomarker isotopes strongly differentiated presumed Jurassic and Cretaceous sourced oil samples. This had been difficult to distinguish by other conventional methods.

(229-Oral) Fracture characterization using mode-converted shear waves from dual offset VSP in Minagish field, Kuwait

Ahmed, Shabbir (Schlumberger - shabbir2@slb.com), Abdullatif Al-Kandari (KOC), Pradyumna Dutta (KOC) and Osama Osman (Schlumberger)

The Najmah-Sargelu Formation in the Minagish field is a fractured reservoir in which fracture alignment controls oil production. Fractures cause the formation to be anisotropic such that seismic shear (S) waves get decomposed into fast and slow components, one aligned parallel to the natural axis of the fracture and the other aligned perpendicular to it. Three-component downhole data recording enables the recording of mode-converted shear waves from a compressional (P-wave) source, which can be used for detecting anisotropy. As part of an ongoing drilling effort in the Minagish field, one well in its southern portion provided an excellent opportunity for understanding the shear wave splitting behavior of the Najmah-Sargelu Formation. Seismic ray trace modeling results revealed that a dual offset VSP would determine the anisotropic trend. Two offset sources, located at 260°N and 350°N, each at 2,000 ft from the well, were used to acquire 3-component downhole data. Zero-offset VSP data was also acquired to calibrate and estimate vertical velocities. Field quality control showed that the signal quality in general was good, indicative of reasonable borehole conditions. P-and S-wavefields were separated from the total wavefield using the Parametric Wavefield Decomposition technique. The shear wave data was projected in the fast and slow directions utilizing the rotation technique. The results showed that despite a limited offset, several interfaces generated converted shear waves, which in turn split into fast and slow shear components. The determined anisotropy direction was in close agreement with the other data. The mode-converted shear analyses using offset VSP added a new dimension to couple this information with the future surface seismic measurements in the area.

(373-Poster) Reservoir geometry and quality across a Triassic alluvial plain: an outcrop analog for the Gharif play?

Aigner, Thomas (U Tuebingen - t.aigner@uni-tuebingen.de) and Jens Hornung (U Darmstadt)

This outcrop analog study investigates Triassic fluvial sandstones (Stubensandstein Formation) deposited on a terminal alluvial plain under semi-arid to sub-humid climatic conditions in the land-locked German Keuper Basin. The Stubensandstein may serve as an analog for reservoirs in parts of the Gharif Formation of Oman. The reservoir properties change drastically over tens of kilometers from proximal and distal paleogeography positions: (1) lithofacies types vary along paleogeographical gradient from proximal erosion and non-deposition to fluvial bed-load, to distal suspended-load deposits and finally to playas with lacustrine carbonates; (2) sandbody geometries change from ribbons to sheets; (3) the average permeability of sandbodies decreases by two orders of magnitudes from about 700 mD to 1 mD along paleogeographic proximal to distal trends. Within a three-fold hierarchy of cyclicity, the (probably autogenic) micro-cycles could not be correlated while the meso- and macro-scale cycles could be correlated regionally using the approach of stratigraphic base-level changes. The observed sedimentary patterns, together with paleosol types, their stable isotope signals and palynological data, indicate that paleoclimatic fluctuations exerted the principal control on the stratigraphic architecture and cyclicity. Shorter and longerterm paleoclimatic fluctuations cause systematic changes in reservoir and seal geometries, extent, and interconnectedness of sandbodies. Thus knowledge of the overall paleoclimatic trends in comparable continental basins such as the Gharif may allow predictions on the regional reservoir architecture.

(374-Poster) Geometry, poroperm and sequence stratigraphy of ‘shoal’ geobodies: outcrop analogs for Middle East carbonate reservoirs

Aigner, Thomas (U Tuebingen - t.aigner@unituebingen.de), Sassha Braun (U Tuebingen), Boris Kostic (U Tuebingen) and Michael Ruf (U Tuebingen)

This outcrop analog study was designed to provide input for static reservoir models of shoal bodies on carbonate ramps. The Germanic Muschelkalk represents excellent outcrop analogs for epeiric carbonate systems in the Middle East, such as the Khuff, Hanifa or Arab reservoirs. The studied shelly-oolithic carbonate shoals are up to 30 km long and 15 km wide. They correspond in dimensions to both modern analogs and to several Middle East oil fields. Meter-scale fundamental sequences are stacked into large-scale regressive-transgressive cycles. Porous intervals within the shoal facies are concentrated around the tops of the fundamental shallowing-upward sequences. Pure separate vug porosity samples are characterized by relatively low permeabilities (0 to about 10 mD) but can reach up to 20 percent porosity. In general, a combination of separate vuggy and interparticle porosity leads to higher permeability (several tens of mD). Maximum porosity and maximum permeability zones follow the cyclic seaward-stepping and landward-stepping of the shoal geobodies. Two factors control the evolution of carbonate shoal-complexes with reservoir potential: (1) cyclicity, controlled by hierarchical eustatic oscillations. The best and most voluminous reservoir bodies are developed during the peak of the large-scale regression, whereby meteoric leaching enhances porosity; and (2) regional differential subsidence of basement blocks. Subtle paleotectonic uplift or low subsidence causes preferred accumulation of shoals on local paleohighs.

(139-Oral) Regional core-based sedimentological review of the glacially-influenced Permo-Carboniferous Al Khlata Formation, South Oman Salt Basin, Oman

Aitken, John F. (Badley Ashton - john.aitken@pdo.co.om), Nigel D. Clark (Badley Ashton), Peter L. Osterloff (Shell), Randall A. Penney (ResLab) and Uzma Mohiuddin (PDO)

The Al Khlata Formation of the subsurface South Oman Salt Basin is a significant hydrocarbon-bearing succession within Oman. Previous sedimentological models have attributed its formation to direct deposition from glaciers during Arabian Plate G3 Gondwanan glaciation. Primary depositional processes were thought to be responsible for perceived extensive and unpredictable lateral sedimentological and reservoir quality heterogeneity. All Al Khlata Formation cored wells in the study area were redescribed in order to determine the stratigraphic and palaeogeographic distribution of facies associations and depositional environments, and to establish controls on reservoir quality variability in relation to the sedimentary organization and the existing palynozonation. Approximately 2.5 km of core has been described, and all existing petrographic and conventional core analysis data reevaluated against these core observations. Twelve lithotypes have been identified, which build into ten lithofacies associations defining three main depositional environments: glaciofluvial, glaciodeltaic and glaciolacustrine environments. The controls on reservoir quality are grain size, sorting and mud abundance. However, as there is a wide variation in these primary depositional features at all scales of sedimentary hierarchy, reservoir quality prediction remains enigmatic. Glaciolacustrine and glaciodeltaic deposits are volumetrically more important than has previously been recognized. In particular, Al Khlata diamictites were entirely deposited by rainout and debris flow and there is no evidence for the preservation of true tillites. Consequently, it is hypothesised that ice never over-ran the South Oman Salt Basin, although it was certainly present in the Huqf outcrop area to the northeast, as evidenced by striated pavements. The absence of an ice cover suggests that there is better predictability of Al Khlata facies that permits more reliable correlation and reservoir modeling.

(459-Poster) Multiple attenuation on shallow marine and land data from the Middle East

Ala’i, Riaz (Anadarko - riaz_alai@anadarko.com)

This study discusses some methodologies and strategies for successful multiple estimation and attenuation on shallow marine and land data recorded in the Middle East. Multiples can be a major problem in seismic data interpretation: they may obscure crucial target structures and making optimal data interpretation and therefore exploration difficult. The examples shown here involve datasets which are contaminated with high-amplitude multiples. Therefore a correct estimation of the multiples and their subtraction from the original data is of importance for optimal subsurface model building and interpretation. The approaches discussed in this study are different for marine and land environments. For the marine data, the surface-related multiples generated between the surface and various subsurface reflectors (including the shallow, strongly reflecting water bottom) appear the strongest. They have been estimated with a multi-gate prediction filter and the multiples are subtracted with a multi-gather subtraction process. The simultaneous suppression of different types and orders of multiples appears to be crucial in these environments. The recorded land data is characterized by numerous types of multiples without velocity discrimination and strong varying near-surface statics. For this data, a combination of data-driven surface-related and internal multiple removal was employed in a quasi pre-stack approach using the CMP domain. Since the land dataset suffers from a poor signal-to-noise ratio, supergathers have been constructed for better signal identification prior to sequential multiple estimation and attenuation. As a result of the successful attenuation of the multiples, a better velocity analysis was facilitated leading to more precise subsurface interpretations.

(390-Oral) The E&P legacy data: a step-change in information discovery, retrieval and use

AlFaraj, Tawfeeq A. (Saudi Aramco - tawfeeq.faraj@aramc o.com) and Peter Attewell (Saudi Aramco)

Throughout the history of Saudi Aramco (1933–present), large amounts of exploration data were kept as hardcopy reports, maps and other hardcopy products across various storage locations. Maintaining, sharing and dissemination of information on these hardcopy products were often tedious and time-consuming. In order to provide easy access to the information on these hardcopy products and to enhance the day-to-day vital functions of the geoscientists, Saudi Aramco undertook a major indexing and scanning project for the conversion of all legacy (hardcopy) exploration products that were identified to have added value to the geoscientists’ day-to-day operations or with a historical value to the corporation. The important considerations involved in the indexing, scanning and quality checking of the digital products are presented. The importance of defining and capturing sufficient metadata, which is information about the data, to support finding and retrieving the digital products are also major considerations. Sound procedures and best-practices for ensuring a fast and most-economical data conversion operation were employed. In addition, the data access rules and sensitivity classification that apply to these digital products, which are stored in a document management system, are implemented. With the completion of this major project, geoscientists at Saudi Aramco are benefiting from quick and easy access to a wide variety of information that was previously difficult to access. The success of this project had created a high quality web-enabled electronic data library using a single database model for the converted hardcopy data. Also, a large amount of storage space was freed up for other uses.

(392-Oral) Reflection tomographic depth conversion in Saudi Arabia

Aljanoubi, Emad (Saudi Aramco - emad.janoubi@aramco.c om), Aldo L. Vesnaver (Saudi Aramco) and Muhatresh F. Al-Mutairi (Saudi Aramco)

Over a large area in Saudi Arabia, the most challenging part of depthing is the hanging horizon depth estimation. The geological framework is smooth and predictable between 100 and 800 m subsea, making attractive the use of so-called hanging horizon as a depth reference for calibrating structural trends. The shallow formations are extremely heterogeneous, including sand dunes, carbonate with cavities and collapses, and paleocanyons, often filled with sand. In addition, the P-wave velocity can drop from 3,000 to 600 m/s within a short distance, with possible velocity inversions. There are uphole, velocity-hole, and structural-hole that cover most of the Kingdom, but unfortunately, not all of them penetrated the hanging horizon, and those that did are sparsely scattered in some areas. Reflection tomography is a viable tool for estimating the velocity-depth model down to the hanging horizons. We experimented with multi-layer refraction and joint tomography. Refraction tomography did not produce a stable model, probably due to the shallow subsurface complexities. On the other hand, the hyperbolic inversion down to the hanging horizon produced a stable model for individual 2-D lines. To avoid possible misties, we inverted a grid of 2-D lines, as a single 3-D, in two areas. The combined inversion in both areas demonstrated that reflection, rather than refraction, tomography was able to generate a geologically reasonable velocity depth model that tied all wells with a minor bulk shift due to the wavelet phase inconsistency.

(303-Oral) Significance of assessing hydrodynamic forces in secondary hydrocarbon migration analyses

Alkalali, Arif I. (Saudi Aramco - arif.kalali@aramco.com)

Hydrodynamic forces are a direct manifestation of subsurface fluid energy gradients that can significantly affect the migration of hydrocarbons in a sedimentary basin, in addition to the traditionally considered buoyancy driving forces. The potential significance of such forces has been previously demonstrated theoretically by mathematical relationships and basin-scale fluid-flow numerical simulation models. The aim of this study was to determine if such significant hydrodynamic forces actually occur in nature. Their occurrence in present-day hydrogeological systems of sedimentary basins can give an insight of past hydrogeological systems at the time of assumed secondary hydrocarbon migration. Using a specially developed technique programmed in a spreadsheet, maps of present-day subsurface fluid potential distributions were analyzed for several subareally exposed basins in different parts of the world that span known depth ranges of secondary hydrocarbon migration. The analyses assessed such hydrodynamic effects on hydrocarbon flow magnitude and direction. The results of the analyses show that significant hydrodynamic forces do occur and need to be considered in addition to buoyancy driving forces. The hydrodynamic effects can become most significant in areas of groundwater flow energy sources, which are strongest in areas of highland surface topographic relief, areas of tectonic compression, or near breaches of aquitards. Thus, based on the observations made in present-day hydrogeological systems of sedimentary basins, as demonstrated by this study, explorationists may assess the possibility of hydrodynamic effects to determine exploration fairways.

(404-Poster) Shear-wave processing of zero-offset VSP for lithologic analysis

Alkhater, Salman (Saudi Aramco - khatersa@aramco.com.sa) and John C. Owusu (Saudi Aramco)

In conventional zero-offset VSP seismic processing, the emphasis has been on the enhancement of the P-wave. The shear wave recorded by the three-component receiver is usually of limited benefits due to a variety of factors including: low signal-to-noise ratio, interference from other wavefields and limited dynamic range of the downhole receiver. However, the shear wave information, used in conjunction with the compressional waves, can enhance our understanding of the reservoir by providing attributes such as pore fluid, lithology and the structural image. Additionally, this information can be utilized in modeling and processing of multi-component surface seismic data. In this study, we show that shear wave recorded in a zero-offset VSP survey can be enhanced by performing hodogram analysis on the vertical and horizontal component datasets. First, the two horizontal components (X and Y) are rotated into horizontal radial (HR), and horizontal transverse (HT) components by maximizing the direct P-wave. This is followed by a rotation of the horizontal radial and transverse components by maximizing the direct S-wave. The P- and S-wave interval velocities and Vp/Vs ratio computed from this analysis correlated very well with those from dipole sonic log. Even more important, this procedure could provide S-wave velocities in the absence of dipole sonic data.

(114-Poster) Computing fracture attributes from azimuthal velocity and AVO seismic data in Saudi Arabia

Almarzoug, Ahmed M. (Saudi Aramco - marzam0d@aramco.com.sa), Fernando A. Neves (Saudi Aramco), Jung J. Kim (Saudi Aramco) and Edgardo L. Nebrija (Saudi Aramco)

Determination of intensity, orientation, and distribution of open fractures is a critical task for optimal location of horizontal wells in fractured reservoirs. For a horizontal well to be most productive in tight (low permeability-porosity) reservoirs, it should cross large vertical fractures (faults) with significant amounts of associated micro-fractures. Mapping fractured areas is known to be a real challenge to the geoscientist. Several studies indicate that the search for vertical fractures with vertical core is fruitless, since the chance of intersecting fractures is quite low for a typical 4-inch core experiment. Secondly, these fracture zones are not easily observed tectonic structures (unlike major faults) on post-stack seismic data. P-wave amplitude versus offset and azimuth (AVOA) and azimuthal velocity analysis using 3-D wide-azimuth full-offset pre-stack seismic data usually provide a detailed map of the fracturing pattern away from well control. This study estimated fracture direction and relative fracture density using azimuthal anisotropy measurements of P-wave velocities and amplitude data. We noted a small azimuthal variation in P-wave velocity and a significant variation in AVOA response at the reservoir. The estimated fracture azimuth computed either from velocity or AVOA data is spatially variable, but generally east-west and north-south, in agreement with the regional tectonic trend and borehole breakout analysis. AVOA analysis showed a more consistent estimate of fracture orientation than velocity analysis.

(186-Oral) Gas detection by extended elastic impedance

AlMustafa, Husam M. (Saudi Aramco - husam.mustafa@a ramco.com), Edgardo L. Nebrja (Saudi Aramco) and Saied Zahrani (Saudi Aramco)

Searching for optimum seismic pore-fluid indicators should concentrate on elastic moduli rather than wave-propagating velocities since it is the moduli that govern the behavior of rocks. Extended elastic impedance derived from elastic impedance, allows us to derive curves proportional to various elastic parameters such as bulk modulus, Lame’s constant of incompressibility, rigidity and Poisson’s ratio. Our analysis concentrates on the incompressibility-rigidity approach because incompressibility is sensitive to pore fluids and rigidity is unaffected by fluids. Combining these two into one measurable parameter should provide an effective tool for delineating gas-bearing zones in sandstone reservoirs. The value of incompressibility divided by rigidity at three well locations showed smaller values in gas-bearing reservoirs than those in tight or water-bearing reservoirs. We applied this extended elastic impedance approach to the Upper and Lower Unayzah Sands for gas interpretation and obtained a fluid and lithology impedance volume highlighting possible gas-bearing regions previously overlooked by conventional acoustic impedance inversion. It has been found that the extended elastic impedance is an atribute sensitive to gas accumulation and thus an essential factor to consider for optimally placing future development wells in the region.

(175-Oral) Salt and bitumen plugging: their combined effect in carbonate stringers, South Oman Salt Basin

Al-Abry, Nadia (PDO - nadia.sn.abry@pdo.co.om), Janos L. Urai (Aachen U), Ralf Littke (Aachen U) and Peter A. Kukla (Aachen U)

Minassa-1H1 well was drilled to test for moveable hydrocarbons in the A1C carbonate stringer cycle in the Dhahaban area of the South Oman Salt Basin (SOSB). Hydrocarbon shows were encountered while drilling and petrophysical evaluation indicated the presence of hydrocarbon pay within the favorable primary reservoir facies (parallel/crinkly laminites and thrombolites) but on testing the well failed to produce hydrocarbons. A detailed examination of the core revealed extensive salt plugging throughout the reservoir interval with prevalence of black substance (i.e. bitumen). Analysis of core plugs and thin sections confirmed the extensive plugging of pores with halite, and bitumen. Preliminary studies conducted on salt plugging indicated that the halite, which is diagenetically late, is deformed with rare primary fluid inclusions. Bitumen is found in pore space and within halite crystals. Several generations of solid bitumen are thought to exist. Petrophysical evaluation of wireline logs indicated a poor quantitative correlation between the log response and the amount of bitumen seen in cores. Although many stringer wells in the SOSB are known to contain bitumen at various percentiles (such as Dhahaban South-1H1 or Dafaq-1H1), bitumen plugging was not believed to present a problem to hydrocarbon flow. However, in Minassa-1H1, bitumen plugging coupled with salt plugging seems to form a major barrier to the hydrocarbon flow by reducing the effective porosity and permeability values in the A1C reservoir. Specialized studies are now focussing on resolving the genesis and regional distribution of halite and bitumen. The studies will also clarify their wireline log response.

(140-Oral) Hanging-horizon depth estimation using geostatistical tools

Al-Ali, Mustafa N. (Delft Um.n.alali@ctg.tudelft.nl) and Abdulnasser M. Khusheim (Saudi Aramco)

The reliability of ‘hanging-horizon’ depth map is important when dealing with low-relief structures (15 to 30 msec). In this study we briefly describe the application of geostatistical tools in estimating a hanging-horizon depth map via integration of velocity wells and seismic data in an area east of Ghawar field in Saudi Arabia. The main objective of this task was to produce a depth map to the top of the Aruma Formation. The section above the Aruma Formation is characterized by lateral and vertical heterogeneities. Although there are many velocity wells in the area that reach the bottom of the Rus Formation, and a few that reach the Aruma Formation, they are not adequate to independently resolve the existing complexities. Therefore, high-resolution 2-D seismic data (2.5 m subsurface sampling) was used to improve the time mapping between the wells. The first step was to tie all the velocity wells to the seismic at critical horizons that can be interpreted over the entire area. Next, ordinary cokriging was used to integrate well times with seismic times (referenced to surface) for every mapped horizon. The resultant time maps were used as markers to guide the 3-D kriging of velocity data from all wells in the area. This produced a 3-D velocity model with each voxel having a velocity value and a time isochron. Therefore, a depth map can be obtained by summation of all voxels thicknesses in each column. Finally, to assure perfect tie to all the well depths, collocated cokriging of well depths and this map was performed. Geostatistical tools proved as a useful means for integrating shallow seismic data with the associated well information.

(318-Oral) A novel technique for near-surface macro-velocity model estimation

Al-Ali, Mustafa N. (Delft U - m.n.alali@ctg.tudelft.nl)

This abstract briefly describes a novel technique for improving near-surface macro-velocity model estimation. It is based on integration of uphole velocity data and a velocity attribute derived from vibrator baseplate information. As it pushes against the earth, the vibrator senses the earth’s response to the applied force through the movements of the baseplate. Therefore, by knowing the dynamics of the vibrator (the reaction mass and baseplate accelerations) estimates can be obtained for the underlying earth properties. Consequently, a P-wave velocity attribute can be derived from these estimates. This attribute has the same spatial sampling rate as the source grid in the seismic survey, which is considerably finer than the sparse uphole grid. It reliably defines the lateral boundaries of near-surface velocity variations. Integration of this attribute and uphole velocity data using geostatistical tools, may lead to improvements in the near-surface macro-velocity model. An important application of this model is in the calculation of seismic statics. The technique outlined above was used to build models in several areas followed by application in seismic stacking. Results exhibited consistent improvements in seismic stacks compared to those obtained from conventionally calculated models. Using the new technique, medium and long wavelength statics anomalies were better resolved. This is attributed to the guidance provided by the vibrator velocity attribute to determine the lateral influence zone of each uphole in the area. Finally, besides the achieved improvements, the data used to derive the velocity attribute is readily available in any land survey that is acquired using vibrators.

(52-Oral) Understanding the behavior of hydrogen sulphide (H2S) in the reservoirs of the Greater Burgan oil field, Kuwait-an integrated approach

Al-Azmi, Saleh F. (KOC - sfazmi@kockw.com), David Jackson (ChevronTexaco), Reham Al-Houti (KOC) and Shymaa Al-Hazzaa (KOC)

The presence of H2S in the Greater Burgan field area became a problem in the 1990s when its presence in the surface facilities became a prominent safety concern. Therefore studies were set up both to cover the surface occurrence, and the subsurface occurrence of H2S. This study describes the subsurface occurrence, and shows how an integrated approach covering geochemistry, geology, geophysics and engineering has led to the presently favored model for H2S encroachment. The model is vital for providing a framework for asset decisions regarding shut-in priorities and allowables, providing qualitative predictions for future H2S behavior, and provide a basis for the development of concepts to mitigate H2S encroachment. Following initial studies to ascertain the size and nature of the H2S phenomena, it was decided to run annual full-field sampling programs; there are now four consecutive years of H2S measurements in gas samples at the wellhead. By simply mapping the data, an overall ‘H2S Plume’ was identified at the crestal part of the Burgan Dome–one of three main structural highs in the Greater Burgan field. The other two structural highs, Ahmadi and Magwa, show much lower levels (in most cases zero concentrations of H2S). The variation between the concentrations in these three areas appears to be a consequence of off-take and intrareservoir seals controlling the migration of H2S from a deep-seated source. Over a four-year period we have identified areas where H2S appears to be decreasing, increasing, and staying relatively constant. A model for this variation has also been proposed.

(215-Oral) Evaluation and testing of bypassed oil accumulations in the Burgan field, Kuwait

Al-Azmi, Saleh F. (KOC - sfazmi@kockw.com), Abeer K. Al-Ali (KOC), David Jackson (ChevronTexaco-KOC), Saleh A. Al-Rasheedi (KOC) and Obaid M. Al-Shammari (KOC)

The acquisition and interpretation of 3-D seismic over the Greater Burgan oil field led to a better understanding of the distribution of unswept oil accumulations. These accumulations range from simple attic closures in massive sand reservoirs–normally associated with simple structural closures, to more complicated accumulations comprising of combined structural-stratigraphic traps in the more interbedded sandstone reservoirs. The Burgan Sandstone Reservoirs are divided into 4 zones: 4th Sand, 3rd Sand Lower, 3rd Sand Middle, and 3rd Sand Upper. Above the Burgan Sandstone reservoirs lies the Mauddud muddy carbonate formation, above which lies another interbedded sand-shale reservoir, the Wara. Examples of bypassed oil are discussed from all of the above clastic formations. The methodology applied involved the integration of well surveillance data (pnc/tdk logs, oil-water production data) with the geological and geophysical architectural data. Although there are vast reserves remaining in the Greater Burgan field, the stacking of reservoirs, combined with the increasing competition for wellbore usage, means that opportunities to sweep undrained oil needs to be assessed and acted upon accordingly. This study concentrates on the subsurface multi-disciplinary approach applied to the assessment of opportunities to drain bypassed oil. However, the interaction of the subsurface team with the surface production facilities and operations departments, is highlighted. Examples of new wells to drain stratigraphically and structurally trapped downflank, bypassed, oil are given; together with workovers which have been carried out to drain both attic oil accumulations in massive sands, and bypassed oil trapped in the interbedded sand-shale reservoirs.

(415-Oral) Eigenimage footprint removal

Al-Bannagi, Muhammad S. (Saudi Aramco - mohammad. bannagi@aramco.com), Kangan Fang (Saudi Aramco) and Panos G. Kelamis (Saudi Aramco)

Geometry acquisition footprints are linear spatial grid patterns seen on seismic time slices. Essentially, they mirror the acquisition geometry used for acquiring the seismic survey. Their presence tends to mask key geological features introducing uncertainty at the final interpretation stage. Although dense seismic acquisition geometries eliminate the footprint signature, they are rarely employed in the field due to the high cost involved. Thus, processing techniques are usually applied aiming to reduce the footprint effect. Pre-stack reconstruction and regularization algorithms, based on Fourier/Radon transforms and combined with apriori information, can be quite effective. Their performance however, depends on spatial sampling, spatial bandwidth and the choice of parameterization. Alternatively, post-stack methodologies based on FK filtering principles, are used but they tend to suffer from the well-known mixing and worming artifacts. In this study, a new post-stack approach is introduced to remove the seismic acquisition footprint. The method is based on eigenimage filtering and offers several advantages over the conventional FK and F-XY prediction filtering techniques while preserving the data character. It only assumes that the number of distinct dips is limited and unlike many eigen-based approaches can work well with dipping reflectors. Additionally, it removes random noise and makes a modest attempt to restore missing data at shallow depths. Its performance is demonstrated with field land data from the Arabian Peninsula.

(151-Oral) Tectonic evolution of mini-basins in the Thumrait block (South Oman Salt Basin): implications from physical analog modeling

Al-Barwani, Badar H. (PDO - bader.barwani@pdo.co.om) and Ken McClay (Royal Holloway, U London)

This study presents structural evolution of the Thumrait block in the southwestern part of the South Oman Salt Basin, and a series of scaled analogue models designed to simulate development of mini-basins. The Thumrait block is characterized by a series of salt ridges and associated salt withdrawal mini-basins. It shows a complex interaction of salt and sediments. The salt withdrawal mini-basins are circular to oval in shape, 1-12 km wide, and encircled by narrow, elongated salt ridges. Four different types of mini-basins formed at different time intervals. Most of the deformation associated with halokinesis occurred at an early stage during the deposition of the Early/Middle Cambrian Nimr Group and the Amin Formation. Pulses of sediment loading manifested by alluvial fan and braided river deposits from the west are the main trigger and driving mechanism for halokinesis. Results from the analogue modeling show that mini-basin formation can be caused by differential loading of the type generated by alluvial fan systems. Differential loading of a ductile polymer created localized extension forming radial and axial grabens. These grabens are sites of reactive rise of the ductile substrate producing ridges that bound withdrawal basins. The results of the physical modeling are compared to the Thumrait block during the early phases of halokinesis during the deposition of the Early–Middle Cambrian Nimr Group.

(152-Oral) Contrasting styles of salt structures in the South Oman and Ghaba Salt Basins

Al-Barwani, Badar H. (PDO - bader.barwani@pdo.co.om) and Ken McClay (Royal Holloway, U London)

Three major salt basins occur in Oman: (1) South Oman Salt Basin (SOSB); (2) Ghaba Salt Basin; and (3) Fahud Salt Basin. Although the Late Proterozoic Ara salt controls the structural evolution of these basins, they differ in styles, geometries and driving mechanisms for halokinesis. In the SOSB, mini-basins and salt ridges are the main features with interconnected salt ridges and no circular diapirs observed. Differential loading during the Nimr Group sedimentation was dominant at the early stage of halokinesis to the west of the SOSB. Later blanket sedimentation during the Ordovician prevented further halokinesis in the SOSB. In contrast to the north of the SOSB, in the Central Oman High and the Ghaba Salt basins 8 salt diapirs are found as a result of ‘thick-skinned’ compression of reactivation of basement faults. These diapirs are interpreted to form as a result of two phases of compression rather than ‘thin-skinned extension’ as previously documented. The first phase formed during the ‘Hercynian’ Orogeny (Late Devonian to Late Carboniferous) as a result of the Huqf Uplift, which triggered further halokinesis. The second phase of contractional salt tectonics occurred during the Cretaceous in the Central Oman High, the Ghaba Salt Basin, and the Fahud Salt Basin, as a result of the emplacement of the Semail and the Masirah Ophiolite in northern and eastern Oman, respectively. The contrasts between diapirs developed in the different tectonic regimes are illustrated in details.

(95-Oral) Calculating long wavelength statics in the Sirte Basin

Al-Dabagh, Hazim H. (Schlumberger - haldabagh@aol.com) and Khaled Khabbush (Consultant)

A new approach has been developed to tackle the problem of calculating long-wavelength statics from conventional exploration seismic data. The method uses the pre-stack reflection data from shot records and an initial near-surface model as input to an algorithm using the ray-tracing technique. The appropriate statics value is that value which produces maximum stack power along travel-time curves generated by ray-tracing through the model. The technique has been tested successfully on both synthetic and real seismic data acquired in a hilly and noisy environment. The procedure does not require the picking of seismic refraction events on shot records. It provides a practical alternative to conventional methods in those areas where refraction events cannot be picked reliably on pre-stack data. This method is able to cope with the vertical and lateral variation in the physical properties of the near-surface layers and produces reliable results for the conventional seismic data example described in this paper.

(434-Poster) Using high-resolution sequence stratigraphy for field-scale characterization of Permo-Triassic Khuff carbonate reservoirs, Ghawar field, Saudi Arabia

Al-Dakhil, Ra’id K. (Saudi Aramco - raid.dakhil@aramco.com), Ghazi A. Al-Eid (Saudi Aramco), Aus A. Al-Tawil (Saudi Aramco), Rick R. Davis (Saudi Aramco) and Shoaib M. Rawasia (Digicon)

The Khuff Formation overlies the Permo-Carboniferous siliciclastic Unayzah reservoir bearing, and is overlain by the fine siliciclastics of the Triassic Sudair Formation. The Khuff C carbonate reservoir contains three high-resolution sequences; whereas the Khuff A and B carbonate reservoirs are each made up of one bearing (third-order?) sequence. Sub-tidal, high-energy, and open-marine facies, overprinted by early diagenetic fluids form high porosity reservoir compartments. Intra-formational seals are anhydritic/dolomitic carbonate coastal successions and form thick, non-reservoir intervals between the Khuff C and B, and the Khuff B and A, during longer-term possible third or second-order highstand system tracts (HST), overprinted by extreme inland climatic aridity, coincident with the assemblage of the supercontinent Pangea. Sequence and cycle-set boundaries are marked by exposure surfaces during periods of sea-level drops, which in turn have a corresponding gamma-ray signature on wire-line logs. Using these regional markers on over 15,000 ft (5,000 m) in 50 cored wells and wire line logs in 200 closely-spaced wells, allowed mapping high-resolution (fourth order?) sequences, as well as deciphering of onlap geometry of the high-frequency transgressive systems tract (TST) and prograding geometry of the high-frequency HST. Glacio-eustacy during the Permo-Triassic times, which are transitional from global ice-house to global green-house times, resulted in moderate amplitude sea-level fluctuations, giving rise to regionally mappable, high-resolution (4th-order) sequences and their component systems tracts and cycle sets. This controlled the vertical partitioning of reservoir facies within Khuff C, B, and A carbonates. The active Ghawar structure during the Permian, lead to lateral partitioning of these facies from proximal on the crest, to distal on the flanks. Furthermore, subtle highs and saddles along the crest, furthered the lateral portioning of the reservoir. Reservoir facies formed during the retrograding oolitic shoal belts of the late TST (Khuff A, B, and C) and the shallow subtidal burrowed facies of the prograding HST of each of the high-resolution sequences (Khuff C only). This high-resolution stratigraphy allowed very precise mapping of facies down to the cycle-set level at a very high resolution of 15 ft (3 m) at the scale of the Ghawar field.

(106-Poster) Tectonic evalution of North Oman from regional scale to field scale

Al-Dhahab, Salah H. (Shell - salah.dhahab@shell.com), Pascal Richard (Shell), Martin de Keijzer (Shell), Safia al Mazrui (PDO) and Jacek Filbrandt (PDO)

A regional review of those aspects of the structure and tectonic evolution, which potentially affect and control reservoir quality and reservoir performance at a field scale, has been done for North Oman, with emphasis on the Shu’aiba Formation. The review included: (1) a compilation of the regional tectonic evolution and structural framework of Oman from selected key publications and internal reports; (2) construction of a GIS database, which brings together structural and other geological data from the regional to the well scales, together with field-scale production data; and (3) the creation of a 3-D regional structural model for the whole of North Oman area (North Oman Common Earth Model - NOCEM) based on seismic data in depth interpreted by PDO. The 3-D regional model is a base to define regional structural domains from the interpretation of structure and kinematic indicators. This enables better understanding of the structural evolution both regionally and per domain, which may include one or more fields. A total of five regional tectonic domains have been defined. The main characteristics used to define these domains were: (1) amount of halokinesis (salt-related deformation); (2) amount of uplift/burial; (3) fault signature (intensity, as far as it can be qualitatively assessed, and dominant orientations). The distinction of the tectonic domains allows, for example, for an assessment of the expected style(s), directions, intensities, etc. of fractures and faults, both from an exploration and field development point of view.

(433-Oral) Proximal-to-distal facies variability within a high-resolution sequence stratigraphic framework defining syndepositional structural activity of Ghawar field during the deposition of the Permian Khuff-C carbonates

Al-Eid, Ghazi A. (Saudi Aramco - ghazi.eid@aramco.com), Ra’id Khalil Al-Dakhil (Saudi Aramco), Aus A. Al-Tawil (Saudi Aramco), Rick R. Davis (Saudi Aramco) and Shoaib M. Rawasia (Digicon)

The up to 90 m thick, gas-bearing Late Permian Khuff C carbonate reservoir is made up of three high-frequency sequences bounded by sharp, regionally mappable boundaries with varying degrees of exposure features and regionally mappable flood-backs. These sequences and component cycle-set boundaries are marked by regionally mappable gamma-ray signatures, facilitating their mapping in non-cored wells. The transgressive systems tract (TST) of each sequence is made up of back-stepping cycle-sets (3 to 10 m each), which remain horizontal and can be traced for over 200 km; onlap geometry can be recognized regionally over locally high areas. Flooding cycle sets are made up of peritidal, lagoonal, and back-barrier facies, which pass into the late TST belt of overlapping ooid shoal facies that thicken northward. The associated fore-shoal and storm-influenced facies are time-transgressive from south-to-north. High-energy, fore-shoal/deep marine bryozoan mud are the most distal Khuff facies in Ghawar field, and form the maximum flooding (MF) of the high-frequency sequences. The prograding highstand systems tract (HST) of each high-frequency sequence is made up of shingled cycles of open marine flooding facies that pass upward into shallow subtidal (reservoir) and minor intertidal (nonreservoir) facies. Slopes of prograding packages are subtle (0.01 degree), and can only be recognized by mapping the high-resolution sequences over the scale of the Ghawar field. High-resolution sequence stratigraphy constrains the distribution of facies within regionally mappable units down to 15 ft (3 m), within which, proximal facies are to the north and along the present-day Ghawar crest, and distal facies to the south and on the present-day Ghawar flanks. This indicates an active Ghawar structure that was plunging to the south during the deposition of Khuff carbonates/evaporites. Crestal variability formed proximal facies over subtle highs to distal facies over subtle lows, whereas local, fault-bounded, down-dropped blocks led to thicker accumulation of sediments as well as local restriction and deposition of salinas and sub-aqueous anhydrite. Delineation of such intervals within the high frequency sequence framework leads to constraining local areas of degraded reservoir quality due to cementation and plugging by remobilized anhydrite. High-frequency (third-/fourth-order) eustacy (low-to-moderate amplitude) during a transitional time from the Permo-Carboniferous glaciation into Permo-Triassic greenhouse gave rise to the regionally mappable high-frequency sequences, their TST, HST, and component cycle-sets.

(249-Oral) Contracting a complex 3-D survey

Al-Ghamdi, Turki M. (Saudi Aramco - turki.ghamdi.8@ara mco.com) and Richard Hastings-James (Saudi Aramco)

The Qatif 3-D survey is Saudi Aramco’s most complex 3-D survey ever, involving Ocean Bottom Cable (OBC) dual sensor, transition zone (TZ), and land vibroseis and dynamite operations. The aims of the survey are to accurately image both the shallower carbonate reservoirs for development purposes, as well as deeper clastic gas reservoirs for exploration purposes. The survey area encompass various types of surface conditions varying from deep-water to mangrove and tidal areas, sand, sabkha, cities, old towns, highways, industrial areas, restricted areas (military bases, airports, farms), and a high density of various categories of pipelines and power lines. In order to investigate and assess the required effort, Saudi Aramco conducted five feasibility studies, of which one is internal and the rest by four different recognized international seismic contractors. The studies assessed the distribution of various surface conditions, identifying possible source and receiver types’ distributions, exclusion zones, high-risk operating areas, and types of permitting issues. Furthermore, Saudi Aramco conducted a 2-D test line with a mix of explosives and vibroseis sources to determine the explosive source configurations, test various receiver configurations, and assess required drilling efforts. Along with the 2-D test, a Peak Particle Motion (PPM) study was run in different site locations throughout the survey area to establish critical safe operating distances from various types of buildings, pipelines, power lines, plants, and water wells. Finally a contract was developed incorporating the above information to optimize the survey area, specify the crew configuration and acquisition parameters, and to specify operational procedures.

(20-Oral) Integrated static and dynamic modeling approach in one of Thamama gas reservoirs of onshore Abu Dhabi

Al-Habshi, Ali H. (ADNOC - alhabshi@adnoc.com), Amr M. Badawy (ADNOC), Abdel Rahman R. Darwish (ADNOC), Adham K. Hathat (ADNOC) and Thanaa E. Hamdy (ADNOC)

The ability of integrated software to present solutions is evolving rapidly and has shifted to emphasize on what a best-practice modeling approach should be. One of the issues often raised is the link between a facies-based model incorporating depositional and sequence stratigraphic characteristics, and its use during dynamic simulation. This study suggests an approach that introduces the concept of modeling based on the reservoir rock type. The example used is one of the major producing gas reservoirs in a giant field in central onshore Abu Dhabi where the general structure trends is NE-SW, and has dimensions of 40 x 30 kms. Its main reservoir zones are part of the Lower Cretaceous Thamama Group. The overall depositional environment is characterized by its location on the Arabian carbonate platform within an intrashelf basin. Applying the sequence stratigraphy principles, the reservoir is divided into two parasequence sets. The lower part comprises a progradational interval overlain by a retrogradational package, with the boundary between each package marking a stillstand. Six lithofacies were identified in the reservoir: (1) bioclastic peloidal grainstone; (2) algal packstone/floastone; (3) bioclastic peloidal packstone; (4) algal wackestone/floastone; (5) bioclastic peloidal wackestone/packstone; and (6) argillaceous bioclastic wackestone. These lithfacies are believed to have been desposited on a homoclinal carbonate ramp that dipped gently seaward. Porosity and permeability are well developed in the reservoir section due to a lack of pore-filling cement. In the field, a clear general trend occurs of down-flank porosity reduction of more than 10 percent from the crest down to the water-bearing zone. This is mainly due to the increased abundance of stylolite formed during burial diagenesis, hydrocarbon migration, and infill of the structural trap. Analysis of both thin-section descriptions and high-pressure mercury injection, led to the identification of five distinctive rock types. Each reservoir rock type has a certain effective pore throat size distribution which will produce a particular capillary pressure curves, relative permeability curves and constrained porosity/permeability estimation.

(438-Oral) Effective reservoir management of Bahrain’s mature oil field: a case study

Al-Haddad, Abdulla M. (Bapco - abdulla_alhaddad@bapco.net) and Challa R.K. Murty (Bapco)

Bahrain’s Awali field, discovered in 1932, is a highly-faulted asymmetrical anticline trending in a NS direction. The field produces from seventeen oil and three gas reservoirs within Jurassic to upper Cretaceous formations, as well as from the Permian-Triassic Khuff limestone gas zones. These reservoirs occur with divergent lithology, rock and fluid properties. Some of them are saturated, while other are highly undersaturated. Some of them are oil wet and some water wet. They operate under various drive mechanisms and pressure maintenance schemes. Gas injection in the Mauddud reservoirs, which is one of the major oil producing zones in the field, has been in operation for the last 65 years. Gas injection in the Arab-D reservoir has been in progress from 1986. Pilot peripheral water injection is in progress in the Wara sands in the northeastern area of the field since 1995. Additionally, different production mechanisms have been applied including gas lift, pumping and stop cocking for GOR control. The field being mature and structurally complicated, naturally demands an integrated approach for effective reservoir management to ensure maximum recovery. Due to the application of diverse reservoir management techniques, reservoir characterization, geostatistical application for anisotropy, and increased accuracy for simulation, the field has been producing with minimum annual decline. By integrating the geological, seismic and reservoir/production data, the productive limits of various reservoirs have been extended adding substantial reserves. This presentation discusses the approach adopted in the effective reservoir management of this giant mature oil field.

(191-Oral) Geochemical analysis to identify prospectivity of Makhul Formation in Kuwait

Al-Hajeri, Mubarak M. (KOC - mhajeri@kockw.com) and Swapan K. Bhattacharya (KOC)

The Makhul Formation has been evaluated geochemically to establish its hydrocarbon potential as a future exploration target. So far the Makhul Formation in Kuwait is considered to be a localized source rock for selective Cretaceous reservoirs and also tested oil-bearing in one of the wells in Minaghish field. In this present work one attempt was made to reevaluate the source characterization using TOC, rock-eval, kerogen composition, thermal maturity and pyrolysis GC data. This study is further extended to compare the compositional variations between oil and extract and isotopic variations between kerogen and pyrolysate. Results indicate that although TOC and rock-eval data show selective source potential, other detailed analysis do not justify the inference. Integration of the results indicate that the Makhul Formation is a poor source even if it has sufficient organic carbon in selected horizons. A second study was conducted to identify any prospective horizons within the Makhul Formation using gas composition from mud log gas chromatogram. For this purpose an unconventional methodology–use of wettability of mud log gases–was used, and correlated over the structures. The correlation was then validated with proven hydrocarbon-bearing horizons in Minaghish field. A certain high percentage of wettability of mud log gas was chosen as a criteria for prospect identification. It was observed that the lower part of Makhul is prospective in selected areas in Kuwait.

(360-Oral) The sedimentology of the upper part of Musawa Formation: a Late Eocene intracontinental basin of eastern Oman

Al-Harthy, Abdul Rahman (SQUabuali@squ.edu.om), Ali S. Al-Rajhi (SQU) and Abdulrazak S. Al-Sayigh (SQU)

The upper Eocene succession of the southeastern Oman Mountains contains an exceptionally thick fluviodeltaic siliciclastic sequence. The outcrops represent the upper part of the Musawa Formation and can be traced laterally for a few kilometers where the lower contact is an unconformity marked by a prominent limestone escarpment. Six distinct lithofacies have been described as follows: cherty conglomerates, sandstones, siltstones, gley-type paleosols, oyster-rich limestones and coal seams. The cherty conglomerate facies is encountered at three major (> 4 m thick) stratigraphic levels and represents an unusual case due to its coarseness and the absence of such deposits in the Central Oman Mountains. The sandstones are predominantly quartz arenite although locally chert clasts can be as much as 20 percent. Siltstone is the most dominant facies while gley-type paleosols occur in the southern outcrops. Most of the coal seams are found in the northern outcrops showing increasing pyrite content up-section, a typical signature of marine influence as recorded in the literature. Foraminifera microfauna associated with the siltstones above the coal seams comprise Nummulities fabianii, N. Stritatus, N. Garnieri, Pellatispira sp., Amphistigena sp., Silvestriella sp., Calcarina sp., Borelis vonderschmitti, Gypsina globules, Fabiania cf. saipanesis, together with rare miliolids and fragments of inderminate encrusting foraminifera (dominantly acervulinids). The stratigraphic ranges of these taxa indicate that the upper part of the Musawa Formation is Upper Eocene, Priabonian (arguably early to middle Priabonian) in age. The absence of the larger foraminiferal genera Assilina and Aalveolina, which are common in the Eocene section of Oman and are known to have become extinct at the end of the Middle Eocene, also indirectly supports a Priabonian age. The occurrence of these thick siliciclastic sediments is interpreted as the result of activation of the North Ja’alan Fault resulting in a strike-slip basin in the Late Eocene. The forces associated with the strike-slip movement are believed to be related to the rifting of the Red Sea and Gulf of Aden during a time of global sea-level fall where a maximum regression took place (about 34 Ma).

(362-Poster) Micropaleontology and sedimentology of the Late Paleocene-Early Eocene Abat Formation of southeast Oman

Al-Harthy, Abdul Rahman (SQU - abuali@squ.edu.om) and Abdulrazak S. Al-Sayigh (SQU)

New micropaleontological data is presented for the Abat Formation of southeast Oman. The formation is of Late Paleocene to Early Eocene (Thanetian to Ypresian) in age. It comprises a thick (114 m) sequence of open marine, resedimented and basinal deposits. The base of the formation begins with thin interbeds of shales and planktonic foraminiferal wackestones, which are progressively overlain by resedimented algal and foraminiferal packstones and grainstones. The planktonic foraminifera include Morozovella and Subbotina species, especially in the lower part. This lower part is in turn overlain by an amalgamation of at least 17 m of graded limestone beds with sharp scoured contacts. The meter-scale limestone beds are made of stacks of at least six resedimented algal-dominated limestone beds with no shale interbeds. Towards the top of the formation, typical shallow-marine fauna are common, especially larger foraminifera such as Discocyclina, Daviesina, Miscellanea, Nummulites, Alveolina, Miscellanea, Assilina and Operculina musawaensis nov. sp. together with smaller benthonic foraminifera including Lenticulina, Nodosaria, Glandulina, Anomalinoides, and Pullenia are also present. Calcareous red algae together with echinoid plates and corals occur sporadically throughout the upper part. The formation unconformably overlies Maastrichtian sandstone turbidites of the Fayah Formation, and is conformably overlain by sandstones and conglomerates of the Musawa Formation with which it interdigitates in its upper part.

(115-Poster) Perseverance in stringers exploration: the Dafaq discovery

Al-Hashimi, Rashid A. (PDO - rashid.raa.hashimi@pdo. co.om), Robert Gardham (PDO), Abdullah Al-Shamakhi (PDO), Aida Al-Harthi (PDO), Jack Filbrandt (PDO), Hisham Al-Siyabi (PDO), Xavier Maasarani (PDO), Leon Hoffman (PDO) and Jean-Michel Larroque (PDO)

The Intrasalt Ara Group Carbonate Stringer play of Neoproterozoic to Early Cambrian age is developed over large parts of the South Oman Salt Basin (SOSB). Six carbonate cycles (A0C to A6C) have been identified and are correlated on the basis of facies, paleogeography, chemostratigraphy and absolute age datings on volcanic tuffs. Oil and gas discoveries have been made in several of these carbonate cycles, encased and sealed by Ara salt, across a variety of carbonate facies and pressure regimes. Well Ambrah-1 was drilled in 1991 to target both the A3C and A2C stringers. The well was sidetracked down-dip after finding out that hole 1 had been drilled through a fault zone. Ambrah-1H2 found a 10 m hydrocarbon-bearing pay zone only, in the A2C and tight A3C. A detailed post-drill remapping of the area with new pre-stack imaging-reprocessed 3-D seismic data has revealed another potential fault zone separating the northern part of the A2C stringer (Dafaq area) from the part penetrated by AMB-1H1 and AMB-1H2. Furthermore, the borehole image analysis derived from these two wells show the A2C is very highly deformed. Dafaq-1H1 was drilled in 2001 two kilometers down-dip of Ambrah-1H1 and H2, based on the assumption that the fault separating Ambrah-1H2 and the Dafaq area is sealing. Dafaq-1 found highly overpressured oil in the A2C, was tested in 2002 and produced at stable commercial rates. Dafaq oil has a low bubble pressure point compared to its initial high reservoir pressure. The discovery is currently being appraised by PDO and early production is planned for mid-2004.

(46-Poster) Single-layer velocity model to derive near-surface correction statics in Saudi Arabia

Al-Homaili, Mohammad A. (Saudi Aramco - mohammad.homaili@aramco.com), Ralph Bridle (Saudi Aramco) and Robert E. Ley II (Saudi Aramco)

Until 1994 upholes were drilled and logged every 4 km along 2-D seismic lines. Having acquired over 42,000 upholes, the near-surface is generally well-sampled. The ‘frozen’ model is a single-layer velocity model from surface to datum. At uphole locations, the average velocity to datum is derived. For upholes that penetrate the datum, average velocity is calculated from the depth and time to datum. Some upholes are shallow; in this case the last high velocity is extrapolated to datum. Creation of the ‘frozen’ model was performed on prospect areas. Each area was interpreted and the uphole location average velocities were contoured with appropriate parameters to reduce artifacts. All the prospects were merged into one grid. Derivation of static corrections is from the ‘frozen’ model velocity grid. The grid is sampled at the source and receiver coordinates. Given the thickness from surface to datum, the static correction is calculated. Advantages of this method are: (1) speed, quick to produce model static corrections; (2) consistency, all static corrections are derived from a single model; and (3) ties, all 2-D and 3-D locations should have time horizons at the same time. Problems occur when: (1) datum is above the surface; (2) weathering is below the datum; (3) rapidly changing near-surface velocity and inversion; and (4) under-sampled areas and shallow upholes. A common expression of a problem in a time section is a cycle skip, and other medium-wavelength effects that can be seen in the near offsets. A simple horizon-tracking approach is used to overcome these short-wavelength problems on 2-D lines. The shallow time horizon is tracked and moved to a reference time. Caution has to be observed as the method can be used to create or mend time structures. The concern over the legitimacy of moving time horizons and the difficulty of applying the method to 3-D blocks lead to more rigorous methods in deriving near-surface models.

(497-Oral) Integration of depositional, diagenetic and seismic tools to predict reservoir quality of Khuff Formation in eastern Saudi Arabia

Al-Jallal, Ibrahim (Saudi Aramco - ibrahim.jallal@aramco.c om) and Shiv N. Dasgupta (Saudi Aramco)

The Khuff Formation, a major source of gas in Saudi Arabia, was studied in detail both locally and regionally. The study shows how to use depositional and diagenetic tools from cores and logs integrated with seismic to predict reservoir extension around the wells. The seismic waveform is calibrated at the well and can be used in other areas with no well control to estimate reservoir quality. The study explains how integrated analysis between multiple disciplines in Geology and Geophysics can be achieved The Khuff depositional setting was defined regionally, lithostratigraphic units were correlated, major facies were recognized, and anhydrite footage and average porosity were mapped. Areas of good reservoir potential around the Gulf Area were defined. Sour gas areas were explained and areas of poor reservoir facies were predicted. Locally, diagenetic and depositional tools were used to interpret good reservoir areas. Dolomitization in this example enhanced the original porosity in grainstones and created intercrystalline porosity, creating the best reservoir facies in north Ghawar. Careful study of these features lead to the identification of a marine embayment or large channels that brought saline water through the layers above, dolomitizing the rocks beneath. Other diagenetic factors, including cementation by anhydrite or calcite and leaching, were defined and their destruction of porosity and permeability were recognized and explained. Recently, seismic inverse modeling was done for the Khuff using the recently acquired high-fold 3-D seismic data constrained by the available petrophysical data from wells. The computed seismic impedance and porosity from well logs and cores were plotted for the Khuff reservoirs and a good linear relationship was obtained. Analyses at well locations described above, have confirmed the usefulness of the integration and the importance of 3-D seismic as a predictive tool if used carefully with well data. Careful examination of wells beneath channels, mentioned above, revealed a major difference in the acoustic impedance values between wells that are dolomitized with good porosity and permeability, wells that are cemented by anhydrite and wells that have moldic porosity with calcite cement. Lower impedance matches the higher reservoir quality. The acoustic impedance attribute is mapped laterally around the well locations and in the interwell space. The areal distribution of this seismic impedance provides an estimate of the regional porosity and permeability to find hidden reserves and could verify large Khuff reservoir potential both north and southeast of Ghawar. The future challenge is to determine if these predicted good-reservoir areas contain hydrocarbons using other seismic tools, such as AVO techniques. The examples explained in this study illustrate the procedure that was used and may be applied for other reservoir predictions.

(275-Oral) Al Kharrata field–a highly heterogeneous, tight fractured carbonate: data integration solving the puzzle

Al-Jeelani, Omar (ADCOojeelani@adco.co.ae), Stephen Bourne (Shell), Maria Boya Ferrero (Shell), Anna Dombrowski (Shell), Ahmed Khouri (ADCO), Jan Manoharan (Shell), Jürg Neidhardt (Shell), Pascal Richard (PDO) and Ben Stephenson (Shell)

The Al Kharrata field is probably one of the most lithologically heterogeneous, intensely fractured reservoirs in the world. The producing formation R’mah is unique as it can act as a source rock, a seal or a reservoir. The challenge of this study was to understand and develop a field that due to its fractured nature, its low porosity and unusual mechanical properties cannot be characterized by stand-alone standard techniques. It was crucial to approach the characterization in an integrated fashion. Prior to the study, despite 14 years of production AKE STOIIP was poorly constrained, as data from logs, core and production seemed contradictory. Two out of the four wells drilled failed to produce hydrocarbons. Lacking a generic model to explain good/bad well behavior further development of the field was hindered. The reservoir model was developed from an integration of petrophysics, reservoir engineering and geology. It incorporated the results of the wells and an outcrop study in Syria, which observed an intimate relationship between fracturing-style and lithology. The model predicts that most of the STOIIP resides in two intensely fractured chert layers, which could not be characterised by standard techniques such as logs, core plugs or borehole images. Given the limited data set and the heterogeneous nature of the reservoir, the unknowns greatly exceed the constraints. Some of the uncertainty remains unresolved. Therefore the approach taken was to capture uncertainty by establishing discrete geologically plausible scenarios and assigning probabilities to their occurrence based on the available data. This study provided a significant improvement in the understanding of the reservoir, which led to recommendations on options for further development and data gathering. In particular the study identified: (1) the recovery factor increased due to better understanding of fracture connectivity and recovery process; (2) STOIIP uncertainty was better defined; (3) existing performance limitations related to current well completion and not to reservoir productivity; (4) recommendation to stimulate existing well resulted on increased production by 10 fold at sustained reservoir pressure; (5) opportunity to further development by drilling a new crestal well; and (6) recommendation to perform an interference test to reduce uncertainty on porosity and connectivity.

(267-Oral) Wide-azimuth 3-D OBC seismic from acquisition to interpretation, offshore Abu Dhabi: a case study

Al-Kaabi, Musabbah H. (ADNOC - malkaabi@adnoc.com), Johan M. Witte (ADNOC), Omar A. Suwaina (ADNOC) and Atef Ebed (ADNOC)

In the last few years, ADNOC has acquired several high-quality, wide-azimuth 3-D OBC seismic surveys. The main objectives were to address key exploration and development challenges like accurate structural imaging, lateral variation in reservoir quality, contact identifications and fracture analysis through pre- and post-stack analysis. This case study covers a wide range of challenges and achievements from survey planning to data interpretation. The selection of wide-azimuth patch geometry was the result of an extensive and elaborate feasibility study. The survey was acquired with high geophysical parameters in terms of fold, offset and azimuth. Key challenges in data processing included aliased energy along the receiver lines due to coarse sampling, multiple contamination and imaging of the deep Khuff and pre-Khuff reservoirs in a structurally complex area. To facilitate the structural interpretation various noise reduction and coherence-type filters were applied after migration. The final pre-stack time-migrated cube showed excellent imaging of the radial faulting at the Lower Cretaceous Thamama level and enabled interpretation of the linear fault pattern in the Palaeozoic clastic interval below. Seismic quality was deemed sufficient to carry out a detailed quantitative seismic reservoir characterization study, which was used for selecting the location of an appraisal well.

(73-Oral) 3-D Pre-stack depth migration on a laptop: travel-time compression

Al-Khalifah, Tariq A. (KACST - tkhalfah@kacst.edu.sa)

Now through the magic of compression, one can perform 3-D Kirchoff pre-stack migration on a laptop. Specifically, travel-time table compression is key for the practical and efficient implementation of pre-stack Kirchhoff 3-D migration. Kirchoff 3-D pre-stack migration requires repeated access to a large travel-time table. Access to this table implies either a memory intensive or I/O bounded solution to the storage problem. Travel-time tables in 3-D media are five-dimensional, resulting in files with sizes often exceeding 50 GB. Loading such files in memory for the application of pre-stack migration is virtually impossible on many machines, resulting in slower implementations of migrations based on continuous access of the computer’s much slower hard-drive. Proper compression of the travel time table allows us to efficiently perform 3-D pre-stack migration. Such compression also allows for faster access to desirable parts of the travel-time table and more accurate travel-time interpolation. The compression is applied to the travel-time field for each source on the surface using 3-D polynomial or cosine transforms. This allows for practical compression up to and exceeding 20 to 1. Additional compression is obtainable through bit-encoding methods in which we represent the typical 32-bit floating point numbers by lower bits. Using travel-time compression we managed to pre-stack 3-D migrate portions of the SEG/EAGE salt model as well as portions of a 3-D image from the Middle East on a laptop.

(246-Poster) Sedimentology and geostatistical modeling of Quwarah Member, Qasim Formation: Paleozoic sandstone reservoir outcrop analog, Saudi Arabia

Al-Khalifah, Fadhel A. (KFUPM - fadhel@kfupm.edu.sa), Osman M. Abdullatif (KFUPM) and Mohammad H. Makkawi (KFUPM)

The increasing demands to maximize recovery from oil and gas fields and recent technological advances have led to an increased application of reservoir characterization and qualitative geological modeling of rock properties. These techniques are limited in representing reservoir heterogeneity in the subsurface. In contrast, surface outcrop analogs provide information about rock body dimensions, size, and orientation; and therefore new insights for geological modeling, understanding and predicting the behavior of fluid flow in the reservoir. This study aims to establish from outcrop, a geological and petrophysical model for the Quwarah sandstone in central and eastern Saudi Arabia. The model is intended to provide a database and enhance the understanding and prediction of the sandstone in the subsurface as a reservoir. The study was carried out at Qasim areas where the Quwarah Member of the Middle to Late Ordovician Qasim Formation. The study includes field sedimentological facies analysis on outcrop sections, permeability measurements, and sample collection for petrographic analysis and porosity measurements from thin sections. The porosity and permeability data are used in the quantitative reservoir model using geostatistical techniques. The analog model is expected to provide a better understanding of the reservoir heterogeneity, and have a significant impact on reservoir development and management strategy.

(135-Oral) Multiple elimination reveals new Deep Haima opportunities in northcentral Oman

Al-Lawati, Mohamed H. (PDO - mohamed.m.lawati@pdo. co.om) and Pieter Spaak (PDO)

Exploration success in the Central Oman High has been confined mainly to the Gharif sandstones and it is from this interval that the main Central Oman oil fields produce. The Mesozoic sequences are devoid of any hydrocarbons, while penetrations into the Haima and Huqf supergroups are limited in number. Although the main ingredients for potential Haima/Huqf play concepts have been proven, these intervals are usually not specifically targeted and consequently, no economic volumes have been found to date. This is to a large extent related to lack of good quality seismic imaging of these intervals. Seismic data quality varies considerably due to the terrain conditions and acquisition history. Sand dunes cover the western half of the area and the data quality suffers from statics problems. An extensive 2-D seismic grid, and some 3-D seismic surveys cover central Oman High. Most of the reflectivity below the Gharif lacks definition and suffers serious contamination of multiples. A 1998 2-D regional grid of long offset data provides better resolution for the deeper strata, but it is still severely affected by multiple contamination below the Gharif. New reprocessing tests of the long-offset lines, including multiple attenuation techniques based on pattern recognition, like SUPERCHEAT and SPLAT applied at both pre- and post-stack stages, show that the imaging of the pre-Gharif sequence can be improved significantly. Additional reprocessing tests are currently addressing the statics and the ‘sand-dune’ effects. This improved data shows a variety of steeper Haima structures below relatively flat younger strata; dipmeter data support the steeper Haima geometries. Relatively weak steeper Haima reflectors can now be mapped with confidence as primary events, which has already helped to recognize additional (faulted-) dip closures. Moreover, this improved seismic data provide a better grip on acoustic impedance contrasts in the Lower Haima, which possibly can be linked to reservoir- and seal-prone sections, which are clear from a review of the available well data. Based on these results additional reprocessing and seismic infill are now being considered.

(180-Poster) Analysis of micro-seismic data and the b-value distribution in Yibal oil field in northern Oman

Al-Mahrooqi, Said S. (PDO - said.mahrooqi@pdo.co.om), Ahmed Al-Abri (SQU), Issa Al-Hussain (SQU), Ali Al-Lazki (SQU), Harry Rynja (PDO) and Guy Mueller (PDO)

Micro-seismicity was monitored continuously by PDO in the Yibal field in northern Oman since September 1999, using a network of five seismographs. The temporal and spatial distribution in the oil field and the b-value of the micro-seismicity activity were examined to determine if a correlation exists between micro-seismicity, oil and gas production, and water injection. In the Yibal field, oil is produced from and water is injected into the Shu’aiba reservoir, and gas is produced from the Natih Formation. A total of 1,061 micro-seismic events were recorded between October 1999 and July 2002 with the largest magnitude of 2.24 Ml occurring in June 2000. A b-value of 0.85 (± 0.033) and a maximum possible magnitude of 3.15 were calculated for these seismic events. The b-value is consistent with b-values calculated elsewhere for a fluid-dominated seismic system. The spatial distribution of b-values over the entire field was found to decrease away from its center. This could be an indication of a rock with high pore pressure and an ambient stress near the point of failure at the center of the field. The majority of events occurred between 700 to 1,100 m depth which is the depth of the Natih gas accumulation in the field. The foci of a larger number of events occurred near the gas producing wells, suggesting that micro-seismicities are induced by the gas production process more than oil production. Micro-seismicity locations migrate towards the east northeast and in the upward direction with time. This trend matches the NE strike of the fault system beneath the field. It also suggests that the pressure wave front migrates northeast in the direction of preferred permeability.

(455-Oral) Discovery of a potential source rock level within late Campanian Sawwaneh Formation in Bardeh area, southern Palmyride, central Syria: petroleum implications

Al-Maleh, Ahmed K. (Damascus U - akmaleh@37.com), Francois Baudin (Pierre and Marie Curie U), Mikhail Mouty (Damascus U), Youssef Radwan (AECS) and Carla Muller (Consultant)

The Rmah and Shiranish formations (Campanian-Maastrichtian) are proven source rocks in eastern and northeastern Syrian (Euphrates Graben and Djezerah). The Sawwaneh Formation, Erk marl equivalent, defined in the Palmyride in the 1980s, lies above the upper Campanian Rmah Formation and is overlain by the marly Maastrichtian-Lower Eocene Bardeh Formation. Generally, the Sawwaneh Formation is marl-limestone of variable thickness (17-320 m) with important facies changes, and local-enrichment by phosphate. Detailed sedimentological and geochemical studies conducted in the last two years uncovered the presence of a 10-m-thick black shale level at the top of the Sawwaneh Formation in the Bardeh area, Southern Palmyride. It is clayey biomicrite rich in hyaline small benthonic foraminifera, with a matrix heavily impregnated by organic matter with microscopic pyrite crystals. Coccolithes dated the entire formation as late Campanian and pin-pointed its boundaries with the Maastrichtian. The analysis of samples taken from this bituminous level confirmed a 25 percent calcium carbonate content and 4.4 percent total organic carbon, with high hydrogen-index value (690 mg HC/gm TOC) suggesting a type II organic matter. Temperatures of maximum Pyrolytic yield (Tmax) is of 423°C, indicating that the organic matter did not experience high temperatures during burial and are still immature with respect to oil-generation. However its total petroleum potential is good with 32 kg per ton of rock in average. The level’s petroleum prospectivity should be considered through a regional context in which the Sawwaneh Formation thickens north and westward (Ad Daww Basin and Homs Depression) where it is buried beneath thick Maastrichtian-Neogene sedimentary cover that may reach 2,000 m.

