Integration of Geology and Geochemistry into Basin Modeling and Exploration Risk Analysis: Case Study from Central Saudi Arabia

Mahdi A. Abu-Ali, Saudi Aramco James E. Lacey, Adry K. Bissada Houston Advanced Research Center and Jim G. McGillivray, Saudi Aramco

This study involves a new approach for play/prospect evaluation that combines basin modeling technology with risk analysis. In this method geologic and geochemical data are integrated to develop a probabilistic estimation of oil and gas reserves.

The process estimates oil and gas generated and expelled by comparing the organic richness, maturity, kerogen type and other factors with the results of a very large number of basin modeling runs. The hydrocarbon charge arriving at the trap is computed by subtracting from the expelled hydrocarbons the amounts leaked, retained by the carrier, or dissolved in the formation water. Due to the inherent uncertainties in estimates of the relevant data, the technique inputs most likely values and probable ranges. Finally, the volume of hydrocarbons trapped is set equal to the lesser amount of either trap capacity or hydrocarbon charge. Results are expressed as the mean and median reserves, the probability of reserves greater or less than critical economic thresholds, and the possible range of reserve values. This process can provide a powerful tool for high-grading exploration prospects in terms of the desired combination of reserves potential and exploration risk. In this paper, details of the process will be highlighted and illustrated by examples from Central Saudi Arabia.

Mahdi A. Abu-Ali is a Geologist/Geochemist with the Regional Mapping Group of Saudi Aramco. He has 13 years of experience in exploration and basin analysis studies. His areas of interest include hydrocarbon generation and migration modeling, geologic mapping and exploration risk analysis. Mahdi is affiliated with the AAPG, EAOG, and ACS. He holds BSc and MSc degrees in Industrial Chemistry and Geochemistry from King Fahd University of Petroleum & Minerals, Saudi Arabia and the Colorado School of Mines, USA, respectively. Mahdi has published and presented several papers on the Paleozoic petroleum system of Saudi Arabia.

James E. Lacey has been a Senior Research Scientist for the Houston Advanced Research Center since September 1995. He previously worked for 28 years for Texaco in exploration research and for three years as a development geologist for Chevron. James received his BSc and MSc degrees from the University of Pittsburgh and a PhD degree from the University of Illinois. His current interests include the application of risk analysis to petroleum exploration and the development of geochemical techniques to allocate commingled production streams to specific sources.

Adry K. Bissada is a Senior Research Scientist and Director of the Geochemistry Unit at the Houston Advanced Research Center. He holds an MSc degree in Geology/Geophysics and a PhD in Geology/Geochemistry, both from Washington University in St. Louis. He has 30 years experience in the petroleum industry. Adry has published numerous papers on principles and practice of geochemistry in exploration and production operations, and lectured extensively around the world on many aspects of petroleum geochemistry. He has developed a variety of geochemical tools and processes for which four patents have been issued.

Jim G. McGillivray is currently incharge of the Regional Mapping Group with Saudi Aramco. He has 27 years of petroleum and exploration industry experience represented by 12 years with Chevron Standard Limited and Wainoco Oil and Gas Limited in Canada, and 15 years with Saudi Aramco. Jim has BSc and MSc degrees in Geology from McGill University.

Geological Reconstruction of the Paleozoic Hydrocarbon System, Central Saudi Arabia

Mahdi Abu-Ali, Saudi Aramco Jean-Luc L. Rudkiewicz, Institut Français du Pétrole Jim G. McGillivray, Saudi Aramco and Françoise Behar Institut Français du Pétrole

In this paper an integrated geochemical model is developed for the Paleozoic oil and gas system of Saudi Arabia. The generation and migration history has been reconstructed through geologic time to assess gas and oil expulsion, migration, entrapment and future exploration potential.

The Paleozoic oil and gas system in Central Saudi Arabia consists of the Lower Silurian Qusaiba Hot Shale as the major source rock and the Permian Unayzah sandstone as the main regional reservoir. To reconstruct the hydrocarbon generation, immature and mature source rock samples were recovered, and their compositional kinetics were determined. The gas potential of the most immature sample amounts to 101 mg/g Total Organic Carbon (TOC), compared to an oil potential of 384 mg/g TOC. The thermal regime and migration directions were reconstructed through time using a 3-D data set comprising the major formations from Paleozoic to Cenozoic over the 480 by 550 kilometer study area. Present day bottom hole temperatures and past maturity indicators were used for calibration. The 3-D data set was then backstripped to reconstruct paleoslopes for all layers, with special emphasis on the Unayzah and Qusaiba formations.

The expulsion history of the Qusaiba source rock shows a peak expulsion younger than 52 million years, with a significant amount of gas being created from secondary cracking of oil retained in the source rock. Paleostructure of the Unayzah reservoir and associated capture areas were computed at different times, especially after peak expulsion. The expelled amounts of hydrocarbons from the Qusaiba source rock were then added up to rank the different structures according to their charge volume and the nature of trapped components. This highlighted the most promising structures for more detailed review of future exploration.

Mahdi A. Abu-Ali and Jim G. McGillivray (see abstract “Integration of Geology and Geochemistry into Basin Modeling and Exploration Risk Analysis: Case Study from Central Saudi Arabia” on page 38 for biographies and photographs)

Jean-Luc L. Rudkiewicz is Project Leader for Pilot Studies in Basin Evaluation with Institut Français du Pétrole (IFP) in Rueil-Malmaison, France. He completed a PhD from the Paris School of Mines in 1989. Starting in 1987, his initial research focused on stochastic modeling of heterogeneous reservoirs. Since 1992, Jean-Luc has been involved in compositional modeling of generation and migration of hydrocarbons in sedimentary basins. He currently applies IFP’s basin modeling tools to basins worldwide, in cooperation with industrial partners.

Françoise Behar is Project Leader with Institut Français du Pétrole for compositional modeling of hydrocarbon generation and degradation in sedimentary basins. She completed a PhD in Geology from the University of Paris in 1978 and a PhD in Chemistry from the University of Strasbourg in 1982. Françoise joined IFP in 1982 and currently works on kinetics of oil and gas generation in source rocks and thermal stability of the hydrocarbons in reservoirs.

First Results of 3-D Seismic Prospecting, Onshore Azerbaijan Republic

Ibrahim D. Akhundov Socar

The Azerbaijan Scientific Research Institute of Geophysics has developed a new technique for seismic prospecting which was tested in Jafarly and Nasibbeyli in onshore Azerbaijan. The technique is suitable in conditions of complex topographic relief and is based on a non-standard system for areal observations on profiles of arbitrary form. The processing of the data includes 3-D time migration and the data is presented in depth.

In the areas of Jafarly and Nasibbeyli, the exploration play is a stratigraphic trap in the top of the Mesozoic which pinches out below a thick series of Miocene-Pliocene deposits. The play was initially defined with 2-D seismic lines acquired by Azneftegeofizika which imaged the top of the Mesozoic pinch out. The distribution of the pinch-out was mapped using the new technique on 3-D seismic data. The 3-D survey also increased the areal distribution of the exploration target.

Ibrahim D. Akhundov is currently Head of the Laboratory of Total Seismic Prospecting at Azerbaijan Geophysical Scientific Research Institute of the state oil company of Azerbaijan Republic. Ibrahim graduated from Azizbekov Industrial Institute, Azerbaijan, in 1957. He has 40 years experience in formulation techniques and processing 2-D and 3-D seismic surveys. He is a member of the National Committee of Azerbaijan Geophysicists.

The Impact of 3-D Reservoir Modeling on Field Development: Case History from the Warad Field, Oman

Talib A. Al-Ajmi Petroleum Development Oman

Full field 3-D modeling was undertaken to enhance the understanding of the reservoir architecture of complex sandstone reservoirs in the Warad field of south Oman. The 3-D modeling has investigated the major geological uncertainties associated with the calstic reservoirs of the sheetflood Mahwis and the glacial Al Khlata formations. Scale and continuity of calcite cemented zones and shales including faulting have been tested through multiple scenarios in various simulation models to assess aquifer pressure support. Modeling has revealed that low productivity characterizes the vertically heterogeneous Mahwis reservoir sands. These sands are dominated by vertically stacked stochastic shales with low vertical permeability. High production associated with high water cut is typical of the homogeneous lower member of Al Khlata Formation and is due to the high vertical and horizontal permeability of the reservoir sands and conductive fractures. As a result, the field development plan includes 12 horizontal multi-lateral wells in areas of high Kv/Kh and 10 deviated (high angle) wells in areas of low Kv/Kh to ensure penetration of the full suite of reservoir units.

Talib A. Al-Ajmi is currently a Production Geologist for Petroleum Development Oman, working on the Amin and Warad fields. He holds a BSc degree in Geosciences from the University of Arizona. Talib has been working with Petroleum Development Oman for the last seven years. He is an SPE member.

The Heavy Oil/Tar Mat in Minagish Field, Kuwait: Detection, Characterization and Impacts on Reservoir Performance

Hamad Al-Ajmi, Ram S. Gaur Kuwait Oil Company and Andrew Brayshaw British Petroleum, Kuwait

In common with many giant oil fields worldwide, the Minagish field (Minagish Oolite Formation) in Kuwait has an areally extensive and variable thickness, heavy oil zone at the base of the oil column. The heavy oil zone, or tar mat, is thought to represent a partial permeability barrier between the aquifer and oil leg, but its fieldwide effect and properties are unknown. As the Minagish field undergoes full-field waterflood, understanding the distribution and properties of the heavy oil zone is critical to planning whether to inject water above the tar mat - with unavoidable reserve losses - or inject into the aquifer directly beneath where the tar mat is poorly developed.

Difficulty in discriminating between cemented and bituminous intervals on electric logs has lead to the adoption of new geochemical techniques (Iatroscan) to detect the presence and thickness of the heavy oil zone. Analyses indicate that the tar mat is characterized by a high proportion of asphaltenes, but low concentration of saturates, polars and aromatics. The Minagish heavy oil zone/tar mat is interpreted to be the result of de-ashphalting as opposed to gravity segregation. Compositional variations through the oil column have been mapped in Minagish using geochemcial parameters measured on samples. A predictive model for API gravity and live oil viscosities has been established for Minagish, together with a model for tar mat occurrence and thickness. New understanding of the tar mat, its genesis and spatial distribution has helped in developing a water injection strategy that maximizes recoverability in Minagish. This information will also play a key role in determining ways to liberate oil held within the heavy oil zone.

Hamad Al-Ajmi is currently a Geologist with Kuwait Oil Company with 6 years experience. He holds a BSc in Geology from Kuwait University and has worked on a range of fields in Kuwait as a Petrophysicist and later as a Development Geoscientist. He also has experience working in the North Sea, playing a role in the Bruce field development whilst on secondment to British Petroleum. His primary area of expertise is in field development, formation evaluation and permeability modeling. He is an active member of the AAPG.

Ram S. Gaur has 37 years experience in development geology and reservoir engineering. He is a Senior Development Geologist with Kuwait Oil Company (KOC) since 1979. Ram holds an MSc from BHU India. Prior to joining KOC he worked for ONGC India for 19 years in the Petroleum Research Institute teaching graduates in development geology and reservoir engineering developing new oil fields. At KOC he has worked on reservoir and development studies of all producing reservoirs, geological operations and training of Kuwaiti professionals. He is an active member of the SPE.

Andrew Brayshaw is currently a Senior Technical Advisor for BP Exploration, seconded to Kuwait Oil Company. He has 13 years experience with BP in exploration, development geoscience and commercial evaluation of reservoir developments. He has worked variously in Qatar, Egypt, Papua New Guinea, Norway, Azerbaijan and Alaska. His primary area of expertise is new field developments and reservoir management. He holds BSc and PhD degrees from the University of London, and a fellowship in engineering at the University of Florence, Italy.

3-D Seismic Survey Design Parameters

Habib Al-Alawi Bahrain National Oil Company

The design stage is an important step in planning the acquisition, processing and interpretation of a 3-D seismic survey. A computer program was written to calculate design parameters such as fold, bin size, maximum and minimum offsets, vertical and lateral resolution. The program was used to evaluate survey design on the Bahrain field.

Habib Al-Alawi acquired a BSc degree in Physics from Bahrain University in 1989. Habib worked as a Teaching and Research Assistant with the same University between 1989 and 1994. He joined Bahrain National Oil Company’s Exploration Team in July 1994 as Exploration Geophysicist, working mainly on the interpretation of seismic data.

Impact of 3-D Seismic Surveys on Minagish and Umm Gudair Fields Development, Kuwait

Alaa M. Al-Ateeqi and Dave G. Foster Kuwait Oil Company

In 1996 Kuwait Oil Company started to acquire a massive program of both 2-D and 3-D seismic data, believed to be one of the largest in the region. The 2-D survey was aimed at defining possible prospective areas, while the 3-D surveys are aimed at achieving increased productivity of the existing oilfields. The 3-D surveys acquired over the Minagish and Umm Gudair fields in the west region of onshore Kuwait were two of the first 3-D surveys to be completed.

The 3-D data is of excellent quality, showing very high signal-to-noise ratios, and having stable phase and amplitude characteristics. The rapid interpretation of these 3-Ds has been enabled by state-of-the-art interpretation and visualisation software at Kuwait Oil Company, and has already had a considerable impact on the perception of the subsurface geology of the mainly Cretaceous reservoirs. Fault patterns have been reliably defined on both fields for the first time. Accurate depth maps have been achieved through the superior 3-D image, together with careful attention to statics corrections and depth conversion. This allows accurate well placement. Acoustic impedance inversion is being used to define reservoir and aquifer porosity. The impact of the 3-D surveys is to enable optimum development decisions to be made, thus maximizing the value of Kuwait’s valuable oil resources.