(205-Poster) Lower Thamama (Lower Lekhwair Formation) sequence stratigraphy and reservoir characterization (Lower Cretaceous, United Arab Emirates)

Al-Mansoori, Abdullah I. (ADCO - amansoori@adco.co.ae), Christian J. Strohmenger (ADCO) and Ahmed Ghani (ADCO)

Significant hydrocarbon accumulations have been found in the Lower Lekhwair Formation (Lower Thamama Group, Valanginian). The succession studied is interpreted to correspond to the transgressive sequence set (TSS) of a second-order supersequence that ranges from the top Habshan Formations (upper Valanginian) to the base of the so-called ‘Lower Dense Zone’ of the Kharaib Formation (Barremian). The TSS is build by a third-order sequence (uppermost Valanginian) that is composed by three fourth-order, high-frequency sequences, comprising three reservoir and three non-reservoir (dense) units. The uppermost high-frequency sequence, the focus of this study, can further be subdivided into five fifth-order parasequences. Third- and fourth-order sequence boundaries, fourth-order maximum flooding surface, as well as fifth-order flooding surfaces were identified in core material from wells of Abu Dhabi and tied to well logs. On the basis of sedimentary textures and sedimentary structures, as well as grain types, seven reservoir lithofacies and four non-reservoir (dense) lithofacies have been identified. The analyzed lithofacies range from open platform, middle ramp to restricted platform subtidal to intertidal environments. Bacinella/Lithocodium packstones to floatstones, floatstones to rudstones, and boundstones, dominate the reservoir zone. Good reservoir quality is further developed within skeletal, peloidal packstones to grainstones and algal, skeletal rudstones. Intensively bioturbated wackestones and packstones, and interbedded argillaceous limestones characterize the ‘dense units’. Based on geological (lithofacies) and petrophysical (porosity/permeability and mercury injection) data, five reservoir facies have been defined. Each reservoir facies shows deterioration of reservoir quality from crest towards flank position. Reservoir deterioration is also observed directly below the sequence boundary (erosive surface) on top of the reservoir. Diagenesis (cementation and compaction) is interpreted to play a major role in reservoir quality distribution within the established high-frequency sequence stratigraphic framework.

(178-Oral) Defining the main heterogeneities within ADCO’s fields

Al-Maskari, Shamsa S. (ADCO - salmaskary@adco.co.ae) and Marie-Odile T. Bockel-Rebelle (ADCO)

Diffuse fracturing, for a number of years, has been understood to be one of the main heterogeneities within a great number of the Middle East carbonate fields. However, diagnosis made on ADCO developed Cretaceous reservoirs weakened this assumption. Using both available static understanding (mainly core and borehole image log interpretation) and dynamic analysis (well tests, Production Logging Tool, production histories), the diagnosis highlighted the fact that the dynamic impact of diffuse fracturing is never clearly observed. Therefore, this fact raised the need to adequately define the main heterogeneities within these reservoirs. In order to achieve such a goal, it is necessary to build a good geological comprehension of the reservoirs, supported by sequence stratigraphy, diagenesis, and the latest knowledge in faulted/fractured reservoirs. Such defined heterogeneities will then be confronted to the dynamic data. Within ADCO’s fields, two major types of heterogeneities have been identified; these include: ‘high K streaks’, and/or large-scale vertical objects (defined as seismic or sub-seismic faults and fracture corridors). The high K streaks, within the undeveloped ADCO Cretaceous reservoirs, were studied using core, thin-sections, logs, and Mercury Injection Capillary Pressure (MICP) data. The results indicated that these high K streaks are mainly products of diagenesis. As a result, bimodal porosity distribution was their strong character. Moreover, the nature of the major porosity system, such as pore-throat and the lateral extension of these streaks were found to greatly impact their dynamic behavior. Prediction of their lateral extent is a challenge that is owed to good geological understanding and the availability of good production data. On the other hand, understanding faults and fractures within the ADCO environment is essential to predict their distribution and characterize their dynamic impact. Thus, study of the faults and fracture corridors together with their associated damaged zone is currently ongoing, using well data, seismic attributes analysis, analogs and dynamic synthesis.

(320-Oral) Arabian Platform structural growth and its impact on facies distributions and hydrocarbon occurrence

Al-Qahtani, Abdelmuttaleb M. (Saudi Aramco - abdelm uttaleb.qahtani@aramco.com), Abdel G. Ahmed (Saudi Aramco), Pierre J. Van Laer (Saudi Aramco) and Tariq U. Usmani (Saudi Aramco)

The Arabian Platform has experienced about six major tectonic events that are responsible for the development of reservoir facies and hydrocarbon accumulations throughout geological history. Recent 2-D/3-D seismic depth imaging and deep wells have enabled us to understand the growth history in the Arabian basins. These tectonic events were the prime contributors to trap formation and evolution, as well as reservoir development and hydrocarbon accumulation. The major tectonic events that affected the Arabian Platform are: (1) Precambrian extension event; (2) Carboniferous or ‘Hercynian’ event, represented by regional tilt and compressional forces; (3 and 4) Permo-Triassic and Triassic growth (Zagros Suture and the opening of Neo-Tethys Ocean); (5) Late Cretaceous (collisional event–First Alpine event) further enhanced the growth of older traps, inverted platform tilts and created new traps; and (6) Middle to Late Tertiary growth (Red Sea opening and Second Alpine event) or Neogene NNE-dipping tilt that formed the final hydrocarbon traps of Arabian Platform structures. Major stability of the Arabian Platform led to the accumulation of thick carbonate reservoirs and platform-wide anhydrites that made it favorable to form different plays. Several of these tectonic events had substantial contributions to the facies distribution, trap creation, modification and hydrocarbon migration. Geoseismic and isopach maps in combination with the basin history and source rocks maturity elucidate the multi-phase generation and migration of hydrocarbons in the Arabian Basins.

(322-Poster) Application of neural networks to predict pre-Khuff seismic facies in Eastern Saudi Arabia

Al-Qahtani, Abdul Motaleb M. (Saudi Aramco - abdelm uttaleb.qahtani@aramco.com), Riyadh S. Al-Saad (Saudi Aramco) and Husam M. Mustafa (Saudi Aramco)

Recent applications of Artificial Neural Networks (ANN) to seismic studies have demonstrated its effectiveness in prediction, estimation, and characterization of seismic facies and reservoir quality. The characterization of pre-Khuff clastic reservoirs requires integration of data and knowledge from various types, and various scales of geological and geophysical properties. A major problem in mapping reservoir quality from seismic characters is that the continuity of seismic events is often weak. In order to overcome this problem, acoustic logs and VSPs from key wells were used to develop relationships between wells and seismic characters. We attempted to explore these relationships by using the learning ability of ANN. The relationships learned using this approach were used to predict seismic characters for different seismic windows. The different approaches ranged from unsupervised to supervised training methods, conducted over a constant seismic window to produce seismic facies and reservoir quality prediction maps. A new technology application of classifying seismic intervals parallel to a horizon based on the shape of the wiggle traces and its geological use was developed. Trace shape, in addition to other seismic attributes such as reflection strength, phase and frequency is a fundamental property of the seismic data. Different trace shapes are used to classify and map seismic facies.

(317-Poster) Geological evaluation and wellbore stability of gas-bearing Barik Sandstone reservoir: Saih Rawl field, Oman

Al-Raisi, Muatasam (Schlumberger - muatasam@musc at.oilfield.slb.com), Ibrahim El-Moula (PDO), Mayya Al-Rawahi (PDO), Paolo Giacon (PDO), Aimen Amer (Schlumberger) and Zed Al-Khathiry (Schlumberger)

The Cambrian-Ordovician Barik Sandstone Member in northern Oman is one of the main gas reservoirs within the Haima Supergroup. The Barik Sandstone Member comprises alternating, sharply-delineated sheets of fluvial sandstone, shoreface sandstone, coastal sediments and mudrock of overbank and marine deposits. Such variability in depositional environments and paleocurrent orientations resulted in deposition of laminated sandstone and shale intervals, some of which can not be recognized on conventional open-hole log measurements. These alternating sandstone and shale units have an impact on hydrocarbon production and borehole stability. This study integrates conventional core measurements with borehole images, dipole shear and nuclear magnetic resonance to better understand variation in reservoir quality and to better diagnose borehole stability issues. Detailed analyses shows that image logs can be used to successfully resolve many of the sedimentological features identifiable in core. A total of six key image facies are recognized and these may be rationalized into a genetic element scheme (similar to that applied to the core). A neural network technique was used to predict the vertical occurrence of different lithotypes in a given well. The cross-bedded facies exhibit the best porosity and permeability and reveals fluvial channels deposits. Both compressive wellbore failures (wellbore breakouts) and tensile failure were observed in the images and used to estimate near-wellbore stress orientations. Most of shear failure seems to be occurring near bed boundaries. Determining reservoir quality sand intervals, wellbore conditions and local variability in the stress orientations are very important in the field hydro-fracture completions and pressure point selections.

(129-Oral) The Rabab, Sakhiya, Zalzala ‘stringer’ discoveries of South Oman, one large field?

Al-Rawahi, Saada (PDOsaada.ss.rawahi@pdo.co.om), Jean-Micheal Larroque (PDO), Rashid Al-Hashmi (PDO), Khairan Al-Mauly (PDO), Robert Gardham (PDO), Hisham Al-Siyabi (PDO), Mark Newall (PDO), Fahar Al-Rabeei (PDO), Joao Rodrigues (PDO) and Nadia Al-Abry (PDO)

The Neoproterozoic to Early Cambrian, Intrasalt Ara Group Carbonate Stringer Play is developed over a large part of the South Oman Salt Basin. Six carbonate cycles have been identified and are correlated on the basis of facies, paleogeography, chemostratigraphy and absolute age datings on volcanic tuffs. Oil and gas discoveries have been made in several of these carbonate cycles, across a variety of carbonate facies and pressure regimes, encased and sealed by Ara salt. The Zalzala, Sakhiya and Rabab discoveries, exhibiting homogeneous reservoir properties and hydrostatic pressures, contain some significant volumes of oil and gas in a single carbonate cycle – the A2C platform. This carbonate platform was initially explored by targeting seismically different prospects disconnected by fault zones and/or poorly imaged data zones. The exploration and appraisal drilling of these prospects followed by detailed geological studies and improvements in seismic processing suggest that the Zalzala, Sakhiya and Rabab discoveries were once a single hydrocarbon accumulation. This accumulation was subsequently segmented into three blocks. PVT data are still consistent with one continuous hydrocarbon column. This model explains the unexpected discovery of gas in Rabab, and if known upfront, would have affected the exploration strategy of the area. PDO has now started early development of the recently discovered accumulations with first production planned in early 2004. This development phase will test the feasibility of gas injection to maximize oil and condensate recovery in these challenging reservoirs.

(218-Oral) Lithology and heterogeneity quantification from image logs and core: implications in carbonate reservoir, offshore oil field, Abu Dhabi

Al-Rougha, Hamad Bu (Zadco - hrougha@zadco.co.ae), Hedhili B.M. Gossa (Zadco), Muatasam H. Al-Raisi (Schlumberger), Toshiaki Shibasaki (Zadco), Ishtiaq A.K. Jadoon (Schlumberger) and Sandeep Chakravorty (Schlumberger)

Most of the carbonate reservoirs in offshore Abu Dhabi are characterized by complex textural heterogeneity that requires high-resolution log data, such as borehole image logs. This textural heterogeneity corresponds to extreme permeability variation that is the controlling factor in reservoir production. This study illustrates an approach to improve the carbonate reservoir characterization of an offshore oil field in Abu Dhabi, by quantifying small-scale heterogeneity using borehole image logs and core measurements. The reservoir under study ranges from mud-supported to grain-supported rocks with variable grain sorting and cementation. Detail core analysis indicates the presence of small-scale, fining-upwards cycles in the order of 0.5–5 ft thick, some of which can only be resolved by high-resolution measurements. The base of each cycle represents coarse-grained sediments with high permeability streaks, which has direct implication on field development plans. An attempt was made to detect this cyclicity from image logs to aid the correlations in un-cored wells. Other factors that contribute to heterogeneity of the carbonate reservoirs include cementation, mouldic porosity and leached-out rudist shells, bioclasts and algae. In the image logs these features are identified and quantified as resistive and conductive anomalies. Through this analysis the macro-porosity system can be quantified and discriminated as primary and secondary porosity and pore-size effects on permeability can be better defined as a continuous curve. This study illustrates a methodology to quantify vuggy and cemented texture of the carbonate rocks at a resolution that is the closest to actual core scale.

(416-Oral) Application of PSDM/Tomography for modeling near-surface velocity

Al-Rowaili, Turki Z. (Saudi Aramco - turki.rowaili@aramc o.com) and Alex Litvin (Paradigm)

In Saudi Arabia, complex surface topographic features such as escarpments, sand dunes, and wadis, strongly affect structural information on the deeper seismic section. The main objective of this study was to estimate the near-surface velocity via pre-stack depth imaging (PSDM) workflow. The workflow was applied to high-density 2-D data and included a tomographic velocity inversion procedure to reveal more realistic subsurface images. The initial velocity model for PSDM was derived via a coherency-inversion approach. Ray-tracing was performed from a buried reflector to the smoothed version of the actual topography for best-fitting the picked travel-time. After the PSDM main flow, residual moveout of the depth-imaged gathers was analyzed for key horizons with a tomographic inversion procedure to refine the initial velocity model. PSDM with tomography inversion clearly reduces apparent pull-down structures due to thickening from outcrops and sand dunes. These velocity corrections lead to a more realistic (geologic) subsurface image for interpretation.

(136-Oral) East-Ghaba Basin: unlocking Haima Supergroup potential

Al-Sadi, Yaqoob M. (PDO - yaqoob.sadi@pdo.co.om), Omar S. Al-Jaaidi (PDO, currently JVR Centre for Carbonate Studies) and Pieter Spaak (PDO)

The Ghaba Salt Basin lies east of North Oman’s major gas fields and was considered to form a major boundary for deep (Haima) charge. Although several large prospects were identified on the eastern basin flank, results of earlier hydrocarbon modeling pointed to a major charge risk. As a consequence, exploration activities were minimized. The hydrocarbon modeling documented two phases of hydrocarbon generation. An early (Ordovician) oil charge was expelled during deposition of the Haima Supergroup from deeper, central parts of the Basin from pre-, intra and post-salt source rocks. During this phase, hydrocarbons migrated onto the basin flanks where most present-day Haima closures were not yet formed. A second Late Jurassic phase occurred after formation of major Haima structures, and is linked to the charge of Oman’s large gas fields. This second charge is thought to have originated from shallower Ara salt pockets, on the basin flanks, going through the gas generation window. These so-called ‘rim basins’ were only recognized from 3-D seismic on the western basin flank. Their distribution, combined with overall uplift of East Oman during late Paleozoic and early Mesozoic, significantly increased charge risk east of the basin axis. Several disappointing exploration wells have been drilled on the eastern flank of the Ghaba Salt Basin. Lack of success was generally attributed to lack of charge. However, a number of these wells have proven hydrocarbon shows, and recent 3-D remapping revealed the existence of several new ‘rim basins’ located on the eastern basin flank which may have provided local gas charge. Geochemical analysis and basin modeling has been initiated to review the regional charge and migration history of North Oman. It is planned to drill a deep well to test this local charge concept.

(490-Oral) Connectivity between the Ghazal and Mazalij fields, Saudi Arabia

Al-Saggaf, Muhammad M. (Saudi Aramco - muhammad.s aggaf@aramco.com) and Matter J. Al-Shammery (Saudi Aramco)

The target reservoir of the Ghazal and Mazalij fields is the Paleozoic Unayzah Formation. The Mazalij gas reservoir was discovered in 2000, on the down-thrown block of a succession of faults that separate it from the crestal area of the field, where the reservoir was missing. The Ghazal field was also discovered in 2000, where it encountered a thick Unayzah reservoir with excellent sand quality. The two fields were initially thought to be disconnected. However, several pieces of evidence (including depositional growth, structural depth, pressure regimes, and geochemical analysis), which are discussed in this study, indicated that the fields may be connected. A delineation well was proposed to test the connectivity between the two fields. In order to select the optimal location for the well, accurate depth maps of the entire Ghazal/Mazalij region were produced. The goal was to generate not only a map of the depth structure of the Unayzah, but also maps of the depth and isopach structures of all key layers in this region. This is vital to understanding the growth structure of the reservoir and to obtaining a good assessment of the depositional environment in this area. The location of the delineation well was selected on the saddle between Ghazal and Mazalij in order to directly settle the issue of the connectivity of the two fields with a high degree of conidence, and to afford a much more accurate assessment of the reservoir compartmentalization in this region. The results of this well helped confirm the connectivity between the two fields.

(11-Poster) The Ratawi Sand, a newly-discovered stratigraphic reservoir in the mature South Umm Gudair field, PNZ, Kuwait and Saudi Arabia

Al-Shaarawy, Osama A. (KOC-JO - shaarawi@kockw.com) and David L. Barge (SAT-JO)

The Lower Cretaceous Ratawi Sand is a newly discovered reservoir introduced herein for the first time to the stratigraphic sequence of the Partitioned Neutral Zone (PNZ), Kuwait and Saudi Arabia. The Neocomian Ratawi Formation of the Thamama Group in the PNZ is divided into three sequences: (1) lower Ratawi Oolite; (2) middle Ratawi Limestone; and (3) upper Ratawi Shale. The South Umm Gudair field produces from a thick oil column of the Lower Cretaceous Valanginian Ratawi Oolite reservoir, following its discovery in 1966. The Hauterivian Ratawi Shale Member is 350 ft thick and lies 500 ft above the mature oolite reservoir. Distinctive sandstone streaks were identified within this Ratawi Shale Member. The average thickness of these sandstone stringers is about 10 ft. An integrated approach involving detailed log and petrophysical analyses from old and modern log suites, together with geologic data interpretation, indicated the Ratawi Sand was deposited both in a very shallow-marine environment (regressive shoreline) and as channel sand during the Hauterivian lowstand system tract (LST). Delineation of the main axis of the channel was the challenge for reservoir prospectivity. The main axis of the channel was observed to be more than 50 ft thick and to run in a NW direction, diagonal to the main axis of the South Umm Gudair field Ratawi structure. After perforating 6 ft of the channel sand, the discovery well flowed clean and low-sulphur oil at a very good rate. The provenance of the Ratawi Sand is from the southeast. It is a pure stratigraphic trap that is unrelated to the main structure of the field. This channel sand exhibits fining-upwards sedimentation. The highstand system tract (HST) of the lower part of the Ratawi Shale was eroded by an incised valley that sculptured, scoured and formed the NW-running trend of the main channel, which was subsequently filled during the transgressive system tract (TST) with mixed clastic Ratawi Sand facies. On top of the channel sand, the maximum flooding surface (MFS) of the Ratawi Shale represents a very good, distinctive correlation marker. The MFS is considered as the main vertical seal above the Ratawi Sand. A localized unconformity is observed at the base of the Ratawi Sand main channel that reflects its scouring nature and the intensity of erosional effects of the Ratawi Sand tepees into the lower Ratawi Shale and Limestone clinoform. More geologic data is required to delineate the southeastern extension of the discovery reservoir, outside the current boundary of the field. Similar studies, utilizing the proposed geologic model, are recommended elsewhere in the PNZ for the delineation of the Ratawi Sand reservoir.

(12-Oral) Humma Marrat oil field, a unique Jurassic reservoir in the PNZ, Kuwait and Saudi Arabia

Al-Shaarawy, Osama A. (KOC-JO - shaarawi@kockw.com), Jim D. Ming (SAT-JO), David L. Barge (SAT-JO) and Ali S. Abul-Hassan (KOC-JO)

The Humma oil field is situated in the southwestern corner of the Partitioned Neutral Zone (PNZ), between Kuwait and Saudi Arabia. It is the only Jurassic producer in the PNZ. It was discovered in 1998 following several unsuccessful wells targeting Cretaceous reservoirs beginning in the 1950s. An integrated approach utilizing 3-D seismic interpretation, oriented core data, open hole and borehole image logs, CMR (Combinable Magnetic Resonance), ECS (Elemental Capture Spectroscopy), and Stonely Permeability (DSI) data was used for the evaluation and understanding of the complexity of the Jurassic Marrat reservoirs in the field. The structural configuration of the field is an elongated NW-plunging anticlinal feature with steeply-dipping flanks. The structural closure of the field was produced from a shear couple that culminated during the Early Cretaceous and continued through the Late Cretaceous. The simple shear tectonic model applied to the Humma field is well expressed by a flower structure associated with both the Jurassic Marrat and Cretaceous Shu’aiba formations as interpreted from the 3-D seismic, oriented core, and borehole image log data. This tectonic model may have analogs elsewhere in the Gulf Region. The complexity of the Marrat reservoirs is attributed to the rapid change in facies from the north to the south, as well as from the base to the top of the Marrat reservoir units. The Lower Marrat succession comprises two overall cleaning-upward cycles of packstones with anhydrite streaks. Depositional environments are predominantly low energy inner shelf (inner ramp to lagoonal) settings. The evaporites at the top appear to be penecontemporaneous with the dolomitized limestone. Hydrocarbon potential for the Lower Marrat reservoir is confined largely to dolomitized sediments. These possess a combination of intercrystalline and moldic porosity with local fracture to breccia porosity. The Upper Marrat reservoirs are composed of a stacked succession of individual and overall shallowing-upward cycles. Deposition was in a protected sub-tidal, open-shelf lagoon to largely filled intrashelf basin as part of a progradational parasequence set. Open fractures of massive dolomite matrix is the target for the Middle Marrat reservoirs. The understanding of the Jurassic Marrat reservoir in the Humma field is required prior to drilling delineation wells. The last well drilled in the field has been naturally flowing at a very good rate since early 2002. The development plan for the Humma field will include the drilling of both vertical and deviated wells.

(33-Oral) Hydrocarbon potential assessment of the Habshan Sequence-1 shoal complex, northeast Abu Dhabi, United Arab Emirates

Al-Shekaili, Fatema (ADCO - fal-shekaili@adco.co.ae), Azhari Abdalla (ADCO), Abdullah Al-Aidarous (ADCO) and Christian J. Strohmenger (ADCO)

Integrated seismic interpretation and sequence stratigraphic analyses were used to assess the hydrocarbon potential of an ooid shoal complex within the Habshan Formation. The Habshan Formation (uppermost Tithonian to Valangenian) is the lowermost member of the Thamama Group. It is composed of several relatively thin reservoir units engulfed in a thicker mud-dominated successions. The Habshan Formation comprises two second-order supersequences, which can be further subdivided into five third-order sequences. Depositional environments within each sequence range from lagoonal and shallow intertidal in the west, to slope and deep-marine in the east. Best reservoir quality is developed within the eastward prograding ooid shoal complex of each sequence. The shoal complex of Habshan Sequence-1 has been targeted several times by exploration drilling with discouraging results. This is despite evidence for adequate reservoir quality, trapping and hydrocarbon migration pathways. In northeast Abu Dhabi (Al Dabbiya/Rumaitha and Arjan areas), this complex has been covered by 3-D seismic (3,340 sq km) which has subsequently been reprocessed for better imaging of the Habshan sequences. Clinoforms of the Habshan Sequence-1 are readily recognizable from seismic data, and a four-way structural closure was mapped with the ooid grainstone shoal as the main target. These grainstones show higher seismic amplitude compared with the lagoonal part of the sequence. However, the observed amplitude changes and the brightening on the seismic do not indicate the presence of hydrocarbons. The four-way structural closure is considered as a high-risk exploration target. Our sequence stratigraphic model indicates that the shoal complex of each sequence is overlain by the shallow intertidal and logoonal deposits of the younger sequences. Therefore, the existence of laterally continuous and competent seals above the shoal complex is unlikely. Accordingly, hydrocarbons will migrate freely upwards and charge more competently sealed traps.

(461-Poster) Petrophysical and geochemical identification of the heavy oil/tar in clastic reservoir, Saudi Arabia

Al-Shobaili, Yousif M. (Saudi Aramco - yousef.shobaili@ar amco.com), Edward A. Clerke (Saudi Aramco), Henry Halpern (Saudi Aramco) and Peter J. Jones (Saudi Aramco)

Areal and vertical distributions of the heavy oil (tar) zone within the reservoir is important in designing well completions, optimizing field development and enhancing reservoir modeling and simulation. The purpose of this study is to provide petrophysical and geochemical guidelines for a heavy oil (tar) case study, and to summarize our experiences in the execution of the petrophysical and geochemical analysis. The petrophysical investigation of a heavy oil (tar) interval started with an inventory of the physical property variations found within the heavy oil (tar) in a clastic reservoir and evaluating the impact of these variations on the formation’s petrophysical and geochemical data. Next our study looked at the indicators of tar presence in core description, core plugs, capillary pressure data and core geochemical data. From the wireline log data, we analyzed well logs, formation pressures, PNL data, and test data for the clastic reservoir. The goal of the study was to identify, characterize and map the distribution of the heavy oil within the clastic reservoir, and to understand the hydrocarbon mobility within this zone. Certain geochemical pyrolytic techniques were developed at Saudi Aramco and are highly useful for reservoir characterization and heavy oil tar zone identification. Parameters derived include Pyrolytic Oil Productivity Index (POPI) that is used to determine productive intervals in oil reservoirs and Apparent Water Saturation (ASW), which gives an estimate of the water saturation in the pore space based only on the pyrolytic data. In addition, an estimate of the API gravity of the oil-in-place is possible. Finally, a Compositional Modeling program (CoMod) was written, whereby complex reservoirs can be assessed.

(5-Oral) Estimation of thickness in a sand dune with a vertical velocity profile

Al-Shuhail, Abdullatif A. (KFUPM - ashuhail@kfupm.edu.sa)

Previous field and mathematical studies have shown that sand dunes may have vertical velocity profiles (i.e. continuous increase of velocity with depth). Therefore, computing the dune’s thickness using conventional seismic refraction methods that assume a vertically homogeneous layer will likely produce some errors. The purpose of this study was to quantify the effect of the vertical velocity profile in a sand dune on the process of thickness estimation using seismic refraction data. First, the time-distance (T-X) data of the direct wave in the dune is calculated using a vertical velocity profile V(z), derived from Hertz-Mindlin contact theory. Then, the thickness is estimated from the calculated T-X data, intercept time, and velocity of the refractor at the dune’s base assuming a constant velocity in the dune. The error in the estimated thickness due to the constant-velocity assumption increases with increasing thickness and decreasing porosity of the dune. For sand dunes with porosities greater than 0.2 and thicknesses less than 200 m, the error is less than 14 percent.

(81-Oral) The Phanerozoic geology of Yemen

Al-Thour, Khalid A. (Sana’a U - hayssan@y.net.ye)

Using extensive surface and subsurface data, the Phanerozoic geology of Yemen was synthesized in this study. The results have important implications for the tectonic evolution of southern Arabia and hydrocarbon exploration strategies. The tectonic deformation of Yemen is focused in five major sectors that have been repeatedly reactivated throughout the Phanerozoic in response to movement on nearby plate boundaries. They are: (1) Tihama Plain including the Red Sea; (2) Western Highland Triangle; (3) Rub’ Al-Khali Desert (Empty Quarter); (4) Eastern Highland Rectangle; and (5) Southern Plain including the Socotra Archipelago. These sectors show the main Phanerozoic sedimentary basins and interbasinal uplifts in Yemen. Most basins, however, are broken up into a varying number of sub-basins and separating highs in consequence to the response to initial and subsequent rifting phases and/or to horizontal movements along bordering master faults with resultant transpressional and transtensional adjustments along different sectors. The geological history of Yemen has been reconstructed by combining the vast amounts of integrated and detailed geophysical and geological data of the major basins with tectonic and lithostratigraphic analyses from the remainder of the country. Specific deformation episodes were penecontemporaneous with regional plate tectonic events. Sedimentation commenced in the infra-Cambrian but little remains of these or of Paleozoic deposits in outcrop except for what is preserved in fault-bounded small basins along the Gulf of Aden border, or the northern part of the western highland triangle. Paleozoic sediments have been encountered in the subsurface only in: (1) the northwestern part of the country; (2) within the Saba’tayn Basin (in Wadi Al Jawf-Marib Basin); and (3) along the southern flank of the Rub’ Al-Khali Basin. They consist mainly of coarse clastics with several major unconformities (representing time gaps), that rapidly pinch out onto the Hadramawt Arch. During the late Paleozoic to the early Mesozoic times, the trends of the basement rocks were oriented NS, NW, NE, and subordinately EW. These trends influenced interbasins rifting directions or elevated uplift/high regions, as differing stress fields built-up during various phases of Gondwana fragmentation. However, the Mesozoic basins vary spatially and temporally from the west to the east of the country. Widespread sedimentary deposition over most of Yemen (except for the persistent paleouplifts and highs) took place from the Early Jurassic and continued with only short, relatively local interruptions into the late Paleogene. During the Late Jurassic to the Early Cretaceous the ancient NW-trending Najd faults were rejuvenated, with final separation of the Arabian and African plates in the Neogene along ENE (Gulf of Aden) and NNW (Red Sea) trends. The sedimentary cover of the Mesozoic and Cenozoic basins shows lateral and vertical facies variations from fully marine to terrestrial.

(252-Oral) Pre-stack depth migration through deep salt

Al-Yarubi, Saeed A. (PDO - saeed.sa.yarubi@pdo.co.om) and Uwe Asmussen (PDO)

The South Oman Ara Salt Basin lies in the Block 6 concession held by PDO. This Cambrian salt basin is explored for intrasalt carbonate stringers. The Stringer play is actively supported by the acquisition and processing of 3-D seismic surveys. Complex salt domes with steep flanks, sometimes associated with salt overhangs, are very challenging to the imaging of deep intrasalt carbonate stringers targets. The main seismic processing challenges are to image the continuity, correct positioning, and fault patterns of these stringers. Pre-Stack Depth Migration (Pre-SDM) has greatly helped to resolve some of these challenges. For example, imaging of steep salt flanks and the definition of fault patterns across existing stringer discoveries has significantly improved. PDO has a dedicated Pre-SDM team working for the stringer exploration and development and sufficient inhouse computing power to run projects exceeding one thousand square kilometers of Pre-SDM output area. Until recently, Prestack Time Migration was the standard processing product that was supplied for seismic interpretation. However, it was realized that Pre-SDM provides a more robust approach, less sensitive to velocity picking. The Pre-SDM technique is gaining ground with the development and maturation of the stringer play and is close to becoming a standard seismic product.

(108-Oral) An integrated subsurface model of the Amin Formation in the context of the Kauther field cluster development in North Oman

Al-Zadjali, Ibrahim (PDO - ibrahim.i.zadjali@pdo.co.om), John A. Millson (PDO) and Mark Little (PDO)

Recent exploration activities in the northeast Afar area of PDO Concession Block 6 have resulted in significant hydrocarbon discoveries in the Kauther Cluster. Accumulations contain wet gas in continental reservoirs of the Cambrian Amin Formation at about 4,000 meters below sea level. In the cluster, substantial gas-initially-in-place (GIIP) has been booked from the Kauther-1 well results, and there is scope for more to be booked from the subsequent Harmal-1 and Fakhr-1 wells. An active drilling, testing and study program for the cluster is currently underway to define robust volumes GIIP and Ultimate Reserves (UR), and to provide input into a field development program with first gas production planned in 2007. With limited time available for stepwise appraisal activities, studies and uncertainty management form key components of this work program. Depositional and structural modeling of the discoveries utilizes a workflow developed for previous activities calibrating outcrops to subsurface (well, seismic, fields) to ensure all data are fully integrated. An improved understanding of the Amin reservoir is being incorporated in static reservoir modeling for the cluster to improve understanding of in-place hydrocarbon volume distribution, recoverable volumes, and hydrocarbon types. Elements of the work may facilitate a better understanding of remaining exploration and appraisal opportunities in North Oman.

(452-Poster) Dip/Azimuth attribute as a tool to map structures

Al-Zahrani, Mohammed S. (Saudi Aramco - mohamme d.zahrani.4@aramco.com), Stephen Bremkamp (Saudi Aramco) and Bhoopal Naini (Saudi Aramco)

The South Ghawar 3-D encompasses an area of approximately 20,000 sq km and as such is one of the largest land 3-D dataset globally. Within South Ghawar and surrounding areas, the Triassic Mid-Jilh gives rise to the strongest of all seismic reflections in the entire stratigraphic section. This reflection results due to the encasement of shales, overpressured in part within predominantly dolomite/anhydrite section. Seismic attribute ‘dip-azimuth’ analysis of the Mid-Jilh reflector yields a coherent and complex patern of linear to sub-linear trends. Detailed structural analysis of the area shows a one-on-one relationship between the seismic attribute derived lineations and the ‘Hercynian’ structures located within the deeper stratigraphic section. Some of these faults extend as far up the section as the Permian-Carboniferous Unayzah Formation. Very rarely do some of these faults propagate up to and above the Jilh Formation. Since seismic data in the pre-Khuff section tends to be of poorer quality due to the presence of noise and embedded interbred multiples, it is difficult to map the pre-Khuff structures unambiguously. We demonstrate that the attribute dip-azimuth computed over the Mid-Jilh reflector is a quick tool that can be used by the interpreters to generate regional fault-trend maps. Recognition of the fault trends provides valuable insights into the location of potential closures, vertical hydrocarbon migration conduits and regions of fracture-enhanced reservoirs. A regional structural interpretation based on the dip-azimuth analysis is presented for the first time.

(441-Oral) Optimal technique in imaging deep salt structures

Amarasinghe, Diwin (Saudi Aramco - diwin.amarasingh e@aramco.com), Hashim A. Hussein (Saudi Aramco) and Dwight Gustafson (Saudi Aramco)

The validation of relatively shallow low-relief structures on seismic sections is a difficult task in areas of complex near-surface geology and topography such as those in Saudi Arabia. The deep salt can be optimally imaged and structurally correlated with shallower horizons, thus minimizing the risk of discarding potential structural reservoirs as long wavelength static anomalies. With the recent advances in the seismic processing technology, and increase in computer resources, pre-stack time migration (PSTM) can now be routinely performed on recorded time that can even exceed 5 seconds. Also, the design and acquisition of composite sparse 3-D surveys developed by Saudi Aramco, provide wide-azimuthal coverage and a relatively higher fold, because of the increased number of far-offset traces by design. In processing, these attributes contribute to better attenuation of multiples, as well as linear and random noise. With deep far-offset data being less sensitive to velocities, they are used to produce a more reliable static solution. Better statics and less noise obviously help in picking better velocities for PSTM which, in turn, reduces the noise and optimally delineates the geometry of deep salt reflectors. The far offsets allow the use of large migration apertures in PSTM which also contributes to the same imaging goal. Furthermore, we incorporated gravity data as a spatial constraint in order to verify the presence, or absence of salt domes. This study shows a case history, where the above procedures are implemented. The data example belongs to the Quwaysim area of Saudi Arabia, which, as interpreted from our seismic data, is now characterized as having deep salt buildups.

(279-Oral) Fracture and in-situ stress characterization of the Unayzah Reservoir, Wudayhi field: an integrated approach

Ameen, Mohammed S. (Saudi Aramco - mohammed.am een@aramco.com), Khalid A. Al-Hawas (Saudi Aramco), Mohammad Wahab (Saudi Aramco), Edgardo L. Nebrija (Saudi Aramco), Faisal Al-Thawad (Saudi Aramco) and Colin Macbeth (Heriot-Watt U)

The Wudayhi field was discovered in Saudi Arabia in 1998, with gas reserves in the Unayzah clastics (Upper Carboniferous-Lower Permian). Well tests indicate that production rates and levels cannot be explained solely by matrix porosity. It is therefore assumed that fractures are present and essential to production, particularly in the lower section of the reservoir. In addition, borehole stability is an issue in the Unayzah reservoir. Thus an optimal development necessitates field-scale characterization of fractures and in-situ stresses in the reservoir. Geological characterization using core and borehole images from key wells indicate the occurrence of open micro-fractures. These occur mainly in the lower part of Unayzah (Unayzah-B). The fractures in the Unayzah-B have two dominant sets trending ENE and ESE, respectively. Insitu stress characterization shows that the maximum horizontal in-situ stress trends at EW to ENE direction, nearly parallel to the ENE-trending fracture set. To detect field-scale distribution and patterns of the open fractures and the in-situ stresses, we applied azimuthal seismic. Wide-azimuth 3-D seismic data is processed and interpreted to detect the azimuthal signature in the reservoir, covering the Unayzah-A and the Unayzah-B. Sweet spots of high anisotropy are detected. These spots show good agreement with the borehole-scale observations on fracture density and in-situ stress pattern. Furthermore it is supported by well test analysis.

(305-Oral) Integrated reservoir modeling of a complex carbonate reservoir, Al Huwaisah field, North Oman

Amthor, Joachim (PDO - joachim.je.amthor@pdo.co.om), Huw A. Davies (PDO), John Keating (PDO), Mohammed Al-Mughairy (PDO) and Charles Kerans (U Texas)

The billion barrel Al Huwaisah oil field is a large, faulted dip-closure with locally significant fracture swarms, which produces from heterogeneous rudist-dominated limestones of the Aptian Shu’aiba Formation. It is the most complex field within the Shu’aiba of Oman in terms of facies distribution, stratal geometry and flow unit architecture, which is reflected in the historical well and field performance. To address the key uncertainties for long-term development of the Al Huwaisah field beyond its primary depletion phase, an integrated modeling approach was adopted. Improved 3-D seismic definition resulted in: (1) a reduction in top reservoir uncertainty; (2) improved imaging of faults and fractures; and (3) improvement in imaging the depositional geometry through the use of seismic facies and attribute analysis. Integration of 3-D seismic data with extensive borehole image log data led to the development of a fault/fracture model which greatly improved the understanding of the water movements in the field. Interpretation of the complex reservoir architecture is based on the integration of seismic and well data (cores, high-resolution image logs, dipmeter and conventional open-hole logs) with the available production performance data. Outcrop data and field analogs were reviewed and integrated into alternative geological models to account for the complex reservoir architecture. To address the range of uncertainty in reservoir architecture and to allow planning of uncertainty mitigation, a number of static reservoir models were constructed using a multiple realization approach. For each of the four field areas, different realizations were constructed to account for variable top structure, fault/fracture architecture, depositional architecture, porosity and permeability distribution and oil saturation models. These area models were then upscaled and exported for reservoir simulation. The simulation models suggest that further development of the Al Huwaisah field through infill drilling supported by waterflood-pressure maintenance can significantly increase oil rates in the next decade.

(37-Oral) Integrated fracture characterization using calibrated seismic data

Angerer, Erika (CGG - eangerer@cgg.com), Pierre Lanfranchi (CGG), Xin-Quan Ma (vsfusion) and Stephen F. Rogers (Golder)

Reliable sub-seismic scale fracture characterization requires a consistent workflow including wide-azimuth acquisition of surface and VSP data, calibrated data pre-conditioning, robust attribute generation, and analysis of fracture-related azimuthal anisotropic effects. Using surface seismic and VSP data examples, we present an innovative workflow of which the main characteristic features conmsist of three steps. The first step involves an ‘azimuth-friendly’, preprocessing sequence that produces amplitude preserved azimuth sectored images. A geostatistical method is applied to decompose the data into: (1) a ‘geological’ common part, (2) the anisotropic signal, and (3) noise. VSP data helps to correct for true amplitudes and refine velocity models. It also provides independent measurements of azimuthal anisotropy and hence fracture properties, which are used to calibrate surface seismic estimates. The second step consists of n azimuth-dependent, 3-D stratigraphic inversion where we apply a layer-based inversion technique to each azimuth sector. In order to ensure an overall consistency, the same initial model is used for all sectors. The 3-D nature of the algorithm produces a set of impedances that are more robust and accurate than conventional AVO-based attributes. The third step is an impedance ellipse-fiting procedure, calculating fracture intensity and orientation models. This information is subsequently integrated into a layer-based Discrete Fracture Network (DFN) model. The DFN approach allows the validation of the static model, through the simulated sampling of well fracture intersections. Furthermore, it provides an environment for simulating pressure transient responses and a route to upscaling grid cell permeabilities.

(59-Poster) Dolomitization of the subsurface Asmari Formation (Oligocene-Lower Miocene), SW Iran: suggested models and reservoir quality controls

Aqrawi, Adnan A.M. (Statoil - aamaq@statoil.com), Mohammad Keramati (NIOC), Neil Pickard (CCL), Gillian Darke (Statoil), Ali Moallemi (NIOC) and Tore Svånå (Statoil)

The sedimentological characterization the Asmari reservoir required a detailed analysis of the facies coupled with the interpretation of the diagenetic overprints. This has been achieved mainly through thin-section analysis (of cores and cuttings) and electric logs interpretation, in addition to the detailed core description and core analysis (i.e. porosity and permeability measurements). Taken together these data have led to a better understanding of the depositional and diagenetic history of the subsurface Asmari Formation, and the prediction of its reservoir units across two studied giant fields. It appears that dolomitization is one of the most important factors controlling porosity and permeability in the Asmari reservoir of southwest Iran. It was necessary to characterize the origin of the various dolomite fabrics, because some non-dolomitised intervals provide very good reservoir too, whereas other dolomitized intervals act as seals. Although dolomite is present throughout the reservoir successions in the selected fields, two dolomite fabrics can be clearly recognized. Fine-grained dolomites, often dolomudstones/wackestones, are typically associated with anhydrite nodules that are interpreted as pseudomorphs of former displacive gypsum nodules that grew from hypersaline brines under sabkha conditions. The fine-grained and thinly bedded nature of the sabkha dolomites that cap the depositional cycles (0.5-5 m thick), results in high intercrystalline micro-porosity but generally low permeability, unless the rocks are fractured. The best reservoir quality is often associated with coarser dolomite fabrics that have replaced subtidal bioclast-rich packstones and grainstones that form the base of the shoaling-upward cycles. In addition to intercrystalline micro-porosity, these dolomitized subtidal facies typically possess interconnected biomoulds that enhance the overall reservoir quality. The bulk stable isotopic analysis of oxygen and carbon of selected dolostone samples, revealed one main sample grouping, regardless of their original depositional facies type (i.e. grainy or muddy). All the analyses have positive δO18 PDB signatures (up to +3.3) suggesting that they formed from either hypersaline fluids or seawater. On the other hand, δC13 PDB varies to a greater extent (-3.56 to + 4.66) with depleted δC13 PDB values indicating an organic carbon input. This grouping may either indirectly indicate that the dolomitization timing or process occurred for the subtidal facies and supra-tidal facies together, and/or later diagenetic modifications have affected both dolomitized fabrics. However, the dolomitization mechanism might have dominated by sabkha pumping for muddy supra-tidal facies and reflex evaporation for the grainy subtidal facies.

(411-Oral) Bitumen Oocurrence in a giant oil field offshore Abu Dhabi: identification and impact on fluid behavior

Arab, Hani (Zadco - arab@zadco.co.ae), Bernard Carpentier (IFP), Eric Pluchery (Beicip-Franlab) and Jean-Marc Chautru (Beicip-Franlab)

Bitumens and tar mats are common features in Middle East oil fields and their presence in a reservoir can have adverse effects on its petrophysical properties and production efficiency. This study aims at assessing the distribution and continuity of the bitumens in the Lower Kharaib Formation of a giant oil field, offshore Abu Dhabi, in order to improve the reservoir production. Geochemical methods (Rock-Eval, gas chromatography and solvent separation) were used in order to identify the different organic materials present in the reservoir and define their typical signatures on wireline logs. Apart from the ‘normal’ moveable oil, which is produced from the field, two types of heavy organic materials have been recognized: (1) bitumen-rich reservoir intervals associated with high resistivities and high oil saturations. These intervals are characteristic of classical tar mats levels. These levels are located at the base of the reservoir layer and are restricted to the crestal area of the present-day structure. No relation with the present day oil-water contact (OWC) was detected. (2) Bitumen associated to low oil-saturated intervals must be classified as heavy residual oils. These are mainly located in the northeastern part of the field; their presence explains the apparent tilted OWC. The study of the structural evolution of the field suggests that the present distribution of the residual oil is due to the field having had a higher closure and a higher oil leg. Based on structural reconstruction, a model of this geological scenario led to a distribution of fluids (water, moveable oil and residual oils) that is close to the observed present-day ones. This predicted residual oil distribution can be used for optimizing the location and efficiency of the wells injectors.

(422-Oral) Reservoir characterization of complex Upper Jurassic Carbonates

Azer, Samir R. (ADMA-OPCO - azer@adma.co.ae), Alasdair M. MacKenzie (ADMA-OPCO), Shawket G. Ghedan (ADMA-OPCO) and Douglas Alexander Boyd (ADMA-OPCO)

The Upper Jurassic (Kimmeridgian/Tithonian), is composed of four carbonate anhydrite cycles (from topbase: A through D) that constitute the dominant reservoirs and caprocks of the Arab Formation. These are overlain by the Hith Formation anhydrites and subordinate carbonates, and underlain by the Diyab Formation source rock. This study summarizes the results of an integrated multi-disciplinary reservoir characterization study of the Arab C and D members. The objectives of the study were to describe, characterize and model the Arab C and D in a mature offshore Abu Dhabi field, to ultimately enhance production and improve reservoir management. Based on sequence stratigraphic concepts, the Arab C and D were subdivided into four sequences, ten parasequence sets and 47 shallowing upwards cycles or layers, 5 to more than 40 feet thick. Thick highstand and thin transgressive systems tracts characterize the Arab C and D. Based on petrographic analysis and mercury injection data, a rock typing scheme was developed. Capillary pressure and relative permeability curves were then generated for each rock type for use in the simulator. Permeability estimators were developed based on statistical methods, which incorporate core measurements, geologic knowledge and well logs. All the data and interpretations were then integrated and a 3-D earth model was built. The 3-D model was used for reservoir simulation, visualization and reservoir management. The update of the model following recent drilling and geochemistry studies highlights water saturation changes as well as tar mat occurrence for the benefit of reservoir evaluation and management.

(405-Oral) Sedimentological and rock-typing definition of the Khuff Formation of an offshore Abu Dhabi field

Azzam, Ibrahim N. (ADNOC - iazzam@adnoc.com) and Arnaud Meyer (Total)

A reservoir facies (lithotypes) classification and Core Rock Typing (CRT) study was carried out on the Khuff Formation of an offshore Abu Dhabi field. This study was a part of the full-field simulation model, and aimed at improving the 3-D geological model of this gas field. The CRT approach was conducted on: (1) a sedimentological description of 2,482 ft of cores from six wells and mainly representative of the Upper Khuff Formation (K1 to K4 reservoir units; K5 reservoir unit was also investigated); (2) the observation of 1,330 thin sections of rocks; and (3) the analysis of 2,480 CCAL and 87 MICP measurements. The first part of the study consisted of the definition of the depositional facies based on lithology, texture, and sedimentological features, deduced from both macroscopic and microscopic descriptions of cores and thin sections. This resulted in proposed sedimentary lithofacies, reservoir layering (based on sequence stratigraphy analysis), and reservoir lithofacies property description. The second part of the study defined: (1) rock types with observed differences of porosity networks; (2) diagenetic evolution of sediments; and (3) qualitative interpretation of petrophysical data. Core-to-log matching and the CRT recognition and identification on wireline logs was difficult and sometimes biased, especially in the dolomite intervals. The application of the CRT approach to the uncored zones remains uncertain, particularly in K4 and K5 reservoir units. Lithofacies and CRT descriptions for the six wells were used to build the 3-D geological model. The 3-D grid also incorporated the sedimentological layering based on facies description, and the sequence stratigraphy analysis. Maps of lateral variations of core type were used in the 3-D model to provide constraints for depositional orientation, facies changes, etc. This study contains a full analysis and integration of all sedimentological and petrophysical available data.

(165-Oral) Petroleum system evaluation, Strait of Hormuz, Iran

Badics, Balazs (Norsk Hydro - balazs.badics@hydro.com), Michael Erdmann (Norsk Hydro) and Thomas Hardt (Norsk Hydro)

The petroleum systems of the Strait of Hormuz were investigated using basin-modeling techniques. Geographically-separated occurrences of oil, gas-condensate and gas discoveries in this tectonically complex area indicate distinct differences in hydrocarbon generation and charge. The emphasis of the study was put on matching predicted and observed fluid properties in known accumulations, in order to predict fluid types in undrilled prospects. Several source rocks are known in the greater area and have been correlated to accumulations during the decade. The Silurian Gakhum source rock, proven at Bandar Abbas (80 km to the north of the area), is thought to have sourced the Gavarzin, Salakh and Suru fields. The high N2 and CO2 content in these gas fields suggest a highly-mature source rock. The Aptian Bab Member and the Cenomanian Shilaif source rocks most likely charged the Henjam, Hangam, Mubarek, and Tusan fields. Both intervals are thin, but organic-rich. The maturation of the Aptian-Cenomanian source rocks occurred from the Middle Miocene to present-day. The Upper Cretaceous Gurpi and the Paleocene-Eocene Pabdeh marls are deeply-buried likely source rocks in the eastern Strait of Hormuz. Trap formation predated charging in the observed cases. Hydrocarbon migration modeling, which includes multi-component PVT analysis, correctly matched all known accumulations and their fluid types, with uncertainties arising from, for example, the applied kerogen transformation kinetic model.

(36-Oral) Well planning for implementation of optimum development of a complex carbonate reservoir

Badri, Abdelmoneim B. (QP - babiker@qp.com.qa)

Proper and accurate well planning has played a major role in anticipated implementation of an integrated development plan involving a major capital project with marginal economics. The objective of this presentation is to review the premise of well planning to most efficiently recover oil and condensates from a gas-recycling project in offshore Qatar as well as details of the plan to reduce uncertainty. The objectives included: (1) production of liquids first for maximum recovery efficiency without drilling of additional wells for gas recycling; (2) penetration of all reservoir layers; (3) maintaining a constant stand-off to gas and water contacts; (4) optimum well completion for flow; and (5) addressing corrosion concerns. Procedures included use of an updated, integrated, multi-disciplinary, rock and fluid characterization to guide plans which would meet the objectives. 3-D seismic mapping that used the techniques of depth-conversion using the interval velocity approach, and also facies, rock typing and layering were incorporated. ‘ZmapPlus’ and ‘Stratamodel’ were used in preparing and checking the surface and property grids, water saturation modeling, and ended with oil/gas volumetric calculation on layer basis. The well targets were then optimally selected using this information. The results achieved all the objectives and were incorporated in a full-field compositional simulation, which indicated that performance forecasting attests to the effectiveness of well trajectories and completion planning. This study shows that careful well planning using updated integrated characterization and guided by the project objectives, can be achieved. Such planning significantly contributes to reducing risk and improving economics.

(346-oral) Cost-effective ‘dynamic’ static corrections in the Arabian Peninsula

Bagaini, Claudio (Schlumberger - bagaini@slb.com) and Tariq Alkhalifah (KACST)

We derive the analytical expression of a new pre-stack operator, the Topographic Datuming Operator (TDO). This datuming operator generalizes the operation of static corrections, which is well known in the seismic exploration community, and widely used in land seismic data processing. TDO eliminates the essential assumption of vertical incidence to the earth’s surface of the downward-and upward-propagating reflected wavefield, which is not valid in the presence of high-velocity shallow layers and/or large offset-to-reflector depth ratios. TDO applies kinematic corrections, which are to a large extent equivalent to those obtained with ‘dynamic’ statics using ray-tracing, in a cost-effective way. The weighting function used in the Kirchhoff implementation of TDO produces redatumed seismic sections that can either be amplitude-preserving or true-amplitudes depending on the requirements. The TDO introduced here, fills the gap between the simple but often inappropriate surface-consistent static corrections, and the more rigorous but computationally-expensive Kirchhoff pre-stack redatuming. In addition, TDO does not require a detailed depth-defined velocity model, but processing parameters that can be updated by applying iteratively the operator itself. This study presents the application of TDO to land seismic data representative of the Arabian Peninsula near-surface seismic challenges. Sand dunes, wadis, velocity inversions in the overburden, and shallow high velocity layers were considered. The study also compares the results obtained using standard static corrections and ‘dynamic’ statics performed by TDO.

(235-Poster) Geochemical studies and source rock evaluation of Lower Cretaceous Sulaiy Formation in Kuwait

Bahman, Fatema K. (Kuwait U - fatma@bahmanco.com), Fowzia H. Abdullah (Kuwait U) and Abbas A. Saleh (Kuwait U)

Most of the oil reserves in Kuwait is produced from clastic sandstones and carbonates reservoirs of early and middle Cretaceous age. Many studies were carried out to evaulate some of these oil reserves. The Upper Jurassic-Lower Cretaceous (Tithonian-Berriasian) Sulaiy Formation is one of these source rocks. The purpose of this study is to evaluate the depositional environment of the Sulaiy Formation by correlating its lithological variations and organic matter content in Kuwait. A total of 114 core samples were collected from Sulaiy Formation wells in Burgan, Minagish, Mutriba, Ritqa and Raudhatain oil fields in Kuwait. Analytical procedures were carried out for organic matter evaluation using LECO analyzer and transmitted-light microscope. Petrographical studies of thin sections and chemical composition of rocks were done using EDS, ICP and XRD. The study also analyzed 21 core samples from the Hith, that underlies the Sulaiy Formation, and 38 from the overlying Minagish Formation. The evaluation of the physical and chemical conditions of the depositional environment variation, above and below the Sulaiy deposits, completed the time deposition of the whole series. The Sulaiy Formation is mainly composed of gray to dark, highly-bituminous, pyrite-rich carbonate. The carbonates alternate with massive and laminated mudstone that contains sponge spicules and foraminiferas, and is most obvious in the northern part of Kuwait. The Hith Formation is composed of anhydrite intermixed with gray to brownish bituminous limestone forming a chicken-wire structure. The Minagish Formation is composed of light gray to brown, poorly bituminous, massive carbonate. The results of TOC measurements range between 0.46 - 6.0 % wt, and may reach as high as 11.0 % wt. The kerogen shows an amorphous organic matter (AOM) mixed with well-preserved zoo-and phyto-plankton (algae) with rare humic particles. The elemental composition of organic matter indicates type-II kerogen. The maturity level and kerogen type indicate a potential source rock especially in the northern part of Kuwait, where the organic matter is well-preserved amorphous marine type-II kerogen. The accumulation of deposits was controlled by a fluctuation of rising and dropping sea level within the general transgression of the sea starting from the supra-tidal-intertidal in the lower part (Hith Formation) to deeper subtidal to more open marine offshore environment at the top (Sulaiy Formation) with an anoxic depositional condition giving rise to overall on lap transgressive sequence.

(35-Oral) Facies modeling within Fateh field, llam case study, Dubai, UAE

Balke, Scott C. (DPC - scott.balke@conocophillips.com) and Fateh Development Team (DPC)

After the first successful well has been drilled, the fundamental challenge in the development of any hydrocarbons is accurate distribution of the reservoir properties. In order to preserve the reservoir heterogeneity, the development geoscientist takes the detailed understanding of the vertical data and applies that knowledge in a 3-D spatial arrangement within a geocellular model. In the case of the Ilam Formation, a productive carbonate reservoir of the Gulf’s Fateh field, numerous wells had been drilled and the field is in an advanced stage of development. This study presents a case example of the effects on the static model using various methods in order to distribute petrophysical information. Reservoir properties within a carbonate rock can vary considerably. The Ilam reservoir was modeled using several different methods in order to capture the range of geologic uncertainties. The most effective approach, which provided the most likely distribution of porosity and permeability, was based upon a precise understanding of facies within the Ilam from core information. Facies delineation was then determined from a sonic and density log cross-plot. Facies maps were constructed and used to populate porosity and permeability within the geocellular model. The objective in building this static model was not only to analyze the various distribution techniques of porosity and permeability, but also to develop the upscaled dynamic reservoir model, which provided a full-field reservoir simulation of the field. A development program for the Fateh field was based upon this dynamic model. Drilling results as well as reservoir performance were compared with the various methods of property distribution.

(334-Oral) Tectonic evolution of Alborz (Iran) since Mesozoic

Barrier, Eric (CNRS-MEBE - barrier@lgs.jussieu.fr), Marie-Françoise Brunet (CNRS-MEBE), Abdollah Saïdi (GSI) and Alireza Shahidi (GSI)

The Alborz Range constitutes the southern margin of the South Caspian Basin. The analysis of brittle deformations in the Mesozoic and Cenozoic Alborz sedimentary sequences enabled us to reconstruct the regional tectonic evolution. After the Middle-Late Triassic Eo-Cimmerian tectonic phase resulting from the collision of the Cimmerian blocks with Eurasia, an extensional event developed during the deposition of the Shemshak Formation (Late Triassic to Middle Jurassic). We assign this extension to the rifting phase of the South Caspian Basin that probably opened in Late Jurassic. During the post-rifting period of thermal subsidence, minor compressional tectonic events intercalated, especially at the Jurassic-Cretaceous boundary and latest Cretaceous. Regional unconformities and the deposition of clastic sediments provide evidence for these compressional phases. In Eocene time, a strong extension lasted, associated with EW-trending normal faulting, originating the thick volcano-clastic Karaj Formation. We assume that this regional sub-meridian extension is related to the back-arc opening behind the northward subduction of the Neo-Tethys oceanic lithosphere beneath the Eurasian margin. The next major orogenic period developed during the Late Cenozoic in relationship with the Arabian-Eurasia collision. This study is part of the Middle East Basins Evolution Programme (MEBE).

(74-Oral) Integration of explicit fracture networks in field flow models for a higher reliability of multi-phase production profiles

Basquet, Rémy (IFP - remy.basquet@ifp.fr) and Bernard Bourbiaux (IFP)

Seismic and sub-seismic faults or fracture swarms generally have a major impact on the hydrodynamic behavior of a reservoir. Early water breakthrough or crossflow between layers are the main effects observed in the presence of such objects. Due to their large scale, the integration of these fractures into a field flow model as homogenized flow properties defined at the hectometric gridblock scale, generally leads to inaccurate predictions of the multi-phase production behavior. To overcome these limitations, the present work proposes a reservoir simulation method based on the dual-medium concept, but keeping the explicit representation of large-scale fractures as identified or modeled by the geologist. This modeling approach is applied for the simulation of water encroachment in a typical fractured oil field model. The results are compared to several conventional approaches based on the single porosity concept or the dual porosity concept, and involving different methods of homogenization of the fracture network. The explicit modeling of the actual large-scale fracture network geometry enables an accurate prediction of the progression of fluids within the fractures while minimizing the number of fracture cells. The method is promising as it enables a straightforward use of realistic geological fracture models in reservoir simulators, for any field study where flow channeling along highly-conductive geological features is suspected.

(355-Oral) The Miocene of the Mut Basin (southern Turkey): an analog for Oligo-Miocene reservoirs of the Middle East

Bassant, Philip (ChevronTexaco - phil.bassant@chevrontex aco.com) and Frans van Buchem (IFP)

Early Miocene and Oligocene oil-bearing limestones of Iran (Asmari Formation) and northeastern Iraq (Euphrates Formation) are characterized by complex lateral and vertical facies variability. These are described in the literature as an alternation through time between ramp and rimmed shelf platform morphologies for the Oligocene limestones in the Kirkuk field (northeast Iraq). Mud-flat, bioherm and bank, foreslope and basinal depositional environments have also been described in the literature. The Mut Basin in southeast Turkey contains excellent-quality outcrops of Early Miocene shallow-marine limestones, sandstones and basinal sediments. These were deposited during a time of rapid marine flooding of a complex antecedent topography during the Early Miocene, Burdigalian stage. The Miocene of the Mut Basin is appropriate as an outcrop analog to the Asmari and Euphrates formations because of four similarities; namely: (1) depositional geometries; (2) facies and fauna (notably foraminifera); (3) interaction between sands and carbonates; and (4) influence of paleotopography on stratigraphic development. A variety of depositional geometries are observed in the Mut Basin; including: (1) tidal carbonate bioclastic ramp; (2) a low-relief carbonate platform that transitions during flooding to an isolated platform complex; (3) rimmed platform with steep slope; and (4) low-relief, intraplatform banks. These are similar to many of the morphologies described in the literature from Kirkuk field. The facies described in the Mut Basin have been closely tied to their position on the depositional profile by direct observation of stratal geometries. Characteristic foraminiferal assemblages exist in each depositional environment from the lagoon, through margin banks and shoals, to the slope and the basin. A mixed-system develops on one flank of the basin where an active delta underwent rapid flooding and became an estuarine system with carbonate reefal banks lying just beyond the estuary mouth. The Early Miocene transgression flooded a complex relict topography in the Mut basin that is similar to the onlapping geometries of the Middle Oligocene units in Kirkuk onto the underlying Eocene strata. While the similarities are striking, two features typical of the Asmari or Euphrates formations have not been studied in the Mut Basin, and should not be considered as part of the analogy; these are: (1) diagenetic history; and (2) development of evaporites. Lastly, one exceptional aspect of the Mut area as an analog for the Asmari and Euphrates formations, is that all these aspects of the Miocene shallow-marine deposits are reassembled in one geographically small area. It remains to be seen whether this also is typical of the Gulf equivalents!

(471-Oral) Sequence stratigraphy of the Late Oligocene-Early Miocene mixed siliciclastic and carbonate sediments in the southwest of Iran

Beiranvand, Bijan (RIPI, NIOC - biranvandb@ripi.ir)

The Late Oligocene-Early Miocene sediments in the southwest of Iran, especially in the Dezful Embayment, are one of the most important reservoirs in the world. These sediments are predominately carbonate, but in the central area of the Dezful Embayment, it consists of a mixed siliciclastic and carbonate reservoir. The amount of siliciclastic material varies from less than 5 to more than 50 percent. In the upper part of the sequence, a sandstone complex (sandy dolomites, medium grained, poorly consolidated sandstones, dolomitic calcareous sandstones, calcareous sandstones, carbonaceous shales and sandstones) rapidly increases in thickness and apparently coalesces, but in the lower part, the fine- to medium-grained loose sands, poorly consolidated sandstones, greenish to black shale, silty shale and thin intervals of silty sands are not regionally extensive and the thickness development on the central part. This mixed siliciclastic and carbonate sequence deposited within a relatively low relief carbonate platform setting. These sandstone intervals have high permeability and constitute a major aquifer system in the region. The sequence stratigraphical analysis logs that have been created by using a systematic core description, biostratigraphic data integrated with sedimentological, and lithological data, and so wireline log criteria by the application of sequence stratigraphic concepts in this carbonate ramp and platform setting show the following results: 1) because of the low angle of the shelf and its broad nature, even small changes in relative sea level, caused by the interaction of sediment supply, tectonics, and eustasy changes, has a major impact on depositional patterns. 2) The thick carbonate intervals produced while the relative rise in sea level is very rapid and the “weak” clastic systems are completely over whelmed and pushed right back into the hinterland. 3) In the upper part of the sequence, sediment supply from the low relief hinterland is weak but as the sea level rise is slow, the clastic system can aggrade and prograde. Slow sea level rise also allows the broad carbonate ramp developed outboard of the clastic system to aggrade. So the fluvially derived clastic sediment supply is sufficient to maintain the clastic shoreline systems in more or less the same position. 4) In the middle and lower parts of the sequence, a rapid rise in sea level overwhelms the available clastic sediment supply, and pushes the clastic shoreline system back (Forced Regression System Tracts, FRST) on to the shelf.

(63-Oral) The creation of late Proterozoic basement highs and their subsequent influence on sedimentation patterns of the Arabian Peninsula

Bell, Andy (Shell - andy.bell@shell.com)

A model of late Proterozoic accretion and cratonization has been developed which can be extended across the Arabian Plate. Shell in conjunction with SRK Consulting of Australia, has used gravity and magnetic data, calibrated by seismic and well data to produce a series of kinematically constrained tectonic models. A model of basement topography was developed across the entire Arabian Peninsula using the SEEBASETM methodology of SRK, which inverts the gravity and magnetic data, allowing a better visualization of basement relief. The model of basement topography shows a series of predominantly NS-oriented ridges which are then off-set by NW-trending lineaments. This NS-orientated basement grain is interpreted as a result of terrane accretion during the late Proterozoic Pan-African Orogeny which was subsequently affected by an anastomosing array of NEtrending continent-scale shear zones corresponding to the infra-Cambrian Najd Event. Evidence from the sub-crop of the Angudan unconformity in Oman and the subcrop of the ‘Hercynian’ unconformity in other parts of the Arabian Peninsula suggest that these highs are bounded by localized zones of more intense deformation. The bounding fault zones to these highs are interpreted as closely spaced near-vertical faults, rooted in basement shear-zones, which have been subjected to both transtension and transpression during various episodes through geological history. The amount of lateral movement on these faults is limited. These long-lived basement positive features act as relative ‘buoyant’ highs independent of the tensile or compressive stresses acting on the plate. As the basement ridges were increasingly buried, subtle differential subsidence and/or hinge lines had perceptible influence on facies distribution and stacking patterns.

(487-Poster) The interpretive stratigraphy of a regional traverse dip section from the Khuff outcrop belt in central Saudi Arabia to Al-Jawb in Eastern Saudi Arabia

Billing, Ian M. (Saudi Aramco - ian.billing@aramco.com), Denis Vaslet (BRGM), Yves-Michel Le Nindre (BRGM), Abduljaleel Abubshait (Saudi Aramco), Raid Dakhil (Saudi Aramco), Rami Kamal (Saudi Aramco), Aus Tawil (Saudi Aramco), Randy Demaree (Saudi Aramco), Geir Ytreland (Saudi Aramco) and Alastair Gray (Saudi Aramco)

The Permo-Triassic Khuff Formation in the subsurface of Saudi Arabia acts as a significant gas reservoir, and a detailed sequence stratigraphic scheme has recently been completed for the Khuff in the supergiant Ghawar field in eastern Saudi Arabia. The challenge then facing carbonate geoscientists was to evaluate this model outside of the Ghawar structure, and produce a regionally-consistent geological framework for this formation. A significant amount of core has been taken in wells outside of Ghawar, and moderately well-exposed outcrops of the Khuff Formation also exist within the Kingdom. This is the result of a detailed geological study of the Khuff Formation to the south of Ghawar as a step in the creation of a regional Khuff Formation model across the entire Arabian Shelf. The Khuff Formation outcrops in a narrow 600-km-long arcuate N-S belt in central Arabia, to the west of Riyadh. While providing good information on potential reservoir geometries and an insight into the stacking patterns of these shallow-water to supra-tidal carbonates, linking the outcrops to the subsurface has proved challenging, due to down-dip facies changes and the paucity of diagnostic evaporite markers, which act as significant units for correlation in the subsurface. By compiling a 250 km-long dip-section traverse, utilizing extensive and detailed core descriptions, micropaleontological analysis and wireline log integration, a consistent correlation has been compiled. This presentation illustrates the results of this traverse from the Qassim outcrops in central Arabia, through shallow-cored water wells, into exploration wells, tying up with the Ghawar field, and terminating at Jawb. This study represents a major advancement in the regional understanding of the sequence stratigraphy and lateral facies distribution of the Khuff Formation, and will aid future exploration efforts throughout the Arabian Gulf.

(264-Oral) Fold and fracture relationships in carbonate anticlines in the Zagros Mountains and Oman

Blanc, Eric J.-P. (Cambridge U - eric.blanc@casp.cam.ac.uk), Christopher A.J. Wibberley (Antipolis U), Mark B. Allen (CASP), Hossein Hassani (Amir Kabir U) and Govand Sherwani (U Salahaddin)

Fractures play a significant role in both the porosity and migration pathways of Middle East carbonate reservoirs. Fracture distribution in folded carbonate reservoirs is controlled by a combination of the tectonic evolution and the mechanical properties of the strata. In order to improve prediction of fracture distributions in Middle East carbonate reservoirs, we are performing studies of fracture development in folded carbonates in the Zagros fold and thrust belt in Iran, Iraq, and the Adam Foothills of Oman. Scales of observation range from satellite imagery studies, through fieldwork, to micro-structural analysis. The orientations and spatial distribution of fracture sets mapped around fractured/faulted anticlines are correlated to the deformation history, particularly with respect to folding mechanisms and the likely evolution of stresses during folding. Such genetic controls are thought to be important in estimating likely reservoir fracture geometries from large-scale, regional information such as tectonic deformation history and evolution of stress regime. Also important in controlling fracture development during folding are the presence of pre-fold and syn-fold faults, whilst late or post-fold faulting commonly develops independent fracture clusters. The relationship between lithofacies and fracture properties is discussed, from a number of points of view. Firstly, strain partitioning along weak beds during folding may affect the vertical continuity of fractures. Secondly, fracture characteristics (e.g. density and aperture) depend on the mechanical properties of a given lithology. Thirdly, diagenetically altered units along key surfaces such as hardground surfaces or paleokarstified units exert a geomechanical control affecting the development of later fracture arrays. An important issue in fractured carbonate reservoirs is whether much of the fracture porosity has been destroyed by calcite cementation. Nevertheless, micro-structural observations show that even cemented fractures can reopen, under certain stress conditions, to act as conduits to fluid flow or as surface fissures held open during reburial by porous sediment infill. Such diagenetic controls highlight the sensitivity of final fracture array properties to the burial and uplift history in relation to folding and fracture generation.

(208-Oral) Log synthesis and pseudo-wells for optimal impedance inversion of a carbonate reservoir, onshore Abu Dhabi

Bloch, Gérard (ADCO - gbloch@adco.co.ae) and Michael Shoemaker (Jason)

Prior to a post-stack model-based inversion to acoustic impedance, it is critical that the geoscientist execute a reservoir well log data consolidation and rock properties analysis, with the ultimate objective of modeling reservoir porosity. Available wells and log data (sonic and density) however, can be sparse, and may require log synthesis and the emplacement of pseudo-wells prior to impedance modeling and inversion. Here, we introduce a systematic approach in achieving the objectives of: (1) statistically synthesize log data from existing information, independent of both layers (vertical) and well locations (spatial); (2) derive and tie synthesized (and available) impedance logs to seismic amplitudes for the accurate estimation of wavelets and seismic synthetics; (3) add pseudo-wells with appropriate pseudo-logs to properly constrain the well-derived, low-frequency part of the inversion in order to conform the model to the known carbonate geology in both space and time; (4) interpolate (via log data) impedance models and invert post-stack seismic to acoustic impedance that honors all available information (actual and pseudo wells); and (5) transform acoustic impedance to reservoir porosity. This new methodology has been successfully tested on a carbonate field, where available log data is sparse. Synthesized logs were estimated from facies-dependent regression analyses, where rock property differences were identified by superposing independent cross-plot analyses of existing log data (in vertical and spatial domains). This resulted in synthesized impedance logs that, when modeled, statistically honored known carbonate stratigraphy. The end result is inverted impedance transformed to reservoir porosity (via rock property relationships) that honors known heterogeneity of vertical and spatially varying rock properties in a complex carbonate reservoir.

(209-Oral) Evaluation of a fractured carbonate reservoir with integrated seismic and image data, onshore Abu Dhabi

Bloch, Gérard (ADCO - gbloch@adco.co.ae), Maged Al-Deeb (ADCO) and Ishtiaq Jadoon (Schlumberger)

In one of the major onshore oil fields in Abu Dhabi, the presence of a large number of fractures and minor faults often leads to higher production and/or water-cuts and mud losses in the Upper Cretaceous carbonate reservoir. Therefore, these features need to be well-constrained for optimum field development. Seismic data is successfully used to predict the presence and distribution of faults, but can also be used to predict sub-seismic deformations. However, due to relatively coarse seismic resolution, these predictions require validation with well data. Electrical image logs such as Formation MicroImager (FMI), allow viewing the reservoir along the borehole for fault and fracture analysis (characterization and distribution). This study shows examples of how integrated seismic and borehole log image data can be used to constrain sub-seismic features along the borehole. In one example of a horizontal well, the presence of a fault is confirmed by the borehole image analysis. Image data, coupled with the open-hole logs, were used to draw a balanced structural cross-section and to calculate about 25 to 43 ft of throw at the fault. In another case, an inferred sub-seismic fault was not observed in the borehole image. However, a kink was recognized between two panels of structural dip, based on the image analysis. The location of the kink was found to be in agreement with the location of the inferred fault. The low number of fractures observed over the kink area is explained by the deformation being consumed by the bending of the layers. In another example of a horizontal well, four sets of open fractures were interpreted by the borehole image analysis. This information is found to be consistent with the detailed seismic interpretation of minor faults. Higher mud losses were observed in this well that are attributed to the better connectivity between fracture networks. In conclusion, fracture analysis based on borehole images, integrated with seismic interpretation, is essential to resolve or reduce many structural uncertainties in the reservoir. Integration closes the scale gap between log and seismic data, and is a key element for improved reservoir characterization leading to better field development.

(232-Oral) Evaluation of salt domes for Mesozoic and Paleozoic targets, offshore Abu Dhabi

Boekholt, Martin P. (ADCO - boekholt@emirates.net.ae), Erik B. Kleiss (ADCO) and John Mariano (ExxonMobil)

Part of the ADCO concession lies in offshore Abu Dhabi around several islands in the Gulf. This offshore area is part of the Hormuz Salt Basin and the discovered hydrocarbon accumulations are related to movement of the infra-Cambrian salt during the Mesozoic and Cenozoic. Continuous growth of the offshore structures was established by back-stripping the depositional packages through geologic times. The continuous diapirism resulted in shallow-marine conditions over and around some salt domes, and hence in the localized deposition of good reservoir facies surrounded by deeper-water deposits. This study evaluated the hydrocarbon potential of two islands that appear to be realted to salt diapirism. Tha fairway analysis included: (1) evaluation of all potential reservoirs; (2) salt body detection and modeling with newly acquired, high-resolution, 3-D gravity data; (3) imaging of sedimentary structures around the salt domes using pre-stack Depth Migration (PSDM); and (4) subregional mapping of key intervals used for charge analysis. Two high-resolution 3-D gravity surveys confirmed the existence of salt diapirs close to both islands, and their size and shapes. Both salt domes reach close to the surface and have feeders to the south, and salt overhangs to the north. The feeder for one salt dome is deep (at least 10 km), and therefore is likely attached to the Hormuz salt. In contrast, the maximum depth of the second, smaller salt body is only 4 km, and indicates a detachment from the Hormuz salt. In addition to PSDM, the seismic data was processed through several iterations of tomographic updates and anisotropic imaging. The resulting images of the sedimentary layers around the domes were significantly improved, including their approximate termination against the salt dome. Potential exploration targets were verified in the depth domain. The interpreted salt body geometries derived by PSDM and gravity modeling are consistent. Both salt domes are located in small NNE-striking salt-withdrawal basins, which are confined by structural highs on both sides. In one syncline, the relevant source rocks for shallow targets are buried deep enough to be mature for present-day oil generation.

(185-Poster) Eoalpine geodynamic evolution of Omans Tethyan continental margin

Breton, Jean-Paul (BRGM - jp.breton@brgm.fr), François Béchennec (BRGM), Joël Le Métour (BRGM), Laure Moen-Maurel (Total) and Phillipe Razin (U Bordeaux)

A revised interpretation of the successive stages of the eoalpine evolution of the northeastern margin of Oman is presented through seven cross-sections of the same lithospheric transect at five million year intervals, from late Albian (100 Ma) to early Maastrichtian. This SW-NE transect starts on the southwest border of the Hamrat Duru Range, crosses the eastern part of Jabal Akhdar, Saih Hatat and the Tethys Ocean, up to the Samail Basin to the northeast. The compilation of the recent structural, stratigraphic, sedimentological, paleogeographical and geophysical studies, of the central part of the Oman Mountains, resulted in the interpretation of the following events: (1) The detachment initiating the subduction of the autochthonous was intracontinental and occurred in the proximal part of the continental margin, south of the external part of the shelf. (2) Between the intraoceanic detachment initiating the Samail ophiolitic nappe and the intracontinental detachment, the part of the margin consisting of the external shelf, the continental slope, and the whole Hawasina Basin formed an independent North Muscat micro-plate. (3) From early Turonian to the end of Santonian, obduction and intracontinental subduction operated in the same direction and the same time. The northeast part of the micro-plate plunged below the Samail nappe and its southwestern part emerged part-thrusting the autochthon. (4) At the Santonian-Campanian transition, obduction and intracontinental subduction stopped after the Samail nappe front overpassed the southwest border of the micro-plate. (5) During the final stage of the intracontinental subduction, the lower part of the subducted continental crust delaminated upwards the overlaying part under buoyancy effect, marking the first stage of the autochthonous exhumation. (6) From early Campanian to early Maastrichtian, the North Muscat micro-plate moved back to the northeast; its northeast part plunging by gravity into the asthenosphere, and the subducted autochthonous exhumed by unfolding and uplift, which caused the emersion and partial erosion of the ophiolitic sequence. (7) The local crustal thickening, related to the delamination of the subducted continental crust, formed the Saih Hatat Dome, in which erosion reaches the pre-Permian succession.

(48-Oral) Multi-layer statics modeling using upholes or first breaks

Bridle, Ralph M. (Saudi Aramco - ralph.bridle@aramco.com), Robert E. Ley II (Saudi Aramco), Mohammad A. Al-Homaili (Saudi Aramco), Bryan Maddison (Saudi Aramco) and Kurt Janssen (Saudi Aramco)

For most of the exploration area in Saudi Arabia, a single-layer velocity model is adequate. In areas of complex near-surface topography and where the datum is above surface the simple single-layer approach can be in error. These time errors create cycle skips or medium to long wavelength structure problems. Multi-layer models can be built on 2-D lines, the control being from the 42,000 upholes that were drilled prior to 1994. For individual 2-D lines a reasonable model may be built, however there are problems tieing the models. The method is to interpret the upholes, and then use the knee points as definition for the base of the layer. The velocity is interpolated linearly between upholes and the base of the layer can be interpolated linearly by thickness or elevation. Though versatile, this layer-building method requires good quality representative upholes that penetrate through the base of the weathering on a regular grid. In areas of severe and complex topographic variations, the uphole multi-layer model becomes inadequate as the 4-km spacing only captures the aliased low-frequency component of these high-frequency changes. The acquisition of high-resolution seismic data with high group density, in some cases 5 m intervals, gives the opportunity to use shot gathers for refraction information. By using the classic refraction spread method the first three horizons can be interpreted from shot gathers of suitable quality. These first-break interpretations create a depth/time model consisting of computed velocity control points that are input into the layer model builder. Assuming the refractors to have zero or small dips, the majority of the problems seen in the near-surface can be solved. This is not a severe assumption in most areas of Saudi Arabia, particularly in the Eastern Province, since surface layers are essentially flat-lying. Layer modeling has created models with less static uncertainty, and can be applied to both 2-D and 3-D acquired seismic data.

(32-Poster) Post-inversion uncertainty analysis for post-stack acoustic impedance inversion

Broadhead, Michael K. (Saudi Aramco - michael.broadhea d@aramco.com)

In order to produce a quantitative confidence estimate for post-stack seismic inversion for acoustic impedance, one would ideally incorporate the uncertainty analysis into the inversion process itself, which would take into account data covariance and prior probabilities. This methodology is published elsewhere based on a Bayesian approach. However, it may also be desirable to produce uncertainty estimates for existing impedance volumes. Such estimates would necessarily be crude, but should have value in at least a relative sense. This new approach exploits the well known series expansion of variance approach in the theory of propagation of errors. To first order, the forward problem gives the variance of the seismic amplitudes in terms of a convolution between a function of the wavelet and a function involving the acoustic impedance, and its associated variance (the uncertainty in impedance which we desire to estimate). To invert this equation amounts to solving a deconvolution problem, where it is assumed that everything is known except the impedance variance. This deconvolution problem is complicated by the need for a positivity constraint on the solution, hence we developed an approximation to the inverse problem that leads to a simple algebraic expression applied in a sliding window. The study also developed a procedure for estimating the seismic amplitude variance, which uses ensemble averaging over a neighborhood of seismic traces within the range of the variogram. The study shows how one could, in principle, incorporate wavelet uncertainty into the formulation.

(369-Poster) Dionisos: a stratigraphic forward-modeling tool for reducing reservoir and trap uncertainty

Burgess, Peter M. (Shell - peter.burgess@shell.com), Henne Lammers (Shell), Cees van Oosterhout (Shell) and Kees van der Zwan (Shell)

Many conceptual geological models and methods, such as sequence stratigraphy, tend to overestimate information and knowledge about the subsurface, and underestimate subsurface uncertainty and risk. Quantitative methods in stratigraphy are important in addressing this problem because they allow more objective analysis. A particular quantitative method, stratigraphic forward modeling (SFM), represents sedimentary processes by equations, rules and algorithms and makes quantitative predictions of the products likely to result from given initial conditions and process parameters. Because a SFM is a quantitative tool, and because good models are based on sound understanding of physical processes, they can to some extent address the problem of quantifying and providing an independent challenge to sequence stratigraphic models. Do SFMs behave in a way consistent with sequence stratigraphic concepts, and make similar predictions? Dionisos is a stratigraphic forward model, developed by IFP and a consortium of companies including Total and Shell. It is being tested and applied throughout Shell in 2003-2004. It is a 3-D SFM, includes many important processes known to operate in carbonate systems, and can be applied to both siliciclastic and carbonate systems either at the exploration or the production scale. Constrained model results can be useful at the exploration scale, helping reduce uncertainty in reservoir, seal and source rock prediction, and at the production scale, predicting probable inter-well reservoir properties. Dionisos has been applied to various subsurface challenges, e.g. a Cretaceous carbonate field Asab in the UAE, carbonate buildups in SE Asia, and Cenezoic deltas on the Atlantic margins, and plays an important role in helping to assess and reduce subsurface uncertainty.

(403-Oral) Impact of surface-consistent processes on pre-stack seismic attributes

Burnstad, Roy M. (Saudi Aramco - roy.burnstad@aramco.c om), Tim Keho (Saudi Aramco,) and Patrick Rutty (Saudi Aramco)

The Permo-Carboniferous Unayzah Formation has been an exploration target in Saudi Arabia for over a decade, with oil and gas production from the unit now well established. Still the Unayzah remains a challenging objective, in large part due to the complex interplay of continental depositional environments it represents. Braided stream, wadi fill, playa lake, interfluve, alluvial fan and eolian dune systems have all contributed to the Unayzah. In the study area, where the Early Permian Unayzah-A2 is the primary target, exploration efforts are now focusing on combination structural-stratigraphic traps. The success of these efforts hinges on precise delineation of sandstone trends. To this end, 3-D surface seismic data presents the best opportunity to extract and map attributes that help define the target trends. The methodology used in this study was attribute analysis of near and far stacks at key stages of target oriented 3-D seismic re-processing. Key processing decisions were guided by these analyses. The study included three major pre-stack processing procedures routinely applied to land 3-D seismic data: surface consistent amplitude analysis, linear noise removal, and surface consistent deconvolution. Parameterization of shot, receiver, common depth point, and offset operators were evaluated. The study results indicate operators chosen for surface consistent pre-stack processing procedures should be carefully analyzed before application. Use of offset-dependent seismic attributes assisted the analysis and ensured that the overall objectives of re-processing were met. Subsequent interpretation led to an improved understanding of the sandstone trends in the targeted Unayzah Formation.

(439-Poster) Stratigraphic architecture and reservoir quality controls on the Shu’aiba reservoir, Shaybah field, Saudi Arabia

Cantrell, David L. (Saudi Aramco - dave.cantrell@aramc o.com), G. Wyn Hughes (Saudi Aramco), Roy K. Sadler (Saudi Aramco), Robert F. Lindsay (Saudi Aramco) and Peter K. Swart (U Miami)

Recent efforts by a multifunctional team within Saudi Aramco has provided new insights into the stratigraphic architecture and depositional framework of the Shu’aiba reservoir in Shaybah field, Saudi Arabia. Within this reservoir interval, three major early Aptian sequences and one late Aptian sequence have been identified, which record changes in water depth and depositional energy from a shallow-marine platform interior and shelf margin environment in the southern and central portions of the field, to a deeper-marine offshore setting to the northeast. Initial topography was established during the lowermost sequence, and influences the distribution of paleoenvironments in later Shu’aiba sequences. The lowermost sequence is initiated above an unconformity and karst surface at the top of the Buwaib (Kharaib) Formation, and begins with a major flooding event (recorded by a cyclic succession of argillaceous orbitolinid packstones and Lithocodium wackstones (informally named the Biyadh at Shaybah), which is typically overlain by a succession of Lithocodium-coral wack-packstones. The second sequence typically sharply overlies the first sequence, and is highly variable in character, containing a differentiated rudist bank complex in the central and northwestern part of the field along the platform margin, which separates restricted platform interior facies in the south from deeper water planktonic foram-rich packstones to the northeast. Again sharply overlying this sequence is a third sequence, which contains a diversity of environments that reflects earlier depositional topography, although it overall represents a relative deepening from the previous sequence below. Finally, the fourth (late Aptian) sequence only occurs as a restricted basinward wedge of foram-rich packstones to the east of the field. Diagenesis has extensively modified the original properties of these sediments. Petrographic and geochemical evidence suggests that the top of the Shu’aiba Formation is a major karst surface, in which meteoric diagenesis has selectively altered portions of the reservoir up to 180 ft below the top-Shu’aiba sequence boundary (which is interpreted to represent a composite sequence boundary). Other sequence boundaries locally display evidence of limited meteoric diagenesis. Specific diagenetic modifications include coarse blocky calcite cements, compaction, and microporosity development. The interplay of stratigraphic architectural elements and diagenesis controls reservoir quality in the Shu’aiba at Shaybah field.

(328-Oral) Geochemical characterization of the Mauddud Formation reservoir, Raudhatain and Sabiriyah fields, North Kuwait

Chetri, Hom B. (KOC - hchetri@kockw.com), Peter Cameron (KOC), John Isby (BP), Abid Bhullar (BP) and Tony Barwise (BP)

Geochemical evaluation of produced oils and core extracts from the Mauddud Formation reservoirs in North Kuwait were carried out to evaluate the possibility of compartmentalization and predict oil quality in flank positions. GC, GC-MS, and Iatroscan analysis was performed on produced oils. Iatroscan analysis was then carried out on nearly 1,000 core extracts. Additional GC analysis was then performed on select core extracts. The geochemical data was then integrated with the 3-D reservoir models, to develop an interpretation of the geochemical character of these reservoirs. GC and GC-MS data show that both Raudhatain and Sabiriyah oils are derived from the same source. Raudhatain is more thermally mature than Sabiriyah. Varying degrees of biodegradation is observed in both oils and core extracts from both fields. Iatroscan has proved to be a valuable, yet inexpensive geochemical evaluation technique. Biodegraded oil is found in less permeable intervals of the reservoir. The correlation of low permeability to more altered oils explains the PVT oil profiles observed in these fields. In Raudhatain field, the heavier oil leg tested in the flanks of the reservoir can be related to reduced reservoir quality in these positions. In Sabiriyah field, GOR differences of oils tested in flank wells can be related to better reservoir quality throughout the Mauddud interval in these wells. A simple ‘fill and spill’ migration history is proposed for these North Kuwait reservoirs. As the reservoirs filled, early oil became biodegraded and reduced the effective permeability of the lesser quality reservoir layers. More mature oil topped-up the reservoirs by migrating through the more permeable layers. Oil quality maps can be produced for these reservoirs by following porosity and permeability maps in existence.

(388-Oral) Log responses, anhydrite detection and reservoir property implications in the anhydritic carbonate of the Khuff Formation

Clerke, Edward A. (Saudi Aramco - edward.clerke@aram co.com)

The Permian Khuff Formation is a varying lithology, low porosity gas reservoir in Saudi Arabia and is a gas and oil reservoir in other areas of the Gulf. Lithological complexities, regionally and locally include: (1) reservoir can be either limestone and/or dolomite; (2) anhydrite in all of its modes (bedded and coalesced nodular, nodular, pore filling and matrix replacement) is present in both the limestone and the dolomite, often in significant volumes, as well as beds of various thicknesses (2 to 35 ft thick) of 100 percent anhydrite, extending over large areas. A visual estimate of anhydrite content may be misleading as some of the anhydrite may be microscopically disseminated. The varying lithology of the Khuff Formation has been addressed by performing slab-veneer-homogenize-powder X-ray diffraction mineralogic studies of 600 ft of core from two wells in the Ghawar area. The goal of our bulk mineralogy study is to quantify the Khuff Formation minerals for improved reservoir modeling and log calibration. Anhydrite volumes are especially important for the modification of reservoir quality by cementation on the depositional rock fabrics and for the significant effect on the log analytical determination of porosity. Certain combinations of well logs and borehole drilling mud can be used to overcome the log analytical problems. In particular, the ECS (Elemental Capture Spectroscopy) well log yields excellent determinations of anhydrite as compared to the veneer XRD data. When a reliable indicator of anhydrite volume is available, improved diagenetic models of the reservoir can be constructed and more complete petrophysical interpretations are enabled. One of these, the Anhydrite Boost, computes the reservoir carbonate porosity rather than the total formation porosity. This approach grounds the comparison of reservoir quality in rocks with the same amount of porosity but with different amounts of anhydrite; since the porosity is a property of the carbonate and not the anhydrite cement.

(389-Oral) Beyond porosity-permeability relationships: determining pore network parameters for the Ghawar Arab-D using the Thomeer method

Clerke, Edward A. (Saudi Aramco - edward.clerke@aram co.com)

J.H.M. Thomeer of Shell Oil Company developed a powerful method for the analysis of mercury injection capillary pressure data and published this method in 1960. This procedure has been used extensively by Shell for the last 40 years but has not been used widely outside of Shell, except by a few Shell-trained practitioners. At Saudi Aramco, the Thomeer method has been used to analyze the mercury injection capillary pressure data (MICP) from 125 samples from the Arab-D reservoir at Ghawar that are part of the Hagerty-Cantrell Data Set. Two complete passes of analysis have been completed on the data using the Thomeer analysis procedure. Of 125 samples, 43 are monomodal, 78 are bimodal and 4 are trimodal. The quality of the analysis is evaluated by generating a Thomeer Permeability using the Thomeer fitting parameters and comparing it to the actual measured sample permeability. The results are quite good over a wide range from 0.1 to 2,000 mD, consistent with the result that Thomeer found for a similar comparison performed on the Shell Rock Catalog data set of 279 rock types; an uncertainty of a multiplicative - 1.8x. This method offers significant advantages over Leverett J function and FZI methods. Key advantages for the Ghawar Arab-D reservoir are the direct handling of micro-porosity using the superposition of Thomeer hyperbolae and the use of the measured and Thomeer empirical permeabilities as a consistency check. Finally, permeabilities computed using the empirical Thomeer equation compare exceedingly well with the measured permeabilities in the Ghawar Arab-D over the wide range from 0.1 to 2,000 mD.

(353-Poster) Use of model based K-L filtering to attenuate interbed multiples in seismic reflections of the Devonian Jauf reservoir, Eastern Saudi Arabia

Cook, Douglas J. (Saudi Aramco - douglas.cook@aramco.com) and Ching Chang J. Tsai (Saudi Aramco)

The use of K-L filtering has been successfully used to attenuate interbed multiples interfering with seismic mapping of the Devonian Jauf reservoir to help expand the success of Saudi Aramco’s gas exploration. Velocity discrimination to stack-out multiples does not work satisfactorily. Since there is often an angular discordance of the Paleozoic interval with the interbed multiples, approaches were sought to attenuate the multiples by dip-discrimination. Model-based K-L filtering was applied to find a method of dip-discrimination that did not smear the desired primary reflections below the ‘Hercynian’ unconformity reference horizon. The process uses the interpreted reference horizon to flatten the seismic data and operate only below that horizon. The process transforms the data into various principle components, each representing a different portion of the data. The largest principle component represents the most similar energy such as flat events, whereas the smallest principle component the least similar energy such as random noise. When the multiples are flat and the primaries dipping, the K-L reconstruction process using principle components, can recover the primary reflections without the presence of the interbed multiples. The same reconstruction can also exclude the principle components representing noise in the data. Thus, the final reconstructed data have a better signal-to-noise ratio. Model-based K-L filtering does improve the imaging of primary events in the Paleozoic section in the exploration target areas. It has increased the confidence of directly mapping the truncation of the Jauf reservoir using seismic data. The method successfully attenuates interbed multiples only when there is dip discordance between the multiples and the primary reflection events of interest.

(474-Oral) Near-surface challenges keynote: static corrections in the 21st Century

Cox, Mike (Geophysical Consultant - mike@geocobb.dirc on.co.uk)

Static corrections are routinely applied to almost all surveys. Their main emphasis has been the computation and application of datum and residual static corrections on land and transition zone surveys, and simple corrections on marine surveys. Model data, incorporating a wide weathering trough, are used to demonstrate the current approach and show the impact on structural and isopach times. In this analysis, the issue of cross-domain leakage in residual static corrections is discussed. Raypath analyses demonstrate that vertical raypaths assumed by static corrections are incorrect, as near-surface layer raypaths are rarely vertical, although vertical travel is a good approximation in many areas. The relationship of static corrections to other data processing techniques also needs to be considered. We should compensate for near-surface features and elevation differences with corrections that take nonvertical near-surface raypaths into account; that is, dynamic corrections should be applied so that the time shifts are functions of reflector depth and source-to-receiver offset. Various techniques have been proposed, such as wave-equation datuming and pre-stack depth migration. However, as with datum static corrections, these techniques require an accurate near-surface model. Many techniques used in geophysical data analysis are based on approximations, but generally constitute a practical or pragmatic approach to solve specific problems; this is certainly the case for static corrections which, in spite of their shortcomings, have served the industry extremely well. Is it now time to phase out their usage for certain types of near-surface conditions so that their application is consistent with the wave equation?

(447-Oral) High-fidelity vibroseis for subtle stratigraphic feature detection

Crisi, Peter A. (Saudi Aramco - peter.crisi@aramco.com) and John L. German (Saudi Aramco)

High-Fidelity Vibroseis (HFVS) is a technique designed to optimize vibroseis imaging. It has been used by Saudi Aramco on a test line over an older vintage 2-D seismic line at Abu Markhah/Nuayyim fields. The objective of the test line was to improve the imaging of subtle stratigraphic features in the Unayzah reservoir and to address the observed changes in wavelet character between the three wells on the line. In the test, the same 2-D line was acquired three times. First, it was acquired with conventional 2-D acquisition parameters, including five vibrators sweeping six sweeps on each VP with conventional source arrays. Next, it was acquired in HFVS mode with point sources sweeping five times on each VP, vibrators spaced cross-line. The third acquisition scheme was in HFVS mode with point sources sweeping six sweeps each VP, and vibrators spaced in-line. Production rates were comparable with the three techniques. This study will examine the relative strengths and weaknesses of each technique from processed results. The HFVS technique involves inversion of the sweep to minimum phase, using one accelerometer on the baseplate and one on the reaction mass of the vibrator. Harmonic distortion, phase errors, and surface transmission variations are handled more accurately than with conventional acquisition, resulting in improved wavelet processing. This HFVS dataset showed improved wavelet stability relative to the conventional datasets. Stacked data results show improved stratigraphic imaging on the cross-line HFVS dataset. This dataset also showed a channel feature in the Unayzah reservoir section that was not imaged on the conventional dataset. HFVS was successful on this dataset in the imaging of subtle, low-impedance stratigraphic features.

(426-Oral) Permanent seismic sensors in monitoring Arab-D reservoir: case study in Ghawar field, Saudi Arabia

Dasgupta, Shiv N. (Saudi Aramco - dasgupsn@aramco.com.sa)

The Ghawar field in eastern Saudi Arabia produces oil from the Jurassic Arab-D reservoir. The northern Ghawar sector has been under production for over 50 years. Reservoir pressure is maintained by peripheral water injection in the aquifer, which is the primary driving mechanism for oil production. As the Arab-D reservoir becomes progressively mature, early water encroachment, anomalous production, faults and fractures create production problems. In order to monitor such irregularities in fluid movement and increase oil recovery, installation of permanent downhole multi-component seismic sensors has been proposed. The recorded data could be used to update reservoir models, make predictions and optimize production by providing consistent time-lapse images of fluid movement, sweep efficiency, by-passed hydrocarbons and other phenomena. Permanent seismic sensors can also detect microseisms caused by the changing stress state of the reservoir during production and injection. Micro-seismic events in the reservoir can delineate fluid-flow paths and define conductive fracture geometry at interwell scale. The key factors that dictate time-lapse seismic application for reservoir monitoring are sensitivity and repeatability. If the sensitivity of seismic time lapse attribute is low, the repeatability issue becomes important. A feasibility study was conducted recently for time lapse seismic monitoring using permanent downhole sensors. Synthetic time lapse seismograms were computed from reservoir flow simulation model and rock physics data from wells. Comprehensive analyses of different, possible, seismic monitoring methods, including both active and passive measurements for micro-seismicity were performed over the Uthmaniyah sector, a mature area in Ghawar field. Well log and core analysis data were used to build the rock physics and petrophysical models that relate reservoir properties (porosity, lithology, fluid saturation) to the elastic rock properties that impact the seismic response (bulk modulus, shear modulus, density). This provided elastic properties in each cell of the dynamic model. For time-lapse steps of the dynamic simulation model, a corresponding elastic model and its seismic response for each cell were computed. Changes in seismic response produced the synthetic time-lapse seismic attribute data that would quantitatively relate to changes in fluid saturation. Results of the study provided the most practical approach for seismic monitoring and design specifications in a field trial.

(482-Oral) Effect of basement tectonics on hydrocarbon prospective in Zagros, Iran

Davoodi, Zeinab (Tarbiat Modarres U - zdavodi@yahoo.com) and Ali Yassaghi (Tarbiat Modaress U)

The studied area is located in the northwest Zagros Fold-Thrust Belt (Dezful Embayment). This structurally complex region was affected by subsurface tectonic lineaments possibly during the late Alpine Orogeny. A detailed assessment of Landsat images, together with geomagnetic and earthquake data, resulted in the identification of subsurface transverse faults. Three sets of faults were identified using the curved geometry of foreland folds and newly developed folds. The first is a right-lateral strike-slip set of faults oriented NW-SE. The second is a less-developed, left-lateral strike-slip set of faults that is oriented NE-SW. The third set is oriented nearly N-S but is less obvious on Landsat images than the other two sets; however it can be clearly detected using geomagnetic data. There are similarities between the orientation of these lineaments and the geomagnetic lineaments, and with previously identified basement faults in the northern margin of Arabian Platform. This data, together with the depth of earthquakes related to reactivation of these lineaments, implicitly reveals that they are deep-seated basement faults. Major oil fields within the Zagros Belt occur as structures within the NW-trending folds within the Tertiary sediments. However, in the Arabian Platform oil fields are in NS-trending anticlines within the Middle Jurassic-Cretaceous sediments. The Arabian anticlines have been attributed to movement along basement faults before the Zagros Collisional Orogeny. This suggests that older oil-bearing anticlines have been overprinted by the younger NW-trending Zagros structures. Therefore it is proposed that the older NS-trending anticlines can also be exploration targets in the Zagros Fold-Thrust Belt.

(19-Oral) Cyclostratigraphic correlation application on the Arabian Plate

de Coo, Jan (Shell - j.decoo@shell.com), Cees van Oosterhout (Shell) and Maarten Wiemer (Shell)

Cyclostratigraphy studies the influence of periodic climatic changes on the stratigraphic record, which is thought to be determined by earth orbital forces with a periodicity between 20,000 to half a million years. The challenge is to extract the cyclostratigraphic signal from the complex stratigraphic records, to arrive at a sound chronostratigraphic correlation. A tool to study cyclostratigraphy is the PC-based application CycloLog (ENRES), which enables the mathematical manipulation of wireline logs to recognize and enhance cyclic bedding amplitude and frequency. A pilot project across a Permo-Triassic evaporitic carbonate sequence in a number of wells from the Arabian Plate, showed that analysis of spectral attributes with the help of an integrated predictive error filter (INPEFA) provides a means of detailed correlation. Inflection points on the spectral attribute curve indicate correlatable geological events related to facies changes and/or basin dynamics. Maximum entropy spectral analysis (MESA) suggested that the dominant observed wavelength is associated with a cyclicity frequency coinciding with a period of 37,000 years, which may correspond with the obliquity periodicity in Triassic times. The interpreted dominant periodicity was used to convert depth logs to geologic time. Subsequently, with the help of a trapezoidal band pass filter a synthetic insolation curve in geologic time could be derived. Results showed that CycloLog provides additional tools to improve correlation between wells both on reservoir and regional geological scales. The results with respect to climatic patterns and cyclic sedimentary sequences however, must be considered speculative, particularly in the absence of detailed chronostratigraphic control.

(117-Oral) From pretty wall paper to value adding image technology

de Lestrange, Vianney (PDO - vianney.mr.delestrange@p do.co.om), Peter Engbers (PDO), Rashid Al-Hinai (PDO), Tobias Wever (GAFAG) and Ulrich Steiner (GAFAG)

Remote Sensing data has been in use for many years as a backdrop for maps and for general planning purposes. The limited wider application (i.e. “to get more out of remote sensing data”) was recognized and addressed through technological initiatives such as InSAR (reasonably accurate Digital Elevation Model information and subsidence measurements) and Hyperspectral. However, the aim is to maximize the value of current sensors by integrating them with other available information. Recognizing this potential, PDO has joined the SAR-View project, an industry project between GAFAG, a company for applied remote sensing services based in Munich Germany, and the European Space Agency (ESA). The purpose of the project was to develop customized data products based on SAR/multi-spectral earth observation data for the oil and gas industry. The end result consists of two products: near-surface and uplift probability mapping. Near-surface mapping is useful as Oman’s oil concession areas mainly consist of flat gravel plain with braided wadis that are filled with loose sand and gravel, and areas of sand dunes. Such near-surface geology with diverse ground types, disparity in surface ruggedness and stiffness, or any other subtle surface/near-surface alteration, can strongly affect seismic data quality. Integrating interpreted remote-sensing data as a ‘false’ horizon into a seismic trace interpretation system clearly demonstrated good correlation between seismic data quality and changes in the surface topography. Further work will be required to establish the actual impact of surface changes on the seismic quality. Uplift probability mapping is designed as a hydrocarbon exploration tool for the detection of uplift structures in the subsurface. It considers geomorphology combined with geological, stratigraphical information and the tectonic settings. The uplift probability map over a pilot area in Oman was validated against interpreted structures from 3-D seismic data. With good correlation between uplift mapping and subsurface structures, it was decided to apply this inexpensive technology to the whole of the PDO concession area (113,500 sq km). Progress made so far clearly indicates that the integration of Remote Sensing information delivers more than pretty wall paper, and can provide value adding information at all stages of seismic acquisition, processing and interpretation, particular in arid countries like Oman.

(171-Poster) Organic geochemistry of oils and condensates associated to sour gas in Gulf

Dessort, Daniel (Total - daniel.dessort@total.com), Francois Montel (Total), Gerard Caillet (Total) and Marc Lescanne (Total)

Hydrogen sulphide and carbon dioxide in reservoirs can be generated by different ways: (1) thermal decomposition of IS or IIS sulphur-rich kerogens at low maturity; (2) oil biodegradation in reservoirs by sulphate reducing bacteria (SRB); (3) thermal decomposition of sulphur-rich oils; and (4) abiological thermochemical sulphate reduction (TSR). Sour gas, and especially hydrogen sulphide concentration in the Gulf varies widely. It is thought that most of the hydrogen sulphide concentration greater than 5 percent was produced by TSR occurring from about 100 degrees C. In petroleum reservoirs, SRB activity appears negligible up to 80 degrees C and is known to produce less hydrogen sulphide than TSR. As the by-products of TSR and SRB are similar, gas analysis alone cannot easily discriminate which process was responsible for the production of sour gas when its relative concentration is low. For these reasons, it is important to study at the same time gas composition and characteristics of associated liquid fractions. Oils and condensates were studied using detailed molecular analysis: (1) the thermal maturity of the liquid fraction was estimated; (2) markers such as thia-adamantanes and mercaptans (formed as by-products of TSR) were measured; and (3) specific biodegradation of light compounds was sought. In addition, analysis of carbon isotope ratios of specific compounds was achieved, TSR and BSR alteration showing different effects on the 13C/12C ratio of specific compounds.

(376-Oral) Automated facies characterization of deep-water fan-channel complexes, western Nile Delta, Egypt

Dight, Michelle (Paradigm - michelled@paradigmgeo.com), Robert M. Bond (Paradigm), Gavin J. Baldwin (Paradigm), David W. Phelps (Apache) and John Bedingfield (Apache)

Over the past 35 years approximately 3.8 BOE have been discovered in the Nile Delta of Egypt, primarily as gas and gas condensate. Between 2000 and 2002, an Apacheled partnership acquired 2,600 sq km of high quality 3-D seismic data in the deep-water portion of Apache’s West Mediterranean Concession in the western Nile Delta. Subsequent drilling resulted in four new field discoveries and one successful appraisal well in the deep-water portion of this concession. Multiple attributes from the seismic survey have been analyzed, classified and calibrated against data from recently drilled wells. The aim of this project was to predict, identify and quantify good quality reservoirs in the Pliocene deep-water, fan-channel complexes. During the analysis, several attribute volumes were generated for the area of interest by applying geometric and post-stack, wave-equation based algorithms. Principle Component Analysis (PCA) was used to gain a better understanding of attribute correlations, data redundancy and noise. This was followed by the application of a number of sophisticated multi-attribute volume classification techniques including Multi-Resolution Graph Clustering (MRGC). MRGC is a dot-pattern recognition method based on non-parametric graph data representation. It works by analyzing the underlying structure of the data to determine the natural data groups within it. Importantly these groups may have very different densities, sizes, shapes, and relative separations. The program automatically determines optimal number of clusters while allowing the geoscientist to control required level of detail. A cross-check was then performed to determine if the seismic data could identify these facies, and the optimal barycentres were used for supervised classification. Application of MRGC and PCA, in conjunction with visualization of the 3-D dataset, resulted in an enhanced understanding of the facies distribution within the deep-water, fan-channel, reservoir complexes. These results will provide useful input into the optimal placement and design of future appraisal and development wells.

(238-Oral) Pre-stack seismic analysis for fracture and rock property prediction over a large Abu Dhabi carbonate field: a feasibility study

Dong, Wenjie (ExxonMobil - wenjie.dong@exxonm obil.com), William Soroka (ADCO), David Y. Wang (ExxonMobil) and James S. Schuelke (ExxonMobil)

The 3-D seismic data acquired recently over a large carbonate field in Abu Dhabi, United Arab Emirates, provide an opportunity for evaluating the feasibility and value of azimuthal AVO (AZAVO) analysis over carbonate reservoirs. In addition to the familiar AVO intercept and gradient attribute volumes, AZAVO analysis produces two azimuthal attribute volumes: azimuthal amplitude variation intensity and the principal direction of this variation. In general, these two azimuthal attributes are related to fracturing intensity and fracture orientation when the data are processed properly. Therefore, an integrated approach for interpreting the four AZAVO attribute volumes can reveal valuable fracture and rock property information for reservoir characterization and potentially reservoir flow simulation. However, in order to gain confidence over the AZAVO results and their range of validity, rigorous azimuthal AZAVO feasibility work must be carried out. In our study, we address AZAVO feasibility for fracture and rock property prediction by detailed examination of the following four fundamental aspects: (1) Seismic acquisition adequacy for AZAVO, source/receiver coupling and directivity, overburden anisotropy effects. (2) Pre-stack seismic data quality, nature of noise, azimuthal integrity of the pre-stack data. (3) Rock physics support for AVO analysis and angle stacks evaluation. (4) Validation/calibration with geological and engineering data and modeling techniques. This study describes the quantitative approaches, analysis methodology, results and recommendations rendered from the study.

(24-Oral) Basin analysis and hydrocarbon potential of the Darag-Lagia Basins, Gulf of Suez, Egypt

Douban, Adel F. (Sipetrol - adouban@sipetrol-eg.com), Ahmed M. Abu Khadra (Cairo U), Mohamed Darwish (Cairo U) and Mounier H. El-Azabi (Cairo U)

This study involved a comprehensive review of the hydrocarbon habitat of the Gulf of Suez rift basin, and a prediction of its remaining hydrocarbon potential. The present hydrocarbon occurrences in the northern part of the Gulf of Suez are compared to the assessed potential reserves to highlight areas for future exploration activities. The study consisted of a basin analysis and an evaluation of the petroleum system (e.g. reservoir quality, source rock distribution, geothermal gradient, maturation history). The study also reviewed: (1) reservoir lithology, distribution, quality and porosity; (2) source rock distribution, organic richness, type and maturity; (3) geothermal gradient maps, burial/maturation history models; (4) sealing rock; and (5) timing of hydrocarbon generation, migration pathways and entrapment style. The study area was subdivided according to the interpreted hydrocarbon migration trends into two major clusters. The northern cluster includes the Darag and Nebwi basins that generally dip to the southwest. The southern cluster includes the Lagia Basin that generally dips to the northeast. The proven recoverable reserves in Sudr, Matarma, Asl and North Darag fields cumulatively are 0.119 BOEB; while the ultimate recoverable reserves in Darag and Nebwi basins are 1.204 BOEB, which is ten times greater than the proven reserves. The ultimate recoverable reserves in Lagia Basin are 1.479 BOEB. Structural or stratigraphic traps, which exist along the migration path should be expected full to the spill point and might be considered for future exploration. Five prospective areas have been identified over the northern Gulf of Suez area, which are: Area I: North Darag, Area II – South Darag, Area III – Nebwi, Area IV – Ras Lagia and Zaafarana and Area V – West Lagia.

(83-Oral) Sequence stratigraphic framework of the Aptian Shu’aiba Formation in Oman

Droste, Henk H.J. (JVR Centre for Carbonate Studies - henk.droste@shell.com)

The Shu’aiba Formation consists of Aptian platform interior carbonates and is an important oil reservoir in Oman. A sequence stratigraphic framework was constructed to assess regional controls on reservoir development. Two third-order sequences can be regionally correlated. The lower sequence starts with a transgressive systems tract (TST) of laterally extensive very shallow marine to intertidal sediments, followed by shallow marine algal limestones transgressing over exposed limestones of the Kharaib Formation. During the late TST the development of algal mound complexes led to a differentiation on the platform. Between these mounds fine-grained, in places organic-rich deeper-water sediments were deposited related to a maximum flooding surface (MFS). During the early highstand systems tract (HST) rudist biostrome complexes colonized the mounds. In the late HST the rudistic growth decreased, distal ramp sediments filled in intermound depressions, and the mounds merged into a platform surrounding an intraplatform basin. A regional drop in sea level associated with subaerial exposure and influx of fine-grained clastics terminated deposition on the platform. The early lowstand systems tract (LST) contains offlapping wedges of argillaceous carbonates and carbonate-rich claystones along the margins of the intraplatform basin. Ultimately, the whole platform interior was exposed and a late LST wedge was deposited along the ocean margin of the platform. The basal clays of the Nahr Umr Formation form the TST overlain by an MFS formed by the Marker Limestone Bed. The sequence stratigraphic framework can be used as a template which: (1) Explains the regional variation in reservoir/flow properties. (2) Allows grouping of fields according to stratigraphic setting for comparison and analogs in reservoir studies. Incorporation of seismic data allowed significant refinement and improvement of the previous sequence stratigraphic models, which were based on well data only.

(85-Poster) Regional controls on reservoir properties in the Shu’aiba Formation of North Oman

Droste, Henk H.J. (JVR Centre for Carbonate Studies - henk.droste@shell.com)

The construction of a regional sequence stratigraphic framework significantly improved the understanding of regional variations in reservoir properties and geometries of the Aptian Shu’aiba carbonates in Oman. A distinct relationship between systems tracts and reservoir facies and architecture has been recognized which is related to: (1) changes in stacking patterns in response to variations in available accommodation space; (2) the response of the carbonate factory to variations in the influx of clays and nutrient content of the water; and (3) duration of exposure at the sequence boundary. Within the Shu’aiba Formation a Transgressive (TST), Highstand (HST) and early Lowstand (LST) Systems Tract has been recognized. Reservoirs within the early TST are laterally extensive but hardgrounds and condensed intervals form horizontal baffles significantly reducing vertical permeabilities. The reservoirs did not experience significant early fresh-water leaching but transgressive lags may form high permeability streaks. The early HST reservoirs consist of rudist biostrome mounds with a highly complex internal architecture. They show strong variations in permeability related to progradational geometries, channeling and impact of early fresh water diagenesis on the rock fabric. The late HST reservoirs show a more simple reservoir architecture with a gradual shallowing-upward trend towards higher energy better reservoir facies. Low angle clinoforms, however, may affect the lateral connectivity. The gradual vertical change in reservoir properties also results in long transition zones. Reservoirs in the early LST consist of porous pelletoidal pack/grainstone wedges with a strong impact of early fresh water diagenesis on rock fabric. Interbedded clays and hardgrounds related to flooded exposure surfaces however significantly reduce vertical permeabilities. Horizontal permeability may be affected by progradational geometries. Wedges and pinch-outs are common and there is a high potential for stratigraphic trapping.

(62-Oral) Sequence stratigraphy of the First Eocene Reservoir, Wafra field, PNZ, Kuwait and Saudi Arabia

Dull, Dennis W. (ChevronTexaco - dennisdull@chevrontex aco.com) and William S. Meddaugh (ChevronTexaco)

Located in the Partitioned Neutral Zone (PNZ) between Saudi Arabia and Kuwait, the First Eocene Reservoir is the youngest of five producing intervals that range in age from Eocene/Paleocene to Lower Cretaceous at Wafra field. The First Eocene dolostones were deposited in arid to semi-arid conditions on a shallow, low to moderate energy inner shelf or ramp setting. The presence of evaporites suggests restriction was sufficient for the development of hyper-saline lagoons and sabkhas. The sequence stratigraphic interpretation of the First Eocene Reservoir is based on five recently cored wells. These wells have numerous hardgrounds that increase in frequency to the north. Intraclastic rudstones occasionally overlay the hardgrounds and subaerial exposure surfaces. In some cases brecciation is observed beneath the hardgrounds indicating intermittent sub-aerial exposure and incipient soil formation. The shallowing-upward cycles are capped by mud-dominated rocks, hardgrounds and exposure surfaces that are correlative with gamma ray (GR) highs that help define the cycle tops on well logs. Many of the cycle tops and associated GR highs can be correlated across the entire length of the Wafra field (approximately 20 km). The ability to correlate the fine-scale GR pattern and correlative cycles likely indicates that the First Eocene Reservoir was deposited in an aggradational-progradational portion of a tectonically stable shelf where subsidence kept pace with carbonate deposition. The First Eocene reservoir has been subdivided into ten interpreted high-frequency sequences (HFS) bound by hardgrounds, subaerial exposure surfaces, or lithofacies tract offset. Placement of the ten observed HFS into the regional sequence stratigraphic framework is on-going.

(481-Oral) Enhanced signal-to-noise ratio and bandwidth through explosives design

Egan, Mark S. (WesternGeco - mark.egan@westerngeco. com), Glen-Allan Tite (WesternGeco), Patrick Thompson (WesternGeco) and Jim Brookes (Schlumberger)

The signal-to-noise ratio and bandwidth of explosive-sourced seismic data are the direct results of the properties of the explosives used and the near-surface conditions. Some of the current properties of seismic explosives may not be the most desirable. Multi-variant testing has confirmed that in many environments, the efficacy of seismic explosives can be improved. These tests indicate that the design of the explosive utilized is critical to the ultimate quality of the seismic data, and that data quality can be improved through customized explosives. Current data suggest that 3 to 6 dB of signal enhancement may be achieved in the seismic bandwidth through the use of metalized explosives. Examples of these improvements will be presented in this study.

(253-Oral) Strontium-isotope dating of the Asmari Formation (Oligocene-Miocene) in Ahwaz, Bibi Hakimeh and Marun oil fields, southwestern Iran

Ehrenberg, Stephen N. (Statoil - sne@statoil.com), John M. McArthur (UC London), Matthew F. Thirlwall (Royal Holloway, U London), Neil A.H. Pickard (CCL) and Gitte V. Laursen (Statoil)

The strontium-isotope method of dating minerals precipitated from sea water has been applied to core samples from the Asmari Formation using micro-analyses of mollusk shells and lime mud matrix. The Asmari Formation consists of about 400 m of cyclic platform limestone, dolostone, sandstone, and shale. Due to the rapid and steady rate of change of the global Sr-isotope curve during Asmari time (31-18 Ma = Rupelian-Burdigalian), and the presence of well-preserved shell and matrix material, the Sr method is ideally suited for dating Asmari stratigraphy. Age-depth profiles in Ahwaz, Bibi Hakimeh, and Marun oilfields show that a distinct decrease in sediment accumulation rate occurred abruptly at around 24.5-24.0 Ma (near the Oligocene/Miocene boundary). Accumulation rate decreased from 41-93 meters/million years (m/my) in Oligocene time to 14-28 m/my in early Miocene time. Major depositional sequences defined from facies relations and cycle-thickness patterns have durations of 1.1-2.6 my, whereas depositional cycles represent average time intervals of 100-300 thousand years. The Sr-age profiles allow correlation of sequence boundaries between the fields, supporting a pattern of progradation and basin infilling from Bibi Hakimeh field toward the northwest. Sr analyses of most anhydrite and dolomite samples plot close to or below (at slightly younger ages than) the macrofossil age-depth trend, indicating formation from seawater, either on the seafloor or by shallow (up to several tens of meters depth) reflux of hypersaline brine. An exception to this is anhydrite of the base-Gachsaran cap-rock and dolomites in the top 25 m of the Asmari Formation, where Sr ages older than the macrofossil age-depth trend may indicate contribution of Sr from older evaporite beds, possibly recycled from the basin margins.

(429-Poster) Geological aspects of the 3-D geocellular model of Thamama reservoir in an offshore field, Abu Dhabi

Elsaid, Mohamed Elhami (ADMA-OPCO - mselsaid@adma.co.ae), Faisal Al-Ginaibi (ADMA-OPCO) and Adel Belgaid (ADMA-OPCO)

A Lower Cretaceous carbonate reservoir in an Abu Dhabi offshore field was characterized with a 3-D-geocellular model. A total of 7,241 ft of core and thin sections were described in detail and tied to the petrophysical log data. Based on detailed semi-quantitative thin section and core description, Mercury injection and petrophysical parameters, a rock-typing scheme composed of 11 rock types was identified and validated. Depositional and diagenetic models were also generated to provide a predictive tool for reservoir quality and its distribution. The depositional model represents a shallow-water carbonate platform with a set of facies that characterize each tract. The diagenetic model comprised surface, subtidal, shallow, and deep burial diagenetic events, such as micritization, fringing calcite marine cement, vadose grain leaching, compaction, stylolitization, dolomitization, anhydrite cementation and fracturing. A sequence stratigraphic framework was implemented based on core and log data. The reservoir model is that of a distally steepened carbonate ramp characterized by thick regressive events or highstand systems tracts (HST), and thin transgressive systems tracts (TST). It is composed of three stacked highresolution sequences, which were further subdivided into 43 high-order depositional cycles, that constitute the basis of the layering model. These eustatic cycles represent the scale at which changes in petrophysical properties occur. The quality of the geological model: (1) has a direct impact on reserves estimates; (2) helps to improve the reservoir development scheme; and (3) affects reservoir management and well placement.

(230-Oral) New approach to analysis behind casing using cased hole resistivity, geochemical, and epithermal neutron logging

Elsherif, Ahmed (Schlumberger - asherif@kuwait.oilfield.s lb.com), Mohammed Al-Haimer (KOC-JO) and Waleed Al-Awadi (KOC)

Evaluation behind casing was achieved several years ago using thermal neutron decay time measurements. Recently, several breakthrough technologies have improved and expanded the ability to see behind the pipe. Cased hole resistivity, geochemical logging, cased hole density and epithermal neutron logging are the main tools used for these evaluations. In this study, we illustrate several examples in which these technologies were used for successful evaluations. The first example covers a well that was logged in open-hole conditions, and then relogged after casing was set. A comparison of the results confirmed the accuracy of formation evaluation behind casing. The geochemical results were used in combination with the epithermal neutron data to predict a density measurement behind casing. The second example illustrates the case of a well that could not be logged in open-hole conditions because of bad hole conditions. Results of the cased hole evaluation gave the client the essential answer to complete the well successfully. The third example covers an old well that was analyzed using the cased hole resistivity and the thermal neutron decay time technique. The comparison with the very old resistivity log on the well was rather interesting since it showed more oil at present which could have migrated. The evaluations described in the study represent the first use of this technology in Kuwait. Wells were operated either by KOC, or Joint Operations, which covers the neutral zone between Saudi and Kuwait.

(231-Oral) Different applications of the geochemical logging over sandstone and carbonate reservoirs in Kuwait

Elsherif, Ahmed (Schlumberger - asherif@kuwait.oilfield.slb.com), Mariam Al-Saeed (KOC), Shaikh Abdul Azim (KOC), Osama Elgendi (KOC-JO) and Ahmed Abdullatif (KOC)

During the last years, geochemical logging has increased dramatically in Kuwait. Several applications have been introduced for both sandstone and carbonate reservoirs. For sandstone reservoirs, the true shale volume is critical for proper reservoir characterization. The presence of ‘hot sands’ makes it difficult to correctly determine the shale volume, because the gamma ray measurement is not a good shale indicator. In these sands, geochemical logging plays an importnat role in evaluating the true shale volume from the aluminum concentration in the formation. Another application is the use of the computed grain density of the formation to calculate the total formation porosity from the bulk density. Historically, a constant value of grain density was used for that purpose. As a result of impurities in the sandstone such as siderite and pyrite, the matrix density is no longer a constant value across different layers of the reservoir. Using the computed grain density from geochemical logging, the total formation porosity was recalculated with a better accuracy. This technique resulted in an increase of the total porosity. One last application is mainly used for carbonate reservoirs with a small percentage of anhydrite. Quantifying the right percentage of anhydrite was one of the requirements of the oil company. That was easily achieved from the sulfur yield of geochemical logging. This technique is not suitable when the oil in the reservoir has a large percentage of hydrogen sulfide; in this case the tool will measure the sulfur from both the oil and anhydrite, giving an incorrect answer.

(266-Oral) Oil viscosity measurement on continuous basis using magnetic resonance: a new approach from Kuwait

Elsherif, Ahmed (Schlumberger - asherif@kuwait.oilfield.s lb.com), Mariam Al-Saeed (KOC) and Mona Al-Rushaid (KOC)

Measuring the oil viscosity during open-hole logging was one of the main requirements of KOC. This requirement was triggered by the presence of different oils across the same reservoir or by the local variation of oil viscosity versus depth. The technique used to accomplish that requirement was based on NMR logging. It is well-known that different hydrocarbons will diffuse with different amplitudes based on their viscosity at down-hole conditions. The idea used in this study was based on acquiring two different passes of NMR logging with two different values of echo spacing. When the logarithmic mean of the two pore size distributions are displayed linearly, they will coincide or separate depending on the hydrocarbon viscosity present in the formation. The more separation between the two logarithmic mean times, the less viscosity the oil is. Furthermore, the results were confirmed using another technique of stationary measurement acquisition using different wait times and echo spacing on selected points in the reservoir. A new technique of processing was also used to process the results of the stationary measurement based on the relation between the amount of diffusion and the transverse relaxation time. The different fluid saturations along with hydrocarbon viscosity determination, were achieved from the stationary measurements. The above technique was used in different reservoirs from Kuwait with good results.

(260-Oral) Sequence stratigraphy, reservoir layering and palaeogeography of the Wara Sandstone Formation, Khafji field

Emerson, Paul F. (Scott Pickfordp.emerson@scopic.com), Keiichi Miyazawa (Al-Khafji JO), Kenji Kaneko (Al-Khafji JO) and Mousa Ali (Al-Khafji JO)

The Cretaceous-aged (Albian) Wara Sandstone Formation forms one of the less well known reservoirs of the Khafji field in the offshore Partitioned Neutral Zone between Kuwait and Saudi Arabia. A recent study to achieve a better understanding of the reservoir layering zonation within a sequence stratigraphic framework recognized a cyclical pattern of deposition. The pattern consists of a series of prograding deltaic/estuarine units: Zones 2B, 3B and 4B (broadly highstand system tracts) that are vertically separated from one another by estuarine/marine mudstones: Zones 2A, 3A and 4A (broadly transgressive systems tracts). These overlie Zone 2V (lowstand system tract), an economically-important incised-valley filled with fluvial and later marginal-marine tidal sands. Early deposition appears to be controlled by structural elements, which principally created a topographic high to the south of the main valley fill. The channel system drained in an ENE direction, which was maintained during a subsequent highstand tract (Zone 2B). During this period a broadly tidal deltaic/estuarine depositional setting was developed in the Khafji area, with more fully-marine settings postulated to the east and northeast. Channel systems were generally low-energy and were laterally equivalent to mud-prone marsh, interdistributary bay, tidal flat and localized shoreface environments. A later rejuvenation of the fluvial/tidal system, during the deposition of Zones 3B and 4B, appears to reflect a slight adjustment of the palaeoflow to a more northeasterly direction, perhaps indicating that the early topographic high to the south had broadly ceased to control the channel systems.

(112-Oral) The poor seismic data quality challenge: new techniques in volume interpretation to improve delivery of structural frameworks

Engbers, Peter (PDO - peter.engbers@pdo.co.om), Jack Filbrandt (PDO), Andrew Growcott (PDO), Martin Roberts (PDO) and Awfa Al-Amri (PDO)

Seismic interpretation is challenging in Oman due to overburden complexity, structure, and reservoir geology. Many areas, particularly in South Oman, have poor seismic data quality at reservoir level due to multiples, and noise, which impart a chaotic seismic image. This makes mapping of top reservoir and faults difficult. Improvements in multiple elimination techniques, although successful at removing multiples, also destroy primary energy. As a result other techniques have been developed to tackle the poor seismic data quality challenge. Recently, seismic volume image processing and interpretation has been the focus to improve seismic data quality for production and exploration purposes. In particular the ‘vanGogh’ filter (structurally-oriented noise reduction filter with edge preservation) is used to enhance seismic images, and to highlight structural features (faults and fractures) using so-called ‘stopper-voxels’ based on the edge detection concept. The interactive environment ‘FaultWorld’ has recently been developed to facilitate fault and fracture interpretations through selection of dip/azimuth ranges of automatically extracted structural discontinuities. Using these toolkits, PDO and Shell are developing various volume interpretation workflows to deliver fast track ‘structural frameworks’ i.e. top reservoir interpretation with faults networks. Data conditioning at various levels is key to developing a robust approach for these poor quality seismic data. Improved coherency of reflections is seen as well as improved fault detection. Using ‘FaultWorld’ and new, robust structurally-oriented trackers, a structural framework can then be generated and exported to static reservoir modeling packages in a relatively short time, where these models can be validated with other datasets.

(113-Oral) Intrasalt carbonate stringer volume interpretation in Oman

Engbers, Peter (PDO - peter.engbers@pdo.co.om), Ahmad Zulkifli (PDO), Fahar Rabeei (PDO) and Saada Rawahi (PDO)

The intra-Ara salt carbonate stringers of the Huqf Supergroup are one of the more complex deep oil plays in South Oman and presently constitutes a significant part PDO’s exploration prospect portfolio. Because conventional seismic interpretation is difficult and time-consuming, novel seismic interpretation techniques are being applied to improve current exploration mapping methodology. Seismic volume interpretation is one of these opportunities. We herein highlight this technology and its role in the stringer exploration workflow. The volume interpretation workflow first subsets data on the basis of continuity (not all stringers are identifiable by high amplitudes) and then uses body checking and unravelling on impedance data to find and analyse the stringers. The stringer bodies are automatically ranked by volume (through a voxel-GRV relation). Further in the unravelling process, the stringer bodies are broken into subbodies subject to more restrictive amplitude thresholds. This is effectively an internal connectivity analysis of the stringers using a range of thresholds to identify a range of connectivity scenarios. This method discriminates bodies into meaningful fault and/or stratigraphic compartments, and estimates sizes and shapes of potential production cells. Subsequently, 3-D visualization of the identified stringers is done using semblance and other discontinuity volumes to evaluate faults in order to test various connectivity scenarios. In pilot studies, resulting bodies have compared well with hand-interpreted stringer horizons. It is now envisaged to fasttrack the interpretation of new unmapped datasets using this technique. It is faster, and provides an essential first step in evaluating new data sets prior to detailed mapping.

(393-Oral) Pre-stack migration velocity analysis in the Tau domain

Erickson, Kevin E. (Saudi Aramco - kevin.erickson@aramc o.com), Emad Aljanoubi (Saudi Aramco) and Tariq A. Al-Khalifah (KACST)

Due to the inherent ambiguities involved in performing pre-stack migration velocity analysis in the depth domain, it is often difficult to converge to a proper estimate of the interval velocities. An error in the initial velocity results in migration of events to incorrect depth, which then makes it difficult to estimate the correct velocities in the following iterations. In order to avoid this issue we explore a new algorithm in which the migration and velocity analysis are done in the vertical time, or tau domain, and the conversion to depth is performed at the end of the process once the best estimates of the velocities have been achieved. Even if inaccurate velocities are used to begin the process, or chosen during one of the velocity analysis iterations, the data will migrate to the correct time. A Kirchhoff migration algorithm is employed for its flexibility, efficiency and ability to handle inhomogeneous media. The capability of the method to focus small parts of the data makes it ideal for use in velocity analysis. The algorithm has been modified to operate in the space-tau domain by calculating the traveltimes with kinematic and dynamic ray-tracing equations. In a synthetic model with a strong shallow velocity anomaly, tau migration has reproduced the model in depth after two iterations. For a land field data example, conventional depth migration and velocity model updating did not completely resolve some of the shallow complexities. Velocity updating in the tau domain, however, converged to the desired velocity, with fewer iterations, and produced a reasonable depth section.

(26-Oral) Structural growth control of the Khuff exploration play in eastern Saudi Arabia

Faqira, Mohammad I. (Saudi Aramco - faqirami@aramco.com.sa), Murdy M. Al-Zahrani (Saudi Aramco), James L. Rico (Saudi Aramco), Khalid M. Shokair (Saudi Aramco), Michael A. Zinger (Saudi Aramco). Nezar A. Al-Talhah (Saudi Aramco) and William B. Stone (Saudi Aramco)

Well and seismic data studies document that the Khuff gas play is primarily controlled by several structural growth periods from Carboniferous to Neogene time. The play is sourced by the Silurian Qusaiba hot shale, whose distribution is controlled by ‘Hercynian’ structural growth and is seismically mappable in eastern Saudi Arabia. Khuff A, B, and C reservoir development was controlled by the Permo-Triassic structural growth over Ghawar field and other trends in the area. The syn-depositional growth of these trends during the Khuff time contributed to reservoir development for two reasons: (1) relatively high paleotopography may have developed a high-energy environment, which set the reservoir quality framework of the Khuff reservoir; and (2) higher magnitude growth of these relative highs may have controlled the early dolomitization process and the porosity and permeability enhancement. The structural growth maps of the Khuff Formation suggest that most four-way dip closures in eastern Saudi Arabia developed in the Late Cretaceous and Early Neogene times. During these times the base Qusaiba source rock was generating wet and dry gases. Fluid inclusion results from Ghawar field Khuff reservoirs confirm the timing of the trap development by showing condensate fluids dated between 96 to 106 Ma. The high magnitude of the Late Cretaceous and Neogene growth reactivated some of the ‘Hercynian’ faults that provide an excellent conduit between the Qusaiba source and the Khuff reservoirs in the area.