Alaa M. Al Ateeqi received his BSc in Geology from Kuwait University in 1993 and joined Kuwait Oil Company in September of the same year. Alaa worked as a well-site geologist for one year before joining the Geophysics Division as a seismic interpreter, where he was initially seconded to Exxon working on exploration assignments. He is currently part of the West Kuwait Fields Seismic Interpretation Team, focusing on the Umm Gudair field.

Dave G. Foster has worked for British Petroleum since 1981 when he received his BSc in Geology with Geophysics from Leicester University. He has extensive 2-D and 3-D seismic interpretation experience, and has occupied posts in Tunisia, the North Sea, onshore UK, Egypt, Canada, and the Gulf of Mexico. Dave is currently seconded to the Kuwait Oil Company, where he is West Kuwait Fields Seismic Interpretation Team Leader.

Integrating Fluid Flow and Borehole Imaging Data in Fracture Characterization, Hanifa Reservoir, Abqaiq Field, Saudi Arabia

Haider H. Al-Awami, George A. Grover, Rick Davis, Saudi Aramco Sait I. Ozkaya and Joerg E. Mattner Western Atlas International

The Hanifa reservoir at Abqaiq field, eastern Saudi Arabia, consists of microporous lime-mudstone (average porosity 17%) with low matrix permeability (average 1 mD). Borehole (core, image log, flow profile) studies, in conjunction with 3-D seismic interpretations, indicate that the Hanifa reservoir is pervasively fractured. Recent integration of fluid flow profiles with detailed interpretations of borehole image logs, from seven horizontal wells and one vertical well, indicate that two conductive fracture types can be distinguished. (1) Fracture swarms are from 100 meters up to several kilometers long, have a dominant east-northeast strike and an average spatial separation of 600 meters between swarms. (2) Stylolitic-fractures are densely-clustered, centimeter- to decimeter-high, tension gashes, emanating from stylolites, with an areal density of at least 7 million fractures per square kilometer. The former are called ‘super fractures’ since they contribute 75% to 100% of wellbore fluid flow when encountered. The latter stylolitic fractures occur mainly in the upper and lower parts of the reservoir. The density of the stylolitic fractures shows an inverse relationship with porosity. Production logs suggest that only a minor flow is contributed from stylolitic fractures.

Fracture length distributions reveal that 30% of the ‘super fractures’ could extend through the overlying Jubaila Formation and into the Arab-D reservoir. Well test analysis, numerical reservoir simulations using both dual- and single-porosity models, 3-D seismic mapping of faults at various horizons and horizontal drilling have confirmed the existence of fault communication between the Arab-D and Hanifa reservoirs. The implications of this faulting on depletion strategies of the Hanifa reservoir in conjunction with the depletion of the overlying Arab-D reservoir are discussed.

Haider H. Al-Awami is General Supervisor, Abqaiq Area Reservoir Management with Saudi Aramco. He joined Saudi Aramco in 1976 and worked in production, drilling and reservoir engineering until 1980 when he had a one year overseas assignment with Exxon Production Research Company in Houston. He became General Supervisor of Reservoir Engineering in 1985. Haider received a BSc degree in Petroleum Engineering in 1977. He is professionally interested in Reservoir Engineering, Economics and Geology.

George A. Grover is a Reservoir Geologist in the Geological Department at Saudi Aramco. George was previously a Research Geologist with Chevron Petroleum Technology Company, La Habra, California (1985-1990), and an Exploration Geologist with Gulf Oil Company, Texas (1981-1985). He holds a PhD in Geology (1981) from Virginia Tech.

Rick Davis earned a BSc in Geology from the University of Texas at Austin and did graduate work at Colorado School of Mines. Rick worked both on exploration and development projects in the Rocky Mountains, mid-continent and eastern US for 13 years. Since 1986 his work has centered on reservoir characterization and modeling, working on the Anschutz Ranch East field (Utah-Wyoming Thrust Belt) for the Anschutz Corporation, and working on the Ghawar and Abqaiq fields for Saudi Aramco.

Sait I. Ozkaya holds a MSc degree in Computer Science, Mining Engineering and a PhD in Geology. His experiences include field geology and regional tectonics, statistical and computer studies in geology. He has developed computer software for various applications such as balanced cross-section construction, and finite element solution of fluid flow and stress. At present Sait is working on fractured reservoir characterization. In particular, he is interested in modeling fracture networks and simulation of fluid flow through fractures.

Joerg E. Mattner is currently Manager of Western Atlas Geoscience Center in Bahrain. He graduated in Geology in 1986 and received his PhD in 1990 from Clausthal University, Germany. During his studies and subsequent teaching assignment, Joerg worked mainly on geological projects in Europe, South America and Northern Canada. He joined the Petrophysical Evaluation Group of Western Atlas International in London in 1990. Joerg was assigned to Syria to establish a log analysis center in 1991, and in 1994 he became the Chief Geologist for the Middle East.

Sedimentology to 3-D Geological Model, Impact on Reservoir Development Upper Burgan Reservoir, Northern Kuwait

Ahmad J. Al-Eidan, Kuwait Oil Company William B. Wethington, BP Kuwait and Roger Davies Badley, Ashton and Associates, UK

The Aptian-Albian Upper Burgan reservoir is a major productive interval in both the Raudhatain and Sabriyah fields, located in northern Kuwait. This reservoir represents a complex series of heavily bioturbated shallow marine sandstones and nested valley fill channels.

The Upper Burgan reservoir is targeted to increase its current production by more than five times, culminating with a plateau rate of 120,000 bopd. The dramatic increase in production will be achieved through the application of a fieldwide waterflood development program. Phase 1 is scheduled to begin in 1999.

A comprehensive and focused geological study has been conducted on the reservoir. The study includes petrographic analysis, core description, image log analysis, 3-D seismic and sequence stratigraphy which has been integrated with all available dynamic data to best define the reservoir architecture and therefore, flow units. A fine grid 3-D geological model has been built to further aide in visualization, data quality and for input into simulation.

The geological analysis has had significant impact on the reservoir development strategy by influencing waterflood strategy, pattern orientation and expected performance.

Ahmad J. Al-Eidan received a BSc degree in Geology from Kuwait University in 1992 and joined Kuwait Oil Company in January of 1993. Ahmad worked as Wellsite Geologist for three years, after that joined Field Development Department as Development Geologist.

William B. Wethington received a BSc degree in Geology in 1985 and a MSc degree in Energy and Mineral Resources from the University of Texas at Austin in 1989. William’s major interests include development geology applications to field development and reservoir management. He has worked in numerous mature fields on Alaska’s North Slope and around the world. Currently, he is leading the multi-disciplinary team that is focusing on the development plans of the Upper Burgan reservoir in Kuwait.

Roger Davies has 17 years experience in the oil industry. He was employed by British Petroleum as a Sedimentologist from 1980 to 1994. Since 1994, Roger has worked as a Consultant, and is an associate of Badley, Ashton & Associates and the Energy Resource Alliance. He has been involved in the description of clastic and carbonate reservoirs in many parts of the world including the North Sea, Alaska and the Middle East. Roger has a PhD from the University of Southampton.

Dual-Sensor Bottom Referenced Acquisition and Processing Results

Issam Al-Esmar, Mahfoudh Al-Ginaibi Abu Dhabi National Oil Company and Abu Baker Al-Jeelani Abu Dhabi Company for Onshore Oil Operations

The dual-sensor technique employs sea-bed located receiver stations containing co-located hydrophones and geophones. The combination of signals recorded from the co-located bottom referenced hydrophone/geophone pairs has resulted in an increase in the bandwidth of the recorded seismic wavelet relative to that achieved with towed streamers. This resolution is derived from an increase in both the low and high frequency content of the wavelet resulting from the dual-sensor combination.

The increased wavelet resolution is maintained through the acquisition process by acquiring the data through a stationary receiver spread. Compared to streamer acquisition, where cable feather acts to produce mid and far offset midpoints from out of the plane of a 2-D line, the midpoints generated from shooting into a fixed receiver spread are more tightly clustered along the axis of the line. This clustering acts to reduce the effect of wavelet “smearing” which occurs when traces in a Common Mid-Point (CMP)gather are distributed along dipping surfaces.

A fixed receiver spread also allows a great deal of flexibility in acquisition geometry design and thus control of the geometric attributes of the traces incorporated into each CMP location. This flexibility allows survey designs to meet the spatial sampling requirements for wave equation-based data processing such as Dip Moveout and migration.

A test line was recorded with dual sensor seismic data for the ADNOC/A/B tie line project in the autumn of 1996. The line extended for 45 kilometers in water depths ranging from 3 to 23 meters. The two main objectives of the project were an evaluation of any apparent increase in seismic bandwidth from the combination of hydrophone and geophone signals and the use of seismic first break information to determine the sea-floor location of the dualsensor packages.

Examination of the receiver positions computed from the seismic first breaks show that, on average, the receivers were within 5 meters of the drop positions with an average inline difference of about 3 meters. Processing of the seismic data shows that there is an increase in bandwidth and whitening of the signal spectra for the dual sensor data relative to data recorded from hydrophones only.

Issam Al-Esmar received his MSc degree in Exploration Geophysics in 1977 from the Institute National des Hydrocarbon, Algeria. He is currently Exploration Geophysicist with Abu Dhabi National Oil Company (ADNOC). Prior to joining ADNOC, Issam worked with Sonatrach, Algeria between 1977 and 1983. He is a member of the SEE.

Mahfoudh Al-Ginaibi received a BSc degree in Geophysics from United Arab Emirates University in 1983. He has been with Abu Dhabi National Oil Company since 1983 where he is Geophysics Supervisor of 2-D/3-D Acquisition and Processing. Mahfoudh is a member of the SEE and EAG.

Abu Baker Al-Jeelani received a BSc in Geophysics from United Arab Emirates University in 1983. He worked with Abu Dhabi National Oil Company as Geophysics Supervisor between 1983 and 1996. Abu Baker is currently a Team Leader with Abu Dhabi Company for Onshore Oil Operations. He is a member of the SEG, SEE and EAG.

Squeezed Integral DMO for Depth Variable Velocity: A Case History in Saudi Arabia

Mohammed N. Al-Faraj, Peter C. Green and Anthony A. Sirtautas Saudi Aramco

In seismic data processing, the dip moveout (DMO) process is known to be relatively insensitive to velocities, especially when velocity does not change rapidly with depth. In fact, the DMO process is totally velocity-independent when the medium velocity is constant, a situation not likely to occur in nature. [Deviation from constant velocity, is a measure that can determine the reliability of constant-velocity DMO (CV-DMO) processing.] When velocity varies moderately with depth, CV-DMO will typically produce reasonable results. This could explain why the popular CV-DMO has been successfully applied in different areas of the world for many years.

In this paper, we modify Hale’s CV-DMO integral method to approximately handle velocity variations with depth by squeezing the CV-DMO operator. We first present synthetic examples comparing CV-DMO with squeezed DMO. We then show the results after applying this squeezed DMO algorithm to a 3-D seismic dataset in Saudi Arabia, and compare them to results obtained without squeezing.

We conclude that the DMO process must be “velocity-tweaked”, in some areas of Saudi Arabia, in order to improve data imaging. A cheap and efficient way of achieving this is to apply the Hale’s squeezing method to an existing constant-velocity integral method. In our case, we conclude that squeezed DMO was able to enhance data quality, in areas of interest, where CV-DMO failed.

Mohammed N. Al-Faraj received a BSc degree in Electrical Engineering from the University of Wisconsin-Milwaukee in 1983, and an MSc and a PhD in Geophysics from the Colorado School of Mines in 1987 and 1993, respectively. Since 1984, Mohammed has been with Saudi Aramco, Saudi Arabia. His interests include seismic data processing, vertical seismic profiling, reservoir characterization, and working in multi-disciplinary teams. Currently, Mohammed is in charge of all 3-D seismic processing in Saudi Aramco, and is the president of the Dhahran Geological Society. He is a member of the SEG, DGS and EAGE.

Peter C. Green is Geophysicist with Saudi Aramco’s Geophysical Processing Division. He was employed by Digicon Geophysical, Houston, Texas from 1983 to 1985 and also held the position of Processing Manager with Tensor Geophysical, Cairo, Egypt from 1986 to 1990. Peter received his BASc in Geologic Engineering (Geophysics) from the University of British Columbia, Canada in 1983. He is a member of the EAGE, SPE and SEG. His professional interests are seismic processing and image processing.

Anthony A. Sirtautas holds BSc and MSc degrees from the Colorado School of Mines in Geophysics and has been an Applications Analyst with the Geophysical Applications Division of Saudi Aramco in Dhahran for the last 7 years. Anthony has had over 15 years experience in the petroleum industry working with Standard Oil, Digicon and Multiflow Computers.

A New Look at the Middle-Lower Cretaceous Stratigraphy, Offshore Kuwait

Abdul Aziz Al-Fares Kuwait Oil Company Pete Jeans and Mark Bouman Shell International Exploration and Production B.V.

In September 1995, a joint study was initiated between Shell International Exploration & Production B.V. and Kuwait Oil Company (KOC) whereby an integrated team of Shell and KOC geologists and geophysicists, based in The Hague (The Netherlands), undertook to review the hydrocarbon potential of offshore Kuwait, including Kuwait Bay and Bubiyan Island.

Offshore exploration in Kuwait commenced in 1961 with the award of a 5,600 square kilometer offshore concession to Shell. Some 6,300 kilometers of 3-fold analogue seismic were acquired in 1961, and 3 wells were drilled in 1962-63. The most encouraging results were obtained from the first well drilled, Riquah-1, which tested at an initial rate of 720 bopd of 38-40° API oil from Lower Cretaceous Ratawi limestones. Hamuur-1 had minor oil and gas shows, whilst a minor gas influx was noted in Zubeidi-1. All three wells were abandoned. In the same period, KOC also drilled their first offshore exploration wells: Bubiyan-1 (which bottomed in Jurassic salt at 14,251 feet), Bahrah-5, and Failakah-1. In 1981, KOC embarked upon a second offshore exploration campaign, acquiring some 6,000 kilometers of seismic data and, in 1983-84, drilling two wells. The first, Riquah-2 was a dry hole with only shows of oil; the second, Jlayah-1, recovered a maximum of 420 bopd on test from the Ratawi Formation.