(89-Oral) Rejuvenating a mature reservoir with 3-D modeling, and horizontal drilling: the SW Fateh, Mishrif case study, Dubai

Faugeras, Xavier (DPC - xavier.faugeras@conocophillips.co m), Jeffrey W. Yeaton (DPC) and Philip J. Rorison (DPC)

The SW Fateh field in offshore Dubai, is located on a salt-induced dome. Production is from three different carbonate reservoirs. This case study shows how a multi-disciplinary team created a step change in the asset’s production profile. The Mishrif reservoir produced under natural depletion from 1972 until 1975, and since then has been under full water injection. Logged contrasts in rock characteristics showed that the water sweep was effective in the better-quality Upper Mishrif reservoir. Logs also indicated that parts of the Lower Mishrif reservoir were unswept and overlain by water; they were ‘over-ride’ areas. A series of horizontal wells drilled since 1996 in ‘over-ride’ areas has made a major contribution to the actual production profile and the expected final recovery. The positioning of the horizontal wells was based on the integration of 3-D seismic, geological model, dynamic reservoir modeling, and a static reservoir model. The presentation describes successes and surprises from the horizontal drilling program and the technology used by the team to manage the reservoir. The current challenge is to reevaluate all static and dynamic reservoir data in order to predict remaining areas of unswept oil. This is not a trivial task after 30 years of production and water-injection by more than 120 wells.

(80-Poster) Discovery of a new play fairway in Yemen: the Late Jurassic Madbi Limestone

Ferguson, Scott (Nexen - scott_ferguson@nexeninc.com), Jonn H. Calvert (Nexen) and John D. Smewing (ERL)

In 2002 a new oil discovery was made by Nexen Petroleum International and partners on Block 14 in Yemen. The discovery was made in the upper Oxfordian-lower Kimmeridgian Madbi Limestone, a stratigraphic interval deposited just prior to, and during, the earliest period of Late Jurassic rifting in this area. This discovery is significant in that it is the first oil produced from this stratigraphic interval in the Say’un Basin of Central Yemen, and has opened up a major new play trend outside of ‘traditional’ Lower Cretaceous reservoirs. The Madbi Limestone records depositional and structural events that spanned the pre-rit to early-rift time frame in the Late Jurassic. The lowermost Madbi sediments (pre-rift) are typically hemipelagic mud-dominated carbonates, deposited in water depths of 100 m or greater. Initial rifting had a major impact on Madbi depositional patterns. In the footwalls of the faults, the Madbi was uplifted to the point where the hemipelagic carbonates were exhumed and eroded, sometimes completely, exposing basement. Rotation of fault blocks in the hanging walls of the faults simultaneously led to vast thicknesses of mixed clastic-carbonate sediments adjacent to the fault and forced regressions on the outer uplifted part of the block. Typical stratigraphic development in these outer margin settings comprises a coarsening-upward succession with hemipelagic carbonates at the base passing up through foraminiferal wackestones and packstones into coarse skeletal grainstones at the top, often succeeded by exposure. The primary Madbi reservoir is developed in these grainstones. Porosity types are primarily intergranular and biomoldic. Repetition of this forced regressive sequence and the stacking of reservoirs is attributed to pulsed movement on the master faults. The primary technical challenge to exploiting this play further is to define the trend of the platform margin facies through geological and seismic means.

(367-Oral) Jurassic to Cretaceous sedimentation and tectonics in Lebanon and Syria

Ferry, Serge (U Lyon - serge.ferry@pop.univ-lyon1.fr), Catherine Homberg (U Paris), Eric Barrier (CNRS), Mustapha Mroueh (Lebanese U), Anis Matar (Lebanese U), Yann Merran (U Lyon), Louaï Machhour (Total), Walid Hamdan (Lebanese U), Fathi Hijazi (Lebanese U) and Rafik Hamzeh (Lebanese U)

On the coastal chains of Lebanon and Syria, regional extensional tectonics in latest Jurassic created roughly EW-oriented grabens that would later host the fluvial Rutbah sandstones in Central Lebanon (Chouf area). Syn-depositional EW to N120E normal faults have been recognized in both the Syrian Coastal Range and Lebanon. They are associated with a N30-oriented, extensional tectonic element controlling the development of the Chouf Basin until the late Albian time. The up to 350-m-thick Barremian Rutbah sandstones in central Lebanon corresponded to a very powerful river with amalgamated large deep channels that constitutes a good potential reservoir in the central part of the basin. Laterally, deposits are more clayey, bearing only unconnected small sandy point bars. The overlying Aptian carbonates (Jezzine Formation) are also thickest in the Chouf area. They pinch out to the east (Anti-Lebanon). A major stratigraphic gap covers the early to middle Albian. The subsequent carbonate system (late Albian to early Turonian) is regularly sloped to the west. It consists of alternating massive or layered platform carbonates, and of planktonic-bearing laminated carbonates; it bears the same number of sequences in Lebanon, Syria and in the Gulf. Coastal sections of Lebanon show spectacular Cenomanian slump scars and large calcarenitic sand waves prograding down-slope within slope carbonates.

(153-Oral) Kinematic interpretation and structural evolution of northern Oman, Block 6, since the Late Cretaceous

Filbrandt, Jacek B. (PDO - jacek.b.filbrandt@pdo.co.om), Salah Dhahab (Shell), Kester Harris (PDO), Abdullah Al-Habsy (PDO), John Keating (PDO), Salim Al-Mahruqi (PDO), Ismael Ozkaya (Baker Hughes), Pascal Richard (PDO) and Tony Robertson (PDO)

The structural characteristics of the northern margin of the Late Cretaceous carbonate platform in Oman differentiate the tectonic evolution of this region from the continental margin now exposed in the Oman Mountains. Imbrication associated with the emplacement of the Semail Ophiolite and NE-oriented telescoping of the Arabian Platform margin culminated in the Campanian. The structural grain contrasts markedly with that of the region immediately to the south, and implies strong strain partitioning. Kinematic indicators from subsurface data, combined with the age of growth faulting, provide the basis for the interpretation that maximum horizontal stress was NW-oriented in this foreland region. The dominant tectonic control on the formation of faults is believed to have been a ‘collision’ of the Arabian Plate with the Indian Subcontinent during the Santonian-Campanian. Deformation was dominated by distributed strike-slip faulting. Late Maastrichtian to Paleocene uplift and erosion, in excess of 500 m, is recorded in the truncation of the Aruma Group and Natih Formation below the base Tertiary unconformity. Velocity and porosity anomalies from Lekhwair in the northwest to the Huqf-Haushi High in the southeast, provide support for the areal distribution of this event. NE-oriented maximum horizontal stress during the late Tertiary led to the formation of major folds resulting in, for example: the surface anticlines over Natih and Fahud fields, as well as inversion of the Maradi Fault Zone. The regional northward tilt associated with crustal loading of the Arabian Plate by the Iranian Plate modified traps during the Plio-Pleistocene from Lekhwair to Fahud and south to Musallim.

(154-Poster) Sequence stratigraphy of the Fiqa Formation and proposed subdivision, North Oman

Filbrandt, Jacek B. (PDO - jacek.b.filbrandt@pdo.co.om), Safia Al-Mazrui (PDO), Peter Osterloff (Shell), Stephen Packer (Millennia), Aida Al-Harthy (PDO) and Uzma Mohiuddin (PDO)

Biostratigraphy, seismic data and field observations have been integrated to develop a model of evolving paleoenvironments in the Coniacian to Campanian foreland basin of the Oman Mountains, southeast of the Suneinah Trough. The depositional sequences of the Fiqa Formation represent part of the Aruma Group, unconformably overlying the platform carbonates of the Wasia Group (Natih Formation). The older units of the Fiqa Formation are informally referred to as the Lower and Upper Shargi members, overlain by the carbonate and/or marl-prone Arada Member. The informal subdivision is based on micropaleontological dating of drill cuttings. Biostratigraphic correlation allows further subdivision of the lower part of the Fiqa Formation. This forms the basis for delineation of deep-water stratigraphic traps, and improved resolution promotes real-time zonal indentification whilst drilling. The Wasia carbonate platform became submerged in the Coniacian. The Shargi depositional system comprised a Santonian to Campanian age deltaic complex and a Campanian turbidite basin fill. The shale-prone Lower Shargi units prograded northward from central Oman during the Santonian. The shelf-slope break was stationary in the early Campanian. Campanian-aged cyclic, turbidite deposits filled the basin east of the Maradi Fault Zone and south of the emplaced nappes. The turbidites onlapped the north-facing delta slope and filled some 400 m of accommodation space. The turbidites are laterally extensive, forming sheet sands, and have moderate to good reservoir properties, derived primarily from exposed Gharif and older sandstones in the emergent Huqf-Haushi High. An ophiolite-derived component increases upwards through the early Campanian as the foreland basin became filled and the Huqf provenance area was transgressed.

(145-Oral) Shu’aiba rudist build-ups and sequence stratigraphy in offshore Qatar

Fischer, Klaus C. (Wintershall - klaus.fischer@wintershall.com), Ismail A. Abdulla (QP), Mamdouh E. Zahran (QP) and Martin Lehmer (Martin-Luther U)

Rudist build-ups within the Aptian Shu’aiba Formation are a prolific reservoir in the southern Gulf. These rudist build-ups were formed along the rim of a shelf interior basin during relative sea-level highstand conditions. The southern limit of this basin is well-defined and comprises major hydrocarbon accumulations, e.g. the Bu Hasa field in Abu Dhabi, the Shaybah field in Saudi Arabia, and several fields in Oman. The northern limit of the basin is less well-defined, there are only few somewhat regional publications. Recent exploration work in offshore Qatar added a new piece of information to the existing view of facies distribution. Primarily based on seismic data, a pronounced Shu’aiba reef build-up was identified. The build-up is part of a discontinuous trend of minor build-ups running more or less in a north-northwest direction. Seismic sequence analysis identified several cycles of eastward progradation and locally vertical aggradation. Following these highstand deposits, a relative fall of sea level resulted in subaerial exposure of the Shu’aiba build-up that generated increased porosity. The Nahr Umr shale/sandstone was deposited above the Shu’aiba Formation. The model was supported by seismic inversion: a distinct decrease of acoustic impedance was observed at the crest of the build-up. Sequence and facies analysis of existing well data supported the model and added more details. The investigations finally allowed for a correlation of sea-level history with other parts of the Shu’aiba basin.

(261-Oral) Salt occurrence in the Gulf region

Folle, Stefan (Schlumberger - folle@hannover.oilfield.slb. com)

The construction of cavities in local salt deposits for the strategic and commercial storage of oil, oil products and gas provides economic benefits in the Gulf countries. This involves, for example, salt production in combination with hydrocarbons for ethylene-dichlorine-plants. This study shows the salt deposits in the Gulf region and focuses on the areas in the vicinity of the marine basin. Beside natural outcrops, some salt deposits have been penetrated by solution mining and conventional mining operations. Other deposits were explored but did not progress into the development phase. Oil and gas exploration has provided additional information on salt occurrences. Iran has the largest evaporite deposits, primarily of infra-Cambrian and Tertiary in age. Jurassic salt deposits are rare. Diapirism is widespread in Iran and lifts the evaporites to extractable depths. The salt deposits of Iraq are primarily characterized by Tertiary bedded salt which lies at relatively shallow depths and extends into Iran. In southern Iraq and Kuwait flat-bedded and relatively deep Jurassic salt occurs in the United Arab Emirates as well as in Oman. Cambrian–infra-Cambrian salt structures are stratified as well as diapiric, some of them at suitable depths.

(372-Oral) A fully-integrated approach for fracture characterization using geological, geophysical and reservoir engineering data in ‘A’ field

Fonta, Olivier (Beicip-Franlab - olivier.fonta@beicip.fr), Maged Al-Deeb (ADCO), Salem El-Abd Salem (ADCO), Loic Godail (Beicip-Franlab) and Gerard Bloch (ADCO)

Fractured reservoir analysis requires: (1) spatial delineation of fractured areas; (2) evaluation of fracture intensity; and (3) determination of the hydraulic properties of the different fracture sets. This study presents a multi-disciplinary integrated approach that includes geology (borehole image logs-≠BHL cores, wireline logs), geophysics (seismic facies analysis), and reservoir engineering data (PLT, Welltest, production data). Field ‘A’ is a giant Upper Cretaceous carbonate reservoir, onshore United Arab Emirates, in which fractures and highly permeable layers play an important role in hydrocarbon production and early-water break-through. The study combined a set of selected ‘fracture-relevant’ attributes in a multi-variable statistical process called Seismic Facies Analysis (SFA). Each seismic facies was mapped and the delineated areas were validated against interpreted well data (BHI, core and dynamic data) to deliver an accurate map of fracture occurrences. The seismic facies map was then used to interpret structural lineaments and to constrain stochastic realizations of the fracture model. The second step consisted of a detailed analysis of dynamic dataset (Welltest, PLT, and production data) with specific innovations used to measure hydraulic fracture properties from Welltest interpretation and from PLT data. Results of the dynamic analysis were combined with the stochastic fracture models to produce full-field reservoir models with fracture properties (porosity, permeability and block sizes), which can be used for single- or dual-media reservoir simulations.

(161-Oral) Approaching vertical permeability issues in fractured fields: an extensive analysis

Foulon, David J. (Total - david.foulon@total.com) and Sylvie Delisle (Total)

Additional world reserves are increasingly due to new developments of current fields. Specific issues arise when applying these sophisticated development schemes to fractured reservoirs. One such issue, improperly addressed by current software, but of fundamental impact on IOR schemes, is the characterization of vertical permeability (Kv) throughout the fractured field. This study presents a way to solve this weakness. The vertical permeability in a fractured field is governed by: (a) the vertical extension of the different sets of fractures; (b) the proportion of cross-bedding fractures; and (c) the exchange area of bedding-terminated-fractures at the interfaces between layers. Several steps have been performed toward a proper evaluation of this aspect of reservoir characterization: (1) Innovative data analysis methods have been developed to better characterize these three features. (2) New ways to calculate the vertical permeability from these data have been formalized, which allow automatic calibration on the available dynamic data through multi-realizations. (3) Routines for extrapolation at field scale respecting the geological understanding of the fracture network, result in realistically Kv-filled geomodels directly usable for rocktyping or upscaling into reservoir models. These advances are currently being applied to a Middle Eastern field.

(159-Oral) Converted shear-wave anisotropy for fractured reservoir management

Gaiser, James E. (WesternGeco - jgaiser@denver.westernge co.slb.com) and Richard R. van Dok (WesternGeco)

Fractured reservoirs have been encountered worldwide and in general they are profitably produced, however it is safe to say that none of them have been depleted efficiently. As the petroleum industry focuses less on exploration, and in a market of rising costs, it is becoming more important to recognize the presence of fractures for optimal reservoir management. Fractures can significantly complicate the behavior of reservoir porosity and permeability, often resulting in numerous dry wells and higher production costs. A key strategy for fractured reservoir management is a quantitative description of the geology, geophysics and petrophysical attributes obtained from seismic methods during production and development. 3-D multi-component seismic surveys, where compressional waves excite shear-wave reflections (PS-waves), can provide complimentary surface-seismic information to help identify fracture properties early in the production history of a reservoir. Based on measurements of shear-wave azimuthal anisotropy, PS-waves can identify fracture density and strike, and because of their asymmetry they are also sensitive to fracture dip. Examples from both land and marine 3-D PS-wave surveys demonstrate the potential of using these attributes to characterize subsurface stress variations that are important for open-fracture development. The intermediate-scale seismic anisotropy properties obtained from PS-waves will be critical for solving specific production problems associated with different fractured reservoir types, and could improve reservoir modeling: production-history and pressure-test matching, and fluid-flow simulation. From an economic point of view, if PS-wave surveys acquired over the life of a field can prevent a small fraction of unproductive wells, they are worth the expense.

(306-Oral) Permeability modeling, up-scaling and dynamic simulations in a complex carbonate reservoir, Al Huwaisah field, North Oman

Gauthier, Philippe (PDO - philippe.j.gauthier@pdo.co.om), Dave Brooks (PDO), Nada Al-Kindy (PDO), Ebufegha Akposeiyifa (PDO) and Subrata Sen (Shell)

The main reservoir of the Al Huwaisah oil field is the Aptian Shu’aiba Formation comprising rudist-bearing shelf margin deposits with a complex depositional architecture. An iterative routine using log data and saturation height functions was developed to estimate permeability in this complex carbonate reservoir where standard porosity-permeability relationships do not exist, and where facies identification is only possible in cored wells. The resulting well permeability profiles compare favourably to well test-derived, effective permeability and preserve significant permeability contrast. Local sweep patterns identified from time-lapse saturation data were integrated with the calculated permeability, production log data, and well-scale pressure profiles, to aid in the identification of key dynamic reservoir characteristics. Up-scaling for reservoir simulation was done in such a way to maintain critical permeability contrast and well-test permeability averages. One aim of the dynamic simulation is to reproduce the local sweep patterns identified in the wells in over 30 years of production. This will allow targeting unswept areas of the field with greater confidence and consequently increase the ultimate recovery.

(349-Oral) Satellite gravity reveals the ‘big picture’ under the northern Gulf

Glenn, William E. (Larch - wglenn@telusplanet.net), Erwin J. Ebner (ELS), Rick Morgan (Consultant) and Aavo Taal (Al-Khafji JO)

One of the most under-utilized tools available to explorationists working in offshore exploration is Satellite Gravity. Recent advances in satellite positioning and gravity instrumentation have progressed to the point where the quality of satellite gravity data rivals that acquired by ship-borne gravimeters. Satellites can now deliver high-quality, low-cost gravity data to provide an enhanced understanding of the regional structure of offshore areas. In 2002, a series of satellite gravity maps were created for the northern Gulf region north of latitude 27. Sandwell 9.2 satellite gravity data were used, and 3-D Bouguer correction was applied using ETOPO-5 bathymetry and GTOPO-30 land data; grid-spacing was 500 m. The series comprised a map of Bouguer Gravity, three horizontal and vertical derivative maps, a band pass filter map, and a final interpreted Bouguer Gravity map. The parameters and data filters used to generate the processed maps were selected to optimize signals from depths of interest to oil and gas explorationists. The mapped data show at least four distinct structural domains in the northern Gulf region. Bouguer gravity anomalies have a strike, wavelength and shape that are somewhat different in each of these domains. Data resolution allows for the detection of gravity anomalies with anomaly widths as small as 6 km, depending on geometry and density contrast of rocks in the subsurface. These maps provide a valuable tool for refining the regional geology of this important area. They can be used to project onshore geological features (terrains, boundaries, faults, structures, lithology, and stratigraphy) to the offshore, to help in understanding and interpretation of existing offshore fields, and to plan the location of marine seismic surveys. The satellite data is of sufficient quality to serve all these purposes well.

(150-Oral) The Jurassic Najmah/Sargelu petroleum system of West Kuwait: a producing fractured carbonate source rock reservoir

Goff, Jeremy (BP - goffj@bp.com), Fahed A. Al-Medhadi (KOC), Hamad N. Al-Ajmi (KOC), Naveen K. Verma (KOC), Anthony J. Barwise (BP), Tim D. Needham (U Leeds), Johnathan M. Henton (BP), Norman Oxtoby (Royal Holloway, U London) and Joyce Neilson (Carbonate Reservoirs Ltd)

Deep exploration drilling by KOC in the Gotnia Basin, West Kuwait, has led to the discovery of light oil (35-40 degree API) in a new reservoir in the Jurassic Najmah and Sargelu formations. Challenging drilling problems due to convergence of pore pressure gradients (up to 0.99 pounds per square inch per foot) and fracture pressure gradients (1.0-1.02 pounds per square inch per foot) in the reservoir and overlying Gotnia Formation evaporite caprock have been successfully overcome. Extensive core data has been acquired to facilitate reservoir description. The reservoir is 100-170 m thick and comprises four carbonate source rock units, and three non-source shelf/slope carbonate reservoir units. Average porosity in the non-source carbonate layers determined from log and core (helium) analysis is 2.3 percent; secondary porosity up to 8 percent is locally present. Fractures are developed at all scales: from microfractures visible in thin sections, hairline fracture networks, bed-confined vertical fractures, and large vertical fractures cutting bed boundaries. Geochemical analyses indicate that oil expulsion has been very inefficient: (1) 90 percent of the oil generated has been retained within the Najmah/Sargelu formations; and (2) 10 percent has migrated downwards through the underlying Dhruma and Upper Marrat Formations into the Middle Marrat Formation carbonate reservoir. Fluid inclusion data from fracture cements record generation of oils of progressively lighter oil gravity; oil generation occurred in mid-Cretaceous-Early Tertiary time. Fractures formed in response to overpressuring associated with oil generation, Kimmeridgian and Turonian folding and Late Tertiary uplift. High-angle wells are being used to locate productive fracture systems and collect additional data on fracture distribution and spacing. Surveillance data indicates a slow recharge of the productive fracture network occurs following production due to expansion of oil in micro-fractures.

(155-Poster) Discovery and geology of a giant fossil Jurassic oil field in the Zagros Mountains, southwest Iran

Goff, Jeremy (BP - goffj@bp.com), Masoud Shamshiri (NIOC), Salman Jahani (NIOC), Farid Farmani (NIOC), Mehrab Rashidi (NIOC), Nicholas J. Whiteley (BP), Claudia Ruiz (BP), Christoph Lehmann (BP), Alexis S. Anastas (Devon), Abid Bhullar (BP), Norman Oxtoby (Royal Holloway, U London), Joyce Neilson (Carbonate Reservoirs Ltd), Bob W. Jones (BP) and Richard Diggens (Deloitte and Touche)

In 1931 geologists from the Anglo Persian Oil Company visited remote valleys cut into the core of a large anticline in the Zagros Mountains. They discovered outcrops of a thick section of bituminous dolomite. Seventy years later, a team of geologists from NIOC and BP retraced the steps of these pioneers to relocate and log these outcrops and determine the significance of the bitumen. The bitumen is contained in secondary porosity in a Middle-Upper Jurassic platform margin dolomite reservoir that has formed during deep burial at temperatures of up to 130 degrees C. Fluid inclusion data integrated with basin modeling indicates that medium-light gravity oil migrated into the reservoir (synchronous with dolomitization) during the burial of a paleostructure in early Late Miocene time. Oil migration continued during late Late Miocene folding. During later uplift and erosion in Pliocene and Quarternary time, the limestone caprock failed. Low-temperature calcite fracture and matrix cements associated with low-salinity aqueous fluid inclusions record the invasion of meteoric water into the reservoir, degradation of the oil, and leakage of the oil accumulation. Logging of the bitumen bearing reservoir integrated with structural mapping, indicates that the fossil oil field originally contained an oil column over 500 m thick. The final trap was an asymmetric anticline, with a gently-dipping back limb, and a steeply-dipping to overturned fore limb. The back limb has locally been thrust over the forelimb due to late structural movement.

(173-Poster) Mid Triassic-Neogene tectonostratigraphic evolution of the northeastern active margin of the Arabian Plate and its control on the evolution of the Gotnia Basin

Goff, Jeremy (BP - goffj@bp.com), Saad Z. Jassim (U Leeds) and Dogan Perincek (Kuwait U)

A new interpretation of the Midi≠Triassic-Neogene evolution of the northeastern active margin of the Arabian Plate is presented, based on correlation of tectonostratigraphic sequences along the Zagros Suture Zone from Southeast Turkey through Northeast Iraq and into Western Iran, using field observations and review of published geological maps. Triassic rifting with deposition of deep-water carbonates and eruption of basalts occurred within the northeastern part of the Arabian Plate; a ridge with shallow water carbonate platform deposition separated this rift from the newly-formed restricted Gotnia Basin to the southwest. Following renewed extension in the Late Jurassic along the line of the Triassic rift, a narrow ocean basin opened in latest Jurassic-Early Cretaceous time between the Arabian Plate and the Bitlis/Bisitoun micro-plate with widespread deposition of radiolarian cherts on the continental slope of the Arabian Plate. From Cenomanian time this ocean subducted to the north and northeast below the Bitlis/Bisitoun micro-plate with deformation of oceanic sediments and the formation of a Late Cretaceous calc-alkaline volcanic arc and forearc basin. In the late Campanian, ophiolites were obducted onto the Arabian Plate forming a narrow foredeep filled by flysch and carbonates. In Paleogene time, eruption of andesitic and basaltic volcanics occurred, associated with deposition of marine carbonates and flysch, north east of the suture zone between the Arabian Plate and the Bitlis/Bisitoun micro-plate. Foredeeps migrated to the southwest across the northeast part of the Gotnia Basin in response to compression and continental collision in Palaeogene and mid-Miocene-Quaternary time.

(176-Oral) Seismic stratigraphy of the Lower Cretaceous Shu’aiba Formation of Abu Dhabi

Gombos, Jr., Andrew M. (ADCO - agombos@adco.co.ae), Jason B. Scott (ADCO), Christian J. Strohmenger (ADCO) and Khalid Al-Amari (ADCO)

A new sequence stratigraphic framework has been established for the Lower Cretaceous Shu’aiba Formation of Abu Dhabi, integrating core, well-log and 3-D seismic data. The Shu’aiba Formation is a second-order supersequence (base ‘upper dense zone’ = Hawar Shale to top Shu’aiba), comprised of five third-order sequences. These third-order sequences are tied to the most recent global cycle chart and correspond to Aptian sequences Ap1 through Ap5. The overlaying Bab Member is interpreted to start with upper Aptian sequence Ap6. Biostratigraphy and nanno-fossil data support the proposed correlation. Seismic stratigraphic interpretation, using geometric observations and internal reflection patterns, allows the identification of the second-order supersequence as well as the six third-order sequences from 3-D seismic data. Lower Aptian sequences Ap1 through Ap2 show retrogradational and aggradational parasequence stacking patterns (transgressive sequence sets) whereas lower Aptian sequence Ap3 (early highstand sequence set) shows aggradational to progradational parasequence stacking patterns. The upper Aptian sequences Ap4, and Ap5 (late highstand sequence sets) clearly display progradational parasequence stacking patterns. Furthermore, 3-D seismic interpretation allows the identification of third-order transgressive systems tracts (dense zones) and highstand systems tracks (predominantly reservoir zones) within the prograding Aptian sequences Ap3 to Ap5. Amplitude maps tied to reservoir data allows the prediction of enhanced reservoir quality within the Shu’aiba prograding sequences Ap3 (late highstand systems tract), Ap4 and Ap5. In addition, dense zones (termed ‘I-Dense’) within the transgressive systems tract of Aptian sequence Ap3 can be predicted using amplitude and discontinuity maps. The proposed new sequence stratigraphic framework allows a more accurate prediction of reservoir quality away from well control, and will thus improve both the static geological and dynamic reservoir models.

(211-Oral) Low-resistivity pay carbonate reservoir, Lower Cretaceous, United Arab Emirates

Gomes, Jorge S. (ADCO - jsgomes@emirates.net.ae), Sunarnyoto Soenarwi (ADCO), Michel J.M. Rebelle (ADCO), Maria T. Ribeiro (ADCO), Youssef Dabbour (ADCO), Khalid Al-Marzouqi (ADCO), Mario Petricola (Schlumberger) and Paolo Ferraris (Schlumberger)

This study discusses the evaluation of a low-resistivity pay carbonate in the Middle East, and presents the approach used for the proper geological and petrophysical characterization of this reservoir. Log data exhibit a very low resistivity (0.3-0.4 ohm-m), which translates into an erroneous Sw (Archie) of more than 80 percent. However this reservoir produces dry oil at a reasonable rate (5,000 bopd with no water cut) without any fracture as evidenced by well tests. A petrographic investigation on thin sections shows high micro-porous facies. The micro-porosity results from large abundance in peloids and micritized organisms, and is associated with a meso- to macro-porosity developed as moldic porosity (dissolution of foraminiferas internal cavities) and/or framework porosity (dissolution of Bacinella internal structures). The micro-porous network traps irreducible formation water which will give a low resistivity response, even if oil occurs within meso- to macro-porosity. A NMR porosity-partitioning method is used to resolve the computation of Sw, by using the T2-distribution from NMR, for porosity partitioning into micro-, meso- and macro-porosity. The result of porosity partitioning will be dependent on the T2-cut off which is used in the evaluation. NMR core measurements were used to calibrate T2 cut-off. A saturation equation modelling non-Archie behavior, and solving for saturation in each individual pore type, through a sequential method that reproduces the oil migration process into the various pore types, was used.

(64-Oral) Geological modeling at Humma field, PNZ

Griest, Stewart D. (ChevronTexaco - griessd@chevrontexac o.com), W. Scott Meddaugh (ChevronTexaco), Joseph Mason (ChevronTexaco) and Sherilyn Williams-Stroud (ChevronTexaco)

The Middle/Lower Jurassic Marrat carbonate reservoir at Humma field was discovered in 1998 in the southwest part of the Partitioned Neutral Zone (PNZ), between Kuwait and Saudi Arabia. Three wells are producing 32 degree API oil from multiple reservoir zones distributed throughout the hydrocarbon-bearing section. The structure at Humma is a high-amplitude, four-way closure formed along a major regional block-faulted rift system that was initiated in the Precambrian Period. All regional tectonic events until the present day have resulted in persistent uplift, folding and faulting of the structure that was contemporaneous with deposition. Jurassic Marrat carbonates exhibit some faulting and fracturing, while shallower Cretaceous carbonates and clastics exhibit complex transtensional faulting within a keystone graben. Marrat reservoir distribution at Humma was influenced by a paleotopographic and paleogeographic configuration associated with the structure. Individual reservoir zones are best developed along a paleotopographic high that closely conforms to the present-day structural configuration. Reservoir intervals are best developed at the tops of shallowing-upwards (progradational) parasequences where inner ramp and inner shelf environments existed within a predominantly transgressive megasequence. The deepest Marrat reservoir interval exhibits dolomitization. An earth model for Humma field based on a geostatistical approach, was used to assess the distribution and degree of uncertainty related to reservoir properties within the field. Structural configuration was based on 3-D seismic and regional 2-D seismic interpretations. Each interval throughout the reservoir sequence was modeled based on the structure and well data. Reservoir properties were measured and interpreted from log analysis, core and production data. Semi-variograms were developed to simulate the lateral distribution of reservoir properties. Porosity was modeled using sequential Gaussian simulation (SGS). Water saturation and permeability were modeled using collocated cokriging with SGS using porosity as secondary data. The earth model was used to evaluate oil-in-place uncertainty and as input to fluid-flow simulation for field development planning.

(16-Poster) Integrated redevelopment of the Soroosh and Nowrooz fields, northern Gulf and remaining subsurface development uncertainties

Guit, Fer (Shell - f.guit@siol.co.ae), Alex Huerlimann (Shell), Nariman Noori (Shell), Hein de Groot (Shell), Parvin Ahmadi (NIOC), Sadjad K. Shiroodi (NIOC) and Ali Hassani (NIOC)

The Soroosh and Nowrooz fields located in the northern Gulf were redeveloped by Shell Exploration BV. Early production in excess of 60,000 bopd was achieved from Soroosh in December 2001 and main production is expected to start in 2004 with the availability of the integrated new production facilities. On Soroosh field, a total of 10 horizontal production wells and two water disposal wells were drilled from two platform locations. The wells target crestal oil volumes in excellent multi-Darcy permeability Burgan reservoir sands. Production will be by depletion drive using ESP’s and wells are designed to deal with a steady drop in reservoir pressure. Crude analyses demonstrate the presence of a density gradient from 20 to 10 degree API over the oil column; also lateral variations in oil quality have been demonstrated. Weak aquifer support is inferred from past production and is due to high viscosities over the base of the oil column. In addition aquifer support has further been reduced by depletion of some 200 psi of the regional Burgan aquifer by massive production from the various other fields in the region. On Nowrooz field a total of 17 horizontal production wells were drilled crestally from 2 platform locations. The structure is heavily faulted along the crest; however, historic production indicates strong pressure support by the volumetrically large aquifer. Although the net-to-gross of the Burgan reservoir is lower than in Soroosh field, the drilling campaign was successful in targeting relatively high proportions of sand in relatively undisturbed fault blocks. This study describes the findings of the production drilling and early production phase and remaining subsurface development uncertainties.

(174-Poster) Paleokarst and porosity development in Cretaceous carbonate reservoirs, central Oman

Guo, Li (CASP - li.guo@casp.cam.ac.uk), Michael D. Simmons (Neftex) and Eric J.-P. Blanc (CASP)

Dissolution associated with subaerial exposure is thought to be responsible for much of the secondary porosity in the Lower-mid-Cretaceous carbonates of the Arabian Platform. However, the presence of subaerial exposure surfaces in much of the succession has not been well-recognized. Outcrops in the Central Oman Mountains provide an excellent opportunity to detect the existence of paleokarst and understand their potential influence on reservoir development. A well-preserved karst profile is recognized at the top of the Natih Formation in southeast Jebel Madar, characterized by the occurrence of solution hollows, fissures, and breccias. A brecciated unit marks the top Shu’aiba Formation in southern Jebel Madar and provides evidence of subaerial exposure features; including brecciation, incipient calcrete fabrics, clay-infiltration and secondary porosity with meteoric cements. Irregular down-cuttings and solution hollows, associated with lithoclasts and clayey matrix, truncate tops of the meter-scale cycles in the lower part of the Kharaib Formation. Some of the features are original hardgrounds modified by diagenesis, and others are likely to be created by desiccation, dissolution and replacement during subaerial exposure. The subaerial exposure surfaces at the top Shu’aiba and Kharaib formations are supported by stable isotopic compositions, which show negative shifts, suggesting an incorporation of soil-gas CO2 into the carbonates and early meteoric diagenetic overprint during the subaerial exposure. These subaerial exposure surfaces have played direct and indirect roles in enhancing reservoir quality. Karstification and burial corrosion, together with fracturing, appear to have been the key factors contributing to the development of reservoir quality in this study.

(472-Poster) Reservoir characterization and modeling in the fractured basement plays of Yemen

Gutmanis, Jon (GeoScience - gutmanis@geoscience.co.uk) and Sylvie Delisle (Total)

Hydrocarbons have been under production from the fractured basement plays of Yemen since the early 1990s when Canadian Occidental Petroleum Ltd. (now Nexen Inc.) made discoveries in the Masila Block. Subsequently other operators have also developed basement plays, such as Total in the East Shabwa Block. This presentation describes reservoir characterization and modeling work carried out in the fractured basements of the Masila and East Shabwa blocks. These blocks are located within a major rift system which contains marly Cretaceous to Tertiary rift and post-rift sediments. From well penetrations, the basement rocks are a complex series of metasediments and metavolcanics, with granitic intrusions, generally at a depth of some 2,500 to 3,000 m. They are believed to be part of the Arabian-Nubian Shield, which extends through much of northeast Africa and Arabia and is of Archean-Proterozoic age. Reservoir characterization primarily involved detailed analysis of well data, especially borehole image logs, core and fluid flow information at a range of scales from individual flow entries to cross-hole interference tests. The objectives were to understand the producing fracture system, especially the types of porosity, their attributes, and their distribution at local to reservoir scale. A key requirement was to determine ranges of values for the key parameters (e.g. porosity, thickness) in order to support volumetric calculations. The well data was integrated with reservoir scale lithostructural and dynamic data to develop conceptual models of the fault and fracture system. A vital component was the use of analog information from literature and outcrop to help constrain the models and the range of parameter values. In general, the studies indicated that faults and their damage zones are the main source of production, and that fault geometry and intersection relationships are an important influence on permeability distribution. Reservoir stress, more specifically the orientation of the maximum horizontal stress axis, was also identified as an important influence on fracture permeability. For the volumetric calculations, faults at seismic and sub-seismic scale were modeled, using constraints from well data, while the smaller-scale ‘background’ fracturing was included in the matrix properties. Sensitivity evaluations were run for each parameter to assess their impact on the OOIP calculations, allowing uncertainties in volumetrics to be ranked.

(199-Oral) Lithology and fluid prediction in Cretaceous clastics using 3-D simultaneous angle stack inversion: results from a pilot area, Burgan Field, Kuwait

Haas, Stephen A. (ChevronTexacohasa@chevrontexaco.com) and Yousef Al-Zuabi (KOC)

In this study, we test simultaneous inversion of seismic angle stacks as method to delineate reservoir sands and fluid contacts in the Wara and Burgan reservoirs in a pilot area in Burgan Field. These two clastic reservoirs account for the majority of Kuwait’s oil reserves, so any direct method that identifies lithology and fluids has tremendous value. Simultaneous inversion incorporates AVO effects into the traditional full offset inversion process. This additional input better constrains predicted lithology and fluid solutions. In our workflow, we first analyzed well logs, including dipole sonic logs, and determined that using both P (compressional) and S (shear) impedances would improve identification of reservoir sands and, to a lesser degree, fluids. We selected a 280 sq km pilot area in the southwest flank of Burgan Field, based on optimal seismic and well data quality, gentle structure, and constrained fluid contacts. Next we reprocessed the 3-D seismic into three relative amplitude angle stacks, completed log editing and modeling, and then calculated P impedance, S impedance and density volumes using simultaneous inversion. Finally, we tested various transform combinations of these volumes to best identify sands and fluids. The results of the pilot simultaneous inversion test are encouraging, but clearly limited by our seismic data quality. Comparing these results with earlier full stack deterministic and stratigraphic inversion results indicates we have improved predicted lithology, but not predicted fluids. We are incorporating our lessons learned into planning for next generation 3-D surveys.

(297-Oral) 3-D anisotropic reflectivity in the Gulf region

Hall, Mike (GX - mah@gxt.com), Jim Simmons (GX) and Ghiath Ajlani (ADNOC)

A multi-component (3-C, 4-C, 9-C) anisotropic reflectivity-modeling tool was used to simulate the seismic response of an earth model common to the Gulf region: an anisotropic overburden overlying a fractured carbonate reservoir. The overburden is a thin-layered sequence of interbedded anhydrites and clastics that can exceed 1,000 m producing a layer-induced VTI (vertical transverse isotropy) seismic response. Thick shale underlying this is intrinsically VTI. A carbonate reservoir is represented as an HTI layer (horizontal traverse isotropy). The seismic response of the anisotropic overburden and reservoir was simulated. The model is restricted to plane, homogeneous layers, but each layer can be arbitrarily anisotropic. A modeling simulation produces a cube of pre-stack seismic traces equally sampled in x, y and t, for negative and positive inline and crossline offsets. As a result, 3-D wide-azimuth, multi-component data is modeled. Vertical and horizontal force sources represent vertical and horizontal vibrators, respectively. Anisotropic modeling indicates the particular type of seismic data (P-P, P-S, SH-SH, SV-SV) needed to best illuminate the fractured reservoir, recover estimates of shear-wave splitting, and evaluate the sensitivity of AVOA (Amplitude-versus-Offset-versus-Azimuth) analysis. Simulated 9-C data was analyzed in acquisition coordinates (inline-crossline) as well as in radial-transverse coordinates. It demonstrated how the latter yields a clear separation of the elastic waves whereas the former does not and can lead to false interpretations of shear wave splitting. This modeling provides insight into how to properly record and process 3-D seismic data to determine fracture orientation beneath a complex VTI overburden.

(6-Oral) Characterization of fractures within Dammam Dome, eastern Saudi Arabia

Hariri, Mustafa M. (KFUPM - mmhariri@kfupm.edu.sa) and Osman A. Abdullatif (KFUPM)

Dammam field is located in eastern Saudi Arabia and is one of the major domes resulted from salt emplacement. The dome hosts the first oil discovery in Saudi Arabia (Dammam-7 well). It covers an area of about 100 sq km, and encompass three major cities; Dhahran, Khobar and Dammam. The dome is characterized by gentle sloping topography in all directions with four hills that stand out. Outcrops within the dome range in age from Paleocene to middle Miocene, and consist, from base upward: Umm Er Radhuma, Rus, Dammam, Hadrukh and Dam formations. Fractures within the Dammam Dome can be divided into three categories according to their size and nature. The first are regional and large size (Mode I or extensional) fractures which extend for more than 500 m and may be related to the doming. The second category consists of local fractures (Mode I and III, III = dip-slip) with a length of 1 to 10 m. The block movements between the regional fractures mainly produce these types of fractures. The third category consists of more localized, small-sized fractures (< 1 m) which develop within rock blocks and are mostly related to the nature of the rock types. These fractures are of different Mode. Each type of fracture has distinctive characteristics and formation mechanism. This study is aimed at characterizing these fractures and defining their regional and local nature. The output of the study will help in understanding the mechanism that formed the fractures within the dome, and the prediction of their occurrence and pattern. Moreover, the findings of this study are important to the field of fractured reservoirs.

(110-Oral) Unconventional Shu’aiba traps and tilted or stepped oil-water contacts in eastern Arabia

Harris, Kester (PDO - kester.dk.harris@pdo.co.om), Gerard Bloch (ADCO), Martin Boekholt (ADCO) and Jean-Denis Bouvier (Daleel)

There are several Late Cretaceous carbonate fields in the northwest of Oman and onshore United Arab Emirates, which are considered to be combined structural-stratigraphic traps, and where faults are interpreted to form the lateral seal in the up-dip direction. This area of Oman and the southern fringe of the Arabian Gulf has undergone regional tilting in Late Tertiary times, generally down to the northeast. The tilting significantly modified the geometry of preexisting fields, and has led to the partial remigration of trapped hydrocarbons. There is a new explanation for the ‘fault-trapped’ oil in these fields: the tilted compartments of the field have not yet reached equilibrium and do not have flat oil-water contacts. This is due to a combination of low permeability of the reservoir, hysteresis in the drainage-imbibition process, and (possibly) insufficient time since tilting. One of the characteristics of the preexisting fields is that early hydrocarbon fill prevented the destruction of porosity, by inhibiting stylolitization. Consequently the reservoir porosities are relatively high at the paleoculminations. This is proven by well data, and is occasionally visible on seismic. The diagenetic destruction of porosity in the water leg below the paleocontacts has led to a significant change in reservoir properties across these surfaces. These surfaces are now also tilted, and so form permeability barriers which prevent–or at least hinder–the remigration of hydrocarbons. These two separate processes (tilting, and the formation of diagenetic barriers) have an impact on the production geology of fields, and give rise to unconventional targets for exploration. The Late Tertiary tilt is a regional event across eastern Arabia, and needs to be accounted for when evaluating stepped or dipping oil-water contacts in this area.

(213-Oral) An integrated picture of faulting and fracturing using image logs and 3-D seismic in a giant Lower Cretaceous carbonate field, Abu Dhabi

Hassall, John K. (ADCO - jhassall@adco.co.ae), Jason Scott (ADCO), Andrew Gombos (ADCO) and Khalid Al-Amari (ADCO)

Fifteen wellbore image logs (mainly FMI) are available in horizontal wells in the field. These logs allow fracturing and faulting in the field to be assessed. The interpretation of a recent high-resolution 3-D seismic survey has shown that more than one hundred and twenty faults are present in the field. The faults mainly show limited vertical throw, frequently less than 12 ft, but may have some strike-slip component. The wellbore image logs show that faults were penetrated in five wells. A comparison between the faults as seen on the image logs, and the faults as mapped on the seismic, shows that they are consistent once the ability of image logs to detect sub-seismic faults is taken into account. Images of the fault planes show variable fault plane disruption. Disrupted zone thickness ranges between a few inches and many tens of feet. The image logs show the majority of the fractures are closed, and run parallel to the faults. Weak fracture clustering is apparent and fracture intensity is enhanced in the neighborhood of some faults. Some of the seismically-identified ‘faults’ may be more properly described as fracture swarms, at least towards their tips. The image logs suggest the impact of faults and fractures on water-flood performance is likely to be minor, and this is confirmed by a review of data such as water front maps and production log data. These show very little evidence for fault/fracture influence on flow patterns after more than thirty years of waterflood. However, the impact of fractures and faults on gas injection schemes (WAG and GI patterns) now being implemented is yet to be determined. These current developments are highly susceptible to the reservoir attributes being discussed.

(278-Oral) Utilizing grain density and clay volume from geochemical logging for improving reservoir characterization in North Kuwait fields

Hassan, Tharwat F. (Schlumberger - tharwat@kuwait.oilfie ld.slb.com), Shaikh Abdul Azim (KOC) and Waleed El Awadi (KOC)

Geochemical logging was highly utilized in Raudhatain and Sabryiah fields of North Kuwait. One of the main advantages of using geochemical logging was the use of the output grain density for calculating the formation total porosity from the bulk density measurement. Historically, a constant value for the matrix density was a common approach to calculate the density porosity. Due to the presence of impurities in the sandstone such as siderite and pyrite, it was found that the matrix density is no longer a constant value across different layers of the reservoir. Using the above-mentioned technique in the fields of North Kuwait resulted in an increase of 1.5 percent in the total porosity on average. That was very important because an accurate total porosity is essential for accurate calculation of water saturation and total oil-in-place. A second application of geochemical logging was the accurate calculation of shale volume. This is important specially when ‘hot sand’ is present in the reservoir. In this case, the GR is no longer a reliable shale indicator. When this technique was used, an increase of the net pay of the reservoir was achieved.

(485-Oral) Geostatistical distribution of eolian facies using a modern analog as a modeling template, Permian Unayzah Formation, Tinat field, Saudi Arabia

Heine, Christian J. (Saudi Aramco - christian.heine@aram co.com), Jim Wilkins (Saudi Aramco), John Melvin (Saudi Aramco), Brian Wallick (Saudi Aramco) and John Cole (Saudi Aramco)

Ancient and modern analogs have long been used in reservoir modeling to add shape, size and areal extent to geological attributes such as lithofacies, porosity and permeability. Consistent with this practice, a modern analog has proved invaluable in constraining the distribution of reservoir quality sandstones in the eolian reservoir of the Unayzah Formation at Tinat field. Sedimentological analysis of image log and core data clearly identified dune, interdune and sheetsand deposits. The regional eolian depositional model incorporates a variety of dune forms that display consistently eastward-dipping foresets. The reservoir is layered in stratigraphic units that utilize a detailed correlation of successive relative rises in water table. Ten units are identified. These range from 25 to 50 ft in thickness, and each unit has been further subdivided into layers approximately 5 ft thick. Facies mapping using image logs and available core has been carried out for each unit within the eolian reservoir. The modern eolian environment analog was selected from Landsat and Spot satellite images from the Rub’ Al-Khali of Saudi Arabia, and the selected image was scaled and oriented based on the interpreted Permian wind direction. An object-based template was drawn for each of the three lithofacies honoring the available well data. The templates were used in a geostatistical method to distribute the three lithofacies types in a 3-D model. The resulting layer-specific lithofacies were then used in modeling the porosity and permeability distribution that corresponds to the eolian depositional environment. Other attributes such as 3-D seismic amplitude extraction and impedance will be integrated during the template building process.

(336-Oral) High-fidelity 3-D processing for the high-density Qarn Alam survey

Herman, Gérard C. (Shell - gerard.herman@shell.com) and Colin Perkins (Shell)

Many of the factors influencing land seismic data quality are related to the near surface. These problems include scattered surface wave noise and surface-consistent wavelet variations. In order to address these issues PDO has acquired a unique dataset in the Qarn Alam area of Oman, with shots and receivers on the same 25 x 25 m grid. In addition to the high-density CMP stack fold generated by this data volume, a new array of processing techniques became applicable that address the very near-surface issues described above. This study discusses two of these new methods and describes how they were applied to this original acquisition. The techniques are mixed-phase, surface-consistent deconvolution, and deterministic prediction and removal of scattered coherent noise. The first technique addresses surface-consistent wavelet variations with an amplitude and mixed-phase wavelet deconvolution approach. The mixed-phase nature of the algorithm allows for residual statics to be calculated in an effective manner. The second technique addresses the long-standing problem of scattered coherent noise. It uses a mathematical model of the near-surface wave propagation to predict and remove the scattered noise. Therefore, this method attenuates all aspects of this noise type, whilst preserving the signal. The theoretical details, and performance of these techniques, compared with existing processing techniques, are discussed, and a way forward for land seismic data is presented.

(28-Oral) High-resolution sequence stratigraphy in the Shu’aiba Formation, Oman: lessons learned from the outcrop

Hillgartner, Heiko (Shell - heiko.hillgartner@shell.com)

High-resolution sequence stratigraphy (HRSS) aims to identify repetitive sedimentological and stratigraphical patterns and interpret them in terms of changes in environmental conditions (commonly bathymetry) of variable frequency and intensity. HRSS analyses of the Lower Shu’aiba Formation in outcrops of northern and central Oman show an internal architecture with several smaller orders of depositional sequences. Potentially this has significant implications for subsurface correlations and interpretation of facies and property distribution in Shu’aiba reservoirs. Learning points are: (1) Depositional sequences are laterally continuous at least on a regional scale, but lateral facies changes are common in environments with unfilled accommodation space. (2) Although a general pattern of vertical facies evolution on different scales is present, superposition of sea-level trends on different scales and different depositional regimes result in a large variety of small-scale facies stacking patterns. (3) Relationships between high-resolution sequence architecture and petrophysical properties are not straightforward and cannot be used as generally applicable templates. (4) Clear bathymetric markers are important to establish a reliable and reproducible high-resolution sequence framework. Can a HRSS framework be established in Shu’aiba reservoirs despite the inherent limitations of subsurface data? Yes, it can be done! However, limitations in the resolution and uncertainty in correlation have to be accepted, managed, and communicated. Only a clear identification and documentation of the procedure and uncertainty in the correlation process can make it reproducible by other workers and counteracts the growing discrediting opinion that “HRSS is not useful because every worker comes up with his own scheme”.

(243-Oral) Oil and gas prospecting by ultrasensitive optical gas detection with inverse gas dispersion modeling

Hirst, Bill (Shell - bill.hirst@shell.com), Steve Gillespie (Shell), Ian Archibald (Shell), Olaf Podlaha (Shell), Graham Gibson (Glasgow U), Johannes Courtial (Glasgow U), Steve Monk (Glasgow U), Ken Skeldon (Glasgow U) and Miles Padgett (Glasgow U)

We report the development and testing of a new oil and gas prospecting technique ‘LightTouch’ that combines real-time sub-part-per-billion ethane concentration measurements in the atmosphere with inverse gas dispersion modeling to locate sources. The extreme sensitivity of the sensor permits detection, at a range of several km, of the naturally occurring ethane plumes that accompany hydrocarbon reservoirs. Using wind and concentration data, the gas dispersion process can effectively be inverted to provide remotely-determined ethane flux maps over the ground, thereby assisting in the search for hydrocarbon reservoirs. We present results from a recent 240 sq km survey in a Middle East desert setting, showing good correspondence between our results and those obtained from a targeted geochemical soil sampling survey performed in a parallel blind trial.

(420-Oral) Yibal field petrophysical integration: a case study in a low permeability, fractured carbonate field

Hogarty, Patrick (PDO - patrick.hogarty@pdo.co.om) and Gareth Henderson (PDO)

This study shows the results of a value driven, data gathering and analysis campaign on a mature high porosity, low permeability carbonate reservoir. The Yibal field commenced oil production in 1969 and is located in North Oman, about 450 km west-southwest of Muscat. One of the key issues in Yibal field is proper water saturation measurement and monitoring for determination of stock tank oil initially in place (STOIIP) and reserves reconciliation. This study discusses the data gathering strategies using open hole suites, cased hole pulsed neutron saturation monitoring and high precision sponge coring technology. The first sponge core cut in Oman was acquired in the Yibal field in 2002. Integration of this low-uncertainty data is discussed in the context of building saturation height profiles in the reservoir. The impact of wettability uncertainty is also discussed in relation to saturation profiles. A novel technique (Micro Computed Tomography) for petrophysical and geological modeling will also be presented.

(330-Oral) The influence of basement lineaments on the basin architecture of the overburden in the Iranian sector of the Gulf

Hoogendijk, Folco F. (Shell - folco.hoogendijk@shell.co m), Ian Glenister (Shell), Mourad Mehenni (Shell) and Mehran Mohammadi Faridan (Shell)

The present-day Gulf Basin architecture is that of a foreland basin to the Zagros Orogenic Belt. This north to NE-dipping mono-clinal basin is intersected by a series of basement-controlled tectonic lineaments trending NS to NNE-SSW, i.e. more or less perpendicular to the basin dip. These lineaments, however, differ greatly from each other in their appearance and timing of reactivation. The most striking of these lineaments is the Qatar Arch which remained a broad arch formed over a basement high throughout its existence from Early Paleozoic times onwards. The Nowruz-Hendijan Ridge, however, is a much narrower and steeper anticline. The appearance of this ridge seems to suggest a Hormuz Salt induced uplift over a reactivated basement lineament that formed during Albian-Cenomanian times, coinciding with the onset of ophiolite obduction along the Neo-Tethys Margin. The other, roughly NS-trending tectonic lineaments identified have a more subtle appearance. No ridges or large fault zones were formed but instead they appear as subtle hinge zones or as a series of infra-Cambrian Hormuz Salt diapirs lining-up above basement lineaments. The salt diapirs are more abundant in the southern Gulf and show a whole array of shapes as well as rates and timing of growth. Besides the roughly NS-trending tectonic lineaments, another set of NW-trending lineaments have been identified based on isochore maps. On the seismic data these reactivated basement lineaments appear only as subtle hinge zones. In the southern Gulf, salt diapirs also seem to line-up along this trend. These lineaments were active from mid to Late Cretaceous to Early Tertiary times. The tectonic reactivation of the Proterozoic basement lineaments had a perceptible influence on sediment facies distribution and stacking patterns in the overburden. It therefore becomes essential to unravel in detail the tectonic history of this basin in order to assess its remaining hydrocarbon potential.

(60-Poster) Paleogeography of the Asmari Formation in southwest Iran based on the sequence stratigraphic concepts

Horbury, Andrew D. (CCL - andy@camgco3.demon.co.uk), Adnan A.M. Aqrawi (Statoil), Neil Pickard (CCL), Tore Svånå (Statoil) and Ali Moallemi (NIOC)

Although paleogeographic maps of many different vintages can be traced within any publication survey about the Middle East, there is usually only limited agreement between any two sets of such maps. This is mainly because the objectives for which maps were made vary in terms of quality of data input, interpretation, geological time covered and area of interest. Most of these maps have not been updated with recent geological concepts and developments such as sequence stratigraphy, plate tectonics and biostratigraphy. Due to recent exploration and development activities of some international oil companies in southwest Iran, the need to establish a series of updated Tertiary paleogeographic maps, based on sequence stratigraphic concepts, was raised and became an objective. The other objective was that these maps should provide a regional basis for studies on the Asmari Formation reservoirs of Iran in order to resolve problems such as locations and orientations of shelf margins, directions of clastic input into different parts of the basin, and therefore likely stratigraphic geometries. These in turn are critical for understanding internal variations (heterogeneities) within different oil fields. A set of 12 Tertiary paleogeographic maps was prepared. These maps represent distinct sequence stratigraphic events (usually MFS + HST, LST + TST) during the depositional period (Oligocene-Early Miocene) of the Asmari Formation in southwest Iran. They start with the demise of the Jahrum/Dammam shelf carbonate system and end with early Gachsaran (or Lower Fars) Formation deposition in Early Miocene. The sequence stratigraphic framework was established using a modified version of the Arabian Plate maximum flooding surface. However, in contrast to this model, the sequence definition used is sensu Vail, rather than sensu Galloway, because the former definition keeps all continuously deposited sediment together within one packet and therefore relates better to the establishment and infill of accommodation space. The maps were initially constructed by composing the best existing published paleogeographies for each sequence, whilst paleontological/stratigraphic calibration was then achieved by posting data for individual localities from key papers. Tens of published articles in addition to textbooks and stratigraphic lexicons of the countries of the region were considered. Age definitions were largely taken from key stratigraphic papers but it was found that work done on Iraq’s stratigraphy was generally better documented than that performed on Iranian stratigraphy, and therefore, an Iraq model was used to calibrate the basin. This stratigraphy was later confirmed by fieldwork on the Khaviz anticline in southwest Iran, where the Pabdeh, Asmari, and Gachsaran outcrop. The main difficulty encountered was the poor distinction of the Aquitainian in Iran, and the position of the Ghar/Ahwaz sandstone units within the stratigraphy. Broadly speaking, the Aquitainian of Iran appears to embrace both the uppermost part of the Oligocene and the Aquitainian. This problem was initially resolved by applying the paleontologically better-constrained northeast Iraqi sequence stratigraphic model to Iran. In addition to a simple reevaluation of the paleontological data, certain guide-horizons were used, which almost certainly are isochronous and correlative with formations in Iraq (e.g. the Kalhur and Basal Anhydrite). To some extent, entry of the major Ahwaz sandstones in Iran on sequence boundaries can also be taken to be relatively isochronous.

(437-Poster) The Arab-D biofacies of Saudi Arabia - their paleoenvironment and new biozonation

Hughes, G. Wyn (Saudi Aramco - geraint.hughes@aramco. com), Abdullah G. Dhubeeb (Saudi Aramco), Osman Varol (Varol), Robert Lindsay (Saudi Aramco) and Harry Mueller (Saudi Aramco)

Despite the maturity of the Arab-D reservoir in the Ghawar field of Saudi Arabia, unexpected reservoir behavior has caused a reassessment of the depositional model using a sequence-based approach. As the Arab-D reservoir has relatively short chronostratigraphic duration, conventional biostratigraphic marker species are unavailable, and local appearance and disappearance events are attributed to paleoenvironmental influence. Nevertheless, biocomponent distribution can provide valuable information on paleoenvironmental variations that may be geologically synchronous between relatively closely-spaced wells. Semi-quantitative analysis of the macrobiofacies, microbiofacies and quantitative nannobiofacies of the Arab-D reservoir carbonates has been used to assist to decipher this problem. This study provides the lateral variations in the various biocomponents across the region, but especially in the Ghawar and adjacent fields, in an attempt to provide assistance towards depositional model using a sedimentologically-based sequence stratigraphic approach. Core samples have been analyzed from Abqaiq, Abu Safah, Ain Dar, Dammam, Hawiyah, Haradh, Khurais, Fazran, Qatif, Shedgum, and Uthmaniyah fields, and outcrop samples from the Tuwaiq Escarpment. There is a remarkable similarity in the vertical stacking of the various biofacies, from the deeper spicule-Lenticulina biofacies in the base, through the domed/encrusting sclerosponge, branched sclerosponge (Cladocoropsis mirabilis) biofacies into the shallow Clypeina jurassica, Mangashtia vienntoi, Pfenderina salernitana, Trocholina alpina and final gastropod biofacies. A series of discrete nannopaleontological events accompany the macro- and micropaleontological events, based on coccolith and didemnid ascidian spicule variations. These events are now documented in an objective, uninfluenced, objective digital database format that will enable ease of access and use by Arab-D reservoir sequence stratigraphers.

(380-Oral) Unconformable stratigraphic trap potential of South Iraq

Ibrahim, Muhammad W. (Target - mitarget@aol.com,)

Several unconformable stratigraphic trap plays were detected below major unconformities in the Phanerozoics of Iraq through regional mapping of the stratigraphic sequences of South Iraq. The trap models involve the juxtaposition of various seal rock facies over several types of reservoir rock facies across structurally modified regional unconformities. In this study the sequences across 10 regional unconformities where potential cap rock facies are unconformably super-imposed on potential reservoir rock facies were mapped to illustrate: (1) four play fairways below two Jurassic unconformities; (2) seven plays fairways below five Cretaceous unconformities; and (3) seven play fairways below three Tertiary unconformities.

(338-Oral) Structural and tectonic evolution of Melut Basin, Sudan

Imam, Abdul-Mageed M. (PDOC - imageed@petrodar.com)

The sedimentary basins of interior Sudan are characterized by thick non-marine clastic sequence of Jurassic (?), Cretaceous, and Tertiary age. These basins form a major segment of the Central African rift systems that extend from Nigeria to Sudan. These systems began to develop in Late Jurassic time during the separation of South America from Africa. Another system of lineaments that trend NW-SE from Kenya to Sudan, are believed to be an older fracture pattern related to the Pan-African Orogeny that became active during the separation of Africa-Madagascar and India. The Melut Basin is one of the four major rift systems in southcentral Sudan. The rift system trends NW and is controlled by Central African shear zones. The depositional sequence in Melut Basin includes lacustrine shales with fluvial-alluvial sandstones and conglomerate. The basin complex exhibits rift tectonic features with strike-slip compressional effects resulting in complex fault-bounded anticlines. The major fault trend through the basin is NNW and parallel to Aswa Lineament that extends from Kenya to Sudan. Twelve cross-sections across the Melut Basin were restored, and they suggest an Early Cretaceous rift phase. The associated structural elements were influenced by the northward propagating Atlantic Ocean. The Tertiary rifting in Melut Basin is characterized by periodic pulses of extensional deformation. During this time the basin was probably influenced tectonically by the Tethys-Mediterranean, as well as the Red Sea-Gulf of Aden rift. In the late Tertiary, the basin was affected by normal faulting that was accompanied by a significant component of strike-slip faulting. The development of the basin during this stage was most likely affected by Arabia and Asia collision. Also there may be a close link between the cessation of fault activity in the Red Sea-Dead Sea transform and the transtensional faulting in the Melut Basin. The Miocene failed rift system propagating from Kenya and truncated at the border of Sudan, is just to the southern part of this basin. During the Tertiary, the basin was affected by the volcanism, which was widespread in the Ethiopian Plateau to the east, and Darfur volcanic swells to the west. Several basic volcanic rocks are recognized in the Melut area. The Quaternary in Melut Basin was calm, and only interrupted by the reactivation of normal the fault.

(163-Oral) Integrated reservoir engineering: from geological concepts to multiple production history matches

Inizan, Marielle (Total - marielle.inizan@total.com), Raffaele Di Cuia (Total), Patrick Henriquel (Total), Philippe Lapointe (Total), Florence Vieban (Total) and Gilles Vincent (Total)

Subsurface uncertainties concerns Geophysics, Geology and Reservoir (2G&R). The Subsurface Uncertainty Management process is now a standard methodology in Total for non-developed fields. However, as a growing number of fields in our portfolio are mature reservoirs, it becomes essential to assess and manage uncertainties for already developed fields. This implies to match the real production history data. This presentation describes a carbonate field case where the entire process of 2G&R uncertainties quantification and ranking was performed leading to several reservoir models that honor the production history. The key messages of this study are: (1) geological concepts are tested through the history match process, i.e. the production data should be used to select the most suitable ones. (2) Stochastic modeling and multi-realization allow multiple production history matches and thus constitute a true risk assessment for forecasts. (3) Such a study can only be achieved by a total integration of the 2G&R engineers and tools.

(142-Oral) The upper Arab Formation: is the present really the key to the past?

Insalaco, Enzo (Total - enzo.insalaco@total.com), Thierry Boisseau (Total), Steve Glover (Total), Florence Viéban (Total) and Fredéric Walgenwitz (Total)

The upper Arab Formation is one of the most important reservoir formations in the Middle East Gulf Region, and one of the world’s biggest reserves. The complex, fine-scale intercalation of dolomitic and anhydritic units poses a number of operational challenges at both exploration and production scales. These are linked to two fundamental issues: (1) the sedimentological and sequence stratigraphic interpretation of evaporites, and their relation to the carbonates; and (2) the diagenesis and remobilization of anhydrites. In order to address these issues a core, thin-section and geochemical synthesis of a number of cored upper Arab wells has been studied. The 3-D facies mosaics are extremely complex, especially for the evaporites where complete gradations between facies types are present. A simple supra-tidal sabkha versus deep subtidal salina model is too simplistic – there are numerous types of evaporitic facies, complete gradations between evaporite types and they can occur across the whole depositional profile. Moreover, late stage anhydritization and development ‘later’ replacive nodules can also cause problems – not all nodular anhydrite-rich units are syn-sedimentary or early diagenetic in origin. The majority of the evaporites in the study window are various types of ‘sabkharized’ shallow salina and sabkha deposits. Also important are zones of later replacive nodules. The sabkha and salina deposits of the study window appear to be significantly different to the sabkha deposits of the present-day Gulf in terms of facies characteristics and facies cycles. The principal conclusions are: (1) understanding the anhydrite facies and diagenesis are key in mixed dolomite-anhydrite reservoirs; (2) do not over-rely on uniformitarianism (actualism) for understanding the evaporites deposits and anhydrites (not all evaporites are sabkhas, not all anhydrites are syn-sedimentary/early diagenetic); and (3) there can be significant amounts of anhydrite mobilization and post-depositional changes. These issues will have an impact at the regional-scale by providing a predictive stratigraphic model in terms of facies organization and reservoir quality; and at the reservoir-scale, by refining reservoir layering schemes and petrophysical groupings.

(143 -Oral) The Khuff (Dalan/Kangan) Formation: from regional models to reservoir simulations

Insalaco, Enzo (Total - enzo.insalaco@total.com), Catherine Baglinière (Total), Roger Brousse (Total), Christian Fraisse (Total), Jean-Paul Gomez (Total), Pierre Masse (Total) and Fredéric Walgenwitz (Total)

The Khuff Formation (Dalan/Kangan) is one of the most important reservoir formations in the Middle East Gulf Region and one of the world’s biggest gas reserves. In order to guide investment decisions and to optimize production of existing reservoirs, the Khuff Formation needs to be understood at all scales from regional understanding of the platform paleography and stratigraphy, to the fine-scale reservoir heterogeneity at a micro-facies level. In order to address these issues a large multi-disciplinary and multi-scale study has been launched on a large Gulf-scale database. The database includes data from: (1) Zagros outcrops; (2) onshore and offshore Iranian wells; (3) offshore Qatari wells; (4) offshore Abu Dhabi wells; and (5) seismic data. Conceptual geological models have been constructed for the large-scale stratigraphic architecture, sedimentological organization and the paleoecological systems. At the reservoir-scale, models for the diagenetic overprinting (including models for poroperm development/occlusion, and dolomitization), and its links to the sedimentological, stratigraphic and fracture framework, have been constructed. These have been supported by geochemical studies on the carbonates and anhydrites, and micro-structural studies on the fractures. These regional to reservoir-scale conceptual models have been used to constrain the reservoir models and to improve the integration of the geological uncertainties. A suite of modeling tools have been used to integrate the conceptual information and assess uncertainties at all scales. At the regional scale Forward Stratigraphic Simulators have been used in a multiple scenario approach to assess large-scale platform organization. Inhouse reservoir-scale modeling tools have been used to model the fine-scale reservoir heterogeneity, and create multiple realizations of the static reservoir properties. Finally these are modeled dynamically to assess the impact of the geological parameters on the production profiles.