In order to establish an integrated sequence-stratigraphical framework for the prospective Lower to Middle Cretaceous interval, a quantitative biostratigraphical study was made. Some 790 biostratigraphical analyses (10% core samples; 90% cuttings) from eleven wells were carried out by Robertson Research International Ltd. (micropaleontology) and Varol Research (nanno-fossils). The nanno-fossil data were particularly important in providing accurate chronostratigraphical calibration, and this data has been used to constrain a preliminary “Time-Rock Synopsis”.

KOC’s lithostratigraphical nomenclature proved to be basically sound and has been maintained as the basis for the present stratigraphical framework. However, the study revealed the existence of two substantial and hitherto unsuspected hiatuses: one between the Ratawi and Zubair formations, of Early Valanginian to Mid-Hauterivian age; and the other, representing the whole of the Early Albian, within the Burgan Formation. This latter result, if it can be further substantiated by more exhaustive study in the onshore area, would neccessitate a redefinition of the Burgan Formation and the erection of a new formation to describe the clastic sequence of Late Aptian age which was deposited before the Early Albian hiatus and after the Shu’aiba Formation, and which has hitherto been included within the Lower Burgan Formation.

Abdul Aziz Al-Fares graduated from Kuwait University with a BSc degree in Geology in 1992, and in the same year he joined Kuwait Oil Company as a Wellsite Geologist. In 1994 Abdul Aziz was assigned to work as a Geophysicist at KOC, and from November 1995 to December 1996 he was a member of the KOC/Shell Joint Study Team. He is currently working as a 3-D Seismic Interpreter.

Pete Jeans is currently a Regional Business Advisor in Shell EP International Ventures’ New Business Development Group. Prior to this, he was Senior Geologist and then Project Leader of the Kuwait Joint Study Team. Pete graduated with a PhD in Geology from Birmingham University in 1973, and worked in Oman, Jakarta, Houston, and Brunei before returning to the Hague in 1989. His particular interest is prospect and play generation.

Mark Bouman gained a MSc in Stratigraphy from the University of Utrecht, and joined Shell in 1982. Following assignments in Peru, London, and Cairo, he returned to the Hague in 1995 and was Senior Stratigrapher in the Kuwait Joint Study Team. Mark is currently Course Director for Geosciences in the Shell Learning and Development Centre, Noordwijkerhoud, in The Netherlands. His areas of expertise include sequence stratigraphy, basin analysis, and stratigraphical computing.

Jurassic Petroleum System in Southern Iraq

Mohammad Al-Gailani GeoDesign Limited

Most of the developed hydrocarbon reserves in Iraq lie within the Tertiary and Lower Cretaceous petroleum systems. However, in the past decade, deep drilling activities in the fields of North Rumaila and West Qurna have proven the existence of a Jurassic pay zone producing very light crude with high API, low sulfur accompanied by some sour gas.

The Jurassic petroleum system in southern Iraq comprises two major rich source rocks laid as part of two different depositional cycles. An early Bathonian-Liassic cycle depositing the Sargelu Formation and a Lower Kimeridgian to Oxfordian cycle depositing the Naokelekan Formation. Both hydrocarbon source kitchens and reservoir seal combinations existed within the Middle to the Upper Jurassic basin. This basin was developed over two tectonic regimes, the Platform Flank of Mesopotamian Foredeep and the North Eastern Slope of the African-Arabian Platform.

The distribution and the possible syntectonic deposition of the various Jurassic formations over growing structures has created various lithofacies. These range from carbonate mud accumulation to oolitic shoals, and lagoonal evaporatic to bedded anhydrite acting like source kitchens / reservoir trap and seal capping facies favorable for hydrocarbon generation and entrapment conditions.

It is concluded that the best reservoir targets for the Jurassic petroleum system are the Upper Jurassic Najmah and Upper Liassic Mus formations. Both of these formations exhibits oolitic to pseudo-oolitic lithofacies with good porosities, covered by tight evaporites and underlain by good quality source rock kitchens. It is evident from the lithofacies description of the various Jurassic formations that the Upper Jurassic petroleum system of Najmah, Naokelekan and Sargelu formations have approximately similar facies from north to south. Whereas, the Lower Liassic petroleum system of Alan, Mus and Adaiyah are composed mainly of evaporites in the north, to pseudo-oolitic and tight limestones in the south.

Mohammad Al-Gailani is currently Managing Director of GeoDesign Limited, a consultancy based in London specialising in databases of the Middle East. He graduated from Baghdad University in 1972 with a BSc degree in Geology and worked briefly for the Iraqi National Oil Company in Baghdad. He won a scholarship in 1973 for Post-Graduate studies in Petroleum Geology where he obtained first his MSc in 1974 from University of Aberdeen and then PhD and DIC in January 1979 from Imperial College, London. Mohammad worked as an independent consultant on several projects both in the Middle East and the Parana Basin in South America where he worked for Pauli Petro in Sao Paulo, Brazil. He has published several papers on the diagenesis and reservoir characteristics at unconformities and on the exploration potential of Iraq. He has been an active member of the AAPG and a member of the PESGB.

Sulfur versus API-Gravity Relationships of Iraqi Crude Oils

Mohammad Al-Gailani GeoDesign Limited Michael D. Lewan and Thomas S. Ahlbrandt US Geological Survey

It has long been recognized that sulfur content of genetically related crude oils increases with decreasing API-gravity. Plots of this relationship have been used as a typing tool to differentiate between high- and low-sulfur crude oils irrespective of the maturity level at which they were generated. Although more sophisticated typing methods employing gas chromatography/mass-spectrometry currently exist, sulfur and API-gravity data are more readily available and allow for more global typing of crude oils as a first approximation. In this study, 330 oils from 34 fields in Iraq were used to determine whether a genetic sulfur versus API-gravity relationship existed. Several fields with Mesozoic and Cenozoic oils that have not been significantly altered by water washing or biodegradation and that span a wide range of API gravities and sulfur contents gave a high-sulfur genetic relationship. Cenozoic and Mesozoic crude oils from Kuwait, Iran, Qatar, and Saudi Arabia also follow this relationship, which suggests a common regional source rock for the Arabian Gulf basin. Sulfur/API-gravity relationships of high-sulfur oils in Alberta, Nevada, California, Wyoming, Gulf Coast, and Venezuela indicate that differences in the depositional conditions of their source rocks results in significant differences in the slopes and intercepts of their sulfur/API-gravity relationships. Oils from the Smackover of the Gulf Coast and from the Mesozoic and Cenozoic of the Arabian Gulf basin have essentially the same relationship, which suggests that depositional conditions of their source rocks were similar. Their similar relationships also have the highest intercepts (S = 6.8 to 7.0) and slopes (S/API = -0.151 to -0.148) of the regions studied. In addition to the high-sulfur relationship, Paleozoic oils from the Akkas field in Iraq and those from Saudi Arabia give a low-sulfur genetic relationship. This distinctly different relationship indicates the existence of a Paleozoic petroleum system in Iraq, similar to that observed in Saudi Arabia.

Mohammad Al-Gailani (see abstract “Jurassic Petroleum System in Southern Iraq” on page 49 for biography and photograph)

Michael D. Lewan is Leader of the Hydrocarbon Processes Group for the Energy Resources Program of the US Geological Survey, where his research efforts for the last 7 years have been on developing a quantitative understanding of petroleum expulsion and kinetics. Prior to this, Michael spent 13 years at the Amoco Production Co. Research Center, where he pioneered the development of hydrous pyrolysis for simulating natural petroleum generation. He also worked for three years as an exploration geologist for Shell Oil Co. in the Gulf Coast offshore. Michael received his PhD from the University of Cincinnati and MSc from Michigan Technological University.

Thomas S. Ahlbrandt is the Project Chief of the World Energy Project and Coordinator for Region 2, the Middle East. He received a BA and a PhD in Geology at the University of Wyoming. Thomas served on the Executive Committee of the American Association of Petroleum Geologists and on the US National Committee for the World Petroleum Congress. From 1965 to 1988, he worked for Exxon, USGS, Amoco, Amerada, MRO and Associates and was partner in Petrostat Consultants. Thomas rejoined the USGS in 1988 and has held various energy positions in Reston, Virginia and in Denver, Colorado.

Geological Evaluation and Hydrocarbon Potential of the Middle Jurassic Araej Formation in Abu Dhabi, United Arab Emirates

Abdulrahman S. Al-Habshi, Ahmed A. Taher, Mohamed M. Abd El-Sattar and Omar Suwaina Abu Dhabi National Oil Company

The Middle Jurassic Araej Formation is an exploration target in offshore Abu Dhabi. It was deposited on prevailing shallow to very shallow warm and clear water shelf conditions. Epeirogenic movements during the Middle Jurassic period caused fluctuations in water depths and consequently produced a variety of limestone types represented by the alternations of lime-mudstones, wackestones and packestones/grainstones. Sedimentation of the Araej Formation was controlled by several structural factors, the most important of which was the Qatar Arch which was subject to uplifting at the early Jurassic and through the Araej time, particularly at the end of the Middle Jurassic (basal Diyab Unconformity and extensive erosion of the Qatar Arch).

The regional electric log correlations coupled with lithofacies interpretation revealed the presence of seven acceptable lithostratigraphic units (two in the upper Araej Member and five in the lower Araej Member) for the Araej Formation. The integration of lithofacies and seismic modeling reveals that the high energy shelfal highstand grainstones having the highest porosities occur in northern, central and western offshore Abu Dhabi.

Good reservoir development is found in the shallow water shoal pellety and/or oolitic packestones/grainstones in offshore Abu Dhabi fields, where hydrocarbon accumulations have been discovered at depths ranging from 9,100 and 12,500 feet subsea in the Upper Araej (Unit 1), Uweinat and Lower Araej (Units 1 and 2). Contribution of low-maturity oil from the Diyab Formation is likely and the available geochemical analyses suggest that the predominant gas charge is derived from a source developed within the pre-Diyab Mesozoic section.

Abdulrahman S. Al-Habshi is currently Supervisor of the Review Geology Section with Abu Dhabi National Oil Company (ADNOC). He has 25 years of experience in geology of which six and a half years were with the French company BRGM in Jeddah, Saudi Arabia, four and a half years with the Petroleum Department in Abu Dhabi and 14 years with ADNOC. Abdulrahman is Vice Chairman of the Society of Explorationists in the Emirates and a member of the SPE. He obtained his BSc in Geology from Baghdad University in 1971.

Ahmed A. Taher is a Senior Geologist with the Abu Dhabi National Oil Company (ADNOC) since 1982 and has worked as an Explorationist for the ADNOC concession areas. He received his BSc in Geology from United Arab Emirates University. Ahmed is a member of the Society of Explorationists in the Emirates. He is particularly interested in the statistical modeling of source rocks and its maturation regime.

Mohamed M. Abd El-Sattar is a Senior Exploration Geologist with Abu Dhabi National Oil Company. He has 21 years of petroleum and exploration experience in the Middle East, of which 11 years were with Gulf of Suez Petroleum Co., Egypt. Mohamed holds BSc and MSc degrees in Geology from Ain Shams University, Egypt. He is a member of many professional societies and has published several papers on structural geology and basin evaluation.

Omar Suwaina is currently Senior Seismic Interpreter within the Onshore Geophysics Group in Abu Dhabi National Oil Company (ADNOC), Abu Dhabi, UAE. He has worked in the processing and interpretation of 2-D and 3-D seismic data of ADNOC surveys. Omar is a member of the Society of Explorationists in the Emirates and SEG. He obtained his BSc in Geological Engineering in 1990 from the Colorado School of Mines.

Diagenetic Evolution and its Effects on Provenance Interpretation of Devonian Tawil Formation, Central Saudi Arabia

Omar A. Al-Harbi King Abdulaziz City for Science and Technology

Diagenesis of quartzarenite of the Tawil Formation was studied to characterize its effects in provenance studies. The main framework of this sandstone is quartz, feldspar and rock fragments. The petrographic study reveals the presence of several diagenetic features such as mechanical compaction and development of pressure solution, compact cementation with silica, corrosion of quartz grains, dissolution of feldspar and rock fragments and development of oversize pores, replacement of detrital grains by authigenic carbonates, alteration of feldspar into clays. For reliable interpretation of provenance, the diagenetic history of the rock must be considered. Based on conventional types of point counting, quartzarenite is dominated by mature quartzose grains. However, when the dissolved grains are considered a different provenance is indicated.

Omar A. Al-Harbi is currently Associate Professor of the Natural Resources and Environment Research Institute at King Abdulaziz City for Science and Technology. Omar is a member of the AAPG and the Saudi Arabian Society for Earth Science.

Reservoir Description: Use of Core Data to Identify Flow Units for a Clastic North Sea Reservoir

O.B. Al-Mahtot and W.E. Mason Robert Gordon University, Aberdeen, UK

An effective and sufficient description and characterization of the reservoir are ultimately essential to successful reservoir engineering management. The integration of sufficient core analysis data is the primary target of reservoir description to permit identification of zones (Flow Units) with similar fluid-flow characteristics. The identification of flow units is the aim of integrated core analysis program. The flow units technique is a method of characterizing a reservoir, and the route to flow unit and reservoir description is dependent on the core data available.

This paper presents a practical application of the flow units technique to a clastic North Sea reservoir using a statistical analysis for flow zone indicator (FZI) to differentiate flow units. All laboratory work was conducted using one-inch long cores. Core analysis porosity and permeability data from 410 core plugs was used to work out the porosity-permeability relationship using the flow units technique. After flow unit characterization, six flow unit groups have been selected, and samples of each individual flow unit were selected for mercury injection analysis using injection pressures up to 50,000 pounds/square inch. Finally the pore size distribution and mean flow radius were calculated. In this paper the applicability of this technique is discussed to examine how an improved reservoir description can be achieved for a specific reservoir.