(450-Poster) Fractures identification and their contribution to production in khuff-3 Reservoir - a tight deep gas dolomite - in the Bahrain field

Janahi, Layla A. (Bapco - layla_janahi@bapco.net) and Adel A. Al-Madani (Bapco)

The Khuff Formation (Permian age) is a major gas reservoir, which has been producing since 1970 under depletion drive mechanism. The Khuff Formation is considered to be the principle gas producer in the Bahrain field since 90% of the gas reserves are contained in it. The remainder of the reserves is believed to be in the pre-Khuff sequence. Khuff Reservoirs produce around one BSCFD of non-associated gas. The Khuff Formation is divided stratigraphically into four reservoir units: K0, K1, K2 & K3. Matrix porosity and permeability are restricted to K0 to K2 units, with the best reservoir quality in K2 whereas reservoir development in the K3 is associated with fracturing. Recently acquired 3-D seismic survey over Bahrain field, calibrated with wells information, has allowed – to far extent – the recognition of the structural style at Khuff levels. The evaluation of fractures at K3 level was carried out by integrating well logs, borehole imagery and drilling information. This multidisciplinary approach has improved the understanding of the fractures distribution nature and occurrence in the Bahrain field at the Khuff level. It is believed that this approach would reduce the drilling risk to developing the K3 reservoir and ensure that gas resources from this tight reservoir are well defined and optimally exploited and targeted.

(270-Oral) Reducing turn-around time of structural interpretation through Volume Interpretation: the Yibal example

Jauffred, Jean-Claude E. (Shell - jean-claude.jauffred@s hell.com), Peter P. Bakker (Shell), Peter Engbers (PDO), Maartje M.D. Koning (Shell) and Guy G.F. Mueller (PDO)

Although seismic interpretation is often carried out in a conventional way, Volume Interpretation technology is getting more widely accepted. Many tools are available in the industry to help seismic interpreters to go beyond simple visualization of data in three dimensions. These tools can be combined into workflows to address specific aspects of interpretation. They help to reduce turn-around time and take full advantage of the amount of detail provided by modern 3-D seismic data. This is particularly the case for fault interpretation, which is always a lengthy part of the interpretation. Volume Interpretation tools such as structural dip and azimuth or coherency have greatly improved the quality of structural interpretation. Still, interpretation of faults has up-to-now been done mostly manually. Automatic fault tracking tools are however under development in the industry. In Shell, a new methodology for fault interpretation has been developed based on the patent pending vanGogh technology: the stopper-voxels. Stopper-voxels represent discontinuities in the seismic data that usually correlate well to faults and can be extracted for analysis and editing. The results are exported as fault sticks or surfaces to a Trace Interpretation System or a reservoir modeling package. The method is used at any stage of the interpretation. In exploration, it can be used to quickly analyze fault trends and structural styles at different levels in a survey. In field development, it is used to speed-up the building of fault models at reservoir level or analyze small discontinuities for fracture trends detection. This study illustrates this novel approach on the Yibal field in Oman, where the tool was used to automate fault modeling and fracture study.

(412-Oral) Petroleum potential of the Triassic System, Saudi Arabia

Jenden, Peter D. (Saudi Aramco - peter.jenden@aramco.co m), Adnan A. Al-Hajji (Saudi Aramco), William J. Carrigan (Saudi Aramco), Abdelghayoum S. Ahmed (Saudi Aramco) and Mahdi A. Abu-Ali (Saudi Aramco)

Triassic oil and gas-condensate has been recovered throughout a large part of the Eastern Province of Saudi Arabia. In order to address the origin of these liquids, pyrolysis data were compiled for over 700 Triassic core and cuttings samples. Oil- and gas-prone source rocks are recognized in the lower Minjur Formation but are most widespread in the Jilh Formation. Samples with the highest organic carbon contents (up to 7.4 percent) have excellent oil yields but net source bed thickness is limited. Petroleum potential has not been integrated over the entire Triassic section because source beds are difficult to recognize in bulk cuttings. Individual cores have potentials up to 800 Mbbl of equivalent 35 degree API oil per sq km. Although sufficient to produce widespread oil and gas shows, these are quite small when compared to petroleum potentials in the well-known Jurassic and Silurian petroleum systems (74 and 33 MMbbl per sq km, respectively). Source rock maturity data show that the Jilh Formation has reached peak oil-generation in sub-basins around the Ghawar field high. Jilh oils and oil-stained rock extracts are readily distinguished from Silurian- and Jurassic-sourced oils using standard geochemical analytical tools such as gas chromatography, stable carbon isotope ratios and biomarker analyzes. Although properties vary widely, Jilh oils have characteristics suggesting a restricted, frequently hypersaline, shale or marl source rock. Reasonably good correlations have been obtained between Jilh oils and extracts of potential Jilh source beds at Shaden and Mazalij fields. We conclude that minor accumulations of Jilh oil at Ain Dar, Qirdi and Sahba fields were generated within the Jilh Formation.

(169-Oral) Structural characterization of carbonates in the United Arab Emirates: from regional to reservoir scale

Johnson, Christopher A. (ExxonMobil - christopher.a.joh nson@exxonmobil.com), Mary Johns (ExxonMobil) and Susan Agar (ExxonMobil)

High-quality 3-D seismic data of carbonate reservoirs of the United Arab Emirates (UAE) provide an excellent opportunity to relate the deformation response to Late Cretaceous compression. At the regional scale, anticlinal culminations form arrays along prominent subsurface ridges. The arrangement of the anticlines, their size and asymmetry, and the character of internal deformation are consistent with a basement-involved origin through oblique compression and inversion of deep-seated (probably Proterozoic) grabens. At the field scale, the anticlines are cut by numerous vertical fault zones that strike at a high angle to the anticlinal axes. The fault zones display patterns of segmentation at all scales down to the resolution of the seismic data. Their orientation and sense of oblique offset suggests they formed as large-scale, conjugate shear bands. Fault-zone spacing and offset reflect local strain partitioning, whereas fault zone strikes (dominantly N75W and N45W) are compatible with regional WNW-ESE compression during fold growth in Late Cretaceous time. The limited offset (usually less than 30 m) and segmentation of the fault zones indicate that the fault zones are unlikely to form major seals within the reservoir. Investigations of the relationships between faults and fractures in seismic data, borehole image logs, and core for one Abu Dhabi field indicate that the faults have not developed major damage zones. Borehole image logs show local clustering of fractures near some, but not all faults. A correlation between fractures in borehole image logs and those in core provides preliminary insights to the relative impact of different fracture sets on production. The dominant NW-trending, fault-parallel fracture set includes grain-size reduction surfaces that are likely to baffle flow. The NE fracture set appears to be dominated by open fractures that are likely to enhance flow. All of these interpretations provide the structural framework integrated over multiple scales that is essential to evaluate structural risk in reservoir performance.

(170-Oral) Structural styles and tectonic evolution of onshore Abu Dhabi

Johnson, Christopher A. (ExxonMobil - christopher.a. johnson@exxonmobil.com), Brian West (ExxonMobil), Mohamed Sattar (ADCO) and Andrew M. Gombos (ADCO)

Deformation in onshore Abu Dhabi has been studied using 3-D seismic data from multiple fields. The structures studied are large anticlines that grew during Late Cretaceous, basement-involved foreland compression. The high-quality subsurface imaging allows an unprecedented opportunity to relate faulting and fold growth over a wide area of the Arabian Platform. The number and individuality of the structures enables comparative analysis of fold geometry and internal deformation. A consistent structural framework can be constructed that explains deformation observed at scales ranging from the deep crust and lithosphere (plate scale), through field-scale growth of anticlines, down to the smallest faults and flexures that are imaged at reservoir scale on seismic data. The integrated picture results in the linking of regional tectonics and plate kinematics, foreland deformation character, fold growth and deep geometry, structural timing, and internal faulting and deformation. The anticlines are crossed by systematic sets of small-offset fault zones arranged in an apparent conjugate relationship. Fault zone directions (approximately N75W and N45W) are interpreted to result from regional WNW-ESE compression during fold growth. Fault zone spacing and offset bear a strong relationship to the magnitude of local strain within brittle Mesozoic carbonates. The observations are consistent with overburden behavior above obliquely inverted deep-seated grabens. From a production perspective the limited offset (usually less than 30 m) and segmentation of the fault zones have significant implications for fluid flow within and across the zones. The ubiquity of faulting, its geometry, and its consistent orientations are of interest to explorationists, particularly in areas where 3-D data are unavailable.

(465-Oral) Advanced pyrolytic techniques to characterize oil reservoirs from core samples

Jones, Peter J. (Saudi Aramco - peter.jones@aramco.com), Henry I. Halpern (Saudi Aramco), Edward A. Clerke (Saudi Aramco) and Stephen G. Cheshire (Saudi Aramco)

Saudi Aramco has developed three novel methods to quantitatively assess reservoir quality from residual staining on drill cuttings and core; the Pyrolytic Oil-Productivity Index (POPI), the Apparent Water Saturation (ASW) Method, and the Compositional Modeling Method (CoMod). POPI provides an independent assessment of oil-reservoir productivity. The ASW Method provides an independent assessment of water saturation (SW) that corresponds closely to standard calculations via the Archie Equation. Finally, the CoMod Method provides assessment of the relative amounts of various organic matter types present in multi-component systems. Pyrolysis methods have proven reliable on 40+ year-old unpreserved core samples and are used extensively in development planning to assess reservoir productivity and changes in reservoir facies. ASW has been an extremely valuable and rapid input into the integrated study of reservoir fluid contacts, calibrating hydrocarbon saturations in the drainage and imbibition cycles in the presence of variable salinities and in providing detailed hydrocarbon saturation profiles in the productive portions of reservoirs and through the oil-water transition zones. Results from pyrolysis are used in an integrated interpretation using core, logs, and dynamic data from well tests. CoMod provides new capabilities that greatly assist in tar mat identification and characterization and can be used to correct data for problems caused by background organic matter from disseminated kerogen, coal, or drilling contaminants. The methods provide powerful, rapid, and cost-effective tools to confirm interpretations, to assist when well logs are ambiguous, and to provide parameters that cannot be obtained through log analysis alone.

(483-Oral) “Real-Time” Pyrolytic Methods to Geosteer Horizontal Development Wells: Qatif Field, Saudi Arabia.

Jones, Peter J. (Saudi Aramco - peter.jones@aramco.com), Henry I. Halpern (Saudi Aramco), Matthew W. Dahan (Saudi Aramco), Gurhan Aktas (Saudi Aramco), Ishak B. Ishak (Saudi Aramco), Salman M.M. Al-Qathami (Saudi Aramco) and Khalid R. Malki (Saudi Aramco)

Novel pyrolytic methods developed by Saudi Aramco to quantitatively assess reservoir quality from residual hydrocarbon staining on drill cuttings have been applied in ‘real-time’ to assist with geosteering horizontal oil field development wells. The subject methods include: the Pyrolytic Oil-Productivity Index (POPI), the Apparent Water Saturation (ASW) Method, and the Compositional Modeling Method (CoMod). Pyrolytic methods have been used at Qatif field primarily to assist in geosteering horizontal power water injection wells (HPWI) that have been drilled in the Arab-C and Arab-D reservoirs. Placement of HPWI wells at Qatif is complicated due to the presence of tar mats that exist on the flanks of the structure. HPWI well placement is designed to be downdip from all sweepable oil, i.e., in the oil-water transition zone and below the SW cut-off for moveable oil. However, the presence of tar mats on the flanks of the structure have resulted in a very narrow tolerance for positioning these wells between oil productive and tar occluded reservoir, where little or no water injection can be accomplished. The analysis is carried out by the POPI Field Analyzer at the wellsite, with the following objectives: (1) confirm well placement in O/W transition zone; (2) identify/characterize/quantify tar intervals that may be encountered; (3) assess successful geosteering out of tar mats once encountered; and (4) identify reservoir intervals that are favorable for water injection. Real-time pyrolysis has proved a valuable tool for reservoir development by quantitatively assessing tar presence and fluid movability in complex reservoir systems.

(162-Oral) 3-D azimuthal tomography on OBC data

Julien, Philippe L. (Total - philippe.julien@total.com), Philippe Berthet (Total) and Jean-Pierre Dunand (Total)

This study proposes an original approach for quantifying the anisotropy that may occur in a fractured carbonates reservoir. Wide azimuthal seismic datasets often exhibit an azimuthal dependency on the normal moveout and the AVO gradient measurements. The success of the methodology for determining azimuthal interval velocity variations is here based on a robust seismic processing, on a robust automatic picking of azimuth/offset events and on an adequate depth tomography. The acquisition of the Ocean Bottom Cable (OBC) 3-D seismic dataset was designed so that the elementary bin has a full azimuthal coverage. The efficiency of the methodology was enhanced by applying the azimuthal tomography in the depth domain. The depth domain avoids azimuthal structural effects and enhances the seismic event coherency for the picking. The depth domain also offers a good resolution in the moveout discrepancy, mainly for non-hyperbolic measurement, and even for thin layers. Based on the elliptically variation of the NMO velocity, the highest interval velocity axis direction was derived first. This axis direction correlates to other study results such as Amplitude versus Azimuth (AVAZ) or Azimuthal High Resolution Velocity Analysis (AHRVA). Afterwards, the medium is considered to be horizontally transversely isotropic (HTI). Thus, the parameters of the medium were inverted using depth tomography. The VTI tomography was subsequently adapted for HTI media. Since non-hyperbolic measurements were achievable, the tomography resolves the three parameters Vp0, δ and ɛ. The time-to-depth conversion of the reservoir map was consistent with the azimuthal measurements.

(77-Oral) Permanent downhole seismic sensors in flowing wells

Jupe, Andrew (ABB - andrew.j.jupe@gb.abb.com) and Will Wason (ABB)

It is generally accepted that the ‘Oilfield of the Future’ will incorporate distributed permanent downhole seismic sensors in flowing wells. However, the effectiveness of these sensors will be limited by the extent to which seismic signals can be discriminated, or decoupled, from flow-induced acoustic noise originating within the production tubing. A specialized test facility has been developed in order to understand and characterize the acoustic noise generated by fluid flow within a production borehole, with the goal of developing the next generation of seismic tools suitable for permanent deployment in flowing wells. By eliminating or reducing the signal contamination due to the flow, the noise floor of the system could be improved, enabling smaller seismic signals to be resolved. This study presents the test facility design and the results of both physical experiments and numerical modeling aimed at the management of flow-induced acoustic noise, for permanently deployed seismic sensors in flowing hydrocarbon wells. From the flow noise experiments, a tool has been developed for permanent deployment into flowing wells. The tool is designed to allow the seismic sensors to be acoustically decoupled from the flow noise, whilst being well coupled to the formation. A number of seismic sensor packages can be distributed at various intervals along the deployed tubing to monitor passive and active seismic data. The system has been designed so other types of sensors (eg; pressure and temperature) can also be incorporated if necessary.

(488-Poster) The Permo-Triassic section at Wadi Bih and Wadi Hagil in Ras Al Khaimah, United Arab Emirates

Kamal, Rami A. (Saudi Aramco - rami.kamal@aramco.com), Ian M. Billing (Saudi Aramco), Abduljaleel A. Abubshait (Saudi Aramco), Denis Vaslet (BRGM), Yves-Michel Le Nindre (BRGM), Christian J. Strohmenger (ADCO), Abdullah Al-Mansoori (ADCO) and Randy Demaree (Saudi Aramco)

Composite geological sections of approximately 3,800 ft of continuous bedded deposits of the carbonate Permian Bih and Hagil, and the Triassic Ghail formations at Wadis Bih and Hagil in eastern Ras Al Khaimah, in the United Arab Emirates, have been prepared. The sections include a comprehensive documentation of bedding, composition, rock texture, mineralogy, sedimentary structures, depositional facies and facies stacking patterns. Lateral variation and porosity were also carefully noted. The stratigraphy/sedimentology was complemented by a description of structural features including faults, folding, collapse features and brecciation. Additionally, two teams of geologists took gamma ray readings along fixed intervals along the described composites. The resultant traces were compared to wireline gamma ray logs from select wells in the subsurface of eastern Saudi Arabia and offshore Abu Dhabi. This has resulted in a correlation scheme with the time equivalent Khuff Formation in the subsurface of eastern Saudi Arabia. The outcrop geology rendered from the descriptions was also compared with core descriptions of the Khuff Formation in the subsurface of Saudi Arabia with a bias towards understanding the geometries of Khuff reservoirs. Finally, the Ras Al Khaimah section was compared to Khuff Formation outcrop sections over 1,000 km to the east in central Saudi Arabia. The implications of this breadth of data capture are invaluable in concurrent efforts to create a unified model for the Khuff formation across the Arabian Shelf.

(489-Oral) A comparative study of visually estimated mineral composition, X-ray diffraction, and trace element determination from cores across the Khuff-C carbonate in Hawiyah, Ghawar field, Saudi Arabia

Kamal, Rami A. (Saudi Aramco - rami.kamal@aramco.com), Ghazi Al-Eid (Saudi Aramco), Bruce W. Sellwood, (U Reading) and Edward A. Clerke (Saudi Aramco)

A 180-ft-long cored interval through the Khuff-C depositional cycle, which includes the Khuff-C reservoir, was subjected to a key study to compare four techniques of mineral composition determination of the same rock, namely from: full core description, thin section descriptions, trace element analyses, and X-ray diffraction analyses. Cored footage from the Khuff-C carbonate in a northeastern Hawiyah area well, was veneered along a length of 180 ft. The thin veneered slabs were ground in one-foot length batches. Homogenized samples from the batches were then X-ray analyzed for mineral composition. Separately, visual estimates of mineral composition were made for the same rock from thin sections taken from core plugs taken at 6-inch intervals in addition to mineral composition estimated from the regularly performed core descriptions. Finally, small samples were acquired from the same plug ends and were pulverized and run through automated trace element detection processes. Data from all four methods were tabulated, plotted and compared. Visual determinations of bulk mineral compositions portray the lithology trends in the rock, expressed in the X-ray determined mineralogy and trace element analyses. Detailed comparisons showed that calcite percentages compared the best. Dolomite percentage compared fairly. Anhydrite percentage trends were correct but values were systematically low compared to mineralogy. The anhydrite discrepancy can be explained by observing that a large percentage of the Khuff anhydrite is concentrated in small to medium sized nodules. Hitting or missing a nodule during the core plugging process can make the difference between a high visually estimated percentage and an almost negligible percentage of the mineral. Although the anhydrite trend is not jeopardized, X-ray diffraction is recommended for studies where accurate anhydrite percentages are necessary. X-ray diffraction revealed the occurrence of minor and trace elements, namely: feldspar, pyrite, siderite, fluorite, and celestite (0.1 – 2.9 percent of bulk rock); that were not recognized by the optical petrographers. Minor element recognition can play an important role in correlation, determination of environments of deposition, and diagenetic sequences. This comparative study reveals the variance between visually estimated mineral composition and what is instrumentally detected. Secondly, the study has shown the variance between geochemical mineral analyses taken from a homogenized ground sample taken across a foot of core and spot measurements taken six inches apart along the same foot of core.

(1-Oral) Arabian Plate structural evolution: GIS application

Kapka, Bettina (GeoTech - bkapka@batelco.com.bh) and Joerg E. Mattner (GeoTech)

Comprehensive surface and subsurface structural data of the Arabian Plate are captured in a Geographic Information System (GIS) database framework. The structural environment and activation history of features (such as faults, folds, halokinesis and volcanism) is documented, mapped and interpreted. The GIS system allows for: (1) the visualization of geological features in different map displays; (2) statistical analysis and interactive querying; (3) the exchange and collaboration of data and interpretations between different parties; (4) on-line access of data; and (5) high-quality output of results for possible publishing purposes. The system, for example, answers questions like: (1) “which structural features are reactivated or newly-created on the Arabian Plate in the Permian”; (2) “what is their orientation and geometric relationship”; and (3) “what local and regional stress direction and stress conditions could have caused these features”. This can be achieved interactively on screen, or via standard formulated expressions. Computer Aided Sotware Engineering (CASE) tools were used to design the database using Unified Modeling Language (UML) diagrams. This strategy has advantages such as: (1) built-in documentation and visualization of the relationships between the attributes of the data; (2) updating and modification of the existing database structure; and (3) transfer of that structure to other GIS users. The database contains over 100,000 structurally-related, surface and subsurface records of the Arabian Plate. The project is specifically designed to permit the integration of geoscience information from GIS and non-GIS users. Besides the scientific value of documenting the regional structural evolution of the Arabian Plate, this rapidly growing database also yields economically important information; e.g. about the possible occurrence and orientation of sealing and non-sealing faults in a particular formation or field.

(102-Poster) Permian Upper Gharif Sandstones of Oman: a new approach to predict them on seismic

Kazdal, Recep A. (PDO - recep.ra.kazdal@pdo.co.om) and Glen William (CGG)

Prediction of Permian Upper Gharif channel belts is a major challenge for the exploration and field development activities in Central and North Oman. The declining portfolio of Gharif exploration opportunities and increasing constraints for additional oil production are pushing geoscientists for an in-depth understanding of the distribution of these sands. The Upper Gharif sand units are discontinuous thin channel bodies, difficult to correlate at field scale and not always in pressure communication. At a time when most of the Gharif fields in Central Oman are entering secondary recovery activities (water flood), identification of connected sand bodies through geophysical and geological means, is of utmost importance. The main challenge is to image the complex distribution of intertwining channels on seismic. The approach presented here is a combination of forward modeling of the well data and visualization of the seismic data. A convergence between the expected seismic response and what is observed, allows the geoscientist to make inferences about the likely presence of sand. The individual sand bodies are quite thin (2-5 m) and below seismic resolution, but variations of the net-to-gross of stacked channels may be seen on seismic. One example shown is from Mabrouk field in North Oman. The seismic response suggests a good correlation with the synthetic seismogram models. Sand development appears to be associated with troughs (negative) on the seismic, and shales with peaks (positive). Moreover, wider troughs seem to correspond with higher net-to-gross. Hence, visualization of troughs might help to detect the net-to-gross distribution. This observation needs further confirmation, but may open avenues for improved picking of injector or producers well locations. Similar observations have been made at Barik, Hasirah, Hawqa Saih Rawl, and Zauliyah fields, where wide troughs can be correlated to high net-to-gross systems, whereas tramlining patterns correspond to low net-to-gross.

(137-Oral) Seismically constrained integrated reservoir modeling of the Al Huwaisah field, North Oman

Keating, John (PDOjohn.m.keating@pdo.co.om), Mohammed Mugheiry (PDO), Chia Fu Hsu (Shell) and Ron Nelson (Shell)

The billion barrel STOIIP Al Huwaisah field is a large, low-relief, faulted dip closure with a thin oil column. It produces from the Aptian (Lower Cretaceous) Shu’aiba Formation, which consists of complex, rudist bearing, shelf margin deposits. Matrix heterogeneity is locally compounded by faulting and fracturing giving rise to highly variable production behavior. Integrated study of the field was driven by a need to understand and improve production performance and plan for future field development. The field is covered by 3-D seismic of 1990-2001 vintage. Volume interpretation and image processing techniques enable a new interpretation of key horizons and faults. A new structural framework, velocity model and depth model for the field have been developed. Seismic inversion was also used to constrain porosity modeling. Seismic facies, attribute analysis and inversion help to identify gross depositional environments (large channels, shoal, lagoon) and determine reservoir/nonreservoir. Faulting and fracturing have a major impact on fluid movement through the reservoir and are important for well targeting and completion. Seismic attributes were integrated with abundant well data (approximately 60 km Borehole Image log) to provide multiple fracture realizations for reservoir modeling. Integrated reservoir modeling allowed the historical performance of the field to be matched for the first time. A number of wells have been drilled to realize opportunities in newly mapped structural highs and reservoir sweet spots based on the current study. These were also picked to avoid seismic discontinuities. Successful wells show high production rates (increase in net oil of about 300 cubic meters/day) and have opened new areas of the field. All wells are now targeted with reference to seismic attribute volumes to minimize drilling losses and maximize production by avoiding potential water bearing features.

(382-Oral) Data-driven internal multiple elimination targeted for land data

Kelamis, Panos G. (Saudi Aramco - panos.kelamis@ara mco.com), Kevin E. Erickson (Saudi Aramco), Daniel A. Nietupski (Al-Khaleej) and Robert L. Clark (Digicon)

The prediction and subsequent elimination of internal multiples in land data is probably one of the most challenging subjects in seismic data processing. The time and space variability of the multiples, their small velocity discrimination compared to primary events, combined with low signal-to-noise ratio and weak reflectivity at the target, are a few of the key obstacles which make the multiple elimination process complex and quite often cumbersome. Using principles from Common Focus Point (CFP) technology a data-driven, internal multiple prediction approach, targeted for land data was developed. It requires no assumptions about the earth model and can be applied pre- and/or post-stack. The kinematics of internal multiples generated by a specific boundary are computed by convolutions of the corresponding CFP gathers. These CFP gathers are essentially half-redatumed shots with sources at the surface and receivers at datum. Thus, in order to compute internal multiples, a layer-stripping, top-down procedure is required that can handle all the interfaces above the target of interest. As an alternative to the boundary-related approach, a layer-related scheme is also introduced in which all the downward reflecting effects of the overburden can be accounted for. The application of the layer-related internal multiple algorithm requires, besides CFP gathers, a fully re-datumed version of the surface data with both sources and receivers at a chosen depth level, also called gridpoint gathers, from which the anti-causal part is used to predict the upward reflecting part of the internal multiples. A series of land field datasets from Saudi Arabia was used to demonstrate the effectiveness of the proposed technique, as well as its impact in exploration and developmental drilling.

(247-Oral) Reducing drilling risk in the Tertiary and Upper Cretaceous using refraction processing and visualization of 3-D seismic data

Kellogg, Stephen C. (Saudi Aramco - stephen.kellogg@a ramco.com), Ean Craigie (Digicon) and Barton A. Payne (Saudi Aramco)

Shallow karsts that are present in parts of the Arabian Peninsula pose significant risks to exploration and development drilling. At the very least, drilling programs must plan on encountering sudden circulation losses and/or bit drops as the drill string approaches a void space. This drives up drilling time and costs. The worst case is the total loss of a well, abandonment, and redrilling. Current production 3-D seismic data is designed for deep reflection targets, from about 5,000 ft down to 17,000 ft. Due to parameters such as bin and array dimensions, very shallow reflection resolution is inadequate to image these voids. We have developed an alternative, simple, and fast method of detecting these shallow karst features by employing seismic refraction data, and then performing a series of attribute analyzes, taking advantage of the latest 3-D visualization techniques. Conceptually, ray-paths will be highly-distorted when encountering a karst feature, with back-scattering/absorption. As a result, the energy recorded at receivers near karsts will be substantially reduced relative to receivers where no karsting is present. Using multiple refractors, we have found that it is possible to track these differences and map them in the near-surface after a simple and fast processing flow. The results can then be passed on to the drilling engineers, who can alter their well plan accordingly, to minimize the risk of drilling through these problematic zones. The results have proven very encouraging when compared in a ‘blind’ manner against well histories. These techniques were applied in a problematic area of the southern Ghawar field.

(469-Poster) Depositional environments and diagenesis of Cretaceous (Albian to Maastrichtian) strata of Abadan plain of the Persian Platform, southwestern Iran

Keyvani, Forooz (NIOC - forooz_kayvani@hotmail.com) and Ezat Heydari (Jackson State U)

Sedimentology, diagenesis, and reservoir quality of Cretaceous (Albian to Maastrichtian) strata were investigated in Azadegan, Kooshk, Khoramsahr, Darkhuain, Mahshahr, and Tangu oil fields of the Abadan Plain province of the Persian Platform in southwestern Iran. Formations studied include (oldest to youngest) Kazhdumi, Sarvak, Ilam, Gurpi, and Tarbur. The overall characteristics of these formations were controlled by relative sea-level fluctuations, although compressional tectonics associated with the closing of the Neo-Tethys Ocean and basement faulting also played minor roles. A relative sea-level rise initiated deposition of organic-rich shales of the Kazhdumi Formation (Albian-Cenomanian). The limestones of the overlying Sarvak Formaton (Albian-Turonian) formed during the highstand. A major sea-level fall at the Cenomanian-Turonian boundary exposed carbonates of the Sarvak Formation. However, the uppermost portion of the Sarvak Formation was deposited during an early Turonian sea-level rise, and was subsequently exposed due to a minor sea-level fall. The shales of the Laffan Member (Coniacian) of the Ilam Formation covered the Cenomanian-Turonian unconformity during the early stages of a major sea-level rise. The limestones of the Ilam Formation (Coniacian-Santonian) were deposited during the highstand and possibly early lowstand. A major transgression resulted in deposition of dark gray shales of the Gurpi Formation (Campanian-Maastrichtian). The Tarbur Formation (Maastrichtian) formed patch reefs along the shelf margin. A disconformity separates Maastrichtian and Danian (Early Paleocene) in this area. The study revealed a variety of lithofacies indicative of strand plain, tidal flats, coastal plain, carbonate sand shoals including tidal bar belts, inner shelf, middle shelf, patch reef, barrier complex, outer shelf, mounds, distal deep marine pelagic depositional environments. Major diagenetic alterations occurred along the Cenomanian-Turonian unconformity. Meteoric processes resulted in karstification, generation of porosity and permeability, and dolomitization, forming good reservoir quality strata in the Sarvak Formation. Burial diagenesis affected all units, in some cases increasing porosity and permeability and in others decreasing them.

(271-Oral) Integration of geological and dynamic data for constructing 3-D geological models: an IOR study from the Ahwaz field, southwest Iran

Khanna, Mohit (Statoil - mkha@statoil.com), Arne Linjordet (Statoil), Torgrim Jacobsen (Statoil), Tor Røsaasen (Statoil), Mohammad Sharafoddin (RIPI) and Ahmad Miryaan (NISOC)

An IOR study has been performed on the Asmari Formation of the Ahwaz field. As a part of this study a 3-D geocellular model was constructed based on reservoir characterization from 338 wells and a regional interpretation of the depositional systems of the Asmari Formation. The model was used as a basis to match 40 years of production history and to predict the outcome of different drainage strategies. This study describes the construction of the 3-D geological model. The Ahwaz field spans 420 sq km in the Zagros area of southwest Iran with 400 m-thick Asmari Formation as the main oil-producing reservoir unit. It consists of interbedded sandstone, shale and carbonate intervals of Oligocene to Miocene age. 3-D geomodeling was performed on a simulation grid design with more than one million cells to avoid upscaling, thereby saving time, cost and avoiding mathematical inaccuracies. The main input to the model was core data, petrophysical log interpretation and dynamic data. In the current model a multi-stage modeling technique was used to include all the wells in the field. Another unique technique that was implemented involved the use of production data to constrain the distribution of sands and carbonates. The production data was comprised of PLT, PI, and perforations. Pre-processing included the generation of a bias log from all the production dataset. A 3-D parameter was generated from this log by interpolation to co-condition the carbonates in object modeling. This bias log was also used during the upscaling of the well data at grid resolution. A 3-D shale volume parameter generated from more than 300 wells by interpolation, was used as a co-conditional parameter for locating shales in the 3-D geomodel. A general markedpoint process algorithm was used to model the lithofacies picked from wireline log interpretation. Core descriptions provided the input for the definition of lithofacies. Petrophysical modeling was performed on the results of the object modeling to simulate effective porosity and log-derived permeability. Water saturation was modeled using a J-function for different lithofacies. The resulting simulation model matched the vertical static pressure and major saturation distribution for 228 wells quickly during initialization.

(207-Oral) Onshore Abu Dhabi 4-D seismic pilot test survey 1998-2003

Kleiss, Erik B.J. (ADCO - ekleiss@adco.co.ae), Peter Melville (ADCO), Samer Marmash (ADCO), Abu Baker Al-Jeelani (ADCO), Majid Al-Mirza (ADCO), William Soroka (ADCO), Andrew Sewell (WesternGeco), Hafez Al-Kamal (WesternGeco) and Paul West (WesternGeco)

In 1998 a first high-spec onshore 3-D seismic survey was acquired over a major onshore oil field in Abu Dhabi, covered at surface by sand dunes up to 60 m high. A repeat test in 1999 confirmed that short-term repeatability was good, and noise levels low enough to detect seismic differences predicted from reservoir modeling. It showed that for a successful 4-D, the 1998 acquisition parameters should be repeated as-perfect-as-possible and surface conditions should not have changed too much. In 2003, a dedicated 4-D survey was acquired over part of this field. Since the first survey, surface conditions have changed and new wells and surface infrastructure came in place, so not all vibrator and geophone locations could be exactly repeated. All this leads to small variations in recorded signal and noise. The main purpose of the 2003 pilot survey is to confirm the expected good seismic repeatability after five years, and if successful, to verify and adjust the dynamic reservoir model. This study presents how the 2003 repeat survey was acquired using economized–yet well-repeatable–acquisition parameters. Data examples illustrate local changes in source and receiver spread, surface conditions, statics, recording procedures and instrument changes. Some tests compared 1998 to 2003 data, and also differences resulting from different source configurations in 2003.

(350-Oral) Enhanced productivity of fractured carbonate reservoir through cross-dipole shear-wave logging in the Bakr-Amer field, Gulf of Suez, Egypt

Klimentos, Theodore (Schlumberger - klimentos@slb.com), Tahe Elzefzaf (GPC) and Maher Omara (GPC)

Earth stress patterns give a general indication of the most likely fracture orientation or maximum stress trend. Nonetheless, local variations and the effects of localized structures, such as large faults, can modify the stress pattern, counter-acting or adding to the regional stress. Thus, such a local stress and fracture profile information can be useful to many petroleum exploration and development related aspects; such as; (1) selecting perforation intervals and strategy; (2) planning hydraulic fracturing operations; (3) optimum well placement; (4) wellbore stability; (5) sand production; and (6) hydrocarbon migration. In this study, cross-dipole shear-wave anisotropy logs, acquired in several wells of the Bakr-Amer field in the Gulf of Suez, were used to enhance the productivity of the Nullipore carbonate reservoir by determining the orientation and magnitude of the principal horizontal stresses and detecting major fractured intervals. Currently, the Bakr-Amer field accounts for 55 percent of the General Petroleum Company’s (GPC) daily oil production. Approximately 40 percent of this amount is solely produced from the uppermost reservoir known as the Nullipore. The cross-dipole shear sonic data were processed to obtain oriented fast and slow shear-waves. This information was then used to determine the direction and magnitude of the insitu earth stresses and the orientation of fractures. Zones showing significant shear-wave anisotropy were detected as open-fracture systems using the shear-wave anisotropy data in conjunction with the Stoneley-wave chevron patterns and other available logs. These intervals were subsequently perforated and produced significant amounts of hydrocarbons. Further application of this technique in several wells of the Bakr-Amer field, proved that the Nullipore reservoir productivity is primarily controlled by the flow contribution from natural fractures. New highly-deviated wells were completed over the Nullipore on the basis of the newly-acquired information, and excellent results were obtained. Moreover, older wells were restudied and recompleted on the same basis, and a large increase of production was attained.

(351-Oral) NMR applications in geomechanics

Klimentos, Theodore (Schlumberger - klimentos@slb.com)

The Biot elastic constant (a) of a rock is a poroelastic parameter that relates stress and pore pressure (Pp). It describes how compressible the dry skeletal frame is with respect to the solid material composing the dry skeletal frame of the rock. According to Biot, a measures the ratio of the fluid volume squeezed out to the volume change of the rock if the latter is compressed while allowing the fluid to escape. This implies that a should be a strong function of permeability, although other factors such as rock compressibility, lithology, and cementation may also be influential to some degree. In petroleum-bearing rocks, Terzaghis effective stress principle may not always be valid. Accordingly, a modified effective stress (σeff) is a function of the Biot constant: σeff = σtot - α * Pp. Despite the great significance of a, only a limited amount of laboratory work on its determination has been reported in the literature. Our recent experimental results showed that permeability has a much stronger effect on a than porosity. Laboratory experiments on two Middle Eastern rock samples having the same porosity (18 percent) but different permeability exhibited very different values of static a. Based on extensive laboratory measurements, a novel empirical equation was developed for the determination of a as a function of permeability and rock elastic moduli. Then, rock permeability and elastic moduli, which were derived from NMR and dipole sonic imaging logs, were used as inputs into the empirical equation for the determination of a. This process led to a more accurate evaluation of geomechanical applications (effective earth stresses, wellbore stability and sand-free maximum drawdown pressure). Moreover, it was found that the NMR-derived capillary pressure in conjunction with permeability may be very useful in determining a sand-free maximum drawdown pressure, especially when there is water influx, which commonly causes sand production by reducing the capillary pressure between sand grains.

(407-Poster) Prospecting for the upper Wasia Mishrif Member in Eastern Saudi Arabia

Knowlton, Andrew M. (Saudi Aramco - andrew.knowlton @aramco.com.sa) and Tariq U. Usmani (Saudi Aramco)

The Mishrif Member of the late Cretaceous Wasia Formation has been largely overlooked as an exploration target since the early days of drilling in the Eastern Province of Saudi Arabia. The first exploration wells found sweet gas in the Mishrif Member at Dammam Dome and this remains the only producing field from the Mishrif in the Eastern Province. The Mishrif was deposited as an alternation of transgressive, highstand carbonates and clastics in a relatively quiescent marginal to shallow-marine setting. The widespread mid-Turonian tectonic event disrupted this depositional cycle and the upper Wasia was subsequently eroded over many emerging structural highs in Eastern Arabia. The pre-Aruma unconformity defines the boundary between the subcropping Mishrif Member and the overlying Aruma Formation. Many potential hydrocarbon traps occur on the flanks of Turonian-activated structures where the Mishrif Member subcrops and is sealed by the shales of the Aruma Formation. Major play risks include hydrocarbon charging of the Mishrif reservoir and sealing capacity of the Aruma Formation.

(400-Oral) Providing easy, quick and secure access to exploration data on the intranet

Kok, Al A. (Saudi Aramco - al.kok@aramco.com), Ibrahim A. Al-Ghamdi (Saudi Aramco) and Sa’id A. Al-Hajri (Saudi Aramco)

Geoscientists require quick and easy access to data for their day-to-day decision making process. For large organizations, these seemingly simple and straight-forward requirements are often complicated by data stored in disparate databases with very little integration. This study discusses the challenges, benefits and the technologies used for providing unprecedented access to exploration data easily, quickly and securely. By leveraging developments in web-enabling technologies, the goal of providing easy and quick access to exploration data anytime and anywhere on the intranet was accomplished at the Saudi Aramco Exploration organization. Virtually all strategic data stored in disparate databases can be queried and viewed easily, along with a map display via a web browser. In addition, tens of thousands of on-line documents stored in a document management system were made easily accessible. Also, by providing the capability to visualize the data via a map display, quality checks have been made easier, thus improving data quality. This implementation, called E-Data, was accomplished by utilizing the web and light-weight GIS technologies as well as the spatial database and document management technologies. E-Data is designed to be cross-browser compliant and platform independent. Data access security is implemented by leveraging the Oracle database authentication mechanisms. To minimize implementation effort, a widely-used, off-the-shelf light-weight GIS was used to facilitate the web map display and to access spatial data in the spatial database.

(272-Oral) 2-D SRME performance in the presence of streamer feathering and structural dip

Koeninger, Chris (WesternGeco - chris.koeninger@wes terngeco.com), Ian Moore (WesternGeco), Dave Monk (Apache), John Bedingfield (Apache) and Ron Roberts (Apache)

Wave-equation based, data-driven multiple prediction algorithms, such as DELPHI’s SRME, can provide a highly-accurate prediction of surface multiples regardless of the complexity of the medium. While acquisition and processing methods for 3-D prediction of multiples are an active area of research, the prediction of multiples from conventional (narrow azimuth) 3-D marine data using enhancements to the 2-D SRME method is of considerable practical importance. It is well-known that 2-D implementations of SRME can be subject to significant kinematic errors in the presence of 3-D effects, such as cable feathering or cross-line structural dip. However, much less is known about the combined effect or relative importance of these sources of error. The widespread use of the method indicates that, in many cases, the data pre-conditioning and adaptive subtraction steps applied before and after the computation of the multiple model compensate effectively for these errors, though the performance of the method can be difficult to predict. This study discusses the results obtained on a data set from the Middle East with emphasis on illustrating the effects of cable feathering and structural dip on 2-D SRME models of free-surface multiples. A recently developed tool is used to predict the timing errors associated with specific modes of surface multiples, taking into account the relevant geological, data acquisition, and data processing characteristics. The error prediction method is extremely fast compared to an SRME-type prediction of the multiples themselves. There are many uses for the errors predicted by such an analysis, including input to the survey design, prediction and QC of the performance of the demultiple algorithm, optimization of data processing parameters, and even potentially, correction of the predicted multiples for the errors involved. The main conclusion of the study is that when the cross-line dips of the multiple generators are small, 2-D SRME predicts the travel-times of free-surface multiples accurately and is reasonably insensitive to cable feathering. As the cross-line dip increases beyond a few degrees, travel-time errors become large, and sensitivity to cable feathering is significant. In such situations, minimizing cable feathering during acquisition by appropriate survey design and the use of steerable streamer technology would be beneficial for improving multiple attenuation results.

(88-Oral) The role of mechanical stratigraphy in structural evolution and trap styles in the Zagros

Koopman, Anton (Shell - anton.koopman@shell.com)

Deformation styles in Alpine compressive belts are critically influenced by stratification and multi-layered characteristics of lithological units, at a variety of scales. Distribution and intensity of fractures correlate with the specific characteristics of mechanical stratigraphy at any of these scales. Dedicated outcrop studies contribute to understand the complex structural relationships in the prolific hydrocarbon province of the Zagros Mountains, where double plunging anticlines constitute the primary trap style. These folds are neither periodic nor cylindrical along their axes, and did not develop by any single growth mechanism. At trap scale, most anticlines resemble models of conjugate kink bands, composed of conjugate pairs of externally rotated, relatively planar limbs, with kinked but relatively rounded hinges at either side of a moderately arched and generally broad crestal zone. Relatively box-shaped or chevron-like fold shapes prevail in well-bedded stratified intervals, whereas more rounded shapes prevail in the competent members of the mechanical multilayer. Thrusts are secondary and subordinate to folding, propagating beyond the locking position of the folds. Localized volume constraints associated with excessive external rotation across primary mechanical boundaries within the fold limbs leads to secondary accommodation of shortening by flexural slip, stepped bedding plane thrusting and generally disharmonic parasitic folding, controlling details of trap geometry, fracture distribution, and fracture bedding relationships. Effects of deep-seated strike-slip, primarily organized according to preexisting basement fabrics, are diffusely distributed across the major detachments and appear to overprint the progressively evolving detachment folds in the cover. There are indications that this overprint resulted in spaced corridors of small-scale faulting and enhanced fracturing, positively affecting permeability and production performance of the main reservoirs in the Zagros Mountains.

(343-Poster) Paleosedimentary environment of the Burgan sandy tongues in the Arabian Plate

Kordi, Masoumeh (IOOC - mkordi@geologist.com) and Sayed H. Kazemeini (IOOC)

Burgan sandy tongues of the Albian Kazhdumi Formation are major productive reservoir in the Middle East. High porosity and permeability of these sandstones and the existence of shales layers–either as source rock or caprock in this formation–have provided all the required conditions for hydrocarbon accumulation. Extension of the Burgan sands was determined by producing subsurface maps and stratigraphic cross-sections. Well log correlation, petrophysical properties and petrography were studied to determine lateral and vertical facies variations, basin analysis and sedimentary environment modeling. Based on lithology and reservoir characteristics, the Kazhdumi Formation is divided into five members (from bottom to top): C (poor reservoir); B (main reservoir); A (secondary reservoir); Dair limestone; and Upper Kazhdumi (Nahr Umr member). Structural, isolith, sand-to-shale ratio, and sandstone percentage maps show that the thickness of sandstones increase to the west, and this trend is roughly perpendicular to the main NW-trend of the basin. Lobate pattern and interfingering development of sands on subsurface maps show that they were formed in a riverdominated, foot bird delta. Paleocurrent and source of sediments in this delta originated from the area of Kuwait and Saudi Arabia. Stratigraphic cross-sections illustrate the wedge shape development of sandy tongues and confirm the deltaic environment. Petrographic studies show that the C member contains black shales, siltstone, glauconite and phosphate grains that indicate deposition in the pro-delta. In this member layers of sandstone are recognized. The B member mainly contains loose sands with more than 75 percent quartz, which become coarser and cleaner from bottom to top that confirm a deltaic environment for these sediments. Roundness, sphericity and abundance of quartz grains show that the source of sands was dominantly sedimentary rocks older than Albian that have undergone more than one sedimentary cycle. The succession of sandstone, siltstone and claystone in the A member indicates a deltaic environment. Towards the east of the Arabian Shield, the Burgan sandstones pass to shale and limestone with an interfingering pattern in a river-dominated delta. The great extent and thickness, and favorable reservoir conditions in the Burgan paleodelta, created the most prolific sandy oil fields in the world.

(399-Oral) Integrated Marrat sequence stratigraphy-depositional model of Divided Zone and Kuwait in relationship to key Marrat boundaries of Arabian Plate

Kumar, Sukhdarshan (KOC - kumars@kockw.com) and Hanan B. Al-Qanaei (KOC)

An integrated sequence stratigraphic study of the Marrat Formation in the Divided Zone between Kuwait and Saudi Arabia and Kuwait was undertaken. It used all 96 wells and improved our understanding of the depositional facies, correlativity and distribution of the key Marrat producing reservoirs. The study focused on building depositional environment models for each of the sequences, and relating them to the key flooding surfaces and sequence boundaries of the Arabian Plate (AP). The study positions the Upper Marrat of Kuwait with the Middle and Lower Dhruma elsewhere in the plate. The age dating of the Marrat sequences is limited by scarce biostratigraphic data, and is based primarily upon correlation. Due to the impact of tectonic movements, some of the sequence boundaries are sharp, not completely preserved, or correspond to non-deposition. Within the Jurassic sequence stratigraphic framework, five sequences are identified in the Marrat succession, and are named from bottom to top as JSEQ-1 to JSEQ-5. A suite of composite logs, core and ditch cutting data, and selected master logs for key wells, were used for defining and correlating the various flooding surfaces and sequences boundaries. Transgressive, highstand, lowstand system tracts were identified and named from bottom to top as MR_00 to MR_70. The new stratigraphic framework not only forms the basis for reservoir correlation within various Marrat fields discovered in the past two decades, but also provides a tool for inter-field reservoir correlation in the Divided Zone and Kuwait. A depositional model for each of the sequences was also developed on a semi-regional scale. This study is likely to enhance the understanding of Marrat depositional environments and contribute to resolving some of the outstanding Marrat boundary issues in the Arabian Plate.

(49-Oral) Right-lateral wrench fault system in offshore ex-divided zone

Kusaka, Hajime (Al-Khafji JO - kusaka@shabakah.net.sa)

The Khafji, Hout and Dorra fields are located in offshore ex-divided zone in the Gulf. The three fields are elongated and asymmetrical domal structures aligned in a NE-SW direction. The discovery of three fields are based on 2-D seismic data. However better understanding of the tectonics of the area was obtained after acquiring 3-D seismic data in the late 1990s. KJO conducted a 3-D seismic survey over Khafji and Hout fields in 1997 and over Dorra field in 1999, for a total of about 1,000 sq km. Advanced processing techniques and extensive interpretation of the 3-D data provided the structural relationship between the three fields and among the fields and tectonic origin. Two major right-lateral wrench faults trending in a NE direction were identified. The northern fault runs through the Dorra and Hout fields. The southern fault runs through the Khafji field and is believed to extend to the south into the Safaniya field. The two faults were generated at the Aruma-Wasia unconformity in late-middle Cretaceous time with NE-directed compression. The trend of the northern wrench fault plane changed in the middle of the Hout field from NE to NNE in direction. A couple of flower structure planes branched out from the main wrench fault, and extend up to the Rus Formation in the central part of the Hout field. An antithetic fault striking in a NW-SE direction divides the field. A structural ridge between the two main wrench faults trends in a NNE direction, and extends from the southern part of the Hout field to the northern part of the Khafji field. Coherency cube reveals several faults along this ridge. The Khafi, Hout and Dorra trend was generated by a pair of wrench faults trending in a NE direction.

(347-Oral) Geomechanical reservoir characterization of a giant fractured carbonate field, offshore Abu Dhabi

Kutty, Abdurahman (Zadco - akutty@zadco.co.ae), Chawki A. Dabbouk (Zadco), Hamad Bu Al-Rougha (Zadco), Mauro Cimolai (CoreLab), Ned Etris (CoreLab)

A geomechanical reservoir characterization was performed in two carbonate reservoirs in an offshore Abu Dhabi field. The ultimate objective for this study was to develop a fully-coupled geomechanical simulation model that more accurately identifies the controls on fluid flow within the reservoirs. The giant field is a very low-relief anticlinal structure consisting of distinct, stacked carbonate reservoirs that hold billions of barrels of light oil. After a primary production phase that started in 1968, a pattern water-flood was introduced in 1983. However, substantial early water breakthrough prompted a range of comprehensive studies to assess the reservoir performance drivers. The present study was initiated to understand the influence of geomechanical effects on reservoir performance, due to variations in reservoir pressure, saturation and temperature caused by production and injection operations. Geomechanical factors could potentially dynamically change the permeability within the formation, thus controlling fluid movement over the field’s history. This study presents the characterization workflow for geomechanical attributes in the reservoirs. Geomechanical attributes like elastic Young’s modulus, Poisson’s ratio, bulk modulus, compressive and tensile strengths, in-situ stresses, shear moduli, and rock compressibilities from 233 wells were computed using various log data. Direct hard data, like core mechanical properties and minifrac tests available in limited wells, were used to calibrate and validate the log-derived geomechanical properties. Mapping and 3-D modeling were subsequently used to ensure spatial consistency and geologic feasibility. A mapping of the initial stress state of the reservoirs was generated. The geomechanical characterization of the reservoirs formed the necessary input for the coupled flow simulation to investigate the effects of rock mechanics on regional flow performance. The results of the geomechanical characterization suggested that the dominant directions of stress have changed significantly over time, and that the current stress field is that of a strike-slip stress regime as opposed to the extensional regime that existed in the past, as revealed from the seismic record. Arising from this study, a newly identified conjugate fault/fracture system across the field was established which proved to be consistent with the pattern of water breakthrough from field operations. This insight added significant complexity to the structural model of the field. Clarification of the geomechanical influence on the reservoir dynamics of the formation has proven to be a complex issue with extended requirements for accurate reservoir data.

(172-Oral) Integration of seismic impedance inversion into the geomodel

Lalande, Severine (Total - severine.lalande@total.com), Youssef Al-Mehairi (ADCO), Shakir Al-Kowaildi (ADCO), Dominique Chenot (Total), Jean-Luc Piazza (Total), Philippe Prat (Total), Jo An Hegre (Total) and Leon Barens (Total)

This study describes the final part of a joint integrated seismic reservoir characterization project on a major carbonate reservoir of an onshore Middle East field. The reservoir geomodel building captured well information, the 3-D structural and seismic information obtained through seismic interpretation and impedance inversion. The aim of this seismic characterisation project was to improve the reservoir management by optimizing well placement, geosteering and geomodeling. These goals imply: (1) deriving the lateral and vertical heterogeneities in the reservoir; and (2) characterizing the reservoir porosity variations, including the location and volume of some non-reservoir ‘dense’ bodies embedded in it. Stochastic inversion was carried out with inhouse software GeoInv. The stochastic approach enables us to compute a family of equi-probable impedance inversion volumes that are both constrained by seismic and well data. For this inversion, a family of 100 realizations was computed using 22 input wells and a mean wavelet extracted from 6 high-quality wells. Each inversion contained 785,000 traces. The mean and the standard deviation (Sigma) were computed from the 100 realizations and analyzed. Next, the probability of a cell to be higher than a described threshold was computed from the inversion family. From these probabilities, the locations of the high impedance or low density zones in the reservoir were delineated and their volume calculated. The results were entered into the geomodel built in time at a one millisecond sampling. The 38 million cell impedance cubes were read in the same stratigraphic time grid, in proportional layers of the reservoir formation, and then read into depth into the geomodel. The depth model was then converted into porosity, estimated stochastically using over 100 wells present in the geomodel. The models corresponding to mean impedance cubes, mean plus and minus a proportion of Sigma were prepared for an uncertainty approach. The porosity models were produced with different methods either deterministic or stochastic, constrained at the wells and then pore volumes computed for these different options.

(217-Poster) Iran’s Balal field development: full subsurface integration within a buy-back contract

Legorjus, Claude (Total - claude.legorjus@total.com), Pierre Bergey (Total), Sabrina van de Beuque (Total), Fabrizio Bolondi (Agip Iran BV) and Khosrow Farhangi (NIOC)

The Balal field, located offshore Iran, has been developed for oil production from the Upper Arab reservoir by Elf Petroleum Iran (Total Group) in association with Bow Valley Energy and AGIP Iran BV. The development was carried out under the terms of a buy-back contract signed in April 1999 with the National Iranian Oil Company. The discovery well 3W-1, drilled in 1967 identified three oil-bearing reservoirs (Upper Arab, Khatiyah and Shu’aiba). Two appraisal wells were drilled in 1968 and 1972. Following acquisition of a 3-D high-resolution seismic survey in 2000 and the drilling of the first development well (BL-1P) in 2001, a comprehensive study of the reservoirs and the overburden was conducted by an integrated subsurface team for risk assessment and development optimization purposes. A 3-D geomodel was built encompassing state-of-the-art micro-structural core analysis, structural seismic interpretation, stratigraphy, sedimentology, seismic impedance inversion, petrophysics, fluid synthesis, tests interpretation and reservoir static and dynamic modeling. Major uncertainties identified prior to the development included OWC positions, compartmentalization, fracture network behavior, aquifer strength and flank dip. Based upon the subsurface study the major identified risks were losses while drilling, shale instability, pressure maintenance and water breakthrough. The development strategy was optimized on a few key aspects (reservoir target locations, data acquisition, well drilling and completion design, reservoir monitoring design, pump installation timing, etc). Recommendations have been proposed to further reduce uncertainties during the field production life. Within the frame of the buy-back contract, the development of the Upper Arab reservoir occurred between 2001 and 2003 with the successful drilling of a total of 10 production and water injection wells. During the development drilling static and dynamic appraisal was conducted on the economically un-proven Khatiyah and Shu’aiba reservoirs. Well results confirmed the major findings of the subsurface study: extension of the fracture network toward the flanks of the structure, and well deliverability.

(332-Poster) Salt movement, tectonic events and structural style, in the central Zagros fold and thrust belt, Iran

Letouzey, Jean (IFP - jean.letouzey@ifp.fr) and Shahram Sherkati (NIOC)

Structural analysis of surface and subsurface data in the Dezful Embayment, the northern Fars, and the High Zagros provinces shows that the presence of the infra-Cambrian Hormuz and the Miocene Gasharan salt layers has a direct control on the structural style. Both are levels of major disharmony and decollement during the Neogene Zagros folding. There is some evidence of Hormuz salt movements triggered by tectonic events: Permo-Triassic Tethyan rifting along High Zagros NW-trends, and Cretaceous-Paleogene obduction and compressive events with basement reactivation of NS Arabian trends. The emergence of Hormuz evaporitic plugs in this zone, is closely associated with major fault zones related to the Zagros folding event. Sandbox models analyzed with X-ray tomography suggest that thrust and wrench fault occurrences were influenced by preexisting salt domes (weak zones). Driving mechanisms of Hormuz salt rising and extrusion was the squeezing of preexisting salt domes. Local pull-apart and wrench fault deflection probably also allowing for rapid salt-piercing.

(45-Oral) Evolution of near-surface models for correction of statics in Saudi Arabia

Ley II, Robert E. (Saudi Aramco - robert.ley@aramco.com), Mohammad A. Al-Homaili (Saudi Aramco), Mike A. Zinger (Saudi Aramco), Ralph Bridle (Saudi Aramco), Robert W. Rowe (Saudi Aramco) and Ameera Al-Mustafa (Saudi Aramco)

Prospective structures in Saudi Arabia are getting both deeper and of smaller relief. Thus the methods for determining near-surface correction statics have to evolve to meet the challenge. Several approaches have been used or developed to resolve near-surface issues: (1) single- and multi-layer modeling; (2) refraction statics; (3) tomography; and (4) geostatistics. One of the first methods used in Saudi Arabia was the single-layer velocity model. All of the 42,000 upholes were interpreted and the average velocity to datum at the uphole location calculated. These uphole average velocities were then contoured to create the single-layer model. This model has worked well for most of the prospective area. For complex near-surface conditions and topography this simple model requires some extra corrections, for 2-D lines in the form of a time shift varying spatially which was applied to the data. However this is very interpretive and difficult to apply to 3-D. So rather than acquiring expensive uphole data, conventional seismic records were analyzed for near-surface velocity layer information. From these analyzes a multi-layer velocity/depth model can be created. Adding the layer travel-times from surface to datum gives the static correction. For 3-D acquisition 2-D shot gathers have been extracted and the thickness, and the velocity has been contoured. Using grid manipulations, the 3-D model was determined. The layer models have improved the focusing of the horizons in many difficult areas. However, there are always more problems to solve. Large amplitude and short wavelength local anomalies can still be present. Other methods were tried to get a better handle on the near-surface statics, including a geostatical approach using vibrator base plate data, refraction statics and tomography.

(224-Oral) Frequency-dependent anisotropy and implications to fracture characterization

Li, Xiang-Yang (BGS - xyl@bgs.ac.uk), Enru Liu (BGS) and Mark Chapman (BGS)

Fractures are critical for ensuring economic oil and gas production in tight formations of otherwise low permeability reservoirs (e.g. carbonates). Attempts have been made to infer fracture properties from seismic data through the use of fracture-induced seismic anisotropy, which has achieved considerable successes in the estimation of fracture orientation and intensity. However, this approach is limited to fractures at the micro-scale, and reveals little information about the facture system at the meso- (formation-) scale. Moreover, there is no control of the fracture size and its distribution. Recently, it has been observed in several cases that anisotropy may change with seismic frequency. As usual, this phenomenon of frequency-dependent anisotropy is often treated as noise and has not been utilized properly for fracture analysis. Our recent modeling development reveals that the frequency-dependent anisotropic behavior depends on a characteristic fracture size. Thus it is possible to fit this parameter to the observed frequency-dependent changes and to measure the fracture sizes with seismic data for the first time. This model has been calibrated against laboratory measurements and verified by numerical modeling, which provides a basis for the application to field data. We invert the field data for fracture size and fracture density from a multicomponent VSP, and find that the resulting fracture size matches geological evidence. This reveals the potential to create fracture length ‘maps’ using multi-component seismic data in addition to the standard fracture density and orientation maps, effectively filling gaps in imaging sub-seismic fractures.

(225-Poster) Static correction in desert and loose terrain

Li, Xiang-Yang (BGS - xyl@bgs.ac.uk), Xiucheng Wei (BGS)

Static correction is a major challenge for seismic exploration in mountains and desert terrain with loose soil, such as in the Middle East. Desert terrains with loose soil are characterized by significant lateral variations and lack of clear vertical layering. The first breaks in seismic records from such terrains usually show characteristic features of bending events at near offsets and linear events at far offsets. Furthermore, the geo-pressure at the near-surface often varies continuously with depth, resulting in continuous depth-dependent velocity variation. Assuming an equivalent medium with quadratic velocity variation in depth (called the quadratic velocity model), we present a travel-time inversion method to perform static correction in desert and loose terrains. The method includes fitting first break times using the quadratic velocity model, separating the first arrivals into turning-wave arrivals at the near offsets and refracted-wave arrivals at the far offsets, and inverting for the near-surface quadratic velocity model. This method is simple to implement and fast to compute compared with the existing method based on tomographic approach. Applications to real data from northwest China show significant improvements in subsurface imaging, and confirm that the method is particularly useful for static corrections in desert terrains with loose soil.

(276-Oral) Improved reservoir characterization of a giant reservoir: Asmari Formation in the Ahwaz field, southwest Iran

Linjordet, Arne (Statoil - avl@statoil.com), Neil Pickard (CCL), Mohit Khanna (Statoil), Daniel Berge Sollien (Statoil), Tor Røsaasen (Statoil), Khosrov Haidari (NISOC), Ahmad Miryan (NISOC), Bijan Beiranvand (RIPI), Ali R. Shakeri (RIPI) and Zahra K. Mosadegh (RIPI)

An IOR study has been performed on the Asmari Formation of the giant Ahwaz field in southwest Iran. This study presents integrated reservoir description of the Asmari Formation as input to the construction of a 3-D geomodel used as a basis for the IOR drainage strategy. Structural definition was established by seismic interpretation on 26 2-D seismic sections. Improved volume control on the flanks was obtained. The Ahwaz Asmari Formation consists of interbedded carbonate, sandstone and shale of Late Oligocene to Early/Mid Miocene age. The Asmari Formation is penetrated by 338 wells, out of which 16 wells have recovered cores. The mixed siliciclastic/carbonate depositional environment plus post-depositional diagnesis, make macroscopic lithologic core description difficult. Evaluation of more than 6,000 thin-sections in three key wells support the geological and petrophysical interpretation. The petrophysical interpretation included mineralogy, porosity, permeability and water saturation. A water-saturation versus depth relation (J-function) was combined with fluid contacts to identify the flooding pattern. Strontium isotope age dating combined with biostratigraphy, show that the Ahwaz Asmari Formation was deposited from 30 to 18 Ma. Sequence stratigraphic correlations combined with Strontium age dating in neighbouring fields, have improved the characterization of how the Ahwaz Asmari sand/carbonate/shale arcitecture develops internally and towards the surrounding oil fields. The Lower Asmari sands were deposited in a restricted area during sea level lowstands, while the Middle and Upper Asmari were deposited over a widespread carbonate ramp and contain transgressive and highstand sands. The results were used to construct the Ahwaz Asmari geo-model.

(381-Oral) Impact of high-fidelity Radon transform on multiple and noise removal

Liu, Qinglin (WesternGeco - qing.liu@aramco.com) and Panos G. Kelamis (Saudi Aramco)

The Radon transform is one of the most commonly used algorithms in seismic data processing with specific applications in multiple and linear noise elimination. It transforms seismic data from the time-offset domain into a model space in which signal and noise can be separated by a simple muting process. Thus, the wanted signal can be reconstructed by the inverse transform. Alternatively, the noise can be modeled followed by a subtraction step in order to recover the signal. The conventional Radon implementation is characterized by two main drawbacks: (1) lack of resolution due to the finite aperture of the recorded data; and (2) failure to properly handle aliased data due to poor sampling in the offset axis. High-fidelity Radon transforms address both these issues and deliver improved resolution and increased performance on aliased input data via the integration of prior information in the algorithm. The derivation of the prior information is an important step in the performance of the high-fidelity Radon transforms. In this study, the prior information is based on a Cauchy function in the model parameters to enforce sparseness. In principle, the Gaussian, least-squares based distribution, is replaced by a distribution that induces sparseness in the model space. The significant improvement of resolution offered by this implementation makes it possible to separate signal and noise with small differences in addition to overcome issues related to aliased data. Both high-fidelity parabolic Radon transform for multiple suppression and high-fidelity linear Radon transform for strong linear noise removal have been developed. Their performance is demonstrated with a series of synthetic and field data examples. In particular, the new algorithms can handle irregular sampled and aliased data and offer true amplitude preservation.

(401-Oral) Multi-azimuth far-offset VSP: data processing and application

Liu, Qinglin (WesternGeco - qing.liu@aramco.com) and John C. Owusu (Saudi Aramco)

A multi-azimuth large offset vertical seismic profile (VSP) survey was carried out near the town of Haradh, Saudi Arabia. The purpose of the survey was to provide a better image of the target Khuff-C reservoir away from the well location. A time structure map from 3-D seismic indicates a very complex reservoir which is poorly imaged. The reflection from the reservoir is very weak and there is a significant mistie between the 3-D seismic and synthetic seismogram generated from well logs. The VSP data was acquired along four azimuths radiating from the well and intercepting three other proposed drill islands. Along each azimuth, two offset VSPs at 6,000 ft and 11,000 ft were acquired. In addition to the offset VSPs, a zero-offset VSP was acquired to tie all the offset data at the well location. Information derived from the VSP data would be used to determine the location of future developmental wells in the area. The processing of the data posed a number of technical challenges. Because of the very large source offset, the data quality–particularly in the shallow part–was poor, and therefore a high resolution three component processing flow was adopted. The processing flow included horizontal rotation, parametric wavefield decomposition, predictive deconvolution, VSPCDP mapping and Kirchoff migration. The results of the P-wave and PS-wave VSP migrated images show a better spatial resolution and improved structural image at the target reservoir due to the higher bandwidth of the VSP data. There is a very good tie between the synthetic seismogram, the zero-offset and offset VSP. The combined P and PS images provide a better understanding of the stratigraphy within the reservoir.

(200-Oral) Jurassic stratigraphic boundaries of the southern Mesopotamian Basin, Kuwait

Lomando, Anthony J. (ChevronTexaco - alomando@kockw.com), Sunil K. Singh (KOC), Aref Al-Doheim (KOC), AbdulAziz Ali Sajer (KOC) and Naema Hussain Al-Ajmi (KOC)

The Jurassic Period in the Kuwaiti sector of the Mesopotamian Basin is a complex, highly cyclic suite of carbonates, evaporites and shales. A recent KOC exploration review was tasked with challenging previously published paradigms of stratigraphic zonation, sequences and the occurrence of local and regional unconformities. Critical importance was placed on evaluating major sequence boundaries. The Early Jurassic is characterized by several depositional cycles within the productive Marrat Formation. Biostratigraphy, cyclostratigraphy and seismic data were used to test the notion of a late Toarcian-Aalenian unconformity (base AP7) reported in many regions of Arabia. The Middle Jurassic Dhruma-Sargelu cycle was tested to see if the late Bathonian–Callovian hiatus extends from the basins of central and northern Saudi Arabia, across the Rimthan Arch into the southern Mesopotamian Basin. The Late Jurassic Najmah Formation, the regional organic-rich carbonate source rock, reflects more of a basinal anoxic restriction than a major deepening event, but culminates in a series of carbonate debris flow units. These terminal units may be the initial indicator of a Late Jurassic tectonic pulse in combination with a low-stand ice house spike in the Jurassic green house world. This pulse, probably reactivated along some Paleozoic structures, was the cause of continued basin restriction and segmentation, and controlled the deposition of the thick Gotnia-Hith evaporite system. The boundary between the evaporitic Hith and transgressive Makhul Formation shales was tested for evidence of a Late Jurassic regional unconformity (top AP7). The approach of target testing pre-existing paradigms has clarified the nature of the Jurassic section in Kuwait in support of continuing exploration efforts.

(409-Oral) Stacking velocities as geopressure indicators in Ghawar and Red Sea areas, Saudi Arabia

Loretto, Thomas (Saudi Aramco - thomas.loretto@aramco.com)

The feasibility of overpressure detection from seismic data is assessed and compared in the Eastern Province (Ghawar field) and the Western Province (Red Sea) of Saudi Arabia using lab measurements on core plugs, seismic stacking velocity analysis, mud weight profiles and formation pressure tests. The lab tests were used to define a velocity-pore pressure relationship which was then used to predict the impact of overpressure on stacking velocities in well-indurated rocks. Stacking velocity fluctuations were compared to compaction trends in the Western Province, and velocity changes predicted from well cemented rocks in the Eastern Province. Mud-weight profiles and formation-pressure tests were used to locate vertical and lateral changes in overpressure. It was found that overpressure-induced changes in stacking velocity, which approximates Vrms, should be on the order of 100 m/s in the Eastern Province. Stacking velocity attributes were mapped, to determine if they correlate to presence of geopressure as indicated by mud weight logs. Little correlation to geopressure-induced drilling hazards was found. Data from the Western Province revealed a more optimistic scenario. Because the sonic log behavior in the Western Province seems driven primarily by compaction, as opposed to lithology, overpressure detection from stacking velocity seems feasible in this region. The stacking velocity profile at the overpressured location has a distinct decrease in slope at the onset of the overpressured zone. The use of stacking velocities as drilling hazard indicators in the Eastern Province should probably be directed at mapping the anomalous occurrence of high porosity and/or permeability in the Jilh formation. This could be the point of future anisotropy-related studies.

(408-Poster) Future petroleum systems of Iraq

Lunn, Grenville (PGAg.lunn@pgal.co.uk), John Scott (PGA) and Augustus O. Wilson (Saler)

Many parts of the stratigraphic succession and many areas of Iraq are only sparsely explored. This poster will summarize the main potential future petroleum systems of Iraq with emphasis on seal-source-reservoir relationships in the under explored sections of the Mesozoic and Paleozoic. Individual intervals to be presented will range from Cretaceous basinfloor/lowstand sequences through the Late Jurassic source-seal couplet, models for Triassic source systems to the Early Paleozoic oil and gas system. The poster will present data and interpretations based on petrographic, paleontological and geochemical analyses undertaken on more than 40 key Iraqi wells over the last 20 years.

(316-Poster) Reservoir characterization and history matching of a fractured carbonate and highly permeable sandstone reservoir

Lyslo, Kellfrid B. (Statoil - kebl@statoil.com), Tone Nedrelid (Statoil), Kjersti Håland (Statoil), Michael Hovdan (Statoil), Claus von Winterfeld (PDO), Mehran Azizzadeh (RIPI), Javad Honarmand (RIPI) and Ghorbanali Sobhi (RIPI)

The studied field is located at the foothills of the Zagros Mountains, near the Gulf. The reservoir consists of interbedded limestones, dolomites and clastic sediments. The aim of this study was to build a 3-D reservoir model describing the matrix properties and the fracture distribution in the reservoir. Further, the aim was to generate a history-matched, dual-porosity reservoir simulation model, from which predictions of improved oil recovery could be made. A new reservoir zonation built on a sequence stratigraphic framework was developed to improve the modeling of flow units in the field. A 3-D corner point grid was built in a reservoir model simulator (RMS) with near-orthogonal grid cell geometry. The grid is laterally identical with the simulation grid, only the vertical resolution differs. The 3-D grid was populated with stochastic realizations of a well and trend constrained facies model. The distributed facies objects (dolostone, limestone, sandstone, shale) were then populated with their specific petrophysical properties, again conditioned to well data and observed spatial data trends. Based on static geological and dynamic well data, in addition to outcrop analog data, a conceptual fracture model was established, representing the general understanding of the distribution and formation of fractures. Using this conceptual fracture model, a 3-D discrete fracture network (DFN) model was generated using ‘FRACA’. The DFN model was upscaled to ‘Full-Field Equivalent’ fracture parameters for the ‘ECLIPSE’ model. The reservoir simulation model was tuned to match the initial highly-tilted oil-water contact created by a dynamic aquifer (preproduction) and tuned to match the overall energy distribution suggested by material balance. Matching criteria for the production history were set for three main issues: (1) pressure development; (2) produced gas/oil ratios; and (3) contact movements. These criteria made it easy to identify deviations and problem areas, and the worst-offending matters were continuously improved. The result was a high-quality history matched dual porosity reservoir simulation model.

(379-Oral) Overcoming the challenges of sampling heavy oil in unconsolidated sands in the Gulf

Maizeret, Pierre-David (Schlumberger - maizeret@slb.com) and Hendrik I. de Groot (Shell)

Wireline formation testing is preferred by many operators because the technique is more cost effective than most types of well testing, and yet can gather much useful reservoir information such as representative formation pressures, permeabilities, and fluid samples. But, when applied to unconsolidated sands containing heavy oil, certain difficulties often occur, which can only be overcome by careful planning and application of advanced approaches. The Burgan reservoir in Nowrooz field in Iran, is an epitome of such a formation. The challenge was to withdraw some representative reservoir fluid while avoiding breaking the rock. The operation was made even more difficult by the fact that the sampling time had to be minimized to avoid getting differentially stuck. The results were critical to optimize the production strategy to revitalize this under-developed field. In order to constantly control the drawdown applied to the formation, the ‘low-shock sampling’ technique was used. Moreover, the optical properties of the fluid flowing through the tool were constantly monitored during the operation in order to check the mud filtrate contamination level of the sample. The results observed for this heavy oil are consistent with previous studies performed in other areas of the world. This study describes the state-of-the-art technology and techniques used to gather representative reservoir samples. All job details, from the planning phase to the execution phase are discussed, and the main results from the formation testing and sampling job are presented.

(216-Oral) Origin and magnitude of over-pressured regimes in subsurface Kuwait and their implications in well planning

Manowar, Ahmed A.M. (KOC - aahmad@kockw.com) and Ahmed Al-Edan (KOC)

Pore pressure data acquired from deep wells in the Valanginian Ratawi Shale Formation indicates the onset of overpressure in most of onshore Kuwait. The formation also represents the initiation of clastic influx after predominantly carbonate Early Cretaceous sedimentation. The Ratawi Formation is a sand/shale sequence with more or less consistent thickness between 350 and 425 ft. Sand content decreases from the southwest towards the northeast, where thin stringers of marine sands are embedded in thick shale beds and pore pressures increase rapidly. Pressure gradients show a depth-to-magnitude relationship, which varies from 0.51 psi/ft to 0.62 psi/ft at 9,300 and 12,100 ft, respectively. The onset of over-pressuring is primarily related to static loading (overburden) and originates out of compaction of predominantly shale sections in the north, where expelled water entrapped in discontinuous sand stringers of the Ratawi Formation are over-pressured. Pore pressure increases steadily in older Cretaceous carbonate formations in the southern part of Kuwait, but shows an abrupt rise in the north, probably related to varying degrees of diagenesis of these sediments. A sharp rise of pore pressure approaching lithostatic occurs within the regionally extensive Jurassic Gotnia evaporites, where water-bearing limestone stringers are subjected to maximum confining pressures. Multiple pressure reversals occur below the Gotnia, and are of varying magnitudes in different areas of the country. In the Greater Burgan area in south Kuwait, a normal pressure profile has been observed within the Najmah/Sargelu and the underlying Dhruma/Marrat sections. In Minagish field of west Kuwait, these formations are encountered deeper, both absolute pressures and gradients appear to be higher within the Najmah/Sargelu section. The Najmah/Sargelu pressures are related to generation and expulsion of hydrocarbon within this source-reservoir unit bounded by the Gotnia and Dhruma formations that provide excellent top and bottom seals. Careful collection and analyses of pore pressure data over the country enabled us to optimize casing strings and better formulate well test strategies.

(421-Oral) Some aspects of the stack response concept for acquisition geometries

Marschall, Roland (RUB - roland_marschall@hotmail.com)

The fundamental properties of a given 3-D acquisition geometry (preferably symmetric) can be evaluated based on its stack response, where the reference geometry is defined by the corresponding 3-D full-fold geometry (for which we have a receiver-line as well as a shot-traverse on each gridline, within a certain maximum offset from the centre = source position). For 3-D full-fold geometries this stack response is called the stack array. The stack response usually is established in the time domain. However, transform domains may also be used as there are the frequency and the wavenumber domains, and additional weighting schemes may be applied in each domain as well. A method will be presented and discussed, which (by using the model of having the same signal–but with different delays–on the input channels including different noises) allows for optimum array forming by applying differential statics, therefore avoiding the conventional straight stack approach for array forming. The method also takes into account variations of the incoming signal’s amplitude spectra, and therefore is applicable to both, i.e. source- and receiver-related effects. The proposed algorithm may be used not only for P-wave but also for S-wave data. Special filters may be implemented in addition to the above mentioned improved array-forming method: multi-component point grid data (i.e. vertical component and horizontal inline component data) allow the use of the phase shift of the Rayleigh wave (on the vertical component as compared to the horizontal component) to design such a special filter for improved ground roll suppression. A particular version of such a special filter will be presented as well.

(292-Oral) Static and dynamic modeling of oil in transition zones: improving oil recovery predictions from carbonate fields with large transition zones

Masalmeh, Shehadeh K. (Shell - shehadeh.masalmeh@she ll.com)

Oil-water transition zones may contain a sizable part of a field’s STOIIP, specifically in low permeable carbonate reservoirs. The field development plan may be heavily influenced by how much oil can be recovered from the transition zone. The amount of recoverable oil in a transition zone depends–among other things–on the distribution of initial oil saturation (Soi) against depth and on the residual oil saturation (Sor), capillary pressure and relative permeability characteristics as a function of initial oil saturation. Due to the general lack of relevant experimental special core analysis data, modeling both the static and dynamic properties of fields with large transition zones remains an ongoing challenge. This study will discuss the limitations of the common practices in modeling transition zones and present laboratory measurements which show that oil mobility in transition zones can be much higher than traditionally assumed. In addition, examples will be shown to address the following questions: (1) Do log and core data give the same saturation height function when using drainage capillary pressure curve and saturation exponent measured on water-wet samples? (2) How should the static reservoir model be initialized? (3) What is the impact of imbibition capillary pressure curves on sweep efficiency in heterogeneous reservoirs with large transition zone. One of the main conclusions of this discussion is that the common practice of initializing static model may lead to erroneous saturation height functions and oil in place calculations due to the effect of wettability and resultant fluid redistribution in the pore space.

(201-Oral) Optimization of a complementary field development plan by assessing subsurface uncertainties

Maubeuge, Frederic (DEZPC - frederic.maubeuge@to tal.com), Jean-Michel Guemene (Total), Gilles Vincent (Total), Thierry Charles (Total), Said Hunedi (DEZPC) and Frederic Paux (DEZPC)

For the first time on a mature field, an entire stochastic workflow has been used for optimizing a complementary development scheme. The first part of this study presents the uncertainty management process developed for this field, with the quantification and the ranking of the main subsurface uncertainties. The important conclusion of this stage was that the uncertainties on fluid contact and petrophysics were of second order in terms of impact on the well productions, compared to uncertainties affecting the gross rock volume. The structural map was therefore a very important parameter for matching 10 years of production history. Accordingly the most suitable maps were selected within the uncertainty ranges of the structural interpretation. Results of forecast simulations had strong operational consequences for the late stage complementary field development: decision of infill producer drilling. Based on several defined history matching reservoir models, a well architecture was selected and a true risk assessment was performed for the economics of the new infill well. Static and dynamic results of the infill producer, drilled a few months after completion of the study, are presented. Although more time is required to clearly quantify the impact of the well on the field performances, positive effects (additional oil recovery) are already foreseen and the operation was revealed to be economic. The achievements of such a study was only possible by the total integration of the subsurface engineering and the dedicated tools.

(130-Oral) 4-D evolution of fold and thrust belts: comparisons of analog models with the Zagros Fold Belt, Iran

McClay, Ken (Royal Holloway, U London - ken@gl.rhul.ac.uk), Tim Dooley (Royal Holloway, U London), Paul Whitehouse (Royal Holloway, U London), Jose de Vera (Royal Holloway, U London) and Adam Pugh (Royal Holloway, U London)

This paper presents a series of scaled analog models designed to simulate thrust development in oblique subduction settings such as the Zagros fold belt in Iran. The models were constructed to produce doubly-vergent Coulomb wedge thrust belts with a pro-wedge and a retro-wedge separated by an uplifted orogenic core. Models were constructed from homogeneous layered sandpacks in a 2 x 2.5 m deformation rig. Progressive evolution of the orogenic wedges was monitored using digital photography and animated for analysis. The analog experiments have investigated subduction obliquities from orthogonal (90°) to as low as 50° obliquity. Variations in sandpack thicknesses and basal detachment frictional characteristics and syn-tectonic erosion and sedimentation were also investigated. Orthogonal subduction models produce long, linear, critically tapered pro-wedge fold thrust belts parallel to the subduction margin together with a narrow, uplifted core and a steep retro-wedge thrust system. Oblique subduction models produced doubly-vergent, thrust wedges with thrust faults parallel to the margin. There was little evidence of discrete strike-slip faulting with oblique displacements being accommodated along low-angle thrust systems. Variations in sandpack thicknesses, basal detachment frictions and syntectonic erosion produced along-strike variations in thrust and fold geometries. Analysis of animations of these models shows how the thrust systems nucleate and propagate. In particular, it is clear that at any one time several thrusts are moving simultaneously. Animated models together are used to demonstrate the variations in structural styles in these thrust belts. Map patterns in the models are compared with those in the Zagros fold and thrust belt in Iran using Landsat TM data.

(402-Oral) GIS in the oil and gas exploration workflow

McLay, Kevin (PDO - kevin.dc.mclay@pdo.co.om), Roland Muggli (PDO) and Safia Mazrui (PDO)

An oil and gas exploration portfolio contains a multitude of data on potential hydrocarbon accumulations. Major challenges in managing such a portfolio are that of ensuring: (1) data is kept up-to-date; (2) a consistent evaluation with a clear audit trial is applied throughout; and (3) that data are available for the ongoing lead/prospect evaluation process. In PDO’s frontier exploration, GIS-based portfolio management tools and processes have been introduced to address these challenges. These tools support the exploration workflow from initial play generation, through data acquisition (e.g. seismic) and onto identification of leads which can then be matured into drill-ready prospects. Key datasets are now either stored and maintained via GIS or made available within it. This includes play, lead and prospect, well, geophysical and geological data. The ability to now ‘evergreen’ this data, together with the strength of GIS in integrating data, has played a key role in the successful adoption of the technology. Enhanced reporting and analysis is now possible which in turn assist in the quality assurance of the exploration portfolio and the generation of new opportunities. Key to the successful implementation of GIS tools has been the close cooperation between the geomatics discipline, the evaluation teams, and the portfolio managers. This cooperation has ensured the tailoring and adoption of the tools to meet the objectives of the workflow. Having joint ownership has greatly facilitated the rapid development and subsequent deployment of these tools. The ultimate aim for all parties is that the GIS environment will be used as an effective data and knowledge management system throughout the exploration workflow.

(34-Oral) Stochastic reservoir model for the Ratawi Oolite Reservoir, Wafra field, PNZ

Meddaugh, W. Scott (ChevronTexaco - scottmeddaugh@ chevrontexaco.com), Dennis W. Dull (ChevronTexaco), Stewart D. Griest (ChevronTexaco), B. Blake Sherman (ChevronTexaco), Daniel Justin (KOC), Sukhdarshan Kumar (KOC) and John Weston (kOC-JO)

The Wafra field is located in the Partitioned Neutral Zone (PNZ) between Saudi Arabia and Kuwait. The field produces from five intervals of which the Lower Cretaceous Ratawi (Minagish) Oolite reservoir is the oldest. The reservoir produces from grainstones and packstones deposited on a gently dipping carbonate ramp. The Ratawi reservoir has produced more than 950 MMbbls since 1956. A 12 million cell reservoir model was generated using a 143 x 200 areal grid with 417 fine layers distributed among 34 stratigraphic intervals. Porosity was distributed using sequential Gaussian simulation (SGS) constrained by stratigraphic interval. Porosity semi-variogram range parameters average 2,700 m with trend varying significantly by stratigraphic layer. Permeability was added using layer specific transforms derived from the core data. The reservoir model was modified to include the cross cutting 6,400 ft Barrier which exists in the Wafra Main Area. The origin of this flow barrier is uncertain, but may be a ‘fossil’ OWC. The 6,400 ft Barrier was defined as a separate region in the reservoir model. The porosity in the barrier was distributed using the SGS technique constrained by data and a semi-variogram for the barrier. Permeability was added using a barrier specific transform derived from core data. Water saturation (Sw) was added to the final model using a J-function that takes into account three ‘rock types’ based on permeability (> 900 mD, 12-900 mD, and < 12 mD). The earth model has been used as input for fluid-flow simulation, for well location, and related reservoir management decisions, and for OOIP appraisal.

(358-Oral) Sequence stratigraphy of an eolian gas sand: layering in the Permian Unayzah-A reservoir at south Ghawar, Eastern Saudi Arabia

Melvin, John (Saudi Aramco - john.melvin@aramco.com) and Christian J. Heine (Saudi Aramco)

In the gas reservoirs of the Unayzah-A Formation in eastern Saudi Arabia, lithostratigraphic correlations based on conventional wireline logs have historically failed to provide a geologically robust stratigraphy. Recent core and Image Log-based studies have identified a complete depositional sequence within the Unayzah-A. Thus, a base-Unayzah-A Sequence Boundary is marked by a ‘significant desiccation surface’ (SDS) that is overlain by a widespread, thin sheet of eolian sand. It is superseded by an extensive deposit of irregularly laminated and locally highly disrupted, silty, very fine-grained sandstones with rare thin siltstones. These reflect very shallow water deposition with periodic desiccation suggesting a shallow ephemeral lake environment. They terminate in a thin but widespread upward-fining unit that represents the ‘maximum extent of the lake’ (MEL). Above that horizon, facies relationships vary among wells, representing a number of terrestrial environments including erg-centre, eolian cross-bedded sandstones; erg-margin, dune and interdune deposits; deflation plain; and ephemeral lake. Cycles of deposition are recognized within each of these major facies associations. Most significantly, these can be shown to be regionally correlatable within and between the various facies tracts. When the intra-Unayzah-A stratigraphy is datumed on the MEL, these correlatable cycles are seen to be essentially flat-lying ‘parasequences’ whose origin is attributed to a fluctuating water table within the regional Unayzah setting. The stratigraphy is therefore clearly pseudo-chronostratigraphic in character, i.e. it is justifiably founded on sequence stratigraphic principles. This permits a clearer understanding of the distribution of reservoir bodies within the Unayzah-A, and predicts the occurrence of intrareservoir variability and potential compartmentalization. Reservoir characterization of these deposits is thus optimized. Outcrop analogs occur in the Permian Cedar Mesa and Jurassic Entrada Sandstones of Utah.

(383-Oral) Post-glacial rebound unconformity within the Baq’a Member of the Sarah Formation (Ashgill): sequence stratigraphic implications at the Ordovician-Silurian boundary in Saudi Arabia

Melvin, John (Saudi Aramco - john.melvin@aramco.com), Merrell A. Miller (Saudi Aramco), Owen E. Sutcliffe (ResLab) and Thomas W. Ferebee (Saudi Aramco)

The recently redefined Hawban and overlying Baq’a members of the Sarah Formation were reexamined at outcrop and in the shallow subsurface at several locations in Saudi Arabia. The Hawban Member comprises a chaotic, syn-sedimentary deformed, interval of green-gray, very poorly-sorted sandy diamictites supporting large boulder-sized contorted clasts of sandstone derived from the underlying Sarah Formation. Palynologically, it is characterized by a stratigraphically admixed assemblage comprising taxa reworked from older Ordovician sediments, as well as indigenous Ashgill marine species. Thus Hawban deposition occurred in a glacimarine setting at the end of the Gondwanan glaciation. The overlying Baq’a Member consists of two units. The lower of these is a pale gray silty shale that passes upwards into finegrained hummocky-stratified and wave-rippled sandstones. Palynologically, this gray shale is characterized by marine taxa dominated by leiospheres, with only rare reworked assemblages. It has variable thickness and infills topographic lows in a post-glacial, shallow marine environment upon the post-Hawban surface. This shale unit is overlain by a Baq’a sandstone unit that comprises stacked, cross-bedded sandstones with numerous sharp, erosional basal bed contacts, of probable braided-fluvial or estuarine origin. The uppermost beds of this facies become more argillaceous and are intensely bioturbated, suggesting the onset of marine conditions. The basal contact of this Baq’a sandstone is demonstrably unconformable across both the Baq’a shale and the Hawban Member. The Baq’a sandstone is considered to have developed in response to post-glacial isostatic rebound (uplift) of underlying units. Stratigraphically, there is clearly a hiatus between it and the older units. It is proposed that the Baq’a sandstone represents the basal unit of a major new stratigraphic sequence that may ultimately be developed in the Qusaiba Member.

(251-Oral) Slip-sweep simulation and energy test experiment

Meunier, Julien J. (CGG - jmeunier@cgg.com) and Turki M. Al-Ghamdi (Saudi Aramco)

Records of correlated and uncorrelated shot gathers were acquired by a Saudi Aramco seismic crew in southwest Yabrin, Saudi Arabia. The experiment was designed and analyzed in cooperation with CGG. The recording geometry consisted of 20 receiver lines, 3,840 channels, and 60 m intervals. Twelve uncorrelated records were acquired in three different field surface conditions (sand and gravel plains). The sweep parameters were linear upsweep, 8 to 80 Hz, and 12 seconds. The listening time was extended to 12 seconds thus enabling the generation of 36-second correlated records extending from -12 to +24 seconds. Time-frequency plots were generated from near-offset traces that showed consistent and relatively high level of harmonic noise. Distortion was significantly stronger in the gravel plains, while sub-harmonics were greater in the sand areas. We had designed a tool for fast harmonic noise evaluation using solely the sweep equation. These theoretical analyses, in combination with the time-frequency plots, led to a precise prediction of harmonic noise leakage. Analyses of the full 36-second correlated records showed contamination of the following record with airwave and sub-harmonic noise. This noise was of the same magnitude as harmonic noise contamination of previous record. With current sweep parameters, a slip time of 12 seconds presents no real risk of harmonic noise contamination. In addition to these tests, energy tests were also conducted. Various combinations of sweep lengths and number of vibrators were tested. They showed that in this area and under these conditions, ambient noise is not the major problem and that data quality improvement should come from an increase in source density rather than source strength. A slip-sweep operation with four fleets of three vibrators and double source density is a possible way to upgrade the current flip-flop operation with two fleets of five vibrators.

(54-Poster) Applications of GIS in regional geological interpretation: examples from the Arabian Plate

Middleton, David (Shell - d.middleton@shell.com), Sundaresan T. Ramamurthi (Shell) Andy Bell (Shell) and Arjen de Kam (Fugro)

As the significance of the Arabian Plate as the world’s premier hydrocarbon province continues to grow, an understanding of the geological evolution of the region is vital to the development of new play concepts and exploration opportunities. Any such regional-scale geological evaluation requires the compilation, visualisation, analysis and interpretation of large volumes of disparate geological data. Geographic Information Systems (GIS) represents a unique and invaluable tool to the geoscientist in this respect. Although traditionally used in surface evaluation, the application of GIS to the subsurface environment has become widely used in recent years. The power of GIS lies in the ready visualisation and detailed numerical and spatial analysis of georeferenced geological information, including depth, well, outcrop, seismic and structural data. The applications of GIS include the generation and interpretation of regional structure, depth, and play maps. The ability to query elements in their spatial context and on attribute information is a fundamental and most important application of the tool for geologists. 3-D functionality allows enhanced visualisation and analysis, such as the ability to ‘drape’ facies maps over structural contours of key reservoir intervals to delineate play fairways. Advanced applications include the generation of depth contour maps in the absence of seismic data, using georeferenced surface geology maps, fault data and Digital Elevation Models. This study demonstrates the power and suitability of GIS functionality in regional geological interpretation, with examples from across the Arabian Plate.

(375-Oral) Distinctive cone-in-cone horizons, macrofossil beds and palynomorph diversity events: their significance to the Silurian sequence stratigraphy of Saudi Arabia

Miller, Merrell A. (Saudi Aramco - merrell.miller@aramco. com) and John Melvin (Saudi Aramco)

A number of thin (< 10 cm) carbonate horizons displaying distinctive cone-in-cone mineralization are identified in dark gray, organic-rich mudstones of the Lower Silurian Qusaiba Member of the Qalibah Formation in eastcentral and northwestern Saudi Arabia. They are thought to have formed as a result of early diagenesis close to the sediment-water interface, and are remarkable because: (1) they are extremely widespread considering their thin stratigraphic thickness; (2) they are commonly associated with fossiliferous horizons rich in intact orthocone nautiloids and bivalves; (3) they occur in close association with regionally-correlative palynomorph events. The most widely correlatable of these is associated with cone-in-cone mineralization without macrofossils. This mineralized bed formed in an environment of minimum clastic input and/or the deepest water setting, suggesting that that particular event indicated by a palynomorph diversity ‘spike’ represents a maximum flooding surface (MFS) in this part of the Arabian Silurian. This inference is substantiated by its concurrence with the Monograptus convolutus graptolite zone, which is globally recognized as a time of sea-level highstand. Above this MFS, downlap is indicated by another correlatable horizon of high palynomorph diversity. This is also considered to represent a marine flooding event, separating discrete prograding clinothems of a highstand systems tract. The available evidence suggests that associated cone-in-cone diagenesis is most fully developed in the most distal (i.e. sediment-starved) muds of the basin. Traverses in a proximal direction identify an increased association of cone-in-cone with macrofossils that ultimately dominate, prior to disappearing as the most proximal recorded of the diversity events become associated only with silt turbidites indicative of high clastic input of these clinoforms.

(203-Oral) Towards improved geological understanding of an Early Paleozoic (Barik Sandstone Member) stratigraphic trap - the Khazzan gas accumulation, Sultanate of Oman

Millson, John A. (PDO - john.a.millson@pdo.co.om), Jamie G. Quin (Repsol), Erdem F. Idiz (Shell), Peter Turner (Birmingham U) and Ahmed K. Al-Harthy (PDO)

The Khazzan gas accumulation is a combination structural/stratigraphic trap with gas reservoired in lower Paleozoic siliciclastics of the Cambrian Barik Sandstone Member. Evaluation of significant in-place gas volume have been tempered by issues of reservoir quality and productivity, with major remaining uncertainties in gas distribution and ultimate recovery. Uncertainties to be addressed are closely linked to improved understanding of the Barik Sandstone (reservoir types, distribution, connectivity and quality) and fluid distribution over the area of the accumulation. The Barik Sandstone incorporates a variety of continental braid plain to marginal marine/offshore reservoir types. The main reservoir developments in Khazzan are contemporaneous with those in the producing Saih Rawl field to the south. Paleocurrents suggest that in addition to a well-established, fluvial-dominated source component prograding from the southeast, one or more westerly sources may have been important. The preferred depositional model suggests that repeated regressive episodes were driven by relative sea-level fall (forced regressions). An intra-Barik layering scheme has been developed which provides a potential correlation resolution of less than about 1 my giving some control on likely intra-Barik reservoir distribution, connectivity and distribution through time. Intra-Barik paleogeographic models and provenance studies hint at a distinct but subtle source/depositional control on reservoir quality. The more productive Barik reservoir in the Khazzan Gas Accumulation is attributed to a significant component of secondary porosity associated with feldspar leaching. Meaningful evaluation of the Khazzan Barik reservoir intervals that are likely to contribute to production has been developed using an in-situ stress-corrected poroperm transform defined from special core analysis. The Khazzan Barik reservoir is a ‘tight gas’ reservoir with typical permeabilities in the < 5 mD range. Crest to flank compositional variations between the Khazzan and Saih Rawl fields hint at complex intra-Barik hydrocarbon charge and flushing between the two areas.

(50-Poster) Characteristics of seismic wave fields in the offshore area between Saudi Arabia and Kuwait

Minegishi, Masato (Al-Khafji JO - minegsm@yahoo.co.jp), Katsuya Watanabe (Al-Khafji JO) and Falah Al-Anazi (Al-Khafi JO)

The seismic vintages obtained by KJO have not been sufficiently qualified for detailed geophysical and geological study of the existing reservoirs. The difficulties mainly come from the complex nature of acquired seismic wavefields, so that the conventional seismic method has failed to extract reflection signals appropriately. For achieving quality improvement, it is necessary to fully understand the characteristics of seismic wave propagation systematically and to define the problems clearly. Such a task requires a seismic wave simulation study based on an expected velocity model. In this study, the velocity model was estimated from several checkshot and VSP data, seismic velocity, and well marker information. Then, the model was used for the Finite Difference and Ray-tracing simulation. Finally, the calculated synthetic seismograms were analyzed in various ways. The result shows that strong heterogeneity of seismic interval velocity in a vertical direction causes strong multiple reflections. In addition, the relatively weak primary reflections around reservoir zones are hidden by those multiples. From snapshot views of seismic wave propagation simulation, it can be seen that two high velocity layers, as well as sea surface, are the main cause of the multiple reflections. The amount of Normal Moveout (NMO) is almost the same for both multiple and primary reflections, and any multiple elimination methods that relied on NMO difference, have not worked well. The study results can be useful in the planning a new seismic data acquisition and processing. For example, a multiple elimination method based on this study can do a better job if the velocity function of primary reflections can be estimated. The elimination result shows the effectiveness of the proposed method in the absence of other noise.

(280-Oral) Vertical hydrophone arrays for transition zone seismic exploration

Moldoveanu, Nick (Schlumberger - moldoveanu1@housto n.westerngeco.slb.com) and Mike Spradley (WesternGeco)

The near-surface geology for a typical transition zone environment consists of a water layer covering a mud layer. The water layer depth ranges from very shallow to over 10 m, and the mud layer thickness could also be variable, from very thin layers to tens of meters. The traditional way to acquire seismic data in transition zone environment is to deploy receivers, typically marsh phones, on the water bottom or to push them in the mud layer. The presence of the water layer and the unconsolidated sediments at the surface could affect the quality of the seismic data due to receiver ghosts, strong seismic reverberations and mud roll that very often contaminate the seismic records and generate a poor signal-to-noise ratio. The objective of this study is to present a new method of acquiring and processing the seismic data in transition zone environment that is based on the use of the vertical receiver arrays. A vertical receiver array is implemented with two hydrophones separated by a certain distance and deployed in the water layer or buried in the mud layer. The vertical hydrophone array gives the possibility to separate the upgoing seismic wavefield, which typically contains the primary events, from the downgoing seismic wavefield, which contains the ghosts and receiver side surface related multiples. Examples of application of vertical hydrophone arrays acquisition will be shown from seismic surveys conducted in transition zone Louisiana and Argentina. The technique could also be used in the Middle East where multiples affect seismic data. The conclusion of the study is that the vertical hydrophone array method could be used successfully to improve the seismic data quality in a transition zone environment.

(118-Oral) Early history of the Nile Delta region

Moustafa, Adel R. (Ain Shams U - armoustafa@hotmail.com) and Farid Abou-Shadi (Shell)

Detailed study of borehole, seismic, and outcrop data of northern Egypt (including the Mediterranean offshore area) has led to a good understanding of the early history of the Nile Delta region since the Oligo-Miocene. Uplift of the eastern and western shoulders of the Gulf of Suez – Red Sea rift basin controlled the Oligo-Miocene drainage around the rit shoulders. Uplift of the shoulder area in southern Sinai formed a large drainage basin in the central and northern Sinai that flowed into Wadi El Arish contributing a large sedimentary budget with good reservoir potential into the offshore Sinai region, east of the present-day Nile cone. Similar drainage of the Red Sea Hills area flowed into NW-SE fault corridors in the Sohag-Asyut-Minia area forming a large, Late Oligocene–Early Miocene delta near Faiyum. Transfer of the throw at the northern tip of the Gulf of Suez into the Cairo-Suez area created a number of fault blocks that formed local drainage basins in the northern Eastern Desert. These also flowed into the Nile Delta area. A major drop in the Mediterranean Sea level, during the Tortonian-Messinian, lowered the base level of erosion of the onshore areas. This led to an eastward shift in the Nile and exposure of the old Syrian-arc folds, after erosion of the intervening Eocene and younger rocks. Deposition of a large coarse clastic section of the Tortonian Qawasim Formation over thick shale of the Cretaceous-Lower Tertiary continental slope loaded that slope area and led to its northward tilting. Associated growth faulting, parallel to the shelf edge, formed the Nile Delta hinge zone. The arcuate outline of the hinge zone and its related growth faults formed a very large, southward plunging antiform on the downthrown side. Collapse of this antiform by normal faults formed a central (keystone) NS-oriented graben in which the Messinian Abu Madi channel flowed towards the north and northwest. Excellent reservoir sands of the Abu Madi Formation were deposited in this channel, which later formed several gas fields of the Baltim Trend. Top Serravallian erosion of the hinge zone area and northern Egypt supplied Tortonian and Messinian sediments into the low areas to the north.

(277-Oral) Fluid transfer mechanism using geochemistry in shallow oil zones of Bahrain’s Awali field

Murty, Challa R.K. (Bapco - cr_murty@bapco.net), Hisham K. Zubari (Bapco), Mark A. Beeunas (OilTracers), Mark A. McCaffrey (OilTracers) and Keith F. Thompson (Petrosurveys)

Geochemical analyses integrated with geological and engineering data has substantially improved the understanding of the mechanisms of hydrocarbon emplacement and fluid movement in shallow oil reservoirs of Bahrain’s Awali field. The field is an asymmetrical anticline, which is intensely faulted and fractured in the shallow and Bahrain zones. The shallow zones include three marine limestone reservoirs (Rubble, Ostracod, and Magwa) which belong to Upper Cretaceous Asia group. In general, the Rubble zone is composed of massive carbonates while the Ostracod and Magwa have muddier limestone. These reservoirs contain heavy and light oil distributed areally and vertically. Divergent rock types and fluid properties, and stratigraphic and structural features could impact fluid transfer between reservoirs. It is strongly suspected that syn-depositional faulting might have affected these reservoirs in addition to a major unconformity which formed during the Late Cretaceous. This erosional event completely removed the Rubble and part of the upper Ostracod in the central part of the field. Further, fault compartmentalization and the extent of fluid transfer from the three zones due to faulting affect the fluid properties. It is required to know the current oil distribution of light and heavy oil and if these phases occurred during migration or later, after reactivation of faults and reservoir compartmentalization, the knowledge of which is essential for developing these reservoirs. There is also a question whether gravity segregation or de-asphalting or bio-degradation was responsible for separation into heavy and light oils across the three zones. To investigate the lateral and vertical reservoir continuity, a geochemical study was initiated involving advanced gas chromatography techniques on oil samples from 11 wells. The methods include: (1) review of abundance of ‘interparaffin’ peaks identifiable; and (2) ‘Star Diagrams’ for finger-printing the oils with the ratios of peaks compared with the nearby wells. The C8 to C20 range is typically the most diagnostic range for reservoir continuity assessments using these diagrams. The other technique used was the ‘Slope analysis’, wherein the molar concentration profiles were used to know the accumulation and alteration. The analyses have provided compositional data that: (1) characterize the difference between oils in the shallow zones; (2) verify reservoir compartmentalization; (3) support specific geological models which explain the inter and intrareservoir fluid communication; (4) reveal reservoir oil bio-degradation events; and (5) indicate at least four discrete episodes of hydrocarbon migration into the reservoirs based on the Slope Factor (SF) analysis and several geochemical parameters.

(413-Oral) Near surface velocity estimation using ground-roll

Muyzert, Everhard (Schlumberger - muyzert@slb.com)

Near-surface velocities are used in statics and applications such as survey design and wavefield separation. In particular, the near-surface shear velocity is difficult to determine. In this study we show how ground-roll can be used to estimate the near-surface P- and S-velocity. A two-step method is used. First, the local phase-velocity of the ground-roll is measured. This can be done in the FK-domain or with a local spectral estimate such as FK-music using spatially unaliased ground-roll such as recorded by single sensor acquisition geometries. Second, the phase-velocity curves are inverted for a near-surface P- and S-velocity model as a function of depth. Tests show that it is difficult to independently resolve the P-velocity and therefore it is tied to the S-velocity model. The model is sensitive to the velocities in the top 50-100 m, and depends on the frequency range of the measured phase-velocities; the model depth can be extended with increasing lower frequencies recordings. The method also allows for determining the local direction of the shallow shear wave anisotropy. We have applied the method to a 2-D 3C seismic line from North America. The near surface shear wave velocities vary up to 100 percent along a line that crosses a dry sand area (Vs = 300 m/sec) and a wet area (Vs =150 m/sec). The obtained near-surface velocity model has an excellent correlation with a nearby shallow VSP.

(147-Oral) A well-driven processing approach for seismic imaging of subtle stratigraphic traps: case history from Murzuq basin, Libya

Nafie, Tarek Y. (WesternGeco - tnafie@cairo.westerngeco.s lb.com), Didier Wloszczowski (Repsol), Mohamed Kawan (WesternGeco) and Ali Bengheit (Repsol)

Accurate correlation between well synthetic, borehole, and surface seismic data in key wells is a fundamental prerequisite for interpreters, so that reflections can be directly correlated to the well stratigraphy. However, at present in seismic industry, the choice of surface seismic processing parameters relies on human judgment, skills and experience of the processing analyst only. Examination of this conventional processing technique shows that it fails in many cases to provide a good tie with borehole data, which in turn, does not allow reliable stratigraphic interpretation of the seismic data. This study demonstrates an alternative processing method for integrating borehole data with processing parameter selection from the earliest stage. The present processing technique is subdivided into two steps. The first step involves proper editing of the well acoustic data (sonic and density). The log editing is based on a multi-log approach and is carried out by direct interaction between borehole and seismic data. The second step is based on quantitative and objective evaluation of the processing parameter selection obtained from the integration of borehole and seismic data by means of statistical attributes calculation of the extracted wavelets. The attribute’s values define both the best correlation between the well trace and the corresponding seismic trace, and the complexity of the extracted wavelet. The present processing methodology is illustrated with data from the prospective concession NC186 in the Murzuq Basin, Libya. The main challenge for seismic technology in this area is to afford the best image of subtle unconformities. The methodology offers three major advantages over the conventional processing approach. First, seismic data show a better resolution and actual definition of sediment onlaps and evidence of the underlying unconformity surface. Second, it provides an improvement in the tie between the surface and the borehole seismic data so that events on the processed seismic data can be easily identified in terms of polarity and time. Third, it attenuates the multiple energy within the surface seismic data, so that the identification of subtle stratigraphic traps can be identified more accurately from the newly processed seismic data.

(91-Oral) Seismic challenges in early gas development

Nebrija, Edgardo L. (Saudi Aramco - edgardo.nebrija@ara mco.com)

Saudi Arabia’s gas deposits occur in Permian carbonate reservoirs and Permo-Carboniferous and Devonian clastic reservoirs at depths of 12,000 to 17,000 feet. The main challenges for the geophysicist are to resolve these deep reservoirs and extract information about their porosity, gas content, and the fractures in them. The limited frequency bandwidth of surface seismic data often fails to resolve these deep reservoirs. Since many of the future producing wells will be drilled horizontally, it is critical to determine reservoir continuity away from the pilot hole. The higher resolution possible with offset VSP surveys allows these gas reservoirs to be resolved, so that a horizontal well may be steered in a direction that ensures maximum reservoir contact. In both the carbonate and clastic gas reservoirs, well logs indicate a strong inverse correlation between acoustic impedance (product of density and velocity) and reservoir porosity. The impedance is obtained from seismic data through inversion and it serves as ‘soft data’ for the geostatistical estimation of the 3-D distribution of porosity. This integrated 3-D model of reservoir porosity forms the basis for the placement of gas development wells. In Saudi Arabia, acoustic impedance senses porosity, but not the fluid content of the reservoir. To detect gas, elastic impedance must also be known because it gives a measure of the rock’s compressibility. Since gas is compressible and water is only slightly compressible, elastic impedance detects gas in the reservoir. From P-wave seismic data, information about elastic impedance comes from off-normal incidence seismic energy. Many of these reservoirs, particularly the clastics, have low porosities due to diagenesis. Core and borehole image logs indicate the presence of fractures in these reservoirs. The probable orientations and relative intensities of these fractures can be determined from wide-azimuth 3-D seismic data since seismic velocity, amplitude, and AVO vary as a function of direction in the presence of vertical fractures. This study shows, through field examples, that seismic data contribute significantly to the early development of Saudi Arabia’s gas reservoirs because they yield critical reservoir information unavailable otherwise from the few wells drilled to date.

(92-Oral) Fracture characterization using transmitted shear waves in a 3-C azimuthal offset VSP

Nebrija, Edgardo L. (Saudi Aramco - edgardo.nebrija@ara mco.com), Bhoopal R. Naini (Saudi Aramco) and Shabbir Ahmed (Schlumberger)

In the presence of vertically aligned fractures, seismic data exhibits anisotropic behavior. The observed propagation velocity, reflection amplitude, and AVO response of compressional waves vary as a function of direction, being largest parallel to these fractures. But, the most diagnostic seismic confirmation of the presence of fractures consists of the splitting of incident shear waves into two orthogonal components that travel at different speeds – the fast shear wave polarized parallel to the fractures and the slow shear wave polarized perpendicular to them. A three-component, azimuthal, offset VSP survey was acquired over the Unayzah sandstone gas reservoir at Wudayhi field in central Saudi Arabia to determine the orientation of fractures that were suspected to contribute to gas productivity. Two multi-offset VSPs at orthogonal azimuths, and four single-offset VSPs at other azimuths, were acquired. Zoeppritz modeling using dipole sonic and density logs showed that significant compressional (P) to shear (S) conversion should occur at the top of the overlying Khuff carbonate section due to its large P-wave velocity contrast with the Sudair Shale above it. The survey results confirmed this expectation. Other interfaces higher in the section and similarly characterized by large velocity contrasts, also generated shear waves. Thus, when borehole receiver arrays placed below the Unayzah reservoir were analyzed for shear-wave splitting, several transmitted shear events could be analyzed. The resulting combination of multiple shot azimuths and offsets with multiple shear events passing through the same fractured reservoir, yielded redundant measurements of the fast shear-wave directions, all of which consistently pointed in the EW direction. This orientation matches the results derived from surface P-wave anisotropy analyses of the wide-azimuth 3-D seismic data, the orientation of borehole breakouts and maximum horizontal stress from log analysis, and the regional tectonic stress direction in the field. A time delay of 18 milliseconds occurs between the fast and slow shear wave arrivals and shear-splitting (or fracturing) starts in the lower part of the Khuff section.

(363-Oral) Multi-attribute seismic analysis for deep gas exploration in Saudi Arabia

Neves, Fernando A. (Saudi Aramco - nevesfa@aramco.com), Timothy H. Keho (Saudi Aramco) and Patrick M. Rutty (Saudi Aramco)

Gas exploration in the Permian Unayzah Formation in central Saudi Arabia is a technically challenging mission. In order to reduce the exploration risk in an area of little well control, advanced geophysical techniques were applied to a 1,350-sq km 3-D high-quality seismic dataset. These included acoustic and elastic impedance inversion, seismic facies analysis using neural networks, spectral decomposition, and coherence analysis. Since seismic data plays an instrumental role in guiding the exploration effort in the area, great care was taken in preparing it for analysis. The pre-stack time migrated data were processed to preserve relative true amplitudes, thereby making the dataset suitable for seismic attribute investigation. Multi-attribute seismic analysis revealed the existence of several meander belts and incised channels, better delineated faults, and provided useful insight about the depositional style in this area. In order to take advantage of the complementary information provided by the various seismic attributes, we employed volume interpretation and simultaneous visualization of these attributes. This study will show that the integration of all these methodologies and analysis techniques highlighted both structural and stratigraphic information that could not be readily derived from conventional seismic amplitude analysis.

(116-Oral) Surface-piercing salt domes of Interior North Oman and their significance for intrasalt hydrocarbon prospectivity

Newall, Mark J. (PDO - mark.j.newall@pdo.co.om), Jeroen Peters (PDO), Jacek Filbrandt (PDO), John Grotzinger (MIT), Mark Shuster (PDO) and Hisham Al-Siyabi (PDO)

The six surface-piercing salt domes of Interior North Oman form prominent topographic and geological features in a flat, rocky desert environment. These salt domes, situated in the central part of the large Ghaba Salt Basin, have been known since the 1950s. A geological survey of the salt domes in 2001 yielded significant new lithological, stratigraphical and sedimentological information on the rocks exposed in these outcrops. This new field data has been placed in the context of ongoing exploration efforts for deep hydrocarbon plays in Interior Oman. A wide variety of rocks is exposed in the salt domes: carbonates, clastics, volcanics, and evaporates. Constituent rocks and structural style vary considerably from dome to dome, but at surface, the main lithological elements of the diapirs are carbonates and evaporites belonging to the Late Precambrian-Early Cambrian Ara Group, the highest element of the Huqf Supergroup. Large exotic blocks of bedded Ara carbonates are well-exposed and form marked hills and ridges, allowing detailed field observations to be made on intrasalt carbonate ‘stringers’ which were carried upwards by rising diapiric salt. The close correlation of facies of the carbonate exotics in the salt domes of North Oman with Ara ‘stringer’ carbonates penetrated and extensively cored in deep exploration wells in the South Oman Salt Basin demonstrates the regional significance of the salt dome outcrops for the intrasalt ‘stringer’ hydrocarbon play in Oman. This work has implications for the prospectivity of other infra-Cambrian evaporite basins in Oman, and also for time-equivalent (Hormuz) salt basins in the Middle East.

(262-Poster) Synthesizing the density log using other wireline logs and artificial neural networks technique

Nikjoo, Mahmood (NIOC - mhnikjoo@yahoo.com), Mohammad Reza Rezaee (U Tehran), Bahram Movahhed (NIOC) and Nader Sabeti (NIOC)

The density log is normally used for determination of porosity as one of the most basic characteristics of hydrocarbon reservoirs. This log is also used in seismic interpretation of reservoir rocks. Without it basic problems may occur in reservoir characterization. Because of operational and technical limitations, the density log is not available in some zones especially in shallow depths where well diameter is large. There are also some zones and layers where bulk density readings are not reliable, e.g. the washed out zones. In our study, synthetic bulk density log was derived using the artificial neural networks technique in combination with other logs including sonic, gamma ray, resistivity and neutron porosity log. The correlation coefficient between synthetic density log values and measured density log values is about 0.912 with a slope of about 0.816. Mean relative error between synthetic bulk density log values and measured bulk density values was about 1.2 percent. These values for correlation coefficient, slope and mean relative error prove that the artificial neural networks technique can synthesize the density log from other logs.

(226-Oral) Cyclostratigraphy of the Lower Cretaceous and Jurassic of the offshore Gulf in Iran: new approach in advanced exploration

Nio, Djin S. (ENRES - enres@euronet.nl)), Mat G.G. De Jong (ENRES) and Peter Wigley (Lynx)

A cyclostratigraphic well-to-well correlation framework was established for the Iranian offshore from the northern Gulf across the South Pars (Qatar) Arch through the southern Gulf to the Strait of Hormuz. Spectral attribute analysis of facies-sensitive wireline logs was used for the downhole prediction of cyclostratigraphic bounding surfaces. The spectral attribute curves were mostly generated from gamma ray logs and show the hierarchical order of cycle boundaries as well as flooding surfaces in each well. Trends in the spectral attribute curves show time-related lithofacies variations. The cycles and lithofacies variations are assumed to be controlled by the interaction of climatic changes and regional and/or local tectonic processes. Problems and uncertainties inherent to lithostratigraphic correlations, with or without biostratigraphic age control, are largely overcome by using spectral atribute analysis of facies-sensitive wireline logs. Spectral atribute analysis is a mathematical tool which enables a time-efficient and acurate construction of a near-synchronous high-resolution stratigraphic correlation framework. The science behind this method is cyclostratigraphy, and is being used to interpret the results of the spectral atribute analysis. The cyclostratigraphic correlations extend across facies belts and enable the evaluation of regional and/or local tectonic activites during the Early Cretaceous and Jurassic. A unifying nomenclature is proposed for the study area, which is known for its many, often confusing, lithostratigraphic nomenclatures. The correlations show the large-scale architecture of the carbonate platform sedimentation, with intrashelf basins, onlap patterns and hiatuses. Cyclic depositional patterns in important reservoirs such as the Sarvak and Arab are easily recognisable as well as the lateral lithofacies variations within these cycles. Important influxes of clastic sediments within the predominantly carbonate successions can be recognised and are correlated with time-related non-clastic intervals in the basin. This detailed and time-related cyclostratigraphic correlation through the Iranian offshore area of the Gulf contributes to a better understanding of the geological development of the area and supports advanced exploration.

(366-Oral) Sedimentology of the hydrocarbon-bearing Miocene Asmari Formation, Zagros Mountains, Iran

Noad, Jon J. (Shell - jon.noad@gec.shell.com), Heiko Hillgartner (Shell) and Ali Moallemi (RIPI)

The Oligo-Miocene Asmari Formation of the Zagros Mountains of southwest Iran is one of the world’s most important reservoirs. Despite this, its sedimentology has received relatively little atention, particularly in terms of outcrop studies. This is surprising, as it can be examined in exposures within ravines cutting through the huge and striking whaleback anticlines that make up the Zagros Fold Belt. Many of these exposures occur close to existing fields, allowing the opportunity to see the reservoir at surface. Recent fieldwork has been undertaken measuring sections through the Asmari Formation, in wadis cutting through anticlines situated close to the super giant Gachsaran oil field. The Asmari limestone is typically around 500 m in thickness, and is generally subdivided into three parts. The Lower Asmari is marly in character near the base, overlain by foraminiferal and coralline algal limestones. The Middle Asmari comprises dolomitized, lagoonal limestones, while the Upper Asmari is more evaporitic. The detailed sedimentological data collected during the fieldwork has been used to develop a sequence stratigraphic framework, subdividing the Asmari limestone into four cycles, and then into 33 subordinate cycles. This framework has been applied regionally to explain the distribution of lithofacies within the Asmari Formation across the Zagros. The deposition of the contemporaneous Ahwaz sandstone member is examined, and may allow the potential stratigraphic position of lowstand wedges to be predicted. The development of the thick Kalhur evaporites to the northwest has also been addressed. The implications of these findings for undiscovered hydrocarbons are explored.

(71-Poster) A new depositional model of the Lehwair-Kharaib formations in Abu Dhabi based on thickness and lithofacies trends

Obara, Hidenori (JODCO - hobara@jodco.co.jp) and Yasutaka Shirakura (JODCO)

The Lekhwair and Kharaib formations have long been interpreted to represent a featureless carbonate platform which developed seaward (east) of a siliciclastic shoreline in western Arabia. Recent work, however, demonstrates that the platform was not flat nor featureless, but comprised a relatively complex westward-facing ramp and shallow intrashelf basin in western Abu Dhabi. This new interpretation is based upon an analysis of the distribution of grain types and thickness trends of log- and rock-based sequence stratigraphic units. Examination of gamma-ray logs in the offshore areas of Abu Dhabi revealed that the Lekhwair and Kharaib formations consist of relatively “hot” and “cool” log signatures and that these signatures commonly matched with grain types and textures. For example, grain-supported rocks tend to have a “cool” gamma-ray response and mud-supported rocks tend to have a “hot” gamma-ray response. Thus, we were able to recognize shallowing- and deepening-upward trends to develop a high-frequency sequence stratigraphic framework. Regional correlation and mapping of sequence stratigraphic units showed a consistent relationship between thickness, texture and grain types (e.g. Bacinella, Hensonella, rudists, miliolids, orbitolinids, etc.). Thick stratigraphic units are made up of grain-supported rocks with shallow-water fossils and thin stratigraphic units are muddy and/or made up of deeper-water fossils. In general, increasing thickness (mainly to the east) corresponds to shallow-marine, high-energy carbonates and decreasing thickness (mainly western offshore Abu Dhabi) corresponds to deeper water. These trends suggest that the Lekhwair and Kharaib formations accumulated in a westwardly deepening ramp into offshore western Abu Dhabi.

(294-Oral) Application of reservoir rock types in dynamic modeling

Obeida, Tawfic A. (ADCO - tobeida@adco.co.ae), Avar I. Vohra (ADCO), Yousef S. Al-Mehairi (ADCO) and Karry S. Suryanarayana (ADCO)

A dynamic model was constructed by upscaling a 3-D geological model (31 million cells) of the Lower Cretaceous Carbonate build-up in one of ADCO’s oil fields in the United Arab Emirates. The carbonate formation is the most prolific and geologically complex oil reservoir. Seventeen Reservoir Rock Types (RRT) were described based on facies, porosity and permeability. Log-derived permeability (based on a Neural Network), honoring the core permeability, was used in the 3-D geological model. Thirty faults and an areal distribution of a dense RRT were incorporated into the model based on seismic data interpretation. Different simulation grids were realized to preserve the geological heterogeneity and the RRTs after upscaling of the geological model, and the dynamic model was optimized to minimize the run time. Mercury injection data was based on RRTs, while SCAL data was screened to honor the RRTs. The dynamic model was initialized using mercury injection capillary pressure (MIPC), but gave erroneous initial water saturation distribution. The task was to develop a method to generate log-derived capillary pressure based on RRTs. A multi-regression technique was developed using Rock Quality Index (RQI), depending on the petrophysical properties, as a correlation parameter to generate J-function per RRT. The dynamic model was successfully initialized. Seventy wells were used to compare the model initial water saturation (Swi) profiles versus log Swi. The STOIP calculations were in good agreement (within 2 percent) with the geological model. Relative permeability scanning curves were generated to represent the fluid displacement, especially in the transition zone for each RRT. Average of seven scanning curves per RRT were generated. In addition, scanning curves were also generated for imbibition capillary pressures, with and without negative pressures. A history match run with imbibition capillary pressures (no negative pressures) gave the best results. History matching is continuing and good results have been achieved so far.

(25-Oral) Applications of terrestrial photogrammetry for 3-D geological structure modeling

Oeldenberger, Stefan (Intergraph - soelden@ingr.co.ae) and Vianney de Lestrange (PDO)

In recent years, the rapid development of computer technology has substantially decreased cost, effort and time required for 3-D data modeling. A variety of data sources, such as remote sensing satellite data, 3-D seismic logs and borehole data have found their way into GIS databases for cross-correlation, data analysis and advanced visualization. Terrestrial Photogrammetry is an important source of 3-D modeling data. It provides the tools and methodologies for the rapid and safe acquisition of accurate structural geology data from often inaccessible outcrop locations. Lightweight, highly portable digital cameras are available today with very high-resolution and geometric accuracy, facilitating the capture of images under field conditions. In the Middle East, the first digital terrestrial imaging trial was successfully conducted in May 2003 for PDO. A dedicated geological visualization and analysis package was used to geocode the images and to autocorrelate digital models of the cliff surfaces. Draped onto the digital surfaces, the images were converted into freely rotatable 3-D image models. Multiple images were merged and transformed into planar, orthorectified image mosaics, for 2-D display/plotting purposes and to accurately measure the heights of stratigraphic columns. The 3-D image models were also the basis for measurements to determine the extent and orientation of sedimentary and discontinuity lineaments. The dip and strike measurements were used to extrapolate bedding and tectonic planes in 3-D space and to display the measurements in a variety of geostatistical representations, for instance as histograms and stereonet projections.

(103-Oral) Thief zones are not fractured layers in the Yibal field, North Oman

Ozkaya, Sait Ismail (Baker Hughes - ismail.ozkaya@baker hughes.com) and Guy F. Mueller (PDO)

The role of faults and fault related fracture corridors as major flow conduits is well established in the Yibal field. Reservoir flow dynamics are dominated by faults and the high permeability thief zones in this carbonate reservoir. Water rises through the faults and moves into thief zones. A key uncertainty is the connection between the thief zones and layer-bound fracturing. Water stays within the thief zones without slumping by gravity even at great distances away from injectors, raising the possibility of a dual porosity system. A fracture study was undertaken to investigate the distribution of layer bound fractures and their correlation to water fingering. The study was based on borehole image logs, water saturation from open-hole logs of recent wells and surveillance data. It confirms previous well test results and points to three important conclusions. (1) At least two very high permeability strata are present in the Yibal field (the top Shu’aiba thief zone and mid-Upper Shu’aiba thief zone). (2) The reservoir has a few fractured layers. One such fractured layer occurs at the reservoir top and corresponds to a cemented interval below Nahr Umr. (3) The thief zones are not, coincident with the fractured intervals but follow layers with high porosity and permeability. Such high permeability layers are often only sparsely fractured. Conductive fractures within the fracture layers do not contribute to horizontal permeability because layer-bound fractures within these layers are not interconnected. Further improvement on the understanding of the interrelation between the thief zones and fractures can be achieved by displaying generated flattop geological cross-sections for all horizontal wells, against water saturation and faults. Furthermore, understanding reservoir wettability is essential as it may be the cause of the apparent dual porosity behavior of the thief zones since they are not fractured.

(104-Oral) Origin and evolution of Lekhwair and Dhulaima structures, North Oman Basin

Ozkaya, Sait Ismail (Baker Hughes - ismail.ozkaya@baker hughes.com) and Kester Harris (PDO)

Structural interpretation based on seismic and borehole image data reveal that the Lekhwair and Dhulaima Fields of North Oman Basin are located on a regional fault propagation fold structure over a deep seated thrust fault. The regional thrusting and associated folding took place in the Late Cretaceous. Thrust direction was from SE to NW. Some local structural highs such as Lekhwair represent fault bend folds over blind thrust faults, which are splinters of the main sole thrust fault. Other local structures such as Lekhwair East and Dhulaima A are associated with back-thrust faults. All of these thrust fault structures are asymmetric in the direction of thrust faulting and elongate in NE-SW direction perpendicular to thrust faulting. The NE-SW asymmetric fold structures of Lekhwair and Dhulaima are intersected by two rhombic sets of WNW and NNW faults which can be interpreted either as a system of conjugate strike slip faults or rhombic normal faults. There is evidence in Lekhwair A North and Dhulaima Fields, in particular, that some WNW faults are actually tear faults associated with thrust faults. These faults are characterized by buckling on one side only. This is attributed to regional tilting in NW direction during Late Miocene time. Time of fracturing, oil emplacement and fracture cementation suggest that the faults of Lekwhair and Dhulaima were re-activated during Late Eocene-Oligocene times and before the Late Miocene tectonic event. This analysis of the structural evolution allows an improved understanding of the fractures critical for field development by relating fracturing to structures and time of multi-phase fracturing to structural evolution.

(457-Oral) High-resolution, 2-D, 2,880 channel production seismic acquisition: what happened to the signal?

Pecholcs, Peter I. (Saudi Aramco - pecholpi@yahoo.com), Bob Vincent (WesternGeco), Richard Hastings-James (Saudi Aramco), Bryan R. Maddison (Saudi Aramco) and Stephen Kellogg (Saudi Aramco)

Three years ago, Saudi Aramco mobilized a 2-D, 2,880-channel, high-resolution seismic crew. This was achieved by converting the conventional 480-channel configuration from 72-geophones/channel at a 30 m group interval to 12-geophones/channel at a 5 m group interval. Tests confirmed that the digital group formed seismic image was equivalent to the analog sum, only if the cross-line receiver pattern dimension was the same. The initial 2,880-channel configuration used a single source and receiver line with a maximum offset of 7,200 m, and a source/receiver inline group interval of 5 m. If the cross-line receiver pattern dimension was reduced to 5 m, it was virtually impossible to recover the signal. We were not prepared to process seismic shot records with a signal-to-coherent noise (S/N) ratio less than one. This design was replaced by a single-source/dual-receiver line design with an in-line group of 10 m and 60 or 120 m cross-line (group-formed). Using a variable cross-line dimension proved to be very effective because optimal processing parameters could be designed for the near-surface (60 m cross-line receiver array) and the deep target (120 m cross-line receiver array). A common medium-wavelength static was derived to couple the two seismic images. Although the new design offered improved S/N ratio seismic images, the seismic processor was still challenged by significantly high levels of ambient coherent noise in the pre-stack shot records. For this purpose, Saudi Aramco selected an 18 km portion of an existing production 2-D line to record single sweep uncorrelated split-spread shot records at a 5 m interval. Application of pre-correlation signal enhancement filters will be presented and compared to conventional post-correlation seismic processing algorithms.

(315-Oral) Burial history reconstruction and thermal modeling in offshore southwest Iran

Peymani, Mohsen (U Tehran - peymani@37.com), Mohammad Reza Kamali (NIOC) and Mohammad Reza Rezaee (U Tehran)

Burial history reconstruction and thermal modeling studies were carried out on 76 wells located in the northern Iranian part of the Gulf. The results indicated that sediments in the center of the Gulf (around the Qatar Arch) have lower depth of burial compared to northwest and east. The depth of burial is maximum in the vicinity of the Strait of Hormuz. The predicted maturity model shows a good fit with maturities obtained by measuring vitrinite reflectance. In the northwest of the Gulf the Pabdeh Formation is immature and Gurpi Formation is early mature. The Kazhdumi, Dariyan and Gadvan formations are in the oil-generation window. The Surmeh Formation is at the end of the oil window and beginning of the gas-generation window. The Kangan Formation is in the gas-generation window and it is estimated that the Sarchahan (Silurian shale) is also in the gas-generation window. In the east of the Gulf, the Pabdeh and Gurpi formations are in the oil window, and near the Strait of Hormuz they are in gas window. The Kazhdumi, Dariyan, Gadvan and Surmeh formations are at the end of oil window and in the vicinity of the Strait of Hormuz they are in gas window. The Kangan Formation chiefly lies in the gas window and it is estimated that the Sarchahan Formation is completely in the gas window. In the center of Gulf only the Kangan Formation has reached the oil window, therefore the Sarchahan Formation must be at the end of oil window in this area. The Pabdeh, Gurpi, Kazhdumi, Dariyan and Gadvan formations reached the oil generation window in about Early Eocene. Timing of oil generation for the Surmeh, Kangan and Sarchahan formations are late Early Cretaceous and Middle Jurassic, respectively.

(167-Oral) Imaging complex reservoirs using single sensor seismic acquisition

Pickering, Stephen (WesternGeco - spickering@gatwick.w esterngeco.slb.com), Stephen McHugo (WesternGeco) and Anthony Cooke (WesternGeco)

Syn- or early post-deposition tectonism can often result in complex reservoir distributions, and contain a variety of lithofacies types which are not easily identified or mapped using seismic data. Some of these reservoirs can be a significant source of economic hydrocarbons, yet their exploitation is often hampered by the difficulty in identifying the distribution and quality of net pay within the field. Because they are seismically difficult to image, these reservoirs are often found relatively late in the economic history of the basin–all too often by serendipity in the search for deeper reservoir objectives. In this study, we describe a complex sandstone injectite reservoir. The gross structural and lithological complexity of the reservoir was previously only comprehended from borehole image data. This study describes the design and execution of a high-resolution point-receiver seismic survey acquisition, and the resulting pre-stack inversion workflow of the data. This dataset was used to predict the lithology and visualize the morphology of an extremely complex field. The study revealed that high-resolution seismic data can provide a greater understanding of the reservoir, revealing in this case structural detail that supports the geologic model of the field. The study also confirmed the operator’s concerns about reservoir complexity. The results revealed good predictions of reservoir facies using reservoir attribute analysis, and evidence regarding the mode of origin of the sandstone distribution in the basin.