This paper describes a new attempt to apply this technique to a North Sea reservoir. The technique is more complex than either the depositional or layer model, but is also the most realistic because it takes account of a wide variety of geological and petrophysical characteristics present. The properties used to derive flow units in this reservoir were the core-porosity and permeability measurements for small, medium and large pore-throat radii. The general porosity-permeability cross-plot shows a large scatter, indicating poor overall correlation between porosity and permeability. However by using the flow units technique a reasonable relationship between porosity and permeability can be shown to exist for each individual flow unit.

The flow unit technique provides a comprehensive reservoir description. Six flow units are defined; three of these exhibit good-to-excellent reservoir quality, one is good reservoir quality and two are poor reservoir quality. It can be said that this technique has been applied successfully to this particular North Sea reservoir.

O.B. Al-Mahtot graduated from Al-Fateh University, Tripoli, Libya with a degree in Petroleum Engineering in 1987. He worked as Science Teacher in the Ministry of Education between 1987 and 1988, as Production Engineer with Oxy Oil Company between 1988 and 1980, then joined Nasar University as Assistant Teacher in Petroleum Engineering in 1990. He received his MSc in Offshore Engineering from Robert Gordon University in 1994. He is currently a PhD candidate at Robert Gordon University and his research focuses on the effect of porosity type, overburden pressure and experimental conditions on electrical properties of sandstone and carbonate rocks.

W.E. Mason graduated from Imperial College, London with a degree in Chemical Engineering. He received his PhD from Imperial College in 1966. He worked in government research on problems of mining safety. He joined the University of Malaya as Lecturer in Chemical Engineering in 1969 and transferred to the University of Singapore in 1976 and was appointed Head of the Department of Chemical Engineering in 1979. He joined the Robert Gordon University in 1983. His current research interests are in petrophysics and thermodynamics.

Application of Multi-Seismic Attributes in Estimating Reservoir Properties

Maher I. Al-Marhoon Saudi Aramco

Seismic attributes can be used in seismic interpretation. As seismic data quality improves, interpretation of seismic attributes becomes more reliable. Seismic attributes reveal information that often cannot be detected in conventional seismic displays. The attributes can be used for both quantitative and qualitative interpretation of any zone of interest.

The main goal of this study is to estimate porosity, water saturation, and volume of silt using several seismic attributes and then arrive at one conclusion based on the quantitative and the qualitative analyses.

In the quantitative analysis, nine seismic attributes are used to estimate the reservoir properties mentioned above. These attributes are calculated and averaged over the zone of interest, from Base Khuff to the pre-Unayzah Unconformity, compared to the log-derived reservoir properties from 19 wells. Multi-variant regression is used to approximate a linear transformation between seismic attributes and reservoir properties. Then the transformation is applied to the whole seismic data.

In the qualitative analysis, spectral attributes are studied in addition to the nine seismic attributes discussed in the quantitative analysis. Attributes are related to the reservoir properties qualitatively. Both the quantitative and the qualitative interpretation are in agreement.

I preserved two wells for validation purposes. The estimated reservoir properties of these two wells using a multi-seismic attributes approach are in agreement with the well driven reservoir properties. The multi-seismic attributes driven reservoir properties method was compared to the singleattribute method and to a method utilizing simple kriging of well information.

Maher I. Al-Marhoon has a BSc in Geophysics (1990) and MSc in Geology (1997) from King Fahd University of Petroleum and Minerals, Dhahran, Saudi Arabia. Maher is currently with the Geophysical Technology Division of Saudi Aramco. He is a member of the SEG and Dhahran Geological Society.

A Regional Sedimentological Study of the Lower Cretaceous Shu’aiba Formation in Oman

Zuwena Al-Rawahi and Neil A. Harbury Birkbeck College and University College London

The Aptian Shu’aiba Formation (80-300 meters thick) crops out extensively in Oman and forms a major hydrocarbon reservoir in the subsurface throughout northern Arabia. In the studied area, Shu’aiba sediments represent deposition on a broad shallow ramp or open shelf platform and comprise predominantly of low energy open marine subtidal carbonate muds characterised by an abundance of Requieniid “clinger” rudists and algae.

A study of both outcrop and the subsurface data provides an excellent opportunity to examine the Shu’aiba regionally. Outcrops in the Huqf region of central eastern Oman, and in the salt cored structures of Jebel Madar and Salakh as well as selected outcrops in the Oman Mountains have been studied. These are compared with subsurface data.

In northern Oman, lithofacies identified range from calcareous shales of the inner neritic zone to stromatoporoidalgae-rudist facies representing shallow marine shelf deposition, and skeletal-rich redeposited facies of the platform edge.

The carbonate sediments are characterised by bioclastic wackestones to packstones forming small-scale shallowing-upward cycles with syndepositional hardgrounds and have an abundance of lime mud, peloids and coated grains. Sedimentation was predominantly in a subtidal environment with localised grainstones representing storm deposits. Facies are generally discontinuous and a complex interfingering of facies over short lateral distances is commonly observed.

In contrast, the Shu’aiba in east-central Oman is thinner and comprises shallow marine subtidal and intertidal carbonates which are cyclic with ferruginous hardgrounds. Several incursions of fine-grained marls suggest a terrigenous source. This is in agreement with the regional paleogeography and implies that sediments in this area are more proximal from those to the north.

Although these carbonates were deposited in different paleogeographic areas, a broad facies correlation of the Shu’aiba Formation will be attempted utilising the excellent biostratigraphic zones previously established for this stratigraphic unit.

Zuwena Al-Rawahi received her MSc in Clastic Sedimentology from McMaster University, Hamilton, Ontario, Canada in 1993. Zuwena is currently working on her PhD project on the Sedimentology of the Upper Kahmah Group in Oman at Birkbeck College, University of London.

Neil A. Harbury received his undergraduate degree from Imperial College in 1982 and completed his PhD in Geology from University College, London in 1986. Neil started lecturing at Birkbeck College in 1985 and has been the Course Director of the MSc program in Sedimentology since 1989. His research interests include sedimentation in areas of active tectonics and he is currently conducting research projects in the Middle East and Mediterranean (Oman, Yemen, Italy, Bulgaria) and southeast Asia (Sumatra, northeast Borneo).

Application of Potential Field Data in Oman

Salim Y.S. Al-Rawahy Petroleum Development Oman

In the past, potential field measurements, i.e. magnetic and gravity data, were used in Oman, as elsewhere in the oil industry, solely to map the extent of sedimentary basins and major fault zones. Such geological features perturb the Earth’s gravity and magnetic fields and may cause anomalies of a few tens of milligals and a few tens of nanoteslas, respectively. For a given set of geological conditions, the limitation in how small features could be resolved was imposed by the precision of the measurement instruments and the resolution. In recent years, however, the advances in the potential field measurement instruments, accuracy in the geographical positioning and computers have allowed more accurate, and higher precision and resolution data to be recorded and readily analysed. These have paved the way to the application of magnetic and gravity techniques in detecting intra-sedimentary features that cause only a fraction of a milligal or of a nanotesla. Compared with seismic, these techniques are cheaper and, due to the fact that they are measuring different rock properties from those measured by seismic, can provide extra subsurface information.

In Oman, Petroleum Development of Oman has carried out a number of high resolution gravity and aeromagnetic surveys to validate or supplement seismic data. Aeromagnetic data have been used to complement the seismic interpretation in the areas of poor seismic data quality and/or lack of acoustic impedance contrast between the successive formations of interest. Gravity data have been used to constrain the seismic interpretation over salt diapirs where seismic imaging is poor. Here we present some examples of these data including acquisition, processing and their analysis.

Salim Y.S. Al-Rawahy received his BSc in Geophysics from Liverpool University in 1990, and MSc and PhD degrees in Geophysics from the University of Durham in 1991 and 1995, respectively. Salim is currently working with Petroleum Development Oman in a team that is responsible for carrying out VSP interpretation and quantitative seismic interpretation. He is also responsible for non-seismic data and their interpretations. Such data include gravity and aeromagnetic measurements.

Optimal Merging of Large 3-D Seismic Surveys

Khalid Al-Rufaii, Stephen Bremkamp and Ramzy Al-Zayer Saudi Aramco

Processing large 3-D seismic surveys can be challenging. Due to acquisition limitations and/or software and computer resources, large surveys are usually subdivided into multiblocks prior to processing. Each block undergoes a separate processing flow up until a certain stage, usually the DMO stack, before different blocks are merged into a single giant block. Prior to merging, the different blocks would typically have identical processing flows and parameters. In our case, each individual block would span an area of about 200 square kilometers. Merging separately-processed blocks does not necessarily yield a smooth product; misties might arise at block boundaries due to improper merging.

Here, we analyze the mistie problem by identifying the various factors leading to misties. Of all the factors contributing to misties, we find that the Floating Datum Statics (FDS) is of utmost importance. If FDS in the overlap zone between two blocks is different, then the statics and velocities will also be different for each dataset (in that overlap zone), thus giving rise to misties.

In order for misties caused by FDS to be eliminated when blocks are merged during processing, we propose a solution which must be implemented at the surveying phase. We simply recommend that an additional leeway (on top of the proposed acquisition area) be surveyed. The selection of this leeway is entirely determined by the planned future surveys. Stated differently, when the seismic data of a block is acquired at a given time, a small part of the block adjacent to it (the block to be acquired next) must be simultaneously surveyed in order for the FDS to be the same in the overlap zone, thus eliminating the artifact of misties.

Khalid Al-Rufaii holds a BSc in Geophysics from King Fahd University of Petroleum and Minerals, Saudi Arabia in 1988, a MSc in Geophysics from Colorado School of Mines in 1992. Khalid joined Saudi Aramco in early 1993 working in 3-D processing. His interests are simultaneous solutions to velocity and statics, and relative amplitude processing.

Stephen Bremkamp received his BSc in Geophysics from Colorado School of Mines. He worked with Western Geophysical in Denver, Colorado and Midland Texas. Stephen joined the geophysical processing division of Saudi Aramco in 1990.

Ramzy Al-Zayer has been working in 3-D seismic processing since 1994. Before that he was working on rotational assignments in the Exploration Organization. Ramzy joined Saudi Aramco in 1988 after receiving his BSc in Geophysics from King Fahd University of Petroleum and Minerals. He is currently working on his MSc in Mathematics. His interests are optimization and signal processing.

Oil Families of Oman

Nashwa Al-Ruwehy and Neil L. Frewin Petroleum Development Oman

In the identification of new prospectivity in mature areas, knowledge of oil families and their oil source rock correlation is the key element. This is particularly important in Oman as the potential source rocks range from Precambrian to Cretaceous in age and all have probably contributed to the producible hydrocarbons.

Four end member oil families have been identified within Oman: Natih, Tuwaiq, ‘Q’ and Huqf. These end members have been identified by their detailed geochemical signatures using biomarkers, carbon isotopes, and migration distance indicators. These tools have given us hard data which constrains our models of the petroleum system of Oman.

The Natih sourced oils are characterised by having a relatively high C27 sterane abundance, and greater than 35% C28 sterane relative to sterane abundance, ∂13C measured at -27‰. Pure end members have been identified in the Natih and Shibkah fields.

The Tuwaiq reservoired oils are recognised by having equal amounts of C28 and C29 total sterane abundance and ∂13C measured at -26.5‰. Pure end members have been identified in Mazhour-1 and Lekhwair-B fields.

The ‘Q’ sourced oils are recognised by having a high C27 sterane abundance of greater than 50% in total relative to other steranes and ∂13C measured at -30.4‰. Additionally, the ‘Q’ oils have a distinctive and as yet unidentified compound which is not found in other oils. This peak has yet to be identified in a known source rock. Pure end members have been identified in Haima and Natih reservoirs in Saih Rawl and Bahja fields.

The Huqf source rocks produce Huqf typed oils which are recognised by having high abundances of C29 steranes, (greater than 50%) relative to other steranes and ∂13C measured at -37.1‰. Pure end members have been identified in Dhulaima, Jebel Madar and Jazal. Within this broad group, the Huqf is comprised of three end members which can be distinguished in south Oman using triaromatic steroids: (a) the Precambrian Buah & Shuram; (b) the Cambrian Athel; and (c) the Cambrian “U”.

Both Huqf and ‘Q’ oils contain common compounds known as ‘X’ peaks (isomers of methyl and dimethyl alkanes.

The undisputed classification of Oman’s hydrocarbons is hindered by the extensive mixing of oils during migration from their respective source rocks along sometimes long distance pathways. Furthermore, until the actual source of the ‘Q’ is penetrated, the search for the enigmatic ‘Q’ source will continue.

Nashwa Al-Ruwehy has been employed by Petroleum Development Oman since 1981. Nashwa holds a BSc Sciences degree from Portsmouth in 1977 and obtained an MSc in Palynology, from Sheffield University in 1990. Nashwa is currently employed as a Geochemist in the Regional Studies Team.

Neil L. Frewin is currently Senior Petroleum Geochemist for Petroleum Development Oman (PDO). Prior to being posted to PDO in 1997, he worked for Shell International in The Netherlands as a Research Geochemist. He holds a BSc in Geology from the University of Wales and a PhD in Geology/Geochemistry from the University of London. Neil spent a post-doctoral year researching biomarker technologies at Delft University, The Netherlands.

A Practical Method of Estimating Permeability Distribution in Tight Gas Reservoirs of Saudi Arabia

Ghiyath Al-Sabeq Saudi Aramco

Permeability is one of the most important reservoir parameters that petroleum engineers use. In the oil and gas industry, it is used as part of the process to identify well completions, to determine whether a well should be completed and brought on-line, and to help to choose optimal reservoir management and development parameters such as production rate, perforation design and drainage points. Several permeability measurement and estimation techniques are used in the oil and gas industry such as wireline-log measurents (including RFT method), core analysis, well testing, and empirical correlations. It is the special interrelationship between these techniques and the procedure used to arrive at a permeability estimate that makes this method a practical one. This method: (1) uses modified Kozeny and Carman empirical correlation (that uses core data) to classify permeability based on the identification of hydraulic units (facies). This also requires basic classical statistical techniques such as histograms and frequency diagrams; (2) well test permability data is related to core permeability data by a fitted transform(s) using regression analysis; and (3) the porosity distribution available from cores/logs/lithology (in the form of net porosity-thickness) can now be used along with the available transform(s) (well test permeability thickness versus core permeability thickness) to distribute well test permeability.

Ghiyath Al-Sabeq is a Petroleum Engineering Specialist in Reservoir Management at Saudi Aramco. His previous position was as a Specialist in the Reservoir Simulation Division at Saudi Aramco where he worked on different aspects of reservoir simulation modeling studies covering model construction, history matching, and performance predictions of various fields in Saudi Arabia. Ghiyath holds a BSc degree in Engineering Sciences with honors from King Fahd University of Petroleum & Minerals, and an MSc degree in Chemical Engineering from Oklahoma State University.

Log Data Normalization, the Greater Burgan Field, Kuwait

Mariam Al-Saied, Salem H. Al-Sabea and Kamal E. Osman Kuwait Oil Company

Over 50 years, 768 wells were drilled in the Greater Burgan field. During this period, different vendors and several vintages of logging tools were used to acquire openhole log data. Significant systematic variation exists between measurements made by different generations of logging tools from the same vendor and between tools from different vendors. These variations lead to major errors and inconsistencies in petrophysical evaluation results. Field-wide data normalization was necessary to reduce these errors and to establish consistency in full-field petrophysical evaluation. We normalized gamma ray, density, sonic, and neutron data to obtain consistent results.

Cumulative frequency histograms were used for normalization. Modern wireline log (1990’s vintage) data were used to establish the normalization standard. The Mauddud carbonate formation, Wara and Burgan shale zones were selected as reference points. The cumulative frequency histograms for each zone were examined to determine common cumulative frequency percentile and log value pairs that were consistent in the reference wells. The selected reference pairs were then compared with corresponding values obtained from the other wells to determine the magnitude of change required for normalization.

About 60% of the wells required significant normalization. Data normalization resulted in average shifts of 3.0 MS for sonic data, 5.0 PU for neutron, 0.15 g/cm3 for density and 7.0 API for gamma ray.

Mariam Al-Saied received her BSc degree in Geology from Kuwait University in 1982. She joined Kuwait Oil Company in February 1995 as a Petro-physicist/Geologist.

Salem H. Al-Sabea received his BSc degree in Geology from Kuwait University in 1990 and joined Kuwait Oil Company in December 1991 as a Well-Site Geologist. Salem has worked as a Petrophysicist since 1994.

Kamal E. Osman is currently a Senior Petrophysicist with Kuwait Oil Company. He joined Chevron Overseas in 1980 and has been a Formation Evaluation Specialist with since 1989. He received his BSc in Geology from Khartoum University in 1979. Kamal is a member of the SPWLA and SPE.

The Impact of Reservoir Characterisation on Field Management: Minagish Oolite Reservoir, Umm Gudair Field, Kuwait

Nawaf S. Al-Salem, Ram S. Gaur Kuwait Oil Company and Clive D. Bishop BP Exploration, Kuwait

The Umm Gudair field is located on the southwest flank of the Kuwait Arch, adjacent to the Burgan field. Oil is reservoired at several levels within the Jurassic and Cretaceous intervals but initial development has focused on the Lower Cretaceous Minagish Oolite reservoir. The field extends southwards into the Kuwait/Saudi Arabia Partitioned Neutral Zone, where it is referred to as the South Umm Gudair field. The discovery well was drilled in 1962 and initial development drilling continued through to 1967. Drilling resumed in the 1980s, with a major expansion of activity in 1993 which is continuing at present. 120 wells have been drilled to date and approximately 400 million barrels of oil have been produced.

The recent renewal of development drilling has provided the opportunity for collection of new core, wireline, pressure and fluid data on which to base an updated description of the Minagish Oolite reservoir. The 450-foot thick Berriasian-Valanginian interval was deposited on a homoclinal carbonate ramp. Three systems tracts are defined, representing 3rd-order sea level cyclicity, each comprising a series of 4th-order parasequences. The dominant rock types are high permeability inner-mid ramp skeletal packstones and grainstones plus inner ramp oolitic sandsheets. Flooding events, associated with the 3rd-and 4th-order cyclicity resulted in deposition of thin mid-outer ramp bioturbated peloidal packstones and wackestones, which form extensive low permeability units. Increased frequency of sea level fluctuations and relative deepening towards the top of the reservoir results in an upwards increase in the proportion and continuity of these deeper water facies.

Integration of Repeat Formation Test pressure data with the static description has shown that the fine-grained units associated with flooding events have the potential to impact fluid flow through the reservoir. Pressure barriers up to 700 psi are observed and an upper unit has been defined which is isolated from the main part of the reservoir. This new understanding has to be reflected in modifications to the field development plan.

Water coning is a key issue for reservoir management. The reservoir has bottom water across its entire area and the high Kv/Kh ratio, within the main part of each parasequence, has been enhanced in the near wellbore area by repeated acid stimulation. Identification of the thin low permeability layers and placement of Injectrol and cement plugs at these levels have proved successful in holding back water cones, reducing water cuts from 50% to 2% over sustainable periods.

Nawaf S. Al-Salem graduated in Geology from Kuwait University in 1996. He has worked with Kuwait Oil Company for 2 years with experience in reservoir studies and wellsite operations.

Ram S. Gaur (see abstract “The Heavy Oil / Tar Mat in Minagish Field, Kuwait: Detection, Characterization and Impacts on Reservoir Performance” on page 42 for biography and photograph)

Clive D. Bishop has 20 years experience as a Geologist and has worked as a Senior Geologist with BP Exploration since 1981. He is currently seconded to the Kuwait Oil Company, working in the Umm Gudair field team and assisting with the development of Kuwaiti professional staff. Clive graduated from the University of Wales in 1977 and has worked in the North Sea, Egypt and Australia. Prior to moving to Kuwait he also worked on a wide range of reservoir characterisation projects at BP’S research centre in the UK.

Bridging Gaps Between Surface Seismic Data and VSP Data for the Improvement of Subsurface Imaging

Riaz Alá’i Delft University of Technology, The Netherlands

Vertical Seismic Profiling (VSP) has proven amongst many other geophysical techniques, to be extremely useful to obtain a more detailed seismic view on subsurface imaging by investigating the characteristics of imaged structures from nearby. For optimal interpretation and identification of the structures at a reservoir, it is fundamental to tie the VSP measurements with the unmigrated surface seismic data (time-axis in common) as well as with the migrated seismic data (depth-axis in common). Due to the acquisition geometry for the VSP measurements it may be that the data is not recorded at all the depths one is interested in (e.g. the target level). In this paper some field data examples will be presented in which the missing data in VSP data at particular depth levels can be interpolated by “virtual” VSP data which is determined from the unmigrated surface seismic data and an estimated model of the subsurface. The use of “virtual” VSP data can be used for improving the quality of real VSP data together with its use in the prediction ahead of the drillbit. An additional advantage of this method is that Amplitude Versus Offset (AVO) behavior of structures at reservoirs intersecting the well can be investigated by enlarging the offsets of the source with respect to the well. Summarizing, some field data examples emphasize the optimal illumination and subsurface imaging by bridging gaps between surface seismic data and VSP data. Moreover, the method allows optimal design of VSP acquisition geometries to accurately define attributes which could be used to estimate reservoir properties and thus defining the reflectivity as one progresses away from the well.

Riaz Alá’i received his MSc degree in 1991 from Delft University of Technology in Electrical Engineering specializing in Control Engineering. In 1992 he started his PhD research at the Delft University of Technology, Centre for Technical Geoscience, Department of Applied Physics, where he was a staff member of the Internationally sponsored DELPHI (DELft PHilosophy on Inversion) Consortium at the Laboratory of Seismics and Acoustics. Riaz received his PhD degree in 1997 and towards the end of 1997 he joined the Atlantic Richfield Company (ARCO) in Plano, Texas, USA. He is affiliated with the SEG and EAEG. His areas of professional interest include wave theory and VSP processing.

Geostatistical Integration of 3-D Seismic with Gravity and Wellbore Data to Identify and Estimate Additional Reserves in the Ghawar Field, Saudi Arabia

David W. Alexander Saudi Aramco and Robert W. Jeffrey Forcenergy

A previously identified structural closure - satellite to Saudi Arabia’s Ghawar field - has been delineated using a geostatistical integration of 3-D seismic, wellbore and gravity data. Time and initial depth mapping of Ghawar’s main reservoir reflection (Arab-D), over the central part of the field’s eastern flank, reveals an anomalous structural nose plunging to the east, normal to the overall Ghawar structural trend. Conversion of the time structure to depth was subsequently redone by applying revised depth conversion velocities derived using a bivariate geostatistical approach in which gravity data was used as a guide variable in estimating velocities away from well control. Residual gravity maps covering this area exhibit a strong visual correlation (and a statistical correlation of 0.76) with depth conversion velocities calculated using well control. This updated depth map shows significant closure in the satellite structure and points to what could be a considerable amount of Arab-D reservoir above the local oil-water contact. This structure, as well as the presence of oil within the prospective area, have been subsequently confirmed by a well drilled on its south flank.

Having demonstrated the existence of the closure and the presence of hydrocarbons, an assessment of the reserve potential within the prospective area required an estimate of the Arab-D pay-thickness above the local oil-water contact. Here again geostatistics proved an invaluable tool for integrating seismically derived reservoir porosity-thickness with porosity-thickness measured in wells. Top Arab-D seismic amplitudes were used as a guide variable in a cokriging program which not only provided a reliable Arab-D porosity-thickness prediction but also yielded the relative uncertainty in porosity-thickness.

Results from the geostatistically derived Arab-D structure and porosity-thickness maps were combined to arrive at the reservoir porosity volume within the prospective area and above the oil-water contact. A volumetric calculation, which accounts for vertical as well as lateral variability in porosity, shows this structure to contain a significant amount of net pore volume.

3-D seismic supported by residual gravity, geostatistically integrated with standard borehole reservoir data, offers a more accurate interpretation of the east flank of Ghawar. Previous structural and reservoir interpretations, using only well control, portrayed the east flank as a simple monocline dipping gently towards the east; the line of injector wells are situated on this monocline just above the oil-water contact and thus provided no clue to the secondary structural high immediately to the east.

David W. Alexander is currently a Senior Geophysicist in the Southern Area Reservoir Geology Division of Saudi Aramco, Dhahran, Saudi Arabia. He has 20 years of exploration and reservoir development experience in both geophysics and geology and has worked for Phillips Petroleum and Tenneco Oil Co. before joining Aramco in 1990. David is an active member of the SEG and AAPG and a Certified Petroleum Geologist as well as a member of the EAGE and the Dhahran Geological Society. He holds BSc (1976) and MSc (1978) degrees in Geology from Brigham Young University.

Robert W. Jeffrey is a Geophysicist with Forcenergy, Alaska. Prior to joining Forcenergy, Robert worked as a Research Geophysicist with Saudi Aramco, and prior to that, with Unocal. Robert attended the University of Washington and the University of British Columbia (Geological and Geophysical Sciences). He is a member of the AAPG, EAGE and SEG.

Mechanism of Mid-Clysmic Event and its Effect on the Pre- and Post-Miocene Structure of Ras Budran Field, Gulf of Suez, Egypt

Ramadan Ali and Ali Mahmoud Khairy Suez Oil Company

The structural configuration of Ras Budran field which lies in the northeastern offshore side of the Gulf of Suez is beyond controversy, considered as a complex pre-Miocene model.

Oil is produced from a “northeast” dipping Cretaceous and Paleozoic Nubian sandstone reservoirs which are delimited to the east and to the west by a set of non-clysmic “northeast-southwest” cross Gulf faults, most likely contemporaneous with the Gulf of Aqaba, and transferred the older set of antithetic and synthetic gravity faults across, these “northeast-southwest” trending boundaries, structurally shaped Ras Budran field into parallel segments.

The intensive phase of mid-clysmic tectonism during the Intra-Rudeis time produced uneven topography governing the successive deposition of the overlying sediments and was responsible for the field present day structure anomaly.

From the tectonic point of view, the Lower Miocene structural new model is very tempting to explain to what extent the structural set up controls the pre-Miocene trap within the field and helps solving many geologic and reservoir uncertainties.

The Nukhul and Rudeis formations are of prime interest in the study area where the thickness distribution of these formations is widely differentiated and varies throughout the field due to the variation in rates of tectonic subsidence and uplifting during the Miocene times. However, this paper is an attempt to present the tectonic framework and its relationship to Intra-Rudeis Event which in essence played an effective role on the field remodeling.

Ramadan Ali is currently Head of Development Geology with Suez Oil Company (SUCO), Egypt. He started as a Well Site Geologist and Mud Logger and a Subsurface and Development Geologist with the Development Team of SUCO. Ramadan has also worked as Field Geophysicist with Western Arabian Geophysical Company, a Mud Logger with Geoservices International S.A., and as a Production Geologist with Deminex Egypt. He received his BSc in Geology from Al Azhar University in 1980.

Ali Mahmoud Khairy is currently Development Geology Department Head with Suez Oil Company, Egypt. He has more than 18 years experience in the oil business and has published papers in Development and Production Geology. Ali received his BSc in Geology from Ain Shams University, Cairo in 1979.