(82-Oral) Tectonic control over Shu’aiba Formation depositional facies

Pierson, Bernard J. (ADNOC - bernard.pierson@shell.com), Rafael M. Rosell (ADCO), Naema Obaid Al-Zaabi (ADCo) and Mohamed Mahmoud Abdulsattar (ADCO)

Integrating in play fairway reviews, the wealth of geological and geophysical data available in Abu Dhabi, including new 3-D seismic data, has led to a better understanding of the tectonic evolution of the Arabian Platform. This understanding is key to predicting the distribution of depositional facies and play elements for any given play fairway. During the Paleozoic and early Mesozoic, a well-defined set of NS basement faults, bounding a number of NS, sub-parallel basement highs and lows, controlled zones of preferential subsidence and determined the distribution of depositional facies in the eastern part of the Arabian Plate. In early Aptian, at the onset of deposition of the Shu’aiba, a NW-SE regional trend of strike-slip faults, which had so far little influence on the depositional facies, became a predominant tectonic feature. This set of faults determined the location of the Shu’aiba shelf margin at the southern edge of the Bab intrashelf Basin. Rudist colonies lined the windward, southern shelf margin, but were more prolific on local highs, at cross points between the NS and the NW-SE regional fault patterns. There, spectacular rudist accumulations generated the excellent Shu’aiba reservoirs found in several giant fields in Abu Dhabi, Saudi Arabia and Oman. The eastern margin of the Bab Basin was located along a broad, subtle NS basement high, possibly offset locally by NW-SE transfer faults. Low-angle ramps lined the edge of this broad high. This morphology coupled with a leeward position of the eastern margin led to local and poor development of rudist reefs. The western margin was probably also controlled by a NS basement high, which may have generated a gentle ramp on which only patchy rudist colonies grew. The northern part of the Bab Basin may have seen the development of isolated rudist platforms over salt-cored highs.

(223-Oral) Facies analysis and organic geochemical study of the Middle Oolitic Member of the Minagish Formation, Kuwait southern oil fields

Qabazard, Suad A.K. (Kuwait U - suadkareem@hotmail.com) and Fowzia H. Abdullah (Kuwait U)

The Lower Cretaceous middle (oolitic) member of the Minagish Formation is one of the major carbonate reservoirs in the southern oil fields of Kuwait and Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. The scope of this study was to deduce: (1) the depositional environment of the Minagish Formation; (2) the post-depositional diagenetic processes; and (3) to estimate the distribution and variations in source rock potential. The investigations of the depositional and post-depositional processes were based on: (1) petrographical studies using transmitted-light and scanning-electron microscopy; (2) mineralogical analyses by X-ray diffraction and an energy dispersive analyzer in order to determine the mineral composition; (3) and to study the micro-fabrics and diagenetic features. These analyses were complemented by inorganic geochemical studies using an ICP-OES analyzer for major and trace metal contents. Organic geochemical techniques were performed based on determinations of total organic carbon (TOC) elemental composition of the organic matter (kerogen) using a LECO analyzer. Kerogen petrography was carried out under transmitted-light to identify the type of the organic matter incorporated during sedimentation. The middle oolitic member of the Minagish Formation contains a laminated organic carbonate wackestone facies that grades into peloidal and ooidal packstones and grainstones. Based on the differences in the micro-facies present, this member is classified into grain-and mud-supported textural types, and consequently is interpreted to represent a protected shelf-lagoonal setting interbedded with high-energy oolite shoals. The microfacies of the Minagish limestones consist of ooids, peloids and intraclasts with skeletal grains of foraminiferas, echinoderms, calcareous algae and shell fragments, reflecting their deposition under oxic marine conditions. Significant amounts of framboidal pyrite are restricted to the mud-supported micro-facies, indicating that reducing conditions were established through bacterial sulfate and enhanced the preservation of organic matter during the deposition of facies. The rocks are dominantly composed of carbonates, with the absence of high percentages of silicates and clay minerals, indicating limited clastic influx into the Cretaceous Arabian Platform during periods of transgression. The micro-facies contain marine, amorphous type II kerogen, providing another piece of evidence of lack in terrestrial input. The sedimentological and geochemical results show that both the coarse- and fine-grained carbonates in the middle Minagish Formation serve as a good reservoir. This is reflected in the high percentages of secondary porosity and micro-porosity. The high TOC (0.53 to 2.546 percent) contents and the abundance of high quality (type II), algal-derived marine (C/N = 4.6-25.1) organic matter in the grain- and mud-supported microfacies indicate high potential source beds but the low maturity level of kerogen shows that the oil accumulated in the pore spaces is not indigenous.

(69-Oral) Estimation of flow units using neural networks as a key to calculate permeability in a carbonate reservoir

Raafat, Khaled T. (QP - raafat@qp.com.qa)

Permeability characterization is an integral part of robust reservoir characterization, reservoir simulation and performance forecasting. The objective of this presentation is to demonstrate a methodology using neural networks complementing other petrophysical work for calculation of permeability and definition of flow units. Procedures included using Winland H.D. equation, which established that pore throat radii at the 35th percentile mercury saturation (R35) correlated well with core porosity and air permeability. R35 was used in a petrophysical model integrating sedimentological, rock and fluid properties, pressure data, cores from 6 wells and wireline logs from 33 wells. Complex pore systems of the carbonate reservoirs were characterized in terms of pore throat aperture. A strong correlation was found between R35 and core permeability. The available mercury injection samples taken from different lithofacies naturally fell in same separate classes deduced from R35 thresholds: Mega (> 10 micros), Upper Macro (5-10 microns), Lower Macro (2-5 microns), Meso (0.5-2 microns), Micro (0.2-0.5 microns) and Nano (< 0.2 microns). An excellent fit was achieved between calculated and measured permeability based on porosity-permeability transforms created for each of the above classes. To establish the same rock classes in non-cored wells, a neural network was trained using log data along with core R35. Upon achieving a very good match, the respective transforms were applied yielding permeability values that compared well with measured permeability. After further validation, the network was applied on the 26 noncored wells. Results were deemed robust for permeability characterization. Flow units were combined into 18 layers, which were used to build 3-D porosity and permeability geocellular models for reservoir simulation. In conclusion, this methodology can be used effectively for robust permeability characterization and establishing flow units in heterogeneous carbonate reservoirs with few cored wells and data.

(9-Oral) A study of natural gas origins in southern Iran

Rabbani, Ahmad R. (Amir Kabir U - rabbani@aut.ac.ir)

The Upper Permian Dalan and Lower Triassic Kangan formations contain extensive gas reservoirs in southern Iran. Gas fields in southern Iran (for example as Aghar, Kangan, Nar, North and South Pars and others) contain more than 18 percent of the proven gas reserves. Gas samples from Upper Permian and Lower Triassic gas reservoirs are composed of methane-dominated light hydrocarbon: CO2, N2 with minor quantities of noble gases. The analytical results demonstrated fairly uniform chemical compositions for gases and isotopic compositions of methane and its homologues in the section overlying the anhydrite zone (Nar Member of Dalan Formation). For example, the carbon isotope composition of methane in samples from the Dalan zones D, C, and E, and Kangan Formation varied from -39.95 to -41.28‰. This allows us to conclude that gas accumulations in the Kangan and upper part of Dalan constitute a single reservoir. Quite different characteristics are displayed by gases from the lower zone (below the anhydrite) of the Dalan Formation (zone G). This gas is characterized by considerable depletion in the light carbon isotope. For example, methane from the lower part of the Dalan Formation has 26.22‰. They also show a number of other distinctive features: significant enrichment in nitrogen; occurrence of isotopically light CO2 (-21.87‰); and an inversion in the isotope relationships of ethane and propane. These peculiarities suggest that the composition of gases in this zone was modified by the process of the thermal chemical reduction of anhydrite. The source rocks of the gas could be either the Dalan Formation itself, or Ordovician-Silurian shales.

(53-Oral) Organic geochemistry of crude oils from the northwestern part of the Gulf

Rabbani, Ahmad R. (Amir Kabir U - rabbani@aut.ac.ir) and Mehdi S. Afrapoli (Amir Kabir U)

Mesozoic and Tertiary source rocks and crude oils from the northwestern Iranian sector of the Gulf have been characterized by means of a variety of organic geochemical techniques. The Biomarker characteristics (molecular fossils) were combined with other geochemical data to interpret the sources, depositional environments, diagenesis and catagenesis processes, migration and alteration. Oil fields investigated include Abouzar, Bahrgansar, Dorood, Foroozan, Hendijan, and Norowz fields. Two groups of petroleum can be recognized on the basis of carbon isotope, biomarker investigation and statistical cluster analysis. Group 1 includes the Abouzar, Bahrgansar and Hendijan oil fields and based on the biomarker and other parameters, these oils were sourced from the Upper Jurassic to Lower part of the Cretaceous shaly rocks. Group 2 includes the Dorood, Foroozan and Norowz oil fields and these oils were sourced from the Upper Permian to Middle Jurassic carbonate rock.

(310-Poster) Facies and sequences of Devonian Jauf Reservoir, Ghawar Field, Saudi Arabia

Rahmani, Riyadh A. (Saudi Aramco - riyadh.rahmani@ara mco.com)

The Devonian System of Saudi Arabia is part of a thick Paleozoic succession of essentially siliciclastic rocks that were deposited across North Africa and the Arabian Plate. Deposition of the Paleozoic succession occurred along a very broad, shallow and relatively stable ramp shelf, extending for several thousands of kilometers along the northern and northeastern margins of Gondwana Supercontinent. In the greater Ghawar field area of eastern Saudi Arabia, the Devonian Jauf Formation is a very important gas reservoir. A detailed sequence stratigraphic and sedimentological study of the Jauf in the area revealed a complex depositional history, and a highly variable stratigraphic architecture. However, applying sound concepts of facies and sequence analysis resulted in predictive facies and sequence stratigraphic models that were proven useful in both exploration and development. The Jauf Formation comprises two third-order sequences, referred to as SQ55 and SQ60. Each one of these two third-order sequences consists of several higher-frequency sequences of the fourth-order. Third-order sequence SQ55 is dominated by a falling stage systems tract (forced regressive shoreface) which prograded from west to east across a distance of 150-200 km. The overlying SQ60 comprises a transgressive systems tract and a highstand systems tract. Depositional environments of the various facies were mostly nearshore and coastal plain and ranged from wave-dominated shorefaces, to estuarine embayment fills of tidal channels and bars to tidal and fluvial-dominated coastal plain channels. Reservoir quality rocks were mostly those deposited during the TST of SQ60 in tidal estuarine environments as channel-fills, bars and bay-fill deltas.

(499-Oral) Maximizing remaining value through integrated reservoir modeling and reservoir management: Yibal Shu’aiba reservoir, Oman

Razali, Mohammed A. (PDO - mohammed.a.razali@ pdo.co.om), Daniel Rayes (PDO), Said Abri (PDO), Hassan Behairy (PDO), Guy Mueller (PDO), Robbert Nieuwenhuijs (PDO), Patrick Hogarty (PDO) and Hamed Al Sharji (PDO)

The Yibal field is one of the cornerstones of Oman’s oil production. The field has contributed 23 percent of PDO’s total cumulative oil production and is currently supplying 17 percent of PDO’s daily production. Oil production is from the Cretaceous carbonate Shu’aiba Formation that is considered to have been deposited in a deep-water setting. The giant Shu’aiba reservoir is faulted and relatively fractured, with good porosity but low permeability. The field has been on production since 1969 and on water injection since 1972 reaching peak production in 1997 at 225 Mbbl/d. Since then the field has been experiencing a rapid decline. In November 2000, a Volume-to-Value exercise was started to focus on a reservoir study and reservoir management, aiming to arrest the decline and maximize the remaining producible volume; an extensive effort was placed on data acquisition and data management. This resulted in two dedicated teams, Study and Reservoir Management, working together in parallel. The study team is focusing on evaluating the reservoir’s uncertainties by integrated modeling, and the reservoir management team is focusing on voidage and pressure maintenance using analytical and reservoir models from the study team. A well-to-fieldwide modeling approach was applied for the reservoir study. The first step was to build a Single Well Model (SWM) to understand the key parameters on production mechanism: a total of 17 SWMs were built that were selected across the field. The second step was to build a Conceptual Model (CM) to verify the findings from the SWM: two CMs were built, at the crest and flank. The next step was to build the models that could be used as a tool for identifying the opportunities and reservoir management. This was done in two ways: Focus Area and Full Field Model (FFM). The two techniques were tested in parallel. For the FFM, it was foreseen to be impossible, due to the size of the field and the limitation on computing power. Hence the coarse 5-layer ‘cake’ model was built. Both methods were very fruitful and successful and the end-products led to more opportunities in determining the new oil, and helped focus on reservoir management strategies. Several new wells for oil production and water injection have been identified and drilled successfully as predicted from the models. Other activities such as additional perforations, ESP conversions were also successfully carried out. On the other hand, for further re-development of the field and getting maximum reserve, the decision was made to build a detailed FFM that could be used for well-to-well planning. This is currently ongoing and shows a promising outcome. As a whole, the current strategy seems to work well and has reduced the decline considerably by a third.

(210-Poster) Lower Cretaceous Upper Thamama reservoir high-resolution sequence stratigraphy, United Arab Emirates

Rebelle, Michel J.M. (ADCO - mrebelle@adco.co.ae), Christian J. Strohmenger (ADCO), Ahmed Ghani (ADCO), Khalil Al-Mehsin (ADCO) and Abdulla Al-Mansoori (ADCO)

The Upper Thamama reservoir is part of the Lower Cretaceous Kharaib Formation (Barremian) and one of the major oil reservoirs of Abu Dhabi. It consists of outer to inner ramp platform carbonates, starting with orbitolinid, skeletal wackestones and packstones overlain by algal Bacinella-rich floatstones with high micro-porosity. Towards the top of the reservoir, rudist (Toucasia) floatstones and rudstones become abundant grading into skeletal grainstones and rudstones of a high energy depositional environment. The top of the reservoir is marked by an exposure surface showing root imprints, desiccation cracks, and reddish staining. The Upper Thamama reservoir is underlain and overlain by so-called dense zones, representing restricted lagoon deposits (orbitolinids wackestones rich in pyrite, clay, and quartz grains). Traditionally, the Upper Thamama reservoir subdivision is based on lithostratigraphic correlation, using the vertical distribution of stylolites. As such an approach is not tenable for building geological (static) and reservoir (dynamic) models, a new high-resolution sequence stratigraphy framework was established. It is based on core and well-log data from different ADCO fields as well as outcrop data from Oman and the United Arab Emirates. The so-called stylolitic intervals correspond to major facies changes related to third-, fourth-, and fifth-order sequence boundaries, parasequence set boundaries, and parasequence boundaries. Early diagenetic processes follow the sequence stratigraphic framework and therefore can be predicted away from well control. The highresolution sequence stratigraphic framework allows a better prediction of the vertical and lateral distribution of reservoir quality and reservoir continuity.

(456-Poster) 3-D Seismic characterization of Nahr Umr reservoirs in Awali field, Bahrain

Reddy, Bapu C. (Bapco - bapu_reddy@bapco.net), Waleed A. Jawad (Bapco), Jonna D. Rao (Bapco) and Masoud M. Faqihi (Bapco)

The prolific hydrocarbon producers of Awali oil field are the reservoirs of Cretaceous Wasia Group, Jurassic Arab Formation and Permian Khuff Formation. The Nahr Umr Formation of Wasia Group is one of the main clastic hydrocarbon producers in the Cretaceous System. It is overlain by the Mauddud Formation with intervening shale and unconformably overlies the carbonates of the Shu’aiba Formation. The widespread occurrence of clastic sediments in the Nahr Umr Formation clearly manifests the prevalence of a marginal marine to deltaic regime with an easterly progradation in a north-south oriented depositional strike. The Nahr Umr Formation is comprised of four clastic reservoir facies; namely: Ca, Cb, Cc and Cd with intercalated shale laminations. It ranges in thickness between 360–440 ft. The youngest Ca member consists of sideritic nodules and gluconitic sands with limestone streaks. Its thickness varies between 10–20 ft and is hydrocarbon bearing. The Cb member consists of sideritic nodule layer, claystones and sandstones to argillaceous sandstones with thickness of 15–25 ft. The Cc member is a well-sorted sandstone with thickness ranges of 45–70 ft and it is the main hydrocarbon producer of the Nahr Umr Formation. The Cd is the oldest and thickest member and its thickness ranges between 250-360 ft with a wide variety of lithological assemblages such as argillaceous siltstone, argillaceous to gluconitic sandstone, sideritic layers with abundant coal laminae. The porosity and permeability of Nahr Umr sands range between 20–40 percent and 20–2,500 md, respectively. In order to bring out the sand body geometries of the Nahr Umr Formation, 3-D seismic attributes were generated by integration of petrophysical and reservoir data. Individual sand body geometries could not be discerned with 3-D seismic attributes; however, composite-window atributes were generated on Ca/Cb and Cc levels. The horizon amplitude, instantaneous frequency and phase data provided circumstantial evidence and a meaningful relationship between acoustic amplitudes and sand thicknesses. The 3-D seismic attributes were reasonably corroborated with the Nahr Umr sands in the axial part of the Awali field. The study brought out a small but distinct attribute anomaly in the southern as well as on the eastern margin, which is well validated with Khuff wells. The study suggests exploratory/stepout locations to test the prospectivity and hydrocarbon potential of these anomalies.

(177-Poster) Subsurface uncertainty management in the Sakhiya A3C reservoir in South Oman

Riyami, Qassim M. (PDO - qassim.km.riyami@pdo.co.om), Asya Rawahi (PDO) and Mike O’Dell (PDO)

There has been a string of exploration successful oil discoveries in the past five years in the Harweel Cluster in South Oman. One of these discoveries is the A3C reservoir in Sakhiya field. This reservoir is 4 km deep, lithostatically pressured, and the oil is sour. Two wells penetrate this reservoir, but only one has been tested. A large degree of subsurface uncertainty exists in gross rock volume and oil-water-contact, reservoir architecture, faults and fractures, reservoir compartmentalization, permeability level and heterogeneity, fluid properties, and other reservoir parameters. Little is known about the scale and relative importance of each of these uncertainties. An uncertainty management scheme developed in PDO for other reservoirs in this cluster was applied to Sakhiya A3C. This scheme uses sensitivity simulation studies to guide the selection of realizations, which are used in further simulation studies to determine the optimum development scenario. It was determined that there is a low uncertainty for recovery on depletion, but there is low recovery in a depletion development, also. For the case of miscible gasflood development, there is high recovery and high uncertainty. The result of the work clarifies the data gathering requirements prior to the next phase of development.

(313-Oral) The Tethyan Margin of Oman: long-term control (10–40 Ma) of the Early Triassic to Late Cretaceous turbiditic sedimentation

Robin, Cécile (U Rennes - robin@ccr.jussieu.fr), François Guillocheau (U Rennes), Spela Gorican (Ljubjana U) and François Béchennec (BRGM)

The Oman Tethyan paleomargin is a Maastrichtian inverted passive margin (ophiolites obduction) showing a continuous turbidictic sedimentation from the Early Triassic to the Late Cretaceous time. The exact paleogeographic setting is still debated: thinned continental crust versus oceanic crust, isolated basin versus open ocean, among other models. Major changes in the turbiditic systems occur in the 10 to 40 Ma time scale. Multiple systems can be defined: pure siliciclastic deep-sea lobes (Lower Jurassic), pure carbonate (ooïdic) deep-sea lobes (Middle/Upper Jurassic), carbonate slope-apron systems (Lower Cretaceous), deep-sea plain siliceous (‘radiolarite’) and carbonate turbidites. They record major events: (1) widespread siliceous sedimentation during Ladinian/Carnian, Toarcian, Kimmeridgian and Cenomanian times; (2) major siliciclastic input at the Late Triassic/Early Jurassic; (3) major progradation around the Middle/Upper Jurassic boundary; and (4) major facies shift and disconformity during the Late Jurassic (late Kimmeridgian?). They record both local and global control, from local tectonics to global sea-level variations, climate or sea-water chemistry changes. The spatial variation (facies, thickness) along this margin, and a correlation with the Arabian Platform, provide information to discriminate these factors. Of particular interest for this study is the Middle/Upper Jurassic Guwaysa Formation that consists of pure carbonate (ooïdic) deep-sea lobes. In the most proximal setting it is 300–350 m thick and consists of a repetitive motif of coarse-grained sandy units (30 to 100 m thick) overlain by a more muddy one (20 to 50 m thick) that had a duration of 1 to 10 million yeas. These features can be explained by a change in both sea level and carbonate production on the shelf.

(166-Oral) Developing a validated fractured reservoir model: an example from the Awali Field, Bahrain

Rogers, Steve (Golder - srogers@golder.com) and Yahya Al-Ansari (Bapco)

A naturally-fractured Cretaceous carbonate reservoir in the Awali field in Bahrain was modeled. Because the reservoir is relatively thin and predominantly penetrated by vertical wells, only limited information exists with which to develop the fracture model. The limited borehole image log and core data, surface fracture data, along with other indirect static and dynamic observations, were synthesized into a number of possible conceptual models that describe the distribution and performance of the various fracture components. Discrete Fracture Network (DFN) models were built and used to conduct flow simulations in order to help establish which of the static fracture models best explained the dynamic flow behavior of the reservoir. The results of the simulations revealed that two distinctive fracture models existed across the reservoir layer: one for the flanks and another for the crestal graben. Both models indicated that significant production was flowing from a conductive fault network. In order to implement these results in the simulation model, reservoir zones with increased permeability multipliers were defined: (1) for the flanks, (2) central graben, and (3) proximal to seismic faults. Thus the impact of the fractures on the reservoir was modeled using a single porosity system with permeability multipliers. This resulted in an accurate history match that was achieved within a fraction of the time that a dual porosity model would have taken.

(84-Oral) Integration of 3-D seismic, reservoir and production data to revitalize assets: Thamama case study, Rashid field, Dubai

Rorison, Philip J. (DPC - phil.rorison@conocophillips.com), Xavier Faugeras (DPC) and Jeffrey W. Yeaton (DPC)

The Rashid field is located in offshore Dubai, on a low-relief, salt-induced dome. Production is from two carbonate reservoirs. This presentation concentrates on the subsurface team’s approach to reevaluating the Thamama reservoir and the results of the horizontal drilling program. The integrated study provided a better understanding of the reservoir and proved to be a solid base for recommending new wells to be drilled on the structure in a phased redevelopment of the asset. Production from the Thamama reservoir began in 1979. Since then, it has produced continuously from vertical wells under natural depletion without significant water production. In 1999, a 3-D seismic survey provided an improved image of the reservoir’s 3-D geometry and fault architecture. The data were interpreted and, together with reservoir property data, were integrated into a fine-scale geocellular model. Finally, a dynamic model was constructed. At each stage of the study, structural, static and dynamic information (as well as uncertainties) was reconciled. The results showed that horizontal drilling and water injection would add value. Implementation of the phased redevelopment began in 2002 with a first multi-lateral, 18 years after the last development well was drilled. As results supported the model, phase 2 was implemented with the drilling of three more laterals in 2003. Phase 3, water injection would involve conversion of the first multi-lateral to reverse ESP assisted dumpflood. In conclusion, revitalization of the Rashid Thamama started with gaining a better understanding of the reservoir, its uncertainties and development options. A phased redevelopment approach was necessary to reduce risk, allowing the model to be verified by drilling results and reservoir performance before making value based investment decisions. We estimate that redevelopment of Rashid Thamama will increase the expected ultimate recovery of the field by 30 percent.

(440-Oral) Khuff and pre-Khuff imaging improvement by integrating well and seismic velocities to create a PSTM velocity field

Rowe, Robert W. (Saudi Aramco - rowerw@aramco.com.sa), Hashim A. Hussein (Saudi Aramco), Gregory Douglass (Saudi Aramco) and Michael Zinger (Saudi Aramco)

The success of deep gas exploration in the Eastern Province of Saudi Arabia relies largely on the imaging accuracy of the pre-Khuff seismic section. Unfortunately, the abundance of multiple energy, low reflection coefficients, and the depth of the target make it difficult to obtain a clear image on the seismic data. Utilizing well velocity and a preliminary geologic interpretation of key seismic horizons in the estimation of pre-stack time migration velocities, allows the geophysicist to create a more accurate velocity field. Seemingly, minor enhancements in the stack and migration velocity field can lead to significant improvements in the seismic interpretation. An analysis of regional well velocities showed a consistent velocity trend at the Jilh and below. This, combined with strong seismic response, and easily interpreted velocity of the Jilh dolomite horizon, enabled calibration of the well velocity to the 3-D seismic at that level. Using the calibration, the velocities of the Sudair, Khuff, and pre-Khuff horizons can be very closely estimated. Once estimated at a particular location, the layer velocities can then be extrapolated spatially throughout the survey, based on the horizontal velocity analysis of the Jilh dolomite event and preliminary interpretations of the Jilh, Khuff, and pre-Khuff horizons. The extrapolated velocities serve as a spatial 3-D guide function for conventional detailed velocity analysis. This technique allows the geophysicist to correctly interpret the deep primary velocity without being distracted by the strong velocity semblance response of the overlaying multiples. Use of the improved velocity field for pre-stack time migration is a key step on the path to correct imaging of the pre-Khuff section. In this study, we show in detail the steps required to implement the velocity integration/extrapolation procedure and view data examples at each step. We demonstrate the regional stability of the calibrated well velocities, as well as the stability of the Jilh dolomite seismic reflection velocity. For two surveys, the 3-D pre-stack time migrated (PSTM) velocity model resulting from the use of this procedure will be shown in conjunction with the PSTM data.

(410-Poster) Mid Miocene-Recent tectonostratigraphic evolution of the northeast Dezful Embayment, southwest Iran

Ruiz, Claudia C. (BP - ruizcc@bp.com), Stephen J. Matthews (BP), Jeremy C. Goff (BP), Bob W. Jones (BP), Nicholas J. Whiteley (BP), Masoud Shamshiri (NIOC), Farid Farmani (NIOC) and Salman Jahani (NIOC)

An interdisciplinary study by NIOC and BP has focused on the tectonostratigraphic and burial history of post-Early Miocene sedimentary sequences in the northeast Dezful Embayment. Progressive southwestward advancement of Late Tertiary compressional deformation was the main control on differential subsidence. Old basement-involved NS-trending fault systems, such as the ‘Izeh Lineament’, appear to have been important in localizing the development of oblique thrust ramps. The complex interaction of this basement structural inheritance, with several potentially active detachment levels, has resulted in substantial lateral variation in thickness and facies of the Middle Miocene to Recent stratigraphic section. The Middle Miocene–early Late Miocene sequence is up to 4,000 m thick in the Dezful Embayment; to the northeast this sequence thins to 1,500 m with pinchout of evaporites. The late Late Miocene sequence (comprising up to 2,000 m of clastic sediments) was deposited in a foredeep synchronous with nearby compressional folding; it was derived by uplift and erosion of the underlying sequence. Folds have evolved as detachment folds or fault propagation folds with a major detachment horizon in Lower Paleozoic or infra-Cambrian sediments, and additional more localized detachments in Paleogene, Cretaceous and Triassic sequences. The Pliocene sequence, comprising up to 1,000 m of alluvial fan conglomerates, was deposited synchronously with further compressional deformation and folding. Intense deformation of the post-Early Miocene sequences has occurred above a second major detachment at the base of the Gachsaran Formation evaporites, with thrusting of the Gachsaran over younger formations. Rapid uplift in Quaternary time led to the incision of deep valleys (tangs) into the rising folds.

(220-Oral) Using 3-D seismic data to define Cretaceous transpressional features in the Bahrah area of north Kuwait

Russell, David J. (KOC - drussell@kockw.com), Khalid Abdul-Rahman (KOC), Ahmed Manowar (KOC), Thakur Sanjeev (KOC), Ghaida Al-Sahlan (KOC) and Meshal Al-Wadi (KOC)

The Bahrah area lies geographically between the Greater Burgan and the North Kuwait Sabriyah fields. The Jal al Zoor Ridge, Kuwait Bay and tidal flats are located within the Bahrah area making good quality seismic data acquisition very difficult. Bahrah structure is a plunging anticlinal segment of the Kuwait Arch, intersected with faults related to Late Cretaceous and Paleogene tectonism. Interpretation of old (pre-1995) 2-D seismic data in this logistically difficult region has presented a challenge to define the local structural elements. A few wells have encountered oil pools with significantly different oil-water contacts indicating compartmentalized reservoirs within the Albian Burgan and Mauddud formations. The acquisition of 3-D seismic data covering the northern oil fields, including Bahrah has aided in the interpretation of positive flower structures and other related features. During Late Cretaceous, left-lateral transpression caused the formation of these approximately 1 x 3 km mildly-asymmetric, positive flower structures. The Mishrif sediments (Turonian) are the youngest formations that exhibit drape over the flower structures, indicating that the transpression ceased in Turonian. A post-Cretaceous graben is superimposed on the flower structure creating an interesting but difficult to interpret image of the subsurface. Although the old 2-D seismic data detected these features it is only with modern 3-D seismic data that we can confidently map these various structural elements within the Bahrah area. Although many of the faults are interpreted conventionally, spectral decomposition of the seismic data helps define the limits of the faults as well as revealing more fault zones. Areas with high fault density and structural elements of a tensile nature are considered prospective in the Mauddud limestone. With the additional fault detail afforded by the 3-D seismic data, the Burgan clastics are being evaluated in terms of isolated oil pools separated by faults. Current interpretation is that these faults provide the necessary barriers between the up-dip water and the down-dip oil accumulations. These types of plays have good potential where traditional four-way structural closures are not developed.

(449-Oral) Applications of image log analyses to reservoir characterization, Ghawar and Shaybah fields, Saudi Arabia

Russell, S. Duffy (Saudi Aramco - steven.russell@aramc o.com), R. Kumbe Sadler (Saudi Aramco), Wang Weihua (Schlumberger), Pete Richter (Schlumberger), Ramsin Eyvazzadeh (Saudi Aramco) and Edward A. Clerke (Saudi Aramco)

The complex relationship between porosity and permeability, particularly in carbonate reservoirs, is mostly attributed to the extreme range in heterogeneity of porosity types–from micromatrix to vuggy. Small-scale porosity and permeability heterogeneity significantly affects reservoir productivity. Conventional wireline logs lack the fundamental vertical resolution capability and quantification of heterogeneity to provide the needed reservoir characterization database. High-resolution image logs have ideal small-scale resolution capability as well as azimuthal borehole coverage, and can be processed to quantify extreme heterogeneity in reservoir porosity and permeability. Recent work in the Arab-D reservoir has shown that the major control on permeability is the size of the largest pore throats of the pore system (Archie C 0.1–2.0 mm and D size > 2.0 mm pores). A new methodology of processing borehole image data is applied to distinguish porosity in various pore size ranges, and hence, permeability variations and stratigraphic rock types through interpretation of specially-processed image log data after initial calibration with cores. First, azimuthal borehole total porosity is quantified. The contribution of large size pores (vugs) to total porosity is quantified and used as later input to constrain permeability values. Porosity now distributed by size range is transformed into permeability. Results from the permeability analyses are used as input into the identification of rock types. A training set of lithofacies is identified on conventional logs and used to initiate a neural network analysis of rock types. In a pilot study, wells in the Lower Cretaceous Shu’aiba Formation of the Shaybah field and the Upper Jurassic Arab-D Formation of the Ghawar field were analyzed in separate applications of the methodology. Image log-based porosity measurements have a significant impact on hydrocarbon pore volumes because of the improved resolution of the extreme range in porosity as classified by pore size. Shu’aiba rudist rudstones exhibit a clear bimodal porosity distribution and the broadest range of pore sizes, which is not detected by conventional wireline logs. Hence in this facies, conventional wireline log porosity calibrated to core data at the plug sample scale is pessimistic. The areal distribution of the bimodal porosity and corresponding permeability of 10 Darcies or more, which accounts for high production flow rates and low pressure drawdown, is limited to one part of the field most affected by meteoric diagenesis. In the upper Arab-D, small-scale vertical reservoir heterogeneities, which are characterized by high image log-derived porosity, correlate to diagenetically altered dolomite and vuggy Cladocoropsis and stromatoporoid-rich intervals that are major contributors to production. Permeability derived from image log analyses that incorporate the role of the large pore throats, and are independent of porosity, result in a permeability estimation at least one order of magnitude higher than the permeability calculated from conventional porosity-only log-permeability transforms in Arab-D Zone 2.

(27-Oral) Chasing Permian dune sandstones in Central Saudi Arabia

Rutty, Patrick M. (Saudi Aramco - patrick.rutty@aramco.co m) and Martin Rademakers (Saudi Aramco)

Interpretation of a 3-D seismic volume from central Saudi Arabia has revealed a remarkably linear valley filled with eolian dune sandstone of the Unayzah Formation. Studies of well logs, cores and test data have further enhanced our understanding of the valley trend and its significance to exploration. The valley first formed in the mid-Carboniferous, when uplift along basement faults caused a drop in base level, emplacing drainage systems that eroded at least 3,000 feet of Silurian and Devonian sediments (‘Hercynian’ unconformity). Far to the southeast, aggradation in an intracratonic basin filling with glacial meltwater decreased the slope of the entire system and generally changed the depositional style from braided fluvial and alluvial fan, to more meandering fluvial, lacustrine and eolian. In the study area, the Unayzah Formation has been found to consist almost exclusively of dune sands that developed during this latest episode of deposition. These sands fill the valley incised during the ‘Hercynian’ tectonic event, extending in thinner accumulations outside the valley. It is not known whether the sands were transported into the area by eolian processes or were instead reworked fluvial sediments, but it is clear that reservoir-quality rock lies only within the confines of the valley. Identification and mapping of this areally restricted Unayzah dune field–only possible with 3-D seismic–and the concurrent improved understanding of its origin, has allowed us to focus exploration efforts in the area.

(158-Poster) Regional distribution, lithologic characterization and petroleum potential of the Oligocene strata in the Arabian Basin

Sadooni, Fadhil N. (UAE U - sadooni@emirates.net.ae) and Abdulrahman N. Alsharhan (UAE U)

The present-day Oligocene sediments over the Arabian Basin are found only as scattered surface and subsurface patches. They were either never deposited or removed by subsequent erosion. In the northern parts of the Arabian Basin, these sediments were described from the supergiant field of Kirkuk and the neighboring outcrop of Qara Chauq Mountain, North Iraq; as well as from some oil fields in northern Iran such as Masjid-i Sulaiman. In the North Iraq localities, these sediments are formed of three vertically-stacked cycles of lagoonal, reefal, fore-reefal and basinal facies collectively known as the Kirkuk Group. In Iran, these sediments are assigned to the Asmari Formation which consists of coral and coral-algal boundstone with foraminiferal limestones. In the Syrian Tichreen field, the Oligocene Chilou Formation is a major reservoir. In southern Iraq, mainly in the oil fields along the Iraqi-Iranian borders, the Oligocene sediments are represented by a clastic succession of fluvial to lacustrine deposits termed the Mesan Group, which is partially equivalent to the Ghar Formation. In the southern parts of the Arabian Basin, the Oligocene sediments are represented by reefal-large foraminifera carbonates outcropping in Hafit Mountain along the Oman-United Arab Emirates (UAE) border, and designated as the Asmari Formation. Oligocene carbonate sediments were also encountered in offshore UAE. The remnants of the Oligocene sediments indicate that only part of the basin-margin coral build-ups and the basinal facies were preserved, and only in small and scattered areas. It is very probable that these sediments were removed by later erosion or were never deposited in other areas. The fractured reefal and fore-reefal limestones of the Kirkuk Group is the main reservoir rocks in Kirkuk oilfield where they have been producing since 1927. Gas seepages from these relatively shallow reservoirs (average depth is 800 m) are responsible for the phenomenal ‘eternal fire’ that remained glowing since the dawn of civilization. Heavy-oil accumulation (24 degree API gravity) occurs in the Asmari Formation in Mandous field (offshore Abu Dhabi). Future exploration work should be directed for the delineation of the basin-margin build-ups in other parts of the basin, where they may contain significant amount of hydrocarbons in both structural and stratigraphic traps.

(364-Oral) The Cretaceous oil systems of the Mesopotamian Foredeep Basin, southern Iraq

Sadooni, Fadhil N. (UAE U - sadooni@emirates.net.ae)

The Mesopotamian Foredeep Basin of southern Iraq hosts more than 90 percent of Iraq’s proven oil reserve. The supergiant fields are the result of a combination of contemporaneous growth due to the Hormuz salt diapirism, and the relative basement-blocks displacement. The basin was dominated during the Early Cretaceous by a low-energy carbonate ramp that underwent frequent gradual clastic invasions reflected in fluvial-deltaic-marine clastic sequences. The ramp was converted into a block-faulted shelf/platform by the end of the Cretaceous. Some of these rimmed shelves were characterized by the presence of basin-margin rudist build-ups and associated with sabkhas and lagoons to the west. Within the three groups of the lower, middle and Upper Cretaceous referred to as the Thamama, Wasia, and Aruma groups in the Gulf region, seven major sedimentary cycles are recognized. Three of these cycles are attributed to the Lower Cretaceous Thamama Group, and each of the Wasia and Aruma groups are divided into two cycles. Each cycle contains well-recognized stacked carbonate and sandstone reservoirs overlain by multiple, tight carbonate, shale and evaporite seals. Potential source rocks are either the marly limestones and shales of the Jurassic Sargelu, Naokelekan and the Chia Gara formations, or the Lower Cretaceous Balambo Formation. Indigenous source rocks within the above cycles may also generate some of the hydrocarbons. Production started during the 1940s from the fields of Zubair and Rumaila South by the Basra Petroleum Company (BPC). Other fields were developed later by Iraq National Oil Company or as joint ventures with foreign contractors during the late sixties and seventies. Most of the production comes from structural traps in gentle, structurally simple, long, homoclinal structures such as Rumaila or West Qurna. The Mesopotamian Basin might contain more potential oil systems within the deeper strata of the present fields. More reserves are likely in the stratigraphic traps of the Mishrif, Zubair, and Nahr Umr formations. Other formations such as the Hartha, Ahmadi, Khasib and Mauddud may prove to be productive outside the presently prospective areas.

(124-Oral) Using seismic inversion techniques to optimize drilling through hard Amin conglomerates of South Oman

Said, Dhiya (PDO - dhiya.mm.said@pdo.co.om), Robert Gardham (PDO) and David Conroy (Sii-ASE)

The conglomerates of the Cambrian Amin Formation pose considerable drilling challenges in the exploration for hydrocarbons in the underlying intrasalt carbonate stringers of South Oman. The Amin sediments comprise a series of hard conglomerates (unconfined compressive strength > 24 kPsi) interbedded with soft sandstones (unconfined compressive strength < 10 kPsi). Drilling through the hard conglomerate layers is very slow (averaging > 30 minute/meter) compared to the relatively fast drilling in the softer sandstones (averaging < 15 min/m). Rig time consumed in drilling the Amin section is therefore a major contributor to the total cost of carbonate stringer wells, to the extent that, whenever possible, wells were located where the Amin was least thick above domal salt structures. It was observed that the drilling rate of penetration (ROP) in the Amin formation exhibited a trend of increasing ROP (min/m) with increasing acoustic impedance (AI), as obtained from the wireline logs of carbonate stringer wells. Hence, a deterministic acoustic impedance inversion of the seismic data was performed to provide a prediction of ROP from AI at the location of an appraisal well, Rabab-2. One of the nearby wells was used as input to the computation, and another well was used as a blind calibration point, where the inverted AI was found to mimic the ROP trend. Successful utilization of the inverted AI at Rabab-2 as a prediction tool for ROP resulted in using three drill bits as opposed to a planned eight to drill through the Amin Formation. Furthermore, continued advances in drill bit technology when combined with AI’s predictive characteristics resulted in more efficient planning and drilling of the Amin conglomerates (estimated saving of 20 rig days). Crucially, teamwork and close communication between the geoscientists and the drilling team ensured that optimal decisions were made with regards to bit trips. The drilling success realized by using AI to predict ROP at Rabab-2 has made the tool a necessity for future wells in this area. To date, this drill-bit optimization has been successfully implemented in five further wells, yielding substantial savings.

(339-Oral) Fracture modeling of the Shu’aiba Formation, Idd El Shargi North Dome field, Offshore Qatar

Satterfield, Will (Occidental - will_satterfield@oxy.com), Charle Gamba (Occidental), Scott Burns (Occidental), Tim Davis (Occidental), Avnish K. Rajvanshi (QP), Paul La Pointe (Golder) and Raed Nasr (Schlumberger)

Image log, lost circulation, and seismic data were used to construct a discrete fracture network model (DFN) of the Shu’aiba limestone reservoir at Idd El Shargi North Dome field (ISND), Qatar. The purpose of the modeling was to capture both the large-scale fracture corridors mapped from seismic and well penetrations as well as background micro-fracturing visible in image logs. With the use of this method, a robust model of fracture intensity and orientation was constructed to guide water-flood planning. The Shu’aiba reservoir at ISND is a high porosity limestone with low matrix permeability. The presence of fractures both along conductive fault corridors and interspersed in the matrix creates enhanced permeability. Wells which intersect fracture trends typically produce at high volumes and recoveries relative to wells located solely in the matrix. An extensive database of horizontal image logs was used as the primary basis for the model. Fluid losses while drilling and production data were used to further constrain placement and orientation of conductive fracture trends. Following calculation of fracture intensity and orientation, the model was calibrated against available dynamic data. As a final step the DFN background fracture model was combined with the large scale fracture attributes to create simulation grid properties. The DFN model incorporated all available geologic and engineering data to calculate, on a cellular basis, directional fracture permeability, fracture porosity, and sigma factor. The DFN approach in this example, is a successful method of modeling a complexly fractured reservoir, which serves as the basis for dual permeability simulation.

(308-Poster) 3-D visualisation for non-conventional wells in Kuwait

Saxby, Ian P. (BP - saxbyip@bp.com), Hanadi Al-Qallaf (KOC) and Thomas Radford (BP)

In 1996 KOC acquired 3-D seismic surveys to cover the major producing fields. The total surface area covered 4,835 sq km (> 50 townships). Analyzing each seismic dataset alone ‘amputates’ the regional structural geology. Structurally, the fields are predominately faulted anticlines with four-way closure. The structures are a result of large-scale strike-slip movement. Simultaneous visualization of multiple seismic attributes (coherency, spectral decomposition, acoustic impedance, and amplitude) on the merged 3-D volumes allows identification of subtle faults and increased quality of well placement. Generally, the faults have little vertical offset, but act as pressure barriers and flow baffles. Calibration of the reservoir properties across the faults requires the detailed integration of all available data. During 2002, several non-conventional wells have been drilled in Kuwait in three different horizons. The wells had different technical objectives for different projects. The first project was a horizontal water disposal well in the Cretaceous Shu’aiba carbonate. The well was planned to penetrate a tight carbonate and then drill into a region of karsting. The second project was a deep sub-horizontal bedding parallel well into the Jurassic Najmah-Sargelu over pressured fractured shale. The objective was to access high gravity oil below the Gotnia salt. The third project was a horizontal infill drilling program also conducted in the Cretaceous Mauddud carbonate in conjunction with a seawater injection scheme. The wells were designed to avoid the faults that have been mapped from the new seismic efforts. In all cases, the final location was chosen from the 3-D visualization of the seismic.

(352-Poster) An assessment of undiscovered oil and gas resources of the greater Silurian Qusaiba-Paleozoic total petroleum system of the Arabian Peninsula

Schenk, Christopher J. (USGS - schenk@usgs.gov), Thomas S. Ahlbrandt (USGS) and Richard M. Pollastro (USGS)

The Qusaiba Member of the Silurian Qalibah Formation was deposited over the northern and eastern part of the Paleozoic passive margin that now forms the eastern part of the Arabian Peninsula. The Qusaiba Member is a major marine source rock for hydrocarbons from the Wadi Sarhan Basin in the north, to the Rub’ Al-Khali Basin to the south. The Qusaiba source rock interval in these basins is as much as 75 m thick, with TOC values ranging up to 20 percent and averaging about 4 percent. Qusaiba source rocks are generally thermally mature or overmature for gas in the central parts of the basins, and are thermally mature for oil along the margins of the basins, as demonstrated by the recent oil fields discovered in central Saudi Arabia. Reservoirs are mainly carbonate rocks of the Permian Khuff Formation and clastic rocks of Ordovician, Devonian, and Permian age. Six assessment units defined within the Greater Silurian Qusaiba-Paleozoic Total Petroleum System in the Arabian Peninsula were assessed for undiscovered petroleum resources, providing total mean estimates of 808 TCFG, 37 BBO, and 51 BBNGL. Most of the hydrocarbons discovered and produced to date from this petroleum system have been conventional gas fields from the Qatar Arch and from the extension of the Qatar Arch in Iran, indicating that significant potential may exist in other basins of the Arabian Peninsula. In the central part of the Rub’ Al-Khali Basin, rocks of this petroleum system may host an unconventional or basin-centered gas accumulation, although a definitive interpretation of an unconventional basin-centered gas accumulation cannot be made with data available to us. Production ‘sweet spots’ within the postulated basin-centered gas accumulation may be associated with fractured reservoirs along regional structural lineaments.

(228-Oral) Central Oman field static dune solution

Schjolberg, Kolbjorn (PDO - kolbjorn.ks.schjolberg@pdo.co.om), Christine Huegen (PDO) and Nigel Benjamin (CGG)

Recently, the Central Oman area has seen increased exploration activity at the Gharif level corrsponding to reflections at 900–1,500 milliseconds (msec) two way time (TWT). Gharif traps are low-relief structures (10-15 msec), and the reservoirs consist of thick sand bodies in the lower Gharif member, and channel sands of complex distribution in the middle and upper Gharif members. Resolving medium and long-wavelength statics has emerged as a critical success factor in determining structural closures. This is complicated by the fact that part of the area is covered by sand dunes. Historically in PDO, sand dune related static anomalies have been resolved by application of an elevation static, followed by a constant one or two-layer sand velocity correction, and a pass of refraction picking. Results were not always satisfactory, so an improved solution was needed for the Gharif exploration campaign. A pilot project was initiated as part of a joint PDO/CGG effort. A refined dune static solution was derived based on the old method. Subsequently, the method was improved by more accurate definition of the dunes, both in terms of sand velocity and dune distribution, as well as application of residual refraction statics followed by two passes of reflection static picking. An alternative method was tested based on first break picking (GLI3-D), but did not give satisfying results due to the variable distribution of near offsets. This is mainly caused by the 3-D acquisition method, combined with variable topography of incised river valleys, escarpments, sand dunes and gravel plains. The refined dune static solution has been applied to 2,250 sq km of newly acquired 3-D data, as well as old existing 3-D surveys. Results show improved stack response and seismic-to-well matches. In the Hawqa 3-D survey, where upholes were drilled, a good match between the seismic and uphole statics was observed. Once the new method was established and proven, it was applied with success on existing 3-D surveys in dune-free areas as well.

(194-Oral) Integrated 3-D static reservoir modeling of a giant carbonate field in the Lower Cretaceous of Abu Dhabi

Scott, Jason (ADCO - jscott@adco.co.ae), Andrew Gombos Jr (ADCO), Karri Suryanarayana (ADCO) and Khalid Al-Amari (ADCO)

Recently acquired 3-D seismic data over a giant onshore field in Abu Dhabi reveals new insights from the extremely high-resolution images of the reservoir structure and internal architecture. The important aspects of this data were captured in a 3-D static reservoir model and combined with a new neural network based Reservoir Rock Typing (RRT) scheme. Seismic attribute analysis within the seismic sequences allows the identification of various rock quality trends and anomalies. In the back-reef portion of the field a series of high amplitude bodies define the location and geometry of low porosity/permeability tidal channels and ponds. In the prograding fore-reef portion of the field, seismic amplitude can be correlated with transitions from good reservoir quality nearshore high-energy grainstone facies, through to deeper-water, low-reservoir-quality wackestones and packstones. Based on a limited number of cored wells in the field 15 separate RRTs have been defined. A recent log-based study utilizing neural networks has allowed the existing RRT scheme to be successfully migrated into about 350 vertical uncored wells on the field. The new static reservoir model has been calibrated with various dynamic data to improve the confidence in its validity. Production spinner logs display marked inflow anomalies that correspond to RRT boundaries. Open-hole pressure measurement data collected in recent wells, display numerous large pressure barriers that correspond to seismic sequence boundaries and changes in RRTs. The final calibrated static model successfully captures all relevant new data sources for the field. Co-visualization of various model properties allows rapid understanding of the field complexities and generates new insights into the mechanisms controlling fluid flow and by-passed oil. The model is being utilized to enhance the ongoing field development, geosteer horizontal wells and is the basis for an improved dynamic simulation model.

(299-Poster) Wadi effect on seismic interpretation

Sedgeley, David (Saudi Aramco - david.sedgeley@aramco. com), Ching-Chang J. Tsai (Saudi Aramco) and Khalid Al-Mahmoud (Saudi Aramco)

In a geophysical sense, a wadi is a near-surface channel filled with very low velocity sediment. Depending upon the size of the wadi with respect to the seismic acquisition geometry, it can cause static and dynamic time distortions that may eventually lead to interpretation errors. The extreme effects of a large wadi are often unresolved by production seismic processing and must be addressed by more detailed analyses. In this project, the effects of a wadi were studied by forward ray-tracing a model of the wadi. Model acquisition parameters are based upon actual field parameters previously used to acquire a high-fold 2-D dataset over an existing major wadi in eastern Saudi Arabia. The model is constructed using structural and rock property information from the seismic data and surrounding well control. The location of drainage systems is often controlled by underlying structure, and in this model a vertical fault with 200 ft of throw has been inserted beneath the wadi. The ability to correctly interpret this fault is used as a primary measure of the accuracy in processing the model seismic data. The results of several processed versions of the model demonstrate its sensitivity to parameter analysis and application. In particular, the initial velocity analysis must be accurate beneath and adjacent to the wadi. The correct stacking velocity field becomes highly distorted across the wadi, and cannot be derived by averaging adjacent velocities from unstructured areas. Use of laterally-smoothed velocities is especially damaging to the stacking at deeper times where more offset ranges are incorporated. Errors in velocity application are exacerbated by the application of autostatics; the combined effect is to add spurious faults and cause segmentation of true faults. This happens regardless of whether shallow or deep cross-correlation windows are used. If the initial velocity application was inaccurate, adding random noise to the model signal may also cause the application of autostatics to create erroneous structures that are significantly different from the noise-free case.

(146-Oral) Nahr Umr sand reservoir development in the Al Shaheen field: reservoir characterization enhancement using long horizontal wells

Sehested, Charlotte L. (Maersk - cse@moq.com.qa), Kenneth A. Nielsen (Maersk) and Troels Albrechtsen (Maersk)

The Al Shaheen field is situated in Block 5 offshore Qatar and is operated by Maersk Oil Qatar under an EPSA with Qatar Petroleum. The mid-Cretaceous Nahr Umr reservoir is one of three main reservoirs in the Al Shaheen field. The reservoir, which is time-equivalent to the muddy argillaceous Nahr Umr Formation in the United Arab Emirates, has a total thickness between 5 and 20 ft and comprises several thin, oil-bearing sands. The reservoir sands represent a transgressive sand sequence deposited in a marginal-marine setting. The sand sequence has proven to be continuous but highly variable, with occasional pinch-outs of individual sands. Development of these thin oil-bearing sands with long horizontal wells has been highly challenging. The pre-drilling characterization of the sands was mainly based on data from vertical wells spread over the large area covered by the field. Drilling and logging results of new long horizontal wells have provided significant improvements to the characterization of the Nahr Umr sand reservoir. In the very thin-layered sand reservoir, the horizontal wells have provided first class information regarding the lateral variability of reservoir quality. Further, they have provided insights into areal variations in sand thickness through detailed interpretation of horizontal well undulating within the reservoir. The latest development plan includes drilling of 18 long horizontal production and injection wells targeting the Nahr Umr reservoir. This study presents the geosteering data gathering and the integration of these data to enhance the reservoir characterization in order to optimize well placement.

(125-Poster) Revised structural interpretation of Sabiriyah field, Kuwait

Sercombe, William J. (BP - sercomwj@bp.com), Ian P. Saxby (BP) and Talal S. Al-Failakawi (KOC)

The structural geology of the giant Sabiriyah field in North Kuwait has undergone a significant reinterpretation. The Sabiriyah field is a low amplitude four-way closure twenty kilometers in length on the Burgan Arch system. The principle oil reservoirs are in the Cretaceous carbonate Mauddud and clastic Burgan formations. Depth slice interpretations of amplitude, spectral decomposition and coherency from regionally merged 3-D seismic volumes indicate a more complex and intense fault pattern than previously recognized. The complexity from seismic is supported by quantitative dipmeter analysis that also indicates significant structural domain variance. The fault grids from seismic were mapped with fault-cut position and throw in all wells. All the datasets were integrated in order to ensure consistency. The Sabiriyah field is interpreted as a restraining bend on an overall NW-SE sinistral strike-slip fault system. Fault movement is associated with a number of Mesozoic and Cenozoic tectonic events overprinted on an earlier infra-Cambrian structural framework. The resultant NW-SE and NE-SW conjugate fault system and associated Reidel faults within the field are new inputs to the revised 3-D geologic model. The revised structure model will be used to improve the static and dynamic models. The complex fault pattern will assist with the fluid flow and compartmentalization issues associated with production, well planning and water flooding.

(326-Oral) Distributing fractures in well models in the Mauddud Formation reservoirs, Raudhatain and Sabiriyah fields, North Kuwait

Sercombe, William J. (BP - sercomwj@bp.com), Ian P. Saxby (BP), Craig Rice (BP), Deryck Bond (KOC) and Talal S. Al-Failakawi (KOC)

The Mauddud Formation reservoir experienced a case of fracture denial during the construction of 3-D reservoir models for use in waterflood simulation studies. Large permeability multipliers were required to match well tests, production logs did not match those one might produce from the permeability distribution in the well, and history matches were difficult to obtain. The Mauddud is now interpreted as a reservoir bearing short, sub-vertical fractures that are: (1) not measured with routine core analysis programs; (2) difficult to detect with borehole imaging techniques; and (3) act as thief zones to injected water. This lead to a challenge of modeling permeability in the well that matched both well test and production logs, and was useable in the 3-D reservoir model. A model of porosity contrast is used to vertically distribute fractures in the reservoir. Permeabilities are assigned to these intervals through an iterative process using values determined from production logs. In this manner, fracture permeability is placed in tighter reservoir intervals whenever it occurs between more porous layers. This methodology has been used to match both well test results and production logs profiles. It forms the basis for distributing permeability in two reservoir models. Recent drilling results from horizontal wells have added a much needed third dimension to the well model. Successful borehole imaging in these wellbores show there is nearly an order of magnitude increase in fractures interpreted in low porosity layers. Stoneley waveform analysis in horizontal wells shows more reflections and higher permeability in low porosity layers. We believe these results confirm the tendency for this reservoir to have significant fracture permeability in tight reservoir layers.

(29-Oral) Integrated reservoir description and geostatistical modeling in Upper Burgan Reservoir, Raudhatain field, North Kuwait

Shaikh, Abdul Azim (KOC - sazim@kockw.com), Craig Rice (BP), Haifa Al-Ajeel (KOC), Peter F. Cameron (KOC) and Shehab Abdullah (KOC)

The Upper Burgan paralic to marine sedimentation process represents a complex cycle of transgressive-regressive sequences during late Albian period in North Kuwait. The shoreface and channel sandstones deposited in this environment hold significant quantity of in-place oil. The reservoir has a production history of more than 40 years with peripheral water flood. An integrated study incorporating static and dynamic data has been carried out to characterize the reservoir for flow simulation so as to formulate alternative development plans suitable for the mature reservoir. Depositional history of the reservoir has been described under three broad categories. The lower Upper Burgan reservoir consists of cycles of shoreface sands and marine shales. The marine shales are laterally extensive reflecting important high frequency sea-level changes. A lowstand systems tract (LST) is interpreted in the Middle Upper Burgan and represents a time during which a complex pattern of stacked channels were deposited. The estuarine shales are discontinuous and act as local baffles. The upper Upper Burgan of the sequence was deposited during an overall transgressive event. The Upper Burgan depositional unit has been divided into 13 major layers bounded by laterally extensive markers. A fine scale, faulted, geological framework captures the key depositional heterogeneity observed within the flow units. The main flow units were derived from correlations between petrophysical properties and dynamic data. Fuzzy logic was used to derive the flow units in terms flowfacies. 3-D facies models were generated using stochastic object modeling constrained by paleocurrent and general distribution of channels. Flow facies exhibiting very high permeability were identified from well logs and specifically incorporated within the facies model to realize the water movement within reservoir. Seismic attributes were used as trends to guide the distribution of individual facies. Petrophysical parameters were generated using stochastic simulation within the facies parameters. The paper describes the approach to reservoir characterization and building geostatistical models in detail.

(304-Oral) Variation of structural style and basin evolution in the Izeh Zone and Dezful Embayment, Central Zagros, Iran

Sherkati, Shahram (NIOC - ssherkati@hotmail.com) and Jean Letouzey (IFP)

The Izeh Zone and Dezful Embayment are located in the central Zagros Mountains of Iran. This region was tectonically affected by the Late Cretaceous Neo-Tethys-Zagros obduction episode and the early Miocene Zagros Orogeny when Eurasia collided with the Arabian Plate. New fieldwork, geological maps, seismic data interpretation, and well information were used to prepare: (1) a regional balanced transect; (2) several updated isopach maps; and (3) tectonic subsidence curves. The analysis revealed the structural style and its relationship to sedimentary facies and the evolution of sedimentary depocenters. Furthermore it shows compression and movements along NS-trending faults from Albian time, in addition to movements along NW-trending faults in the Zagros basement which predate the Neogene Zagros orogeny and influenced the sedimentary basin. The depocenters migrated to the southwest with time. During the Zagros Orogeny the basement was involved in the main structures and below some folds. A new structural classification of the Zagros sedimentary cover highlights the different mechanical behaviors of the formations in the stratigraphic column. It shows the existence of several local disharmonic horizons that were activated during folding. These decollement levels separate lithotectonic units that accommodate shortening in different ways. The lower Paleozoic is the basal decollement level throughout the studied area. The intermediate decollement levels are: (1) Triassic evaporites; (2) Albian shales; (3) Eocene marls; and (4) Miocene evaporites. The beds associated with the intermediate decollement have variable facies, and usually constitute the most efficient caprocks. The wavelength, amplitude and style of folding is closely influenced by: (1) the lateral facies and thickness variations of the intermediate decollement horizons; (2) the sedimentary overburden; and (3) the inherited fault patterns. In many cases, surface structures do not necessarily coincide with deeper hydrocarbon structural traps where these disharmonic decollement horizons were involved in folding. Exploration wells that target reservoirs below the intermediate decollement levels should take these factors into consideration.

(494-Poster) Lithostratigraphy, biostratigraphy, sedimentary environment and paleogeography of Nesen Formation (Upper Permian) in central Alborz, northern Iran: new sight to P/Tr boundary

Shokravi, Gholamreza (Petropars - shokravi@sp68.com) and Ebrahim Ghaseminegad (Tehran U)

The Upper Permian Nesen Formation outcrops in the central Alborz Mountains, northern Iran. This formation was deposited on the passive margin of the northern side of the Lut Block, which was a part of Cimmerian Block. Plate tectonics played an important role in the deposition of this formation, and the formation is closely related to the Abadeh-Djulfa range. In order to study this formation two sections were sampled: (1) Siah-Bisheh section, located near a small village along the Tehran-Chalus road; and (2) Amol section, located 35 km from Amol along the Tehran-Amol road. The study focused on the lithology, paleontology, microfacies and sedimentary aspects of the Nesen Formation. In the Amol section, subaerial exposure, claystones and lateritic sediments of the basal Nesen Formation overlie the Ruteh Formation. In the Siah-Bisheh section, volcanic and volcanoclastic rocks of variable lithology were divided into three units (lower, middle and upper). The underlying Ruteh Formation is covered by shale and limestone of the Nesen Formation. In total 11 microfacies (from lime mudstone and shales of deep sea to pisolitic packstone) were recognized; these can be attributed to four different environments: (1) open sea; (2) bar; (3) lagoon; and (4) tidal flat. Vertical changes in microfacies and fossil evidence indicate that the Permian sediments in central Alborz were deposited as a shallowing-upward cycle, consisting of higher frequency, meter scale, shallowing-upward cycles (parasequences). The vertical and lateral changes of the microfacies suggest that the Nesen Formation was deposited in a rimmed shelf (Siah-Bisheh section) and a ramp (Amol section). The Nesen Formation deposits were diagenetically altered by several processes including: cementation, neomorphism, dissolution and replacement, silisification and bioturbation. Biostratigraphical studies based on foraminifera show evidences for the existence of the latest Late Permian Changhsingian stage for the first time in central Alborz.

(419-Poster) Microbial sediment and chemostratigraphy in the Soltanieh Formation, northwest Iran

Siabeghodsy, Aliasghar (U Urmiaa.siabeghodsy@mail.u rmia.ac.ir)

The Soltanieh Formation outcrops along the ridges east of the village of Chapoghlu in the Soltanieh Mountains. Coordinates of base of section: 36°11′36″N, 48°55′29″E. Three major subdivisions are distinguished in the formation: (1) Lower Dolomite Member (123 m thick); (2) Chapoghlu Shale Member (274 m); and (3) Upper (main) Dolomite Member (790 m). Stromatolites are fairly common in the higher dolomites and dolomitic limestones of the type-Soltanieh section, and are common throughout the formation; they include forms of Microbial mat that has been described at this study. The Microbial structure is commonly recognized with stromatolite. A comparison of Carbon–isotope (C13) chemostratigraphy versus the stratigraphic column of the Soltanieh Formation shows that Precambrian-Cambrian Boundary occurs in the Upper Dolomite Member of the Soltanieh Formation. The Soltanieh Dolomite, with or without the intervening Chapoghlu Shale, has been traced through a great part of northern, central and eastern Iran; the westernmost occurrences known so far are in the Lake Uromieh area.

(370-Poster) Tectono-stratigraphic evolution of the southern Tethyan margin, North Africa and Arabia: an updated sequence stratigraphic interpretation

Simmons, Michael D. (Neftex - mike.simrnons@neftex.co m), Peter R. Sharland (Neftex), Roger B. Davies (Neftex), David M. Casey (Neftex) and David Boote (Consultant)

Prior to the opening of the Red Sea in the Neogene, North Africa and Arabia were part of the same southern Tethyan Gondwanan continental margin. To better resolve the tectono-stratigraphic evolution of this southern Tethyan margin, we present a chronostratigraphic chart, running from Morocco in the west to Oman in the east, which correlates the sequence stratigraphy of these two hydrocarbon provinces against latest published timescale data. Refined sequence stratigraphic correlation allows the plethora of disparate lithostratigraphic schemes in use across this vast region, to be placed within coeval second-order depositional sequences. The stabilization of the stratigraphy at this scale also provides the framework to correlate and map higher-frequency surfaces (maximum flooding surfaces and sequence boundaries) between these continental plates. The sequence stratigraphic interpretation presented here updates that published in GeoArabia Special Publication 2, and integrates recent relevant literature. North Africa and Arabia were both affected by the Hercynian, Cimmeride and Alpine orogenies, and by synchronous glacial events in the end Ordovician and Permo-Carboniferous. Throughout much of the Mesozoic–Paleogene they occupied a position on the tectonically quiescent margin of southern Tethys. In these later periods carbonate deposition prevailed, influenced by global eustacy, although progradation of clastic systems from ancient shield areas at times of synchronous uplif are notable features of both North Africa and Arabia.

(244-Poster) Improving structural distortions by mitigating near-surface effects and modifying shallow velocity models

Singh, Ravi K. (Saudi Aramco - ravindra.singh@aramco.com) and Robert E. Ley III (Saudi Aramco)

In Saudi Arabia, complex surface and near-surface conditions prevent seismic reflections from properly imaging the seismic events associated with the subsurface formations. Presence of sand dunes, jebels, wadis and sabkhas causes the heterogeneity of the near-surface conditions. Shallow horizons exhibit high structural variations caused by near-surface statics on the 3-D dataset. The high structural variations of the shallow horizons do not appear to be supported by wells drilled in the areas. Additionally, several prospective areas south and east of Ghawar structure include many subtle traps having only 10-20 milliseconds of structural closures. Small-order residual statics of less than 10 milliseconds becomes critical to correct for the structural dips in these areas. Conventional methods of solving the statics are not completely adequate. Implementation of state-of-the-art statics solutions and depthing techniques were applied to overcome these problems. A new method of computing the statics solution was implemented, where pseudo-upholes were generated using the information from 3-D data. The analysis involved creating a two-layer velocity model. The seismic sections analyzed using the two-layer model mitigated the near-surface effects and accurately portrayed the dips on the subsurface seismic events. The computed static difference between the earlier velocity model and two-layer model were applied to the time maps for key horizons. The corrected time maps were used to make depth maps at the top of the reservoir using a ‘layer-cake’ approach. The results from the corrected maps give better definitions of the structural configuration compared to the maps based on the earlier velocity model.