GEO’98: Short Course No. 2

Fractured Reservoirs Characterization and Modeling

18-19 April, 1998

Content: The lecture series integrates subjects from geology, geophysics, reservoir engineering and laboratory testing. The lecturers will define and illustrate how fractures may be used to build a comprehensive fracture network. The upgrading of such a model for reservoir simulation purposes and the description of a dual porosity simulator will be described. Participants will have the opportunity to gain a sound background on all the specific features of fractured reservoirs and to consequently be more able to limit the risk when managing them.

Topics include: specific features of a fractured reservoir, fracture families, fracture attributes, fracture characterization, seismic and fractures, modeling of fracture networks, numerical simulation, specific problems in fractured reservoir simulation among others.

Instructors are Research Scientists from the Institut Français du Pétrole: Bernard Bourbiaus, Marie-Christine Cacas, Jean-Marc Daniel, Francis Faure, Laurence Nicoletis and Jean-Claude Sabathier.

For more information please contact:

Mr. Eric Gross

IFP Arabian Gulf

P.O.Box 3282

Manama, Bahrain

Tel: (973) 214-778; Fax: (973) 217-908;

e-mail: egifpbf@batelco.com.bh

Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation

Joachim E. Amthor, Jos J.M. Terken Petroleum Development Oman and Marietta Vroon-ten Hove Shell International E&P

Exploration in the Ghaba Salt Basin of North Oman found substantial gas and condensate in sandstones of the Barik Sandstone Member (Andam Formation, Cambro-Ordovician Haima Supergroup) at depths between 4,200 and 5,200 meters. The observed play variations and uncertainties highlighted the need for a interdisciplinary approach to the evaluation of this play.

A number of critical success factors were identified in a series of interdisciplinary studies: (1) The depositional environment determines the net sand content of the Andam Formation sandstones. Fluvial/tidal reservoir sands grade towards the north into non-reservoir (marginal) marine heteroliths. (2) The main diagenetic controls on reservoir quality distribution are depth and the timing of liquid hydrocarbon charge. Early cementation by dolomite and depth-related compaction and cementation (mainly by quartz) reduce porosity by 0.5% per 100 meters, whereas processes related to liquid hydrocarbon charge improve or preserve porosity. The main diagenetic factors were translated into an empirical function for reservoir quality prediction. (3) Two different source rocks have sourced most of the movable oils, condensates and gases in the Haima in the Ghaba Salt Basin. Both source rocks are linked to areas of salt deposition and are thought to be located within and at the top of the Ara Salt. (4) The timing of the initial oil charge into the reservoir relative to the diagenetic and burial history is also a critical factor. Basin modeling indicates three periods of hydrocarbon generation, during Haima (Andam-Safiq) deposition (520-375 million years ago (Ma)), during Akhdar-Kahmah deposition (270-100 Ma) and during Aruma/Tertiary deposition (80-0 Ma). In the Fahud Salt Basin, Early Ordovician/Silurian oil charge from the Ghaba Salt Basin was converted to bitumen through biodegradation either immediately after emplacement as a result of the shallow depth of the reservoir, or upon Carboniferous uplift. The resulting pore-filling bitumen has downgraded the reservoir quality in older structures in this area. In the Ghaba Salt Basin, Barik reservoirs were charged during Akhdar-Kahmah deposition (270-100 Ma). The greater burial depth (>3,000 meters) of the Barik reservoirs prior to charge resulted in significant pre-charge compaction and porosity reduction by quartz cements, it safeguarded the oil from biodegradation. (5) Gas charge and evolution of migration pathways: gas was generated in the Ghaba Salt Basin as early as 510-375 Ma from Huqf source rocks and during Sahtan/Kahmah deposition from source rocks on the west flank. Modelling suggest this later charge to migrate mainly to the east into Haima structures along the western margin of the Ghaba Salt Basin. Gas expelled from source rocks in the Fahud Basin charged structures across the Fahud basin and reached the Makarem High (80 Ma - present day).

Due to down-building of salt in the Ghaba Salt Basin gas charge from the western flank never reached structures located near the eastern margin of the Ghaba Salt Basin. Lack of ‘recent’ west flank charge, together with an adverse timing between structuration and early charge from the salt basin provide each similar Haima structure in the Central Ghaba Salt Basin with a charge risk.

These results of the interdisciplinary studies were translated into better risks constraints for prospect ranking, reservoir evaluation and calculation of reserves volumes.

Joachim E. Amthor received a PhD in Geology from City University of New York Graduate School in 1990. After two years as a Post-Doctoral Fellow at McGill University in Montreal he joined Shell Research in The Netherlands in 1992 as a Research Geologist. In 1996 Joachim was posted to Petroleum Development Oman where he is currently working as a Geologist in the exploration unit. His work involves mainly reservoir-quality prediction in both clastic and carbonate rocks, with emphasis on how diagenetic processes affect hydrocarbon reservoirs on both the exploration and production scales.

Jos J.M. Terken joined Shell in 1982 and has worked in exploration in The Netherlands, Brunei, New Zealand and Indonesia. Since 1993 he has been with Petroleum Development Oman as a Senior Review Geologist and Basin Modeller in the regional studies team. He received his MSc in Geology and Sedimentology from the University of Utrecht in 1982.

Marietta Vroon-ten Hove joined Shell International E&P in 1989 after receiving her MSc in Geology from the University of Utrecht. After her first assignment as Seismo-stratigrapher in Shell Research, she was transferred to Shell Madagascar as Team Geologist. In 1994, Marietta joined Petroleum Development Oman to study the deep gas reservoirs as Sedimentologist. Currently, she is working as Seismic Interpreter for Shell’s Research and Technical Services Division in Rijswijk, The Netherlands.

The Athel Play in Oman: Controls on Reservoir Quality

Joachim E. Amthor, Tom Faulkner, Neil L. Frewin, Jean-Louis Alixant Petroleum Development Oman Albert Matter and Karl Ramseyer University of Bern

The intrasalt Athel silicilyte is a unique source and reservoir rock found in the South Oman Salt Basin, where slabs of Athel silicilyte are entrapped in salt at 4 to 5 kilometer depth. Discovered in the early 1990’s, the play is characterized by light sour oil, hard over-pressures, and a high porosity, low permeability silica matrix rich in organic matter. The first two Al Noor wells encountered over 300 meters of pay with a permeability-thickness product of 8 to 9 microDarcy meter permeability. Reserves of 15.0 x 106 m3 oil were established from expectation oil-in-place of 210 x 106 m3. Production tests have shown both the challenges and the opportunities to produce from the unique reservoir. The play has no direct geological analogues, hence understanding the depositional environment and the development of reservoir quality were amongst the critical success factors which were addressed in a multi-disciplinary study.

The Athel silicilyte is part of the Athel Formation (Vendian to Early Cambrian Huqf Supergroup) of South Oman. The paleogeographic setting at the time of deposition was a restricted shallow-marine basin, most probably a rift-basin setting, bounded by carbonate platforms along the rift margins. The deeper parts of the basin were periodically anaerobic, resulting in the preservation of substantial amounts of organic matter and the formation of hydrocarbon source rocks of exceptional quality and thickness, one of which is the Athel Formation silicilyte. Present-day thicker (distal) silicilyte sections tend to have a higher average porosity than thinner (proximal) sections. The highest rates of accumulation are likely to have been in the distal parts of the silicilyte half-graben setting away from the source of clastic and carbonate input.

Typically for the silicilyte are finely laminated, porous lithofacies which can reach thicknesses of over 300 meters. The rock matrix consists of up to 80% of microcrystalline quartz with high amounts of microporosity (up to 30 pu). The very small modal crystal size of 2-3 microns explains the microDarcy permeability. The silica matrix is considered to have been biochemically precipitated as primary micro-crystalline quartz at low temperatures.

The Athel silicilyte is also a world-class source rock, with total organic carbon (TOC) values up to 6 wt-% and hydrogen indices in excess of 400 mg HC/g TOC. However, traditional TOC evaluation methods do not readily apply, mainly due to the presence of the significant liquid oil phase during increased maturation. Furthermore, the oil is not efficiently expelled from the source rock and can remain intimately associated with the immobile source material. The calculation of bulk densities for the petrophysical evaluation of downhole porosity can therefore be hindered by the presence of hydrocarbons in as yet undefined phases.

During burial, the silicilyte most likely did not undergo the same dissolution/reprecipitation processes that characterize Monterey Formation siliceous rocks, and which cause orders of magnitude reduction in porosity (up to 30% during opal-A to opal-CT transition alone). The early precipitation of a stable silica phase helped to preserve some of the high primary porosity. Most porosity loss after formation of the microquartz framework occurred through mechanical and chemical compaction.

Porosity in hydrostatically-pressured silicilyte generally decreases with increasing depth. Overpressured wells depart from this porosity-loss trend by having higher porosity for an equivalent burial depth, probably because overpressures retard/inhibit compaction and/or cementation. Fluid inclusion data indicate the presence of early hydrocarbons in fracture-filling quartz cements at temperatures of 70-80°Centigrade. These temperatures correlate with the modelled temperatures at which hydrocarbon generation started in the silicilyte. The loss of overpressures at any stage in the burial history of a silicilyte slab resulted not only in loss of hydrocarbons but also in a resumption of porosity loss by compaction and cementation.

The results of the multi-disciplinary study greatly improved the understanding of the depositional environment and the development of reservoir quality and were used to refine prospect evaluation and to optimize field development.

Joachim E. Amthor (see abstract “Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation” on facing page for biography and photograph)

Tom Faulkner is a Senior Seismic Interpreter in the Exploration Department at Petroleum Development Oman (PDO). Tom’s main responsibilities are prospect evaluation, applied sedimentology and integration with seismic data. Before joining PDO in 1994, he was employed as Sedimentologist by Shell International and Shell Research in The Netherlands. Tom has a BA (Honors) in Geology from Oxford University and a PhD from Bristol University.

Neil L. Frewin (see abstract “Oil Families of Oman” on page 55 for biography and photograph)

Jean-Louis Alixant is currently responsible for Athel petrophysics in Petroleum Development Oman (PDO). Jean-Louis joined Shell International as a Petrophysicist in 1990, and worked initially on quantitative seismic inter-pretation and pore pressure evaluation at Shell Research. He was then assigned to Shell Gabon where he held positions as Economics Engineer, Technology Planner, and Petrophysicist. He joined PDO’s exploration team in 1996. Jean-Louis graduated from Institut Industriel du Nord (1986) and Institut Français du Pétrole (1987), and earned a PhD in Petroleum Engineering from Louisiana State University in 1989. He has a keen interest in reservoir surveillance, nuclear magnetic resonance, measurement while drilling, and resolving complex reservoir characterisation problems through data integration.

Albert Matter received his PhD in Geology from the University of Bern, Switzerland, in 1964. Following postdoctoral appointments at Rice University and Johns Hopkins University, he returned to Bern in 1966, where he is now a Professor. His major research interests are in clastic sedimentology and diagenesis applied to petroleum exploration. Albert and his students are currently working in collaboration with petroleum companies in Germany, Hungary, the Sultanate of Oman and Switzerland.

Karl Ramseyer received MSc (1977) and PhD (1983) degrees in Geology from the University of Bern, Switzerland. After two years as a post-doctoral fellow at the University of California, Santa Barbara, he returned to Bern in 1985 as Assistant Professor. His research is concentrated on quantifying diagenetic reactions and the effect of organic matter on mineral diagenesis.

3-D Vertical Cable Processing

John Anderson, Ilkka Noponen, Wenying Cai, Helen Delome PGS Tensor Dwight Sukur and Sandra Boyd Texaco E&P

A new method of seismic data acquisition, the vertical cable marine survey, has been verified as a viable exploration-exploitation tool. A large (7 OCS blocks) 3-D vertical cable survey was acquired in the Gulf of Mexico, processed through Pre-Stack Depth Migration, and compared directly with a conventional 3-D horizontal streamer survey. Both were acquired and processed for the purpose of making a controlled comparison. Care was taken to make the processing of the two distinct data sets as close to each other as was possible. The only processing differences allowed were those necessitated by the fundamental differences of the two data sets. This paper describes the processing performed on the data with emphasis on those aspects of vertical cable processing which contrast with conventional streamer survey processing.

There are several inherent operational advantages to vertical cable acquisition when compared to streamer acquisition. The receiver cables are anchored to the water bottom well below the water surface so that towing noise is eliminated and surface wave noise is reduced. The small horizontal extent of the cables allows easier deployment near obstacles such as platforms or drilling rigs (Paul Krail; personal communication).

The basic acquisition unit of the vertical cable operation was a cable containing 16 hydrophones spaced 45 meters apart anchored at the end to the water bottom and buoys at the other end to maintain vertical tension on the cable. A second floating buoy carried the recording system and a tape drive for storage of the seismic data. The vertical cable survey at any given time had 12 live cables positioned in a 3 by 4 array. The inline and crossline spacing of the cable array were 1,600 meters and 1,800 meters respectively. The source vessel shot a series of inlines with shot spacing of 50 meters and line spacing of 40 meters over the array with the far line of receiver cables being rolled along the survey was extended in the crossline direction. In the end, 99 cable positions had been occupied in an area of 14 by 16 kilometers.

The horizontal streamer survey was a multi-streamer two boat operation with two vessels towing three cables each. The length of all receiver cables was 3 kilometers. The two vessels proceeded in aline at a distance of 6 kilometers, so that the second vessel towing the source array recorded offsets out to 3 kilometers and the first boat recorded offsets 3 kilometers to 6 kilometers.

Relatively large scale acquisition of vertical cable seismic data is operationally viable in the Gulf of Mexico deep water area. From preliminary analysis of the data, it is clear that the vertical cable method based on a sparse receiver array and dense source pattern yields processed seismic data that are remarkable similar in amplitude and character to data acquired more conventionally by towing streamer cables.