(79-Poster) The Makran Accretionary Complex: tectonic and structural architecture of an active accretionary complex

Skarpnes, Oddvar (Statoil - oskar@statoil.com), Oyvind Skinnemoen (Statoil), Seyed Mahdi Fazeli (NIOC), Alireza Rostami (NIOC) and Bahman Soleimani (NIOC)

The Makran Accretionary Complex formed as a result of the northward subduction of the Neo-Tethys underneath the Eurasian Plate, a process that has been ongoing since Early Cretaceous. The accretionary complex extends for more than 900 km, from the Zendan Fault in the outer part of the Strait of Hormuz, to the Ornach Nal Fault in Pakistan. The width of the complex is about 500 km. The present accretionary front is located 230 km offshore. The Persian Carpet seismic survey acquired in 2000 (PC-2000) is the first seismic dataset covering the whole Iranian offshore part of the Makran Accretionary Complex. Based on the PC-2000 seismic dataset, satellite gravity and bathymetric maps, ten structural elements/provinces directly or indirectly related to the accretionary processes have been defined in the outer Hormuz and the Iranian part of the Oman Sea. The offshore continuation of regional onshore strike-slip faults play an important role in conveying the tectonic stress eastward, as continent-continent collision takes place in the western part of the area. The convergence/collision along the Zendan Fault is very oblique, resulting in right-lateral transpressional tectonics and structuring. In the southwestern part of the survey area thrusting towards the north is interpreted as toe-thrusts related to large scale listric faulting along the continental shelf of Oman. The defined structural elements and provinces clearly demonstrate the continuity in the accretionary processes. Defining structural events in an accretionary complex is therefore meaningless. ‘Structural events’ in an accretionary complex should be viewed as responses to subduction rates, sediment properties, sedimentary thicknesses, and similar geological aspects.

(442-Oral) Reducing drilling risk using seismic data processing attributes

Smith, Wayne (Saudi Aramco - wayne.smith@aramco.com), Khalid Mahmoud (Saudi Aramco), Barton Payne (Saudi Aramco) and Hashim A. Hussein (Saudi Aramco)

Drilling locations, picked on structural seismic time data, can be qualified as either high or low risk by using seismic processing attributes. The time dimension of a seismic volume can be distorted by near-surface features, resulting in sub-optimal velocities, statics, and datum correction. These near-surface artifacts often permeate deeper in the data, causing locally time-shifted horizons, which mislead the interpretation of the seismic data. During the processing sequence, we keep track and save many attributes such as velocities, statics, elevation, datum corrections, and location of surface features. Later, the attributes are compiled in such a fashion as to indicate these false time structures. The advent of new, more powerful visualization tools allows us to easily merge these attributes with the seismic time volume, giving a level of confidence in the validity of time structures. The same technique can be applied early in the processing sequence as a quality control, eliminating many incorrect structures from the final data volume. We use a 3-D pre-stack time-migrated volume to demonstrate the effectiveness of this tool. With careful selection of color maps and opacity, we superimpose the seismic attributes into the final amplitude volume. Cutting through this new composite time volume allows us to easily correlate horizon perturbations to near-surface anomalies. In this way, probable false time structures are highlighted and passed on to the interpreters to assist them in lowering the risk associated with planning well locations.

(473-Oral) Surface Wave Methods for near-surface characterization

Socco, Laura V. (Politecnico di Torino - valentina.socco@p olito.it) and Claudio L. Strobbia (Politecnico di Torino)

Surface Wave Methods (SWM) are very powerful tools for the near-surface characterization of sites: the shear velocity and the damping ratio can be obtained overcoming, in some cases, the limitations of other shallow seismic techniques. For complex near-surface applications, surface-wave results represent a useful integration of the information inferred by other seismic techniques. Information can be often attained, with no additional acquisition, by extracting the data from the ground roll present in traditional P-shot gathers. But in situations that are critical for other seismic methods, SWM can even be an effective alternative to reflection and refraction: data can be acquired also in noisy environments and can be correctly interpreted also in the case of velocity inversions and hidden layers. The different steps of SWM have to be optimized considering the conditions imposed by the scale of near-surface problems that often allows only the acquisition of apparent dispersion characteristics: robust modeling algorithms able to take into account for modal superposition are necessary. Acquisition has to be properly planned to obtain quality data in an adequate frequency range: (1) processing and inversion should allow the interpretation of the apparent dispersion characteristics evaluating the local quality of the data; (2) filtering coherent noise due to other seismic events; and (3) considering energy distribution, higher modes of propagation and attenuation.

(183-Oral) Geochemistry and natural salt closure combine to prevent a costly workover: case study from a deep over-pressured well in South Oman

Soek, Harry (PDO - harry.soek@pdo.co.om), Mark Laws (PDO), Paul Taylor (Shell) and Janos Urai (Aachen U)

A number of appraisal wells have been drilled to assess the economic viability of miscible gas injection to enhance oil recovery from intrasalt stringer reservoirs in the Harweel cluster area in South Oman. The Precambrian carbonate stringers are fully encased in salt, deep, highly over-pressured and contain sour light oil. Operational difficulties whilst running a liner over the reservoir section in one of the appraisal wells, combined with a sub-optimal cementation, led to a gradual build-up in pressure on the well’s A-annulus. This pressure build-up threatened the integrity of the well and could have potentially lead to a costly workover. A number of steps were therefore undertaken to determine the cause of this build-up and to plan remedial measures: (1) geochemical fingerprinting of the leaking oil and comparison to similar data from cuttings and core samples to better understand the origin of the oil. The oil could have originated from any of the multiple oil-bearing zones penetrated by the well, or it could have been introduced during well construction. (2) A pro-active annular pressure monitoring program; including pressure build-up and bleed off cycles to investigate pressure behavior over time and under different conditions. (3) A study into the behavior of salt as a means to provide a natural seal against the liner instead of cement. The geochemical work allowed an unambiguous identification of the source of the oil. Study work on the salt has identified the likelihood and time required for the salt to close around the liner. The salt closure is mainly driven by the quality of the cement and the assumed liquids behind the liner. A proactive pressure surveillance program has underpinned this salt closure prediction. Recent observations have shown that the pressure build-up on the annulus has ceased, which implies that the salt has crept and sealed off the annulus between the liner and wellbore. It has therefore effectively provided a secondary barrier hence restoring the integrity of the well. A clear understanding of the causes and sources of the problem has emerged. This better understanding, together with a surveillance program which supports the annular pressure prediction (based on gradual salt closure) has led to the recommendation not to work over this well for integrity reasons. It has saved the company a considerable amount of money and has triggered a conceptual cementation design study to investigate how salt can be exploited deliberately to provide well integrity in future wells.

(132-Oral) Learnings from a focused exploration campaign in Central Oman

Spring, Laurent (PDO - laurent.y.spring@pdo.co.om) and Mohamed S. Al-Harthy (PDO)

After the (re) discovery of the Hawqa field in 2002, the most significant Gharif find in the last 10 years, PDO Exploration set a goal to evaluate and unlock the potential of the Gharif Formation in Central Oman by undertaking the following activities. (1) Setup a multi-disciplinary team of geoscientists, petroleum engineers, and other specialists to focus on various aspects of the Gharif play in Central Oman. (2) Embark on an extensive 3-D acquisition program (approximately 2,250 sq km), coupled with uphole drilling and Low Velocity Layer (LVL) surveys. (3) Attempt new approaches to (re) processing of seismic data by addressing surface statics and multiples suppression problems that traditionally blur seismic images of very low-relief (< 20 milliseconds two-way time) structures. (4) Undertake a staged drilling campaign to test geological and geophysical models, with clear milestones to continue or stop exploration in the Gharif of Central Oman. One year after the onset of the project, an ‘After Action Review’ (AAR) was conducted. This very structured event helped PDO to understand how well the objectives of Central Oman Gharif campaign were met, and what were the key learned experiences–both positive and negative–that resulted from this project. The structure of the AAR concentrated on: (1) the objectives; (2) what actually happened; (3) what were the learned experiences; (4) what should be done differently-if anything-for the overall planning of the project; (5) the way subsurface uncertainties are approached; and (6) drilling aspects of a focused exploration effort.

(307-Poster) Diamondoid hydrocarbons in characterization and source-oil correlation of secondary altered oils; results from onshore Iran

Steen, Arne S. (Norsk Hydro - arne.sigurd.steen@hydro.co m) and Linda Schulz (Norsk Hydro)

Secondary alteration processes, like biodegradation, evaporative fractionation and cracking, affect the hydrocarbon composition and consequently the geochemical signature of the sample. Diamondoid hydrocarbons are known to be more resistant to thermal cracking or biodegradation than most other petroleum components. Diamondoid signatures are used to report hydrocarbon maturity, source rock facies and levels of biodegradation or thermal cracking. Diamondoid hydrocarbons are naturally occurring constituents in petroleum. These low-molecular-weight hydrocarbons have a diamond-like cage structure. The simplest member of this class of compounds is the C10 cage structured adamantane. The next homologue of the diamondoid hydrocarbon series is diamantane, followed by triamantane, etc. The hydrocarbon signature in outcrop and seep samples are typically affected by biodegradation or evaporative alterations. The potential of this diamondoid hydrocarbon approach is demonstrated on a set of Iranian samples, including outcrop samples from known source rock formations versus borehole source rocks and reservoir fluids. The results are compared to regional studies offshore Norway and worldwide datasets. Multi-variate statistical analyses are used to evaluate the significance of these diamondoid hydrocarbons.

(273-Poster) Cenozoic sequence stratigraphy, Arabian Platform and Gulf

Steinhauff, D. Mark (ExxonMobil - mark.steinhauff@exxon mobil.com), Chengjie Liu (ExxonMobil) and George J. Grabowski Jr. (ExxonMobil)

Nine hiatuses or major sequence boundaries (SB) are recognized in Cenozoic strata throughout the Arabian Platform and Gulf: (1) a basal Tertiary (Danian to lower Selandian) SB separating the Tertiary Umm Er Radhuma (UER) Formation from the Upper Cretaceous; (2) a mid-Thanetian to upper Ypresian SB within the lower UER; (3) a lower Lutetian SB indicated by the absence of the ‘Rus’ anhydrite from some anticlines; (4) a mid-upper Lutetian SB; (5) an uppermost Lutetian to Bartonian SB; (6) a lower Rupelian SB at the top of the Dammam Formation; (7) a lower Chattian unconformity separating Rupelian 2nd-order sea-level highstand deposits from the mid-upper Chattian second-order lowstand; (8) a lower Burdigalian SB separating Asmari carbonates from overlying Asmari siliciclastics; and (9) an upper Serravallian SB not prominent over shelf areas. The Serravallian, Tortonian, and Messinian stages are represented by shale and evaporite in the foredeeps along the Iran and Oman margins. The Tortonian and Messinian are represented by mixed siliciclastics, carbonates, and evaporite deposits across the shelf. Sequence boundaries are typically conformable in the foredeeps and subtle towards the Qatar Arch. For example, tens of meters of strata are typically truncated from sequences over 100s of kilometers in the offshore United Arab Emirates. Greater stratal thicknesses are truncated from salt-cored anticlines (Dammam and Awali) including the entire lower Lutetian sequence comprising ‘Rus’ subsurface evaporite. Paleogene through mid-Miocene sequences formed in response to global eustatic sea-level fluctuations in a slowly to moderately subsiding foreland setting. Post-mid Miocene deposition was influenced by the late Neogene Zagros Orogeny.

(319-Oral) Correlation of the Permian rocks of Oman and Saudi Arabia

Stephenson, Michael H. (BGS - mhste@bgs.ac.uk), John Filatoff (Saudi Aramco), Uzma Mohiuddin (PDO), Randall A. Penney (PDO), Peter L. Osterloff (Shell) and Moujahed I. Al-Husseini (GPL)

The recent publication of an integrated palynological biozonation for Oman and Saudi Arabia has allowed the sequences in those countries to be correlated throughout most of the Permian System. In the scheme, three biozones are established in the palyniferous Lower Permian sequence in Oman, and to some extent these are recognizable in sequences of central and southern Saudi Arabia. These biozones, OSPZ1 - OSPZ3 (Oman and Saudi Arabia Palynological Zones), are associated with the Al Khlata and Lower Gharif formations of Oman and the Unayzah C and B members of Saudi Arabia and are of Stephanian to Artinskian age. The OSPZ3 zone itself is further subdivided into three subzones which are exclusively associated with the Lower Gharif member. The succeeding three biozones, OSPZ4-OSPZ6, are established in the episodically palyniferous Middle and Upper Permian sequences. These are associated with the Middle and Upper Gharif members of Oman, and the Unayzah A member and the ‘basal Khuff clastics’ of Saudi Arabia. They range in probable age from Artinskian to Capitanian. The correlation and characterization of OSPZ4-OSPZ6 has been rather tentative until now, but work done since the publication of the new biozonation has allowed: (1) subdivision of the OSPZ5 biozone; (2) improved palynological characterization of the Upper Gharif member and the Oman Khuff Formation; (3) correlation between the surface Upper Gharif in the Huqf outcrop area in Oman, and the subsurface in areas to the west; (4) improved understanding of the paleoenvironments and paleoecologies seen in Gharif and Khuff sediments.

(414-Poster) Delineation of faults and fracture zones using Spectral Decomposition analysis in the Idd El Shargi field, Qatar

Street, Karl D. (Landmarkkstreet@lgc.com), Scott D. Burns (Occidental) and Abdulla Seliem (Occidental)

The geophysical analysis technique, Spectral Decomposition, enables the geophysicist to analyze the seismic data in more detail than ever before. This technique uses the Discrete Fourier Transform to break down the broadband seismic wavelet into one Hertz (Hz) frequency slices enabling greater resolution and characterization of seismic data. This analysis tool has recently become available to the interpretive geophysicists across the world with the release of Landmark’s Spectral Decomposition software. However, all publications to date have focused on using Spectral Decomposition for the stratigraphic analysis of clastic channel systems. The Idd El Shargi field consists of two elliptical, faulted domes, aligned approximately north-south and is Qatar’s oldest producing offshore field. Oil production is from the Shu’aiba, Arab and Araej carbonate reservoirs. Spectral Decomposition has been used to delineate faults and fracture zones in these reservoirs in more detail than any other geophysical analysis technique tried before. Other techniques previously used to define the faults include: dip-azimuth, coherency, and edge detection, but none have matched the quality and resolution of Spectral Decomposition. Since November 2002 all wells have been drilled using the Spectral Decomposition software.

(122-Oral) Sequence stratigraphy and reservoir characterization of the Lower Cretaceous Kharaib Formation, Abu Dhabi

Strohmenger, Christian J. (ADCO - cstrohmenger@adco.co.ae), Lawrence J. Weber (ExxonMobil), Ahmed Ghani

(ADCO), Khalil Al-Mehsin (ADCO) and Omar Al-Jeelani (ADCO)

Important hydrocarbon accumulations have been found in platform carbonates of the Lower Cretaceous Kharaib Formation (Upper Thamama Group) of Abu Dhabi. By integrating core and well-log data from a giant field of Abu Dhabi as well as outcrop data, a sequence stratigraphic framework has been established for the Barremian Kharaib Formation. The Kharaib Formation can be described by a second-order supersequence (base lower ‘dense zone’ to base upper ‘dense zone’ = Hawar Shale), built by two third-order sequences. The lower third-order sequence starts at the base of the lower ‘dense zone’ and is capped by a pronounced sequence boundary (exposure surface) some ten feet below the middle ‘dense zone’. It is overlain by a third-order sequence that is bounded on top by a regionally correlative sequence boundary below the upper ‘dense zone’. Second- and third-order sequence boundaries and maximum flooding surfaces, as well as fourth-order flooding surfaces were identified in core and tied to well-logs. Eleven fourth-order parasequence sets that built the two third-order sequences show predominantly aggradational stacking patterns, typical for greenhouse cycles. On the basis of faunal content, texture, sedimentary structures, and lithologic composition, thirteen reservoir lithofacies and eight non-reservoir (dense) lithofacies have been identified. Lithofacies range from open platform, lower ramp, to restricted platform subtidal, to intertidal environments. Intensively bioturbated wackestones and packstones, and interbedded argillaceous limestones characterize the lower and middle ‘dense zones’ and correspond to the early transgressive systems tracts of the two third-order sequences. Locally, mudcracks, blackened grains, and rootlets have been observed. The reservoir zones correspond to the late transgressive and, dominantly, highstand systems tracts characterized by parasequences that show shallowing-upward trends from open lagoon, burrowed skeletal wackestones to skeletal, peloidal packstones, algal, coated-grain grainstones/rudstones, and rudist, algal floatstones. Well-developed Thalassinoides firmgrounds (Glossifungites surfaces) indicate temporary cessation in sedimentation and cap several parasequences.

(204-Poster) Sequence stratigraphy and reservoir quality characterization of the Upper Jurassic Arab and Asab formations, Abu Dhabi

Strohmenger, Christian J. (ADCO - cstrohmenger@adco. co.ae), Abdelfatah El-Agrab (ADCO), Rafael M. Rosell III (ADCO), Suleiman Ali (ADCO), Jean Francois Dervieux (ADCO), Na’ema Al-Zaabi (ADCO), Ahmed Khouri (ADCO), Tom Slater (RRI), Anna L. Matthews (RRI) and Marguerite J. Fleming (RRI)

A sequence stratigraphic framework has been established for the Kimmeridgian-Tithonian Jubaila/Arab and Asab formations offshore and onshore Abu Dhabi. A total of six third-order composite sequences have been identified called J70 (Jubaila/Arab-D), J80 (Arab-C), J90 (Arab-B), J100 (Arab-A/Lower Asab Ooilite), and J105 (Hith/Upper Asab Oolite). The overall depositional environment envisaged for the Arab and Asab formations is that of a barrier shoal complex with open marine, offshore sedimentation to the east and a protected, evaporitic, intrashelf basin to the west. A barrier shoal complex developed along the platform margin and deposition was dominated by oolitic grainstones. Concomitant deposition of sabkha, tidal flat, salina and lagoonal sediments occurred westwards, and open-marine mudstones and wackestones were deposited eastwards of the barrier shoal complex. The J70 to J105 sequences belong to the highstand sequence set of the Upper Jurassic second-order supersequence and show progradation of the facies belts towards the east. Through time, the lagoon behind the barrier bar complex, became increasingly evaporitic being dominated by salina deposits during Hith deposition (J105 Sequence). The net reservoir and reservoir quality is strongly controlled by the depositional environment and the lithofacies types. The best reservoir is present within grain-dominated lithofacies types of the barrier shoal complex. Relatively poor reservoir quality is characteristic of mud-dominated lithofacies types that occur in open-marine environments. In the intrashelf basin the dominantly dolomitized lithofacies types show quite good reservoir qualities within thin intercalated packstone to grainstone layers, interpreted as tidal channels or washovers. The proposed sequence stratigraphic correlation enhances the prediction of reservoir facies and reservoir quality distributions away from well controls.

(212-Poster) Depositional setting, sequence stratigraphy, and reservoir quality of the Hanifa Formation in the eastern part of onshore Abu Dhabi

Strohmenger, Christian J. (ADCO - cstrohmenger@adco.co.ae), Abdullah Al-Aidarous (ADCO), Abdelfatah El-Agrab (ADCO), Martin P. Boekholt (ADCO), Rafael M. Rosell III (ADCO), Azhari Abdalla (ADCO), Marguerite J. Fleming (RRI) and Anna L. Matthews (RRI)

The Upper Jurassic (Kimmeridgian) Hanifa Formation is comprised of a barrier shoal complex (Hanifa reservoir facies) passing laterally into the Hanifa intrashelf basin (Hanifa source rock facies). Deposition within the intrashelf basin ranges from shallow lagoonal to intertidal on top of isolated topographic highs, to a deeper, restricted lagoonal environment. The latter corresponds to the so-called Hanifa source rock facies. The Hanifa Formation represents a third-order sequence called J60. It is bounded at the base by sequence boundary J60-SB (exposure surface) and at the top by sequence boundary J70-SB (exposure surface). The maximum flooding surface J60-MFS separates the lowstand (LST)/transgressive (TST) and highstand systems tracts (HST). Within the Hanifa intrashelf basin five correlative high frequency sequences-parasequences are identified, corresponding to the LST/TST. These high frequency sequences-parasequences onlap onto sequence boundary J60-SB. Six correlative high-frequency sequences-parasequences characterize the Hanifa HST. Potential source rocks are developed during the TST whereas reservoir facies dominate the HST of the Hanifa Sequence J60. Depositional environment, lithofacies, and the established sequence stratigraphic framework control reservoir quality and source rock distribution. The best reservoir occurs within the barrier shoal complex of the HST. Amplitude extraction after horizon interpretation of 3-D seismic data and rock properties analysis allow the mapping of the lateral extend of the porous shoal complex. Potential source rocks, representing deeper-marine, restricted deposits of the intrashelf basin formed during the LST/TST and correspond to a good seismic reflector close to the base of the Hanifa Formation.

(57-Oral) Controls on reservoir performance: lessons learned from fracatured giant fields

Sun, Qing (C&C - sqsun@ccreservoirs.com) and Jack Allan (C&C)

One hundred fractured reservoirs from around the world were evaluated to determine the most important factors controlling ultimate recovery. Fractured oil reservoirs comprise four groups. Type I reservoirs have little matrix porosity and permeability. Fractures provide both storage capacity and fluid-flow pathways. Type II reservoirs have low matrix porosity and permeability. Matrix provides some storage capacity and fractures provide the fluid-flow pathways. Type III micro-porous reservoirs have high matrix porosity and low matrix permeability. Matrix provides the storage capacity and fractures provide the fluid-flow pathways. Type IV macroporous reservoirs have high matrix porosity and permeability. Matrix provides both storage capacity and fluid-flow pathways, while fractures merely enhance permeability. An analysis of controls on recovery factor (RF) efficiency shows that Type I and Type II reservoirs (average RF = 21 percent and 26 percent) are easily damaged by excessive production rates. In Type III reservoirs (average RF = 24 percent), recovery factor is dependent upon lithology, wettability, and fracture intensity. Enhanced recovery techniques are essential for optimum exploitation. In Type IV reservoirs (average RF = 34 percent), recovery factor is most sensitive to drive mechanism. Fractured reservoirs can achieve recovery factors comparable with those of conventional unfractured reservoirs when the correct reservoir management strategy is chosen.

(234-Poster) Sequence stratigraphy and reservoir characterization of the Thamama reservoirs and outcrop equivalents: a core workshop and field seminar

Suwaina, Omar A. (ADNOC - oswaina@adnoc.com), Lawrence J. Weber (ExxonMobil), Christian J. Strohmenger (ADCO), Lee Vaughan (ExxonMobil), Abdulla Al-Mansoori (ADCO), Sameer Khan (ExxonMobil) and Ahmed Ghani (ADCO)

As large producing properties in the United Arab Emirates (UAE) become more mature and require capital-intensive secondary and tertiary methods to maximize oil and gas recovery, greater emphasis is placed on building more accurate and predictive subsurface reservoir models. Sequence stratigraphy, based on sedimentary response to changes in relative sea level, provides the production and development geoscientist with a powerful predictive tool. Application of sequence stratigraphic concepts to UAE subsurface seismic, core, well log, and outcrop data can lead to alternative, insightful, subsurface reservoir models. Outcrop geology in the northern UAE is, in many ways, analogous to subsurface geology of large producing fields in Abu Dhabi. Subsurface data is used to populate 3-D geologic models and conduct fluid-flow simulations using the reservoir architecture developed from these outcrops. At the outcrop, we will: (1) Investigate the impact of reservoir architecture (for example, lateral and vertical facies changes, sequence boundaries, and flooding surfaces), diagenesis, variogram range, and porosity/permeability relationships on the development of quantitative geologic models (2-D/3-D), using continuously exposed Thamama equivalent outcrop in Wadi Rahabah, Ras Al-Khaimah. (2) Conduct fluid-flow simulations on selected geologic models of Thamama outcrops to examine interwell-scale heterogeneity issues that may affect recovery efficiency for Thamama producing reservoirs. The focus of this core workshop and field seminar is the description of the reservoir and the role the description has on understanding reservoir performance. At the end of this workshop and field seminar, each participant should have an appreciation for the set of sequence stratigraphic tools necessary to construct subsurface reservoir models.

(344-Oral) Intrashelf basin development in the Sarvak Formation: example from the High Zagros Mountains

Taati, Farid (NIOCfarid.taati@ifp.fr), Frans S. Van Buchem (IFP) and Philippe Razin (U Bordeaux)

The Sarvak Formation, of Cenomanian/Turonian age, constitutes one of the major reservoir intervals in the Central Zagros Mountains in Iran. A particular feature of this carbonate system is the presence of intrashelf basins. Since they may play a significant role, both as the site of potential source rock deposition, as well as through their influence on reservoir properties in the adjacent carbonate platforms and their margins, our work has focused on the genesis, palaeogeography, and geometries of one such intrashelf basin. The studied site is located in the High Zagros (Kuh-e Landareh), where, along a 10-km-long and 300-m-high transect, two margins of an intrashelf basin are exposed. In combination with information of other outcrops in the area, a regional map of the basin was constructed. This intrashelf basin was probably formed during the last third-order depositional sequence of Cenomanian age. An overall backstep occurred well into the Turonian times, followed by a strong progradation. This was terminated by the formation of extensive laterite soils in the region (Laffan Formation). The intrashelf basin margins show an evolution from a very low-angle geometry (1 to 2 degrees) to a steep margin geometry (upto 30 degrees). Facies changes are very abrupt, both in a vertical and lateral sense. The platform margin is constituted of coarse grained rudist-dominated grainstone to rudstone, while the platform top consists of a foraminiferal (mostly miliolids) wackstone, and the basinal facies is a mudstone with oligostegina and planctonic foraminifera. This type of outcrop analogs provide us with geometrical information that is beyond the scale of seismic. They may help to better appreciate the lateral variability and geometrical complexity in subsurface intrashelf basin margins of the Sarvak Formation.

(263-Oral) Sweet gas exploration potential of the pre-Khuff reservoirs, western offshore Abu Dhabi

Taher, Ahmed A.K. (ADNOC - ataher@adnoc.com) and Johan M. Witte (ADNOC)

The principal pre-Khuff hydrocarbon reservoirs in Abu Dhabi are the siliciclastic sediments deposited during Late Carboniferous to Early Permian time. These sediments, which were previously known in Abu Dhabi as the Lower (PK-3), Middle (PK-2) and Upper (PK-1) pre-Khuff reservoirs can be correlated with the Unayzah and Berwath formations of Saudi Arabia, which are of the same age. The Unayzah depositional environment of western offshore Abu Dhabi is interpreted as sheet floods, deposited on an arid or semi-arid distal plain. Locally occurring braided channels, cutting into the stacked sheet flood sands, may form thick sand bodies with significant reservoir potential. Structural growth and hydrocarbon generation histories were modeled. Early growth and charge were identified as a significant condition for the formation of economic hydrocarbon accumulations. The Late Triassic to Early Jurassic period was found to be the optimum time for hydrocarbon charge of the Paleozoic reservoirs. Structures of later age were found either tight or water bearing due to extensive diagenesis, which reduced reservoir properties by cementation. Quartz cement, illite and compaction were found to be the major diagenetic elements impacting the reservoir quality of the Unayzah Formation. The pre-Khuff section was explored in most of the prominent western offshore Abu Dhabi fields, but it positively tested sweet gas only in one of these locations. The negative results in the other pre-Khuff exploration wells are mainly attributed to the fact that most of the wells were drilled in crestal positions in these fields, where palynological studies have proven absence of the Unayzah Formation due to tectonic uplift and erosion. In the successful well, only the lower part of the Unayzah-A was found. However, the possible presence of Unayzah sediments on the flanks of the crestal tested structures may alter the pre-Khuff section into an attractive exploration play for sweet gas in western offshore Abu Dhabi.

(68-Oral) Clay minerals in Cretaceous Nahr Umr sandstone and their influence on reservoir, Qatar

Trabelsi, Ali M.S. (QP - trabelsi@qp.com.qa) and Mirza A. Beg (QP)

In Qatar, the Nahr Umr Sandstone is oil productive in several offshore fields. Located on the western flank of the Qatar Arch, offshore Nahr Umr sands have sheet-like geometry, covering an area of about 1.600 sq km. Nahr Umr Sandstone occurs at an average depth 2,500–3,600 ft in onshore Dukhan field and 4,900–5,350 ft in offshore Qatar. This sandstone was deposited in a shallow-marine environment as evident by glauconite peloids, orbitolinid foraminifera, brachiopods and other shallow-marine fauna. Onshore, the Nahr Umr Sandstone appears to have a fluvial origin as indicated by the presence of coal, plant debris and a paucity of shelled, invertebrate fauna. Overall, the Nahr Umr Formation comprises alternating intervals of quartzarenite to sublitharenite sandstone, argillaceous sandstone, glauconitic sandstone and shale. In general, the quartzarenite sandstone consists of angular to sub-angular, moderately to poorly-sorted, fine-grained sandstone with reasonable amount (about 20 percent) of predominantly intergranular porosity. The argillaceous sandstone streaks have significantly lower permeability than clay-free intervals. This is due to the presence of detrital and pore throat blocking authigenic clay minerals. X-ray diffraction (XRD) and scanning electron microscopy (SEM) analyses reveal significant amounts of detrital and authigenic clays, especially kaolinite, chlorite, illite/smectite mixed layers and illite. Detrital clay forms a significant portion of the sandstone matrix. It is present at grain-to-grain contacts, as laminae and clay wisps. Authigenic clay, especially kaolinite exhibits higher degree of crystallinity, has delicate morphologies and predominantly coats sandstone (quartz) grains and partially fills and lines the intergranular pore spaces. Nahr Umr marine sandstone samples can contain as much as 17 percent clay. In most samples kaolinite is the predominant type, followed in abundance by chlorite, illite and illite/smectite mixed layers. Some offshore marine samples contain significant amounts (up to 32 percent) of goethite as revealed by XRD analysis. Goethite occurs as well-rounded and sub-spherical micro-porous peloids (70-125 m). These peloids probably resulted from the diagenetic alteration of originally chamositic grains. The Nahr Umr Sandstones also contains smaller amounts of pyrite, dolomite and siderite, occurring predominantly as replacement and cement. Volumetrically these constituents are relatively less abundant. While not a primary depositional and diagenetic control on permeability, chlorite (chamosite) and other iron-rich minerals can create problems if Nahr Umr Sandstone is acidized without using iron sequestering materials and clay stabilizers. Smectites and mixed layer illite/smectite clays are sensitive to fresh water and low salinity fluids. They swell in contact with these fluids. The swelling results in blocking of pore and pore throats and causes near wellbore damage. The swelling problems can be avoided by using oil base, potassium or ammonium chloride drilling, completion and stimulation fluids.

(44-Oral) How sure are you that your Shu’aiba stratigraphy is correct? New findings from chemical stratigraphy

Vahrenkamp, Volker C. (PDO - volker.vc.vahrenkamp@pd o.co.om)

Some 1,400 new data from 27 wells of the Shu’aiba Formation in Oman have been collected to refine previously established correlations between carbon isotope profiles in the Gulf region with isotopic variations proposed for Aptian seawater. Anchored by biostratigrahy, gamma ray (GR) logs and a regional Shu’aiba correlation frame a reference curve has been established for the Aptian, which significantly surpasses others from elsewhere in the world, both in time resolution and definition. Surprisingly, the carbon isotope composition of the Shu’aiba Formation in the measured sections seems little changed from its original marine signature despite long term subaerial exposure prior to burial and extensive early and/or late diagenesis. The new reference curve constrains the time intervals during which individual sections accumulated. Correlation of time equivalent sections, both on a regional and field scale, establishes a stratigraphic architecture of the Shu’aiba Formation, which is significantly more complex than previously assumed. For example, during the early Aptian, complete infill of accommodation space by rudist build-ups at Al Huwaisah field caused multi-directional progradation into adjacent incompletely filled areas (e.g. north-westwards towards Yibal field and the shallow-shelf Bab Basin; southeastwardly towards a lagoon between Al Huwaisah and Saih Rawl fields). This lagoon, which contains the areas of both Burhaan and Musallim fields only filled during another later early Aptian sequence. Without control from chemo-, bio- or seismic stratigraphy, it is difficult to define an order of depositional sequences or correlate over large distances using stacking patterns in cores or GR-logs. Carbon isotope stratigraphy offers a robust and inexpensive tool to provide stratigraphic control both on reservoir and exploration scale.

(329-Poster) Stratigraphy of the central Saudi Arabian Khuff Formation

Vaslet, Denis (BRGM - d.vaslet@brgm.fr), Yves-Michel Le Nindre (BRGM), Daniel Vachard (CNRS), Sylvie Crasquin-Soleau (CNRS), Jean Broutin (U Paris), Mohamed Halawani (SGS) and Moujahed I. Al-Husseini (GPL)

The Permian-Triassic Khuff Formation outcrops of central Saudi Arabia are divided, from base to top, into five members: Ash Shiqqah (formerly Unayzah member of the Khuff Formation), Huqayl, Duhaysan, Midhnab and Khartam. According to benthic foraminifer and algae associations, the Ash Shiqqah Member is tentatively dated as Capitanian (Midian). The Huqayl Member is assigned to a Wuchiapingian (Dzhulfian) age. The Duhaysan Member remains undeterminated in age. The Midhnab Member is dated as Changhsingian (Dorashamian). Within continental facies in the topmost part of the Midhnab Member, swamps and crevasse splay deposits yielded the Upper Permian Midhnab flora. The lower Khartam Member contains rare Permian foraminifers, locally reworked. However, abundant ostracods of the Paleocopid group support a late Late Permian age. The disconformity between the Midhnab and Khartam members thus occurs during the Permian Period. The upper Khartam Member is confirmed as Early Triassic Scythian in age based on the abundance of Spirorbis phlyctaena. The Permian-Triassic boundary is thus located within the Khartam Member. A sequence stratigraphic interpretation resulted in the identification of three main Maximum Flooding Intervals (MFI). The lower Huqayl MFI is located above the widespread subsurface Khuff-D anhydrite marker bed. The lower Midhnab MFI represents the maximum inundation of the Arabian Platform during Late Permian time. The lower Khartam MFI represents the last Permian inundation of the platform after a continental episode at the top of Midhnab Member. Secondary flooding intervals occur within the upper Huqayl, Duhaysan, and upper Khartam members. The first Triassic MFI could occur within the upper Khartam Member.

(430-Oral) Removal of complex near-surface effects by semi-automatic data-driven focusing operator determination

Verschuur, Dirk J. (Delft U - d.j.verschuur@ctg.tudelft.nl)

A major problem in Middle East land data is the imprint of complex near-surface effects on the subsurface image of the seismic data. Current solutions mainly involve the assumption of vertical ray-paths through a relatively simple near-surface layer, imposing a static shift on each seismic trace. As the propagation of seismic waves through the unknown near-surface layer is more complex than that, the solution should come from an imaging-based approach. The Common Focus Point (CFP) technology may provide a solution to this problem without deriving a complex near-surface velocity model, as it approaches the problem in a pure data-driven manner. The basics and initial results with this methodology have already been demonstrated by a few authors. The current implementation still involves considerable user-interaction, which may prevent this method from being used at large scale in the data processing stage. Therefore, the CFP iterative focusing operator updating procedure is proposed to be replaced by a global search through a solution space of possible focusing operators. Currently, genetic algorithms are employed for this purpose. Apriori information on the propagation effects is included to constrain the solution. This semi-automatic updating process can be formulated for both the travel times as well as the amplitudes related to the focusing operators. The end result should be a model-independent true-amplitude wavefield redatuming of the prestack data towards a selected datum reflector, below which the seismic reflection energy can be handled by the conventional processing techniques.

(406-Poster) Sequence stratigraphy and reservoir characterization of the Second Eocene Dolomite Reservoir, Wafra field, PNZ, Kuwait-Saudi Arabia

Wani, Mohamad R. (KOC - morafiq@kockw.com) and Sondos K. Al-Kabli (KOC)

The Second Eocene dolomite reservoir is one of the major producers in the giant Wafra field of the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia. This reservoir is of Paleocene age and occurs in the Tertiary Umm Er Radhuma Formation. The reservoir has been producing since the late 1950s under depletion drive. Recoveries, however, remain poor (about 5 percent of OIIP) mainly due to low-gravity oil and reservoir heterogeneity. A geological model that better defines reservoir heterogeneity is a prerequisite for evaluating and implementing EOR techniques. Primary porosity in subtidal dolomitized carbonates associated with evaporites as well as its modifications by dolomitization, dissolution and cementation typically occur in multiple zones that formed within shallowing-upwards, high-frequency cycles. This study attempts to identify these cycles in the Wafra Second Eocene reservoir, and place them in a sequence stratigraphic framework. Based on the study of core material, core photomicrographs and descriptions, and correlations in more than 500 wells, seven high-frequency cycles, which are further divided into 13 ‘zones’, were recognized. This zonation scheme better defines the poorer reservoir units and the intervening non-reservoir sections in a systematic manner. It highlights the distribution of grain-rich dolomites and evaporites, as well as the cyclicity of dissolution and cementation. The combination of (1) primary rock fabric, (2) diagenetic imprint, and (3) the zonation scheme introduced here, resulted in a better correlation of porosity versus permeability. This study will help improve reservoir definition over the entire field, and result in a more robust stochastic characterization. The reservoir model will be used in the sectorial development of the field.

(149-Oral) Permian-Triassic anoxia, carbonate productivity collapse and no consequences for reservoir rocks?

Weidlich, Oliver (U Kiel - ow@gpi.uni-kiel.de) and Michaela Bernecker (Erlangen U)

The Permian-Triassic boundary (PTB) event encompasses the end-Middle Permian and end-Late Permian mass extinctions. The latter is the most severe Phanerozoic event, which caused a complete breakdown of the marine carbonate-secreting communities during long-term oceanic anoxia. Far-reaching consequences concern the marine sediment composition during the Early Triassic on a global scale, because a unique facies prevailed, which is characterized by finely-laminated and horizontally-bedded mudstones, enigmatic cement crusts, and thrombolites. Except for some rift areas in the Neo-Tethys and the rim of the Arabian Plate, these Early Triassic limestones were deposited during a major transgression and, thus, lack common features of karstification. These sediments with unique sedimentological and geophysical properties, cover productive hydrocarbon reservoir units in the Middle East and other regions. While the impact of the PTB for the marine biota is well-constrained, consequences for the reservoirs in the Middle East have rarely been considered. Therefore, we tested the assumption that the Early Triassic facies significantly contributed to reservoir heterogeneities: (1) by compilation of our own and published data, we show that Lower Triassic sediments are thick enough to be resolved by wireline logs. (2) Using our digital archive of the Saiq and Mahil formations (Saih Hatat, Oman), we present facies and petrographic data flanked by stable isotopes characterizing the rock properties. (3) Using available log data from the Middle East, we try to trace the Lower Triassic facies on larger scale. Based on our integrated dataset, we regard Early Triassic carbonates as an important benchmark in both, pure carbonate and mixed carbonate-evaporite systems and, thus, recommend further studies on this unit.

(121-Oral) Fault zone morphology and segment geometry of onshore Abu Dhabi

West, Brian P. (ExxonMobil - brian.p.west@exxonmobil. com), Christopher A. Johnson (ExxonMobil), Mohamed Sattar (ADCO), Andrew M. Gombos (ADCO) and Peter D. Melville (ADCO)

Volume-based interpretation of extensive 3-D seismic data from onshore Abu Dhabi yields observations regarding the style and timing of deformation in this portion of the Arabian Plate. The most pervasive structural style is characterized by highly segmented, small-offset fault zones that we interpret as a conjugate shear set resulting from Late Cretaceous, NW-SE compression. The fault zones include a dominant, approximately N75W trend and a subsidiary, approximately N45W trend, both of which are segmented laterally and vertically. The dominant trend appears to be more through-going and exhibits both trans-pressional and trans-tensional dextral offset. The subsidiary trend is more variable and exhibits almost exclusively sinistral, trans-tensional offset. The subsidiary trend is also inferred to be associated with secondary stress-inducing factors that reinforce its expression; including; (1) torque at saddle point relays between non-parallel anticlines; (2) drape over anticlinal axes; and (3) reactivated, preexisting structures. There is no evidence for significant offset along either of these fault zones, despite their through-going map pattern (10s–100s of km). Rather, numerous individual fault segments compose the fault zone and are on the order of 100s of meters in length down to seismic resolution. The morphology of the fault zones is strongly influenced by the mechanical properties of the stratigraphy. Slight clockwise reorientation of many fault segments from deep to shallow is also analogous to clay-cake models of Riedel shears overlying deeper strike-slip faults. These observations have important implications for the evaluation of the fault seal risk in exploration settings and reservoir segmentation in production and development settings.

(289-Oral) The hydrocarbon potential of the underexplored Paleozoic and Triassic petroleum systems of Northwest Arabia

Whaley, Jane (IHS - jane.whaley@ihsenergy.com)

The majority of exploration in the northern Arabian Plate has been directed towards late Mesozoic plays, leaving the Paleozoic and Triassic sections relatively under explored. Since 1936 there have been over 12 deep structures drilled in western Iraq with seven oil and gas discoveries, six in the Triassic and one in the Paleozoic. Similarly in Syria, since 1940, there have been 120 structures drilled for Paleozoic and Triassic plays, with at least five Paleozoic and 52 Triassic oil, gas and condensate discoveries. In Jordan, two Ordovician gas reservoirs have been discovered since 1984. In northern Saudi Arabia, one important Ordovician gas and condensate field/discovery was made in 1993. When one considers the geographical size of the area, it is immediately apparent that these plays have significant potential. This paper describes the hydrocarbon potential of these sediments in northwest Arabia and introduces new play concepts to further unlock the potential in this prolific area. The paper covers Jordan, Syria, western Iraq and northwestern Saudi Arabia to the west of 43 degrees and north of 29 degrees. The paper is based on a recent study that (1) illustrates the hydrocarbon potential of the Paleozoic and Triassic sediments; (2) identifies the location of the Paleozoic and Triassic petroleum systems; (3) introduces new play concepts; (4) links plays and petroleum systems to known fields and discoveries; (5) analyses the proven hydrocarbon reserves of 67 Paleozoic and Triassic fields and discoveries; and (6) identifies, maps and highlights the potential of the Paleozoic and Triassic in more than 500 undrilled structures.

(431-Poster) Horizontal development of shallow shelf carbonate reservoirs: Cretaceous Saar Formation, Masila Block 14, Yemen

Wilkinson, Kent (Nexen - kent_wilkinson@nexeninc.com)

Oil was discovered on Masila Block 14, Yemen, in 1991 with first commercial oil production starting in 1994. Most of the oil production has been from clastics in the Early Cretaceous Upper Qishn Formation. The Tawila field is the largest of the 15 existing fields in the Masila block. Over the past three years greater emphasis has been placed on deeper secondary targets. The Tawila field is located on an isolated fault block structure within the NW-SE Say’un-al Masila Basin. The Saar Formation in the Tawila field is a 600 ft post-rift succession consisting of a series of shallow shelf carbonate sequences. Three reservoir facies have been identified within the uppermost portion of the Saar Formation: (1) leached rudist biostromes; (2) sucrosic tidal flat replacive dolomite; and (3) leached bioclastic-peloidal grainstone shoals. Multiple subaerial exposure events can be identified in core by irregular contacts, shale-filled cavities, and karst-related breccias. A mud-supported rudist floatstone biostrome forms a significant reservoir facies due to the creation of secondary micro- and macro-scale moldic and vuggy porosity (10-27 percent) related to an overlying exposure event. Dolomitization plays a key role in reservoir development. The early formation of dolomite directly below the Valanginian Saar unconformity is associated with restricted, tidal-flat sediments. Fine-grained sucrosic euhedral dolomite forms an excellent intercrystalline reservoir. A horizontal development program initiated in early 2003 has demonstrated a four-fold improvement in initial production rates (> 5,000 bopd) with a 30 percent increase in drilling cost compared with older vertical wells.

(182-Oral) Managing uncertainties in exploration and exploitation, Gharif Formation, Central Oman

Willoughby, John (PDO - john.willoughby@pdo.co.om) and Mohamed Al-Lawati (PDO)

The Gharif is the most productive clastic reservoir unit in PDO’s portfolio, but after almost 20 years of intense and successful exploration and exploitation, the play is now considered to be mature. The current prospect portfolio is dominated by subtle low relief closures, with vertical relief in the order of 10 -20m, and as such they are very sensitive to uncertainties in the accuracy of depth conversion and seismic imaging. Management of these is crucial if PDO is to pursue a successful exploration and exploitation program in the Gharif. This paper will focus on three of the principal uncertainties and will show how they are being managed. a) Imaging Uncertainty: Superior statics solution led to a reduction on the uncertainty of structural risk on the remaining opportunities, allowing PDO to polarise its portfolio. b) Velocity Uncertainty: By resolving the statics issues, we could demonstrate a marked improvement in our ability to establish “normal” time depth relationships which has led to an improvement in the accuracy of our depth conversion. c) Interpretation Uncertainty: Uncertainty exists in our ability to pick the Top Gharif in a reliable and consistent manner. Experience has shown that the expected seismic response of a strong Top Upper Gharif reflector is frequently not observed on reflectivity data, and it is very difficult to interpret top Gharif with confidence. New risks and uncertainties have been identified, understood and are currently in the process of being mitigated. This should translate into an improvement of the quality of the prospect portfolio. In the future, PDO’s Central Oman Gharif activities are expected to focus on field development and Near Field Exploration.

(202-Oral) 3-D boundary element modeling for fracture distributions in deep carbonate intervals, northern Kuwait

Wu, Haiqing (ChevronTexaco - hwu@kockw.com), Mohammed D. Al-Ajmi (KOC), Andrew Corley (ChevronTexaco), Anthony Lomando (ChevronTexaco), Lilian Skander (ChevronTexaco), Sunil K. Singh (KOC), Nikhil C. Banik (KOC), Abdul Aziz H.A. Sajer (KOC), Heyam M. Ammar (KOC), Moinuddin Didwai (KOC) and Meshary Ameen (KOC)

This study used a Boundary Element Method (BEM) to analyze reservoir scale deformation and build a geomechanical model to predict fracture distributions in the deep Jurassic carbonate intervals in northern Kuwait. BEM is much more efficient than the Finite Element Method (FEM) in 3-D numerical analyses for faulted reservoirs. The BEM model is based on seismic interpretation of faults and horizons, boundary conditions on these faults, remote stresses and overburden, and well control using image logs and cores. Stress tensors are calculated first at observation points around major faults. Coulomb failure criterion and maximum principal differential stresses are then used to determine the possible orientations and distribution of fractures or small faults. Borehole image logs and core data constraint the model for fracture density and orientation. Finally, fracture bubbles and rose diagrams are generated for better 3-D visualization and well planning in the area. A specific workflow process including curvature analysis, analog comparison, and geostatistical modeling was applied to validate the geomechanical modeling effort. We collected acoustic borehole images, cores, logs, and seismic interpretations in the deep Jurassic carbonate intervals to detect fracture distributions from the Najmah/Sarjelu through Lower Marrat formations. An uncertainty model was generated to show the influence of a variety of data types, ranges, and proportions. Finally, we analyzed present-day stress distributions and directions, built a 3-D stress model, and calculated stress distributions on major faults and fractures to indicate if they enhance or prevent fluid flow in the carbonate intervals. Results include: (1) 3-D fracture density distribution and possible fracture orientations; (2) possible sub-seismic fault locations and orientations; and (3) present-day stress distributions in the reservoir and on major and sub-seismic faults showing slip tendency and dilation tendency.

(480-Oral) Processing, inversion, and interpretation of shallow seismic data

Yilmaz, Oz (GeoTomo - oz@geotomo.com)

The seismic method has three applications with different requirements for band-width and depth-width: (1) earthquake seismology with a bandwidth up to 10 Hz and a depth of interest down to 100 km; (2) exploration seismology with a bandwidth up to 100 Hz and a depth of interest down to 10 km; and (3) engineering seismology with a bandwidth up to 1,000 Hz and a depth of interest down to 1 km. Each of the three categories of seismology makes use of a specific wave type: (1) in earthquake seismology, dispersion of surface waves is used to delineate velocity-depth models for the oceanic and continental crusts. (2) In exploration seismology, reflected and diffracted waves are used to derive an image of the subsurface. (3) In engineering seismology, refracted waves are used to derive a velocity-depth model for the near-surface. For a specific category of seismology, the associated wave type is considered signal, while other wave types are considered noise. For instance, surface waves are essential for earthquake seismology, while they are treated as coherent linear noise in exploration seismology, ground roll in land seismic exploration, and guided waves in marine seismic exploration. I present a workflow for analysis of shallow seismic data to estimate a near-surface model defined by layer geometries within the soil column, and the P- and S-wave velocities of the layers themselves. Specifically, I use reflected waves in recorded shallow seismic data to derive a seismic image represented by a CMP stack and refracted waves to estimate a P-wave velocity-depth model of the near-surface. I then use the P-wave velocity field resolved from tomography to guide the interpretation of the CMP stack so as to delineate the layer geometries within the soil column in depth. Additionally, I use Rayleigh-type surface waves to estimate an S-wave velocity profile in depth. I demonstrate the unified workflow for shallow seismic data acquired for geotechnical site investigations, and coal and groundwater exploration.

(119-Poster) Integrated 3-D seismic analysis and sequence stratigraphy of the Lower Cretaceous for a large carbonate field in Abu Dhabi

Yose, Lyndon A. (ExxonMobil - lyndon.a.yose@exxonm obil.com), Steve Bachtel (ExxonMobil), Andrew Gombos (ADCO), Jason Scott (ADCO), Po Tai (ExxonMobil), Christian J. Strohmenger (ADCO), Nat Stephens (ExxonMobil), Ismail A. Al-Hosani (ADCO), Imelda Johnson (ExxonMobil), Jim Schuelke (ExxonMobil), Peter Holterhoff (ExxonMobil), Khalid Al-Amari (ADCO), Amy Ruf (ExxonMobil) and Brian Coffey (ExxonMobil)

New, high-effort 3-D seismic data collected for a field in Abu Dhabi provide some of the highest resolution images ever obtained for a carbonate reservoir. Seismic data were integrated with well and core data, and with available age dates (biostratigraphic and isotopic), into a new sequence-stratigraphic model for the Lower Cretaceous (Aptian/Albian). Third-order sequences stack to form a complete accommodation cycle from transgressive, to highstand, to late highstand, to lowstand. Stratal architecture, facies distributions, and reservoir quality all vary predictably within the sequence stratigraphic framework and, at variable scales, are directly imaged or detected by the new 3-D seismic data. The seismic workflow employed in this study included post-stack data optimization, evaluation of multiple seismic attribute volumes for interpretation of reservoir architecture, quantitative seismic facies classifications, multi-attribute porosity predictions, and calibration with well, core and production data. Advanced visualization tools and volume co-rendering allow for imaging carbonate environments and architectural elements rarely seen in carbonate seismic data. In the early highstand of the composite sequence, a mosaic of rudist patch reefs and shoals (flow units), tidal channels (flow baffles), and inter-shoal ponds (lateral flow barriers) are clearly observed in seismic images, comparable in detail to Landsat images of modern carbonates. Seismic images of a prograding shelf margin complex (late highstand) reveal remarkable detail on clinoform geometry and connectivity, and systematic architectural variations keyed to changes in accommodation and sediment supply. The integrated seismic interpretations and reservoir framework provide new insights on carbonate sequence architecture, and for improved reservoir modeling and optimization strategies.

(120-Oral) Integrated approaches to carbonate reservoir characterization and prediction: examples from United Arab Emirates fields and outcrops

Yose, Lyndon A. (ExxonMobil - layose1@upstream.xomc orp.com), Lawrence J. Weber (ExxonMobil), Christian J. Strohmenger (ADCO), Abdulla Al-Mansoori (ADCO) and Omar Suwaina (ADNOC)

Quantifying carbonate reservoir architecture and flow properties in 3-D geologic models requires integration of multiple types and scales of data within hierarchical sequence-stratigraphic and structural frameworks. The present study highlights the following workflow elements with examples from the Lower Cretaceous in Abu Dhabi: (1) integration of outcrop and subsurface data to develop regional structural and sequence-stratigraphic frameworks that can be applied consistently from one field to the next; (2) volume-based enhancement and analysis of 3-D seismic data for quantification of reservoir architecture and rock properties; (3) validation and calibration of reservoir predictions using outcrop, well, core and production data; (4) characterization of sub-seismic (high frequency) variability in structural and stratigraphic rock properties through integration of outcrop and subsurface data into high-resolution frameworks; and (5) hierarchical integration of all scales and types of data in static and dynamic 3-D reservoir models for performance prediction. Special emphasis is placed on the value of 3-D seismic in defining the ‘next generation’ strategies for reservoir management and optimization in Abu Dhabi. High-effort, high-quality seismic data provide unparalleled imaging and visualization of carbonate reservoir architecture (stratigraphic and structural) that can be incorporated directly into 3-D models. Prestack and poststack seismic attributes provide quantitative information on carbonate porosity and fracture properties at the interwell spacing. Time lapse (4-D) seismic shows promise for tracking fluid front movement over time. Successful application of seismic technologies and information, however, remains highly dependent on calibration to appropriate outcrop and subsurface data, validation with geologic models and concepts, and integration within sequence-stratigraphic and structural frameworks.

(105-Oral) Hawqa-revival of a Gharif field in central Oman

Young, Adrian (PDO - adrian.nr.young@pdo.co.om), Andrew Faulkner (Baker Hughes), Jonathan Strauss (Baker Hughes), Xavier Maasarani (PDO), Alan Wheeler (Baker Hughes), Abdullah Shamakhi (PDO) and Walter Slijkerman (PDO)

This study describes the issues regarding the subsurface development plans for the Hawqa field, located in the Bahja area of Central Oman. Hydrocarbons are structurally and stratigraphically trapped in several but relatively thin shallow marine and fluvial sandstones within the Permian Middle (MG) and Upper Gharif members. There is evidence for multiple fluid contacts and fluid properties range from high gravity saturated oil in the MG3 reservoir to volatile oils in the MG2 units, to rich gas condensates and oil in the Upper Gharif member. The structure was perceived to be small at the time of discovery in 1989. Gross production from the exploration well declined rapidly within weeks and the well was closed in by mid-1990. A recent review of the Hawqa accumulation identified a significant upside potential, which was subsequently proven by the appraisal well Hawqa North-1 in April 2002. In particular, MG3 production potential has been found to be prolific. However, recovery due to depletion is expected to be very low (about 5 percent) as MG3 reservoir pressure is near bubble point and aquifer support is expected to be modest at best. Thus, water flooding is planned from the start of production. A fast track development of the Hawqa field is being pursued by a joint team from PDO and Baker Atlas. Major field-development risks have been identified and are being managed by an ongoing data acquisition and study program leading to a development plan by September 2003. Major subsurface development risks include structural definition and reservoir continuity. Reservoir structure has been delineated by aggressive appraisal drilling and by newly-acquired 3-D seismic. A high degree of reservoir continuity in the MG3 has been confirmed by interference testing between wells. An additional risk for the water flood is effective injectivity near the wellbore of planned injectors. Full compatibility with injection water is planned by using the underlying Al Khlata Formation water as a source. Moreover, only low solids concentrations are being allowed in the injection water and, hence, high standard water filtering is being planned. Currently, the choice between matrix injection and injection aided by fraccing is being studied. Further study will decide on the optimum well placement pattern and well type. Water flood in the Hawqa field is planned to yield production in 2004. A rigorous technical and value assurance review process was put in place to assure that investments are secure. Full field development will take place in subsequent years; whilst developing the MG3, the overlying, complex MG2 and Upper Gharif reservoirs will be extensively appraised.

(448-Oral) Next tomography for near-surface imaging

Zhang, Jie (GeoTomo - jie@geotomo.com)

During the past ten years, constraining and stabilizing travel-time tomographic inversion has been a major research topic. As a result, tomography has advanced from ‘creeping’ inversion that damps model changes to ‘jumping’ inversion that constrains the model itself. The objective function of a tomography problem no longer includes just a data misfit term. Model regularization becomes explicit. Even more, continuum inverse theory has been introduced into seismic tomography and the tomography solution becomes independent on initial models. These achievements have led to many successful applications of tomography in both the near-surface and subsurface areas. However, the challenge for tomography accuracy still remains; in particular, in the near-surface areas where lateral velocity contrasts are often great. Resolving these velocity contrasts is critical for making accurate statics interpretation. Although the use of continuum inverse theory for grid-based tomography validates a stable solution, imposing continuum often lowers resolution across different geological units. The truth is that there is really no continuum from soil to limestone. Thus, we must develop the next tomography that is not only well-posed, but also preserves highresolution contrasts. One of the proposed methods is Geology-Regularized Tomography (GRT) that imposes continuum only within the same geological unit and breaks smoothing at interfaces. We may apply well logs and uphole interpretation to help define a priori geological zones. Initial tomography using continuum inverse theory will generate a globally-smooth solution, and different geological units will be automatically identified from velocity contours. Subsequent tomography using GRT method will lead to a geology-consistent high-resolution solution.

(385-Oral) Refraction residual static corrections using far offset data

Zhu, Weihong (Digicon - weihong.zhu@aramco.com) and Yi Luo (Saudi Aramco)

This study presents results of applying a novel, Refraction Residual Statics (RRS) algorithm to seismic data from Saudi Arabia in order to compensate for near-surface effects. The RRS method involves three main steps: (1) automatic picking of travel-times of a selected refraction event with some user-defined seed values; (2) the picked travel-times with the same offsets are smoothed and used as the calibration curves for the next step; and (3) the differences between the raw picks and the computed calibration curves are inverted for the final statics at every shot and receiver location in a surface-consistent manner. The RRS method can significantly improve the focusing of seismic data, and thus enhance the quality of time stacked sections in areas with severe statics problems. The maximum statics value in our study reached up to 40 milliseconds. More importantly, it was found that refraction data from deep events, received at far offsets, can be used to derive the correct statics values. Contrary to most conventional refraction-based approaches that rely on near offset data, our methodology employs far-offset refraction data. This successful attempt using far-offset data may have significant implications in most areas of the Arabian Peninsula since near offset travel-times are often difficult to pick automatically and/or even manually.

(94-Oral) Thin-skinned ramp promontory model for the Dezful Embayment, Zagros Mountains, Iran

Zweigel, Peter (SINTEF - peter.zweigel@iku.sintef.no)

The oil-prolific Dezful Embayment is a structural depression in the outer part of the Zagros foreland fold and thrust belt. Formations in the embayment are several thousand meter deeper than in its lateral neighborhood. Publicly discussed theories for the origin of the embayment include a tectonic half-window, thrusting into a preexisting depression, local post-thrusting subsidence along fault zones bordering the embayment, and basement faults active during Cenozoic convergence. This study suggests an alternative model, which tries to explain the structural depression as being caused by the presence of a footwall ramp promontory of about the same size and shape, but presently slightly more hinterlandward position than the present embayment. A foreland-ward shallowing of the basal detachment onto the ramp would imply a correspondingly reduced thickness of the frontal part of the hanging wall. This model would explain interalia the following features: (1) plunge of anticlines from the neighboring areas (thick hanging wall) into the depression (thinner hanging wall); (2) tighter folding and thrusting, higher topographic position, and erosion to deeper stratigraphic levels hinterland-ward of the depression (the promontory acting as a buttress) as compared to the laterally neighboring areas; (3) higher topographic position and erosion to deeper stratigraphic levels in the foreland-ward parts of the areas laterally neighboring the depression (thick package thrusted onto ramp) as compared to their hinterland-ward part (normal thrusting of thick package). The hanging wall ramp flexure at the lateral margins of the embayment, which are oriented obliquely to the convergence direction, is a preferred site for structural complications.

ABBREVIATIONS OF ORGANIZATION

The names of companies and institutions to which presenters and chairpersons are affiliated have been abbreviated. For convenience, all subsidiary companies are listed as the parent company. The following is the list of abbreviations used.

Aachen University, Germany

ABB Offshore Systems, UK

ADCO: Abu Dhabi Company for Onshore Oil Operations

ADMA-OPCO: Abu Dhabi Marine Operating Company

ADNOC: Abu Dhabi National Oil Company

AECS: Atomic Energy Commission, Syria

Ain Shams University, Egypt

Al-Khafji JO: Al-Khafji Joint Operations, Saudi Arabia

Al-Khaleej, Saudi Arabia

Amir Kabir University, Iran

Anadarko Petroleum Corporation, USA

Antipolis University - Nice Sophia

Apache Egypt Companies

Badley Ashton & Associates, USA

Bapco: Bahrain Petroleum Company, Awali

BGS: British Geological Survey, UK

Birmingham University, UK

BRGM: Bureau de Recherches Géologiques et Minières, France

C&C Reservoirs Limited, UK

Cairo University, Egypt

Cambridge University, UK

CASP: Cambridge Arctic Shelf Programme, Cambridge University, UK

CCL: Cambridge Carbonate Limited, UK

CGG: Companie Générale de Géophysique, France

CNRS: Centre Nationale Recherches Scientifique, France

CoreLab, Canada

Daleel Petroleum Company, Oman

Damascus University, Syria

Delft University of Technology, The Netherlands

Devon, Canada

DEZPC: Der Ez Zor Petroleum Company, Syria

Digicon Geophysical Ltd., USA

DPC: Dubai Petroleum Company, United Arab Emirates

ELS Consulting Ltd., Canada

ENRES International, The Netherlands

ERL: Earth Resource Ltd., UK

Erlangen University, Germany

GAFAG: Gesellschaft fuer Angewandte Fernerkundung, Germany

GNPOC: Greater Nile Petroleum Operating Co. Ltd., Sudan

GeoScience Limited, UK

Geosystem Srl, Italy

GeoTech Consulting, Bahrain

Glasgow University, UK

Golder Associates: USA

GPC: General Petroleum Company, Egypt

GPL: Gulf PetroLink, Bahrain

GSI: Geological Survey of Iran

GUPCO: Gulf of Suez Petroleum Company, Egypt

GX Technology Canada Ltd., GX Technology

Heriot-Watt University, UK

IES: Integrated Exploration Systems, Dubai

IFP: Institut Français du Pétrole, France

IHS: IHS Energy Group, UK

Intergraph Middle East, UAE

IOOC: Iranian Offshore Oil Company, Tehran

Jackson State University, USA

Jason Geosystems Middle East, UAE

JNOC: Japan National Oil Company, Tokyo

JODCO: Japan Oil Development Company, Tokyo

Joint Virtual Reality, Centre for Carbonate Studies, Oman

KACST: King Abdulaziz City for Science and Technology, Riyadh, Saudi Arabia

Kelkar and Associates, USA

Keyhan Exploration and Production Services, Iran

KFUPM: King Fahd University of Petroleum and Minerals, Dhahran

KOC: Kuwait Oil Company, Ahmadi, Kuwait

KOC-JO: Kuwait Oil Company-Joint Operation

Kuwait University, Kuwait city

Larch Consulting Ltd., Canada

Lebanese University, Beirut

Ljubjana University, Slovenia

Lynx Information System, UK

Maersk Oil Qatar AS

Martin Luther University, Germany

Millenia, UK

MIT: Massachusetts Institute of Technology, USA

MMWR Oman: Ministry of Municipalities and Water Resources, Oman

MPI: Max Planck Institute, Germany

MVE: Midland Valley Exploration Ltd., UK

Neftex Petroleum Consultants Ltd., UK

Nexen Petroleum International, Canada

NIOC: National Iranian Oil Company

NIOZ: Netherlands Institute for Sea Research

NISOC: National Iranian South Oil Company

Norsk-Hydro, Norway

OAPEC: Organization Arab Petroleum Exporting Countries, Kuwait

OilTracers, USA

Paradigm Geophysical Ltd., UK

PDO: Petroleum Development Oman

PDOC: Petrodar Operating Company, Khartoum, Sudan

Petrosurveys, USA

Petropars Ltd., Iran

PGA: Petroleum Geological Analysis Ltd., UK

PGS: Petroleum Geo-Services

Pierre and Marie Curie University, France

Politecnico di Torino, Italy

QP: Qatar Petroleum, Doha

Repsol, Spain

ResLab: Reservoir Laboratories, UAE

RIPI: Research Institute of Petroleum, Iran

Royal Holloway, University of London, UK

RRI: Robertson Research International, UK

RUB: Ruhr University at Bochum, Germany

Saler Geological Services, USA

Sana’a University, Yemen

SAT-JO: Saudi Arabian Texaco-Joint Operation

Selan Exploration & Technology Ltd., India

SGS: Saudi Geological Survey, Jeddah

Sii-ASE, Oman

SINTEF Petroleum Research, Norway

Sipetrol International SA, Egypt

SQU: Sultan Qaboos University, Muscat, Oman

Stanford University, USA

Statoil, Norway

Talisman Energy, Canada

Tarbiat Modares University, Iran

Target Consultants, UK

TEEC: Trappe Erdöl Erdgas Consultant, Germany

University of Aberdeen, UK

Université de Bordeaux, France

University of Bremen, Germany

University of Darmstadt, Germany

University of Kiel, Germany

University of Leeds, UK

University of London, UK

Université de Lyon: France

University of Miami, USA

University of Milan, Italy

Université Paris IV, France

University of Reading, UK

Université de Rennes, France

University of Salahaddin, Iran

University of Tehran, Iran

University of Texas, Austin

University of Tuebingen, Germany

UAE U: United Arab Emirates University, Al Ain

University of Urmia, Iran

UC London: University College London, UK

USGS: United States Geological Survey, USA

Varol Research, UK

Vsfusion, UK

Zadco: Zakum Development Company, United Arab Emirates