(biographies and photographs for John Anderson, Ilkka Noponen, Wenying Cai, Helen Delome, Dwight Sukur, Sandra Boyd are unavailable)

Subsalt Depth Imaging Using 3-D VSP Technique in the Ras El Ush Field, Gulf of Suez, Egypt

Mohammed A. Badri Schlumberger Wireline & Testing Taha M. Taha Gebel El Zeit Petroleum Company and Robert W. Wiley Marathon Oil Company

Subsalt imaging in the Gulf of Suez is a difficult problem. Although 3-D surface seismic data has significantly improved our understanding of the structural and stratigraphic elements dominating a given reservoir, however, in certain cases it proved to be limited. In the Ras El Ush field, Gulf of Suez, hydrocarbon was discovered in the pre-Miocene section in the Matulla and Nubia sandstone formations based on an aeromagnetic anomaly high in which the basement appeared to come close to surface. The reservoir showed a dip magnitude of about 42 degrees to the southwest. After drilling several delineation wells based on geological modeling it was observed that the field was far more complex than originally anticipated due to the presence of a thick South Gharib salt section and two tectonic trends breaking up the field into several titled and rotated compartmental blocks. Since the reservoir is less than 2,000 meters deep and part of the field resides in shallow water, the acquisition and processing of 3-D surface seismic would be costly, with long turnaround time on processing and may not produce the desired results for understanding the structural settings and support successful development well drilling.

A delineation well was drilled but it did not encounter the reservoir due to the presence of a fault which was not anticipated. A 2-D walkaway VSP profile was acquired and clearly revealed the presence of a cross element fault. This success lead to the acquisition of the first 3-D VSP survey in Egypt and the Middle East in two different wells with deviation of about 60 degrees. A multi-component downhole seismic array was used in the 3-D VSP acquisition. Both surveys were successfully acquired and processed in a remarkably short time. The 3-D VSP migration process required the building of an accurate velocity model. 3-D depth model building is based on geometric elements represented by formation boundaries and faults which delimit each volume. A volume unit can be assigned properties such as velocity, density and dip. Layer tessellation, a process which divides the layered velocity model into tetrahedra, was performed. Interval velocities were assigned to each subvolume and stored at each corner of every tetrahedra. Ray tracing was then performed for several lines and look up tables were generated for input to the Kirchhoff depth migration algorithm. Migration control parameters such as dip and aperture were carefully selected to produce optimum results.

The final migrated 3-D volumes of both walkaway VSP surveys were loaded on a workstation and interpreted. The data allowed the mapping of reliable horizons beneath the evaporite section which absorb most of the reflection energy. Three key horizons have been picked and structural maps have been derived in depth. Key faults affecting the reservoir geometry were identified and included in the maps. The derived maps have significantly improved the definition of the field and helped in detecting promising blocks.

Mohammed A. Badri is based in Egypt and is Schlumberger’s Senior Geophysicist for the East Mediterranean Region covering Egypt, Turkey, Syria, Jordan and Sudan. He graduated from the University of Minnesota, USA, in 1985 with a PhD degree in Geophysics. He worked for King Saud University, Saudi Arabia, as a Professor of Geophysics from 1985 to 1990. In 1990 he joined Schlumberger Wireline and Testing Services in Saudi Arabia. Currently, he is in charge of borehole seismic and sonic services including data acquisition, processing, interpretation and development. His main interests are reservoir imaging technology, anisotropy, permeability and shear waves. He is a member of the SEG and EAGE.

Taha M. Taha is the Geophysical Sector Manager for Gebel El Zeit Petroleum Company, Cairo, Egypt. He graduated from the University of Alexandria in 1966 with a BSc in Geology. He obtained a Diploma of High Studies in Geophysics and a Diploma of High Studies in Petroleum Geology in 1970 and 1972, respectively, from Ain Shams University. He worked with several oil companies including Marathon Petroleum Egypt, Bahrain National Oil Company, ALGEO in Algeria, Sonatrach Exploration in Algeria and General Petroleum Company in Egypt. He is a member of the SEG and AAPG.

Robert W. Wiley is an Advanced Senior Geophysicist with Marathon Oil Company. Bob has worked with Marathon since 1973. He started in the Production Technical Services Department, moved to Research, and was recently transferred to Technical Support. Bob holds a BSc degree in Math (1971) from Colorado School of Mines and a PhD in Geophysics (1980) also from Colorado School of Mines. His current interests are seismic modeling and inversion, VSP processing and imaging.

Foreland-Basin Development and Petroleum Migration in the Zagros and Oman Mountains

Ian R. Baron, Conoco Middle East Ltd., Robert J. Hooper and Mehdi Alavi Conoco Inc.

The concept of the foreland-basin system has evolved considerably in recent years. Of particular significance to petroleum system analysis is the recognition that foreland basins are dynamic systems and that there is considerable overlap and interaction between the orogenic wedge and its associated foreland-basin system. Early-formed strata in the foreland basin, can be progressively incorporated into the orogenic wedge. The recognition of distinct phases of foredeep development associated with the Late Cretaceous to present day shortening in the Zagros and Oman Mountains is critical to understanding the petroleum system of the eastern Arabian Plate.

The northern margin of the Arabian Plate stabilized following the Permo-Triassic break-up of Gondwana and carbonate deposition persisted over most of the platform. Development of the foreland-basin systems began in the Cenomanian/Turonian as a northeastward-directed subduction zone, within Neo-Tethys, began to impinge upon promontories on the Arabian margin. Emplacement of the orogenic wedges depressed the margin and created a series of foreland-basin systems, the effects of which were widely felt over the platform. Continued encroachment onto the Arabian margin ultimately caused the emplacement of ophiolite suites – the ophiolites of Kermanshah, Neyriz, and the Oman Mountains – into the embayments on the Arabian margin. In Iran, the carbonate bank retreated rapidly to the southwest, and a flysch/shale apron developed in front of the advancing allochthons. For the first time since the breakup of Gondwana, the dominant source for siliciclastic deposition on the northern margin of the Arabian platform was from the north-northeast, a situation that would remain to the present day. The margin gradually stabilized following the emplacement of the allochthons and the early foredeep progressively filled. The flysch/shale/carbonate system retracted towards the allochthons and the carbonate bank once more built-out over the earlier foredeeps. By the Neogene the northeast margin of the Arabian platform had fully docked with Eurasia and the intervening microcontinents of Central Iran. In Iran, rocks deposited in the Late Cretaceous foredeeps became progressively imbricated and incorporated into the developing Zagros fold belt. Evaporitic and molassic sedimentation eventually succeeded the stable-platform carbonate facies as the new foredeep which developed in association with the developing Zagros orogenic wedge progressively advanced from the northeast.

In our paper we will present outcrop data, satellite imagery, and plate and cross-section reconstructions that illustrate key features in the development of the Zagros and Oman foredeeps. The development of these foredeeps and the thermal effects their creation had on source rocks in the Paleozoic, Mesozoic and Tertiary, created a complex hydrocarbon system in which different hydrocarbon phases were generated at different levels at different times in different places! The application of modern concepts of foreland-basin development, combined with paleo-reconstructions of the Arabian Plate and modeling of the thermal history, provide the first step in defining optimal areas for future exploration.

Ian R. Baron is Vice President and Manager of Conoco’s Middle East Business Development office, based in Dubai. Apart from a brief spell working in the North Sea and Australia, most of his career has been spent working in the Middle East. For the last 10 years he has worked with DPC, Conoco’s operating unit in Dubai, and with Conoco’s Mideast New Ventures Group. He obtained a BSc (Honors) in Geology from the University of Manchester in 1977. Ian is a member of the AAPG, SEE and the Geological Society of London.

Robert J. Hooper has been with Conoco in the capacity of Senior Research Scientist since 1991. His primary function is to serve as a consultant to worldwide exploration groups on matters of structural geology, the interpretation of structures in seismic data, and regional tectonics. He is also involved in research into structural development in a wide variety of tectonic settings, and monitors several external research programs. Prior to joining Conoco, Robert was an Assistant Professor at the University of South Florida (1984-1991). He received a PhD in Geology from the University of South Carolina in 1986. He is a member of the GSA and the Geological Society of London.

Mehdi Alavi is a Structural/Tectonic Geologist and Basin Analyst with Conoco’s Advance Exploration Organization. He received a BSc from Tehran University, a MSc from the City University of New York, and a PhD from the University of Massachusetts at Amherst. He has carried out several research projects concerning various aspects of the orogenic belts in the Middle East and the Appalachians of North America. He established the Research Institute for Earth Sciences of the Geological Survey of Iran (GSI) and was Deputy General Director of GSI between 1995 and 1996. Mehdi is a member of the GSA and the International Association of Structural/Tectonic Geologists (IASTG).

Getting Maximum Value from NMR Data: New Developments in Core-to-Log Calibration

Paul B. Basan Applied Reservoir Technology

The fundamental NMR response is a measure of the proton decay in fluids confined within the rock. NMR instruments produce a distribution of echoes from the decay of signal amplitude, over a period of time, commonly called the timedomain data. Few petrophysicists work with these data preferring instead to interpret rock properties from processed echo trains. Processing procedures use an inversion (fitting and smoothing) algorithm to produce the familiar frequency patterns, known as T2-domain data.

Fitting data sometimes creates distributions where no meaningful signal actually exists. However, virtually any petrophysical interpretation made using T2-domain data can also be made using time-domain data (e.g. porosity and BVI). The advantage of using time-domain data is that the interpretation depends on the actual quality of the signal. Using this approach not only furnishes an interpretation but also a QC/QA check.

NMR core analysis databases provide a way to determine both the range of the T2 cutoff, and its dependency on other petrophysical parameters, in formations having different rock and pore types. Previously the NMR interpreters placed considerable emphasis on substituting a single core-derived cutoff for the default cutoffs used by the wireline companies. Logically, given the amount of variability shown in NMR databases, the idea of measuring the T2 cutoff in a series of core plugs, taking the central tendency of the data, and using it in place of the default cutoff was a nice idea, but one that seldom provides the best interpretation. We now recognise that log analysts cannot use core data directly for deriving an interpretation.

Matching the NMR signal from a core plug to the rock formation requires a thorough understanding of the signal, the response to rock formations, and the variations imposed by pore geometry and fluid type. Any log interpretation based on default, or core analysis parameters usually lacks precision without taking these factors into consideration. These complications lead to some unavoidable conclusions.

First, the single T2 cutoff approach is an over simplified interpretation strategy. Second, obtaining a thorough interpretation requires using the core and log data within the context of the reservoir formation. In other words, solid interpretation strategies must employ a certain amount of upscaling.

One way to upscale is to package a sequence into units based on a set of uniform criteria. Sedimentologists use this approach to perform facies analysis. The NMR signal contains both pore size and fluid distribution. We therefore reasoned that vertical changes in wireline-log NMR distributions also reflect changes in rock properties. We call these packages NMR Facies to distinguish them from facies used by sedimentologist.

NMR distributions, especially those generated from log data, are not easy to interpret from visual inspection. Consequently, developing NMR facies requires a reliable way first to identify similarity or dissimilarity and, second, a reliable way to package the units into facies. Statistical techniques, especially principle component analysis and cluster analysis, provide the tools required to interrogate NMR data and develop NMR facies.

Going from an individual NMR distribution to a set of similar distributions, and then packaging them into units is a useful upscaling procedure for comparing the NMR response to core descriptions, borehole images, other wireline logs and, ultimately to reservoir-scale models. However, NMR facies analysis (NFA) serves an even more important function for log interpretation. Changes in the characteristics of the NMR signal usually reflect changes in pore geometry, fluid content, and other parameters that may signify a change in the T2 cutoff needed to interpret BVI. NFA identifies these changes, and therefore provides the basis to develop a T2 cutoff customised to the individual facies.

Paul B. Basan received his BSc in 1965 from Indiana University and an MSc in 1970 from SUNY Binghamton. Upon completion of his MSc Paul worked for Texaco as an Exploration Geologist. In 1971 he attended the University of Georgia where he received a PhD in Geology and again returned to the industry as a Research Geologist for Amoco. Since 1978, Paul has held several positions in exploration and management and founded Applied Reservoir Technology in 1988.

Geological-Geophysical Prognosis of Oil and Gas Potential of Mesozoic Volcanites in the Kura Depression

Gulara A. Bayramova Geology Institute of Azerbaijan Academy of Sciences

In the Kura depression, the major prospects for the increase in hydrocarbon reserves are tied to the Mesozoic deconsolidated volcanogenic reservoir rocks. In this work, search for ways of forecasting such type reservoir rocks in a sedimentary section, as well as of localizing within those oil and gas-bearing zones, with regard to the central part of the Kura depression in Azerbaijan, were carried out by employing geological-geophysical and gas-geochemical data.

On correlation between the anomalies of the gravitational and magnetic fields, and the findings of seismic and electrical prospecting, the depths and spatial contours of protrusions of the Mesozoic volcanites are determined. We have substantiated a complex of gas-geochemical characteristics with respect to the areas where in the section the Mesozoic deconsolidated volcanogenic rocks occur (including the Muradkhanly oil field). The presence of contrasting high values for the near surface anomalies of heavy and light hydrocarbons, above the volcanogenic reservoir rocks, is a sign of likely presence of oil and gas in individual areas. A number of factors such as basement protrusions, velocity inversion, the high electric conductivity of the section, and gravitational and near surface hydrocarbon anomalies, has established certain regularities for the occurence of the Mesozoic volcanites, as well as non-traditional oil and gas traps associated with them.

An area characterized by low values of the velocity of the longitudinal elastic waves has been detected in the site of Saatly super-deep well (near Muradkhanly) at the depth range 3,540 to 4,060 meters. This interval with the velocity decrease of 0.6 kilometer per second, from 5.3 kilometers per second to 4.7 kilometers per second within 710-740 meters depth range, is related to the roof of the volcanites of the Mesozoic basement. This velocity inversion interval corresponds to the deconsolidated roof of the Cretaceous Volcanites of the Mesozoic Basement. These anomalous volcanogenic rocks form a new type of reservoir – Muradkhanly oil field – and trap the bulk of the field’s oil reserves. The nature and extent of the fluid saturation in these reservoir rocks can be mapped by the amplitude of the seismic reflection.

Based on the results of the data interpretations, the maps and profiles of the prospective oil- and gas-bearing zones for individual areas (Muradkhanly, Agdam-Khachinchay etc.) were made and exploration well sites identified.

Gulara A. Bayramova graduated from Azerbaijan State University. She has a PhD degree in Geology and Mineralogy. Gulara is a Geological and Petrological Engineer with the Geology Institute of Azerbaijan academy of Sciences. Her main areas of scientific interest are studying the specific features of geological structures by interpreting geophysical materials, describing oil and gases from the point of view of geochemistry and the geochemical and geophysical methods of searching for hydrocarbon deposits in sedimentary basins. She has published numerous papers and is a member of the EAGE and Azerbaijan Petrologist and Geologist Society.

Development Drilling of the Tawila Field, Yemen, Based on Three-Dimensional Reservoir Modeling and Simulation

Craig I. Beattie, Brian R. Mills and Virginia A. Mayo Canadian Petroleum International Resources Ltd.

Canadian Petroleum International Resources Ltd. and partners in the Yemen Masila Block have successfully used detailed three-dimensional reservoir modeling and reservoir simulation to optimize the development of the larger oil fields in the Masila area. The models were used to predict reservoir performance and plan additional development drilling which subsequently demonstrated that the models accurately predicted drilling results.

The main producing horizon in the Masila area is the Cretaceous Upper Qishn Formation, a clastic-dominated transgressive depositional sequence with fluvial sediments at the base, tidal dominated estuarine sediments in the middle, and marine shoals at the top. This variable array of facies presents modeling challenges but the resulting heterogeneous models provide a realistic representation of actual reservoir characteristics. This paper describes the approach used to stochastically distribute both facies bodies and petrophysical parameters, and to upscale the model for reservoir simulation, while preserving the complex reservoir description.

The Tawila field was the first Masila field to have wells drilled on the basis of the modeling effort, with very encouraging results. For these new well locations, the model successfully predicted both reservoir development and oil-water contact movements resulting from production from existing wells. This paper presents key conclusions and predictions from the modeling and reservoir simulation, and compares them to the results from subsequent drilling. As a result of the successful development drilling, these models are now an integral part of reservoir management and development planning for all Masila fields.

Craig I. Beattie is the Reservoir Engineering Manager for the Yemen Operations Group of Canadian Petroleum International Resources Ltd. (CPIRL). Prior to assuming his current position he was the Project Leader for the Masila Modeling Project and Reservoir Engineer for the Tawila field. Craig has 17 years of reservoir engineering experience, primarily in reservoir management, reservoir simulation, and enhanced oil recovery. Prior to joining CPIRL in 1994, he worked for 14 years at a major oil company. He holds BSc and MSc degrees in Chemical Engineering from the University of Toronto.

Brian R. Mills graduated from McGill University with Honors in Geological Sciences in 1977. He has 20 years of experience as a geologist in the petroleum industry with more than ten years in the international sector at Canadian Occidental and Canadian Petroleum International Resources Ltd. He has worked in a variety of roles in Canadian Occidental’s international petroleum exploration, business development and development endeavors. He is currently a Senior Geoscientist with the Yemen Operations Group and has been an active participant in the company’s recent three-dimensional geological modeling project for the Masila Block fields in Yemen.

Virginia A. Mayo is a Reservoir Analyst in the Yemen Operations Group of Canadian Petroleum International Resources Ltd. (CPIRL). She has been working on the Masila project for 6 years in roles of increasing responsibility. She has worked on the Tawila field since 1996, and is currently responsible for all reservoir engineering for the field. Prior to joining CPIRL, Virginia worked at the Saskatchewan Research Council. She holds a Certificate in Petroleum Technology from the Southern Alberta Institute of Technology.

Improved Modeling of Matrix-Fracture Transfer Terms in Dual Porosity Simulators

Bernard Bourbiaux and Jean-Claude Sabathier Institut Français du Pétrole

The long-term behavior of naturally-fractured reservoirs during exploitation mainly depends on the flow exchanges occurring between the high-capacity matrix medium and the high-conductivity fracture medium. Dual-porosity simulators have been designed to simulate this specific flow behavior. They involve the use of two superposed grids, a matrix grid and a fracture grid, with matrix-fracture transfers being computed at each gridlock location.

To obtain reliable predictions, the physical mechanisms contributing to these transfers must be identified, and an adequate formulation has to be used at gridlock scale in order to correctly simulate the kinetics of matrix-fracture fluid exchanges as well as the final saturation of matrix blocks. However, these formulations remain very approximate because matrix blocks are not discretized. Therefore, pseudo kr-Pc curves, to be input in the dual-porosity simulator, have to be calibrated from a finely-gridded single porosity model before running any field-scale simulation. Such an approach is time-consuming and generally not satisfactory for long-term production forecasts. Actually, the calibration of transfer terms through pseudo kr-Pc curves is valid for a given physical mechanism, whereas the whole field life most often involves a combination of different mechanisms.

Institut Français du Pétrole has been developing a formulation which improves the representation of flow mechanisms involved in matrix-fracture transfers. In this paper, we present the water injection case and show how we can accurately simulate the matrix-fracture flow exchanges linked to capillary imbibition, including a possible effect of gravity forces.

The improved formulation of capillary imbibition takes into account the gradual water penetration in matrix blocks surrounded by water-filled fractures. At matrix block scale, results are very consistent with a finely-gridded single-porosity model, whatever the block shape and rock-fluid data. If significant, the effect of gravity forces can also be implicitly taken into account in the formulation.

Water injection was then simulated in a cross-section of a typical fractured reservoir in order to quantify the practical impact of this new formulation. The previous and new formulations of capillary imbibition transfers lead to significantly-different predictions of water-oil ratios, especially in the presence of large matrix blocks. The simulations also indicate that the formulation correctly accounts for the contribution of gravity forces to matrix oil recovery, which may be important for intermediate-wettability rock-fluid systems.

Such results demonstrate that the proposed representation of matrix-fracture transfers, which requires to input only the actual petrophysical properties of the matrix medium, is worth being introduced in dual-porosity simulators for reservoir engineering applications.

Bernard Bourbiaux is a Research Engineer in the Reservoir Modeling Group of Institut Français du Pétrole. He has been working on various topics related to the simulation of naturally-fractured reservoirs since 1994. Bernard was in charge of laboratory studies of multi-phase flows in porous media from 1982 to 1994. Bernard holds a BSc degree in Geology from ENSG, Nancy and MSc degree in Reservoir Management from ENSPM, Rueil, France.

Jean-Claude Sabathier is Associate Director of Research at Institut Français du Pétrole (IFP) in charge of the coordination of projects on reservoir characterization. Before joining IFP in 1993, he was scientific manager of Beicip-Franlab for 22 years, in charge of the supervision of the Reservoir Group. He was also attached to the Ministry of Industry, France, as an expert on French oil and gas supplies. Jean-Claude holds a MSc degree in Aeronautical Engineering from ENSAE, Paris and a post graduate degree in Petroleum Engineering from ENSPM, Rueil, France.

Pre-Job Planning of Production Logs in Multi-phase Horizontal Wells: Multi-phase Flow Model Assisted Well Log Programming

Olaf Bousché, Alex van der Spek Shell International Exploration and Production BV Hassan A. Al-Nasser, Petroleum Development Oman David Chace, Darryl Trcka and Crawford Anderson Western Atlas Logging Services

The ability to predict generic flow characteristics in multiphase, horizontal producers (flow regime, liquid hold up, pressure gradient and actual liquid and gas velocity) which any production logging tool attempts to measure would greatly facilitate the planning and programming of production logging operations. Since the predicted characteristics match the quantities to be measured, a plot of the predicted characteristics versus along hole depth produces a synthetic or simulated log. This may determine the choice of tools, the required tool specifications, centralized running, cable speed, position of stations, logging time at stations and many other operational parameters. In addition, the synthetic logs may be used to compare predicted versus real production behavior once logging has commenced.

A software package that produces simulated logs based on simple well data, i.e. production history data, deviation or survey data, completion information and fluid PVT properties was used to draft logging programs for 6 wells in Oman. The package uses a sophisticated two-phase flow model that has been extensively validated on both pipeline and well data. The software is easy to use and fast so that case studies can be generated quickly and the effect of various inflow profiles on the simulated logs can be evaluated. Sample results from the pre-job planning include the selection of stations, the choice of and specifications of tools and the generated simulated logs.

Olaf Bousché is currently responsible at the Shell International E&P Research and Technology Service Center for contacts with Western Atlas International on production logging issues. In addition, he is part of the team working on the advancement of the capabilities of production logging in horizontal multi-phase producers. Olaf joined KSEPL in 1993, starting in the Quality and Production Measurements Section working on a diverse range of subjects. In 1996 he started working on multiphase flowmeters for surface operations and on capacitance based instruments in particular. He joined the Rock and Fluid Property Evaluation Contract Center in 1997. Olaf holds an MSc in Applied Physics (Non-Newtonian Fluid Properties) from University of Enschede, the Netherlands (1986) and a PhD in Biophysics (Advanced Infrared Techniques for Protein Study) from Boston University in 1993.

Alex van der Spek received a PhD in Physics (Laser Spectroscopy) from Eindhoven University of Technology in 1992 after completing a MSc in Physics (Theoretical Aerodynamics) at the same institution. Present day prime responsibility of Alex is to substantially advance the capabilities of production logging in horizontal multi-phase producers. This entails both new technology hardware and advanced, multi-phase flow-model assisted interpretation of production logs. Alex recently joined the Rock and Fluid Property Evaluation Contract Center of Shell International E&P to continue working on production logging in horizontal wells.

Hassan A. Al-Nasser graduated with a BSc in Petroleum Engineering from the University of Southern California, Los Angeles, USA. He joined Petroleum Development Oman (PDO) in March 1982. After the wellsite period, he worked as a Petrophysicist in various PDO concessions in Oman, covering carbonate and clastic reservoirs. Hassan is currently working as Petrophysicist in the Yibal team and is focal point for special production logging applications and cased hole logging in PDO.

David Chace is a Project Leader in the Engineering Department of Western Atlas Logging Services. David received a BSc in Physics from the University of Rhode Island. He has been involved with development of pulsed neutron logging instruments and interpretation, including C/O, PNC and oxygen activation logging. He worked for several years in Malaysia and Saudi Arabia and was responsible for pulsed neutron and production logging and interpretation. He is currently the Project Leader for the Multi Capacitance Flowmeter.

Darryl Trcka is a Senior Research Physicist in the Nuclear Research Department of Western Atlas Logging Services. He received his PhD in Nuclear Physics from Florida State University and joined Western Atlas in support of logging programs at the nuclear test site in Mercury, Nevada. He is currently the Project Leader for the Pulsed Neutron Holdup Imager.

Crawford Anderson graduated with a BSc in Physics from the University of Birmingham, England. He joined Western Atlas in 1980 and held various positions in operations and technology development. He is currently in The Hague, Netherlands working as Business Development Manager, responsible for interfacing with Shell International Exploration and Production.

Seismic Imaging of Geologically Complex Areas

Keith Branham, Kay Dautenhahn Wyatt, Paul Valasek and Brackin Smith Phillips Petroleum Company

There is an increasing amount of exploration work in areas of complex geological structure and strong velocity contrasts. Conventional 3-D seismic processing in the time domain has proven inadequate to image these areas. Depth imaging technology, in the post-stack and pre-stack domain, can provide significantly improved images. Obtaining reliable depth seismic images in areas of complex geology requires proper application of techniques in acquisition, processing, velocity modeling and imaging. Each of these steps can play a critical role in the quality of the final seismic image.

Location, orientation and geometry of the acquisition equipment can lead to different subsurface images. Acquisition geometry type and source-receiver offset distribution can affect subsurface illumination and velocity estimation. Examples of these acquisition effects will be shown.

To properly image seismic data, both the structure and velocity of a layer are needed. A proprietary velocity estimation package, VEST3D, has been developed to derive 3-D seismic velocity models. We will review the techniques and application of this technology for real data cases. Case history examples will be shown comparing various poststack and pre-stack depth imaging algorithms.

Keith Branham received a BSc in Geology from Southwest Missouri State University in 1984 and an MSc in Geophysics from the University of Kansas in 1986. He joined Phillips Petroleum Company in 1986 as a Processing Geophysicist. Currently he is Team Leader of the 3-D Processing and Advanced Imaging Team where he is active in 3-D model building and depth imaging. Keith is a member of the SEG and the Geophysical Society of Tulsa.

Kay Dautenhahn Wyatt received a BSc in Electrical Engineering from the University of Tulsa in 1976 and an MSc in Electrical Engineering from Oklahoma State University in 1977. She joined Phillips Petroleum Company in 1977 as a Research Geophysicist, and began application of signal processing principles to seismic data processing. In 1979, Kay began research in vertical seismic profiling and helped pioneer VSP imaging techniques, including the VSPCDP transform. In 1982, she began research in 3-D seismic imaging, geological modeling, and velocity estimation. From 1988 to 1995, she served as Project Manager for the advanced seismic imaging group at Phillips. Kay is currently a Research Leader with Phillips. She has published numerous papers and holds several patents in the area of seismic imaging and vertical seismic profiling. She has served in several capacities to the SEG, most recently as the SEG First Vice President for 1996-1997.

Paul Valasek received a BSc in Geophysical Engineering from Montana Tech in 1984, a MSc in Geophysics from the University of Wyoming in 1987 and a PhD in Geophysics from the Swiss Federal Institute of Technology in 1992. Paul joined Phillips Petroleum Company in 1992 where he has conducted research in 3-D seismic imaging. He is a member of the SEG and GST.

Brackin Smith is a Research Geophysicist at Phillips Petroleum Company currently applying wave equation methods to improve seismic imaging in areas of complex geology. He received a PhD in Physics from the University of Texas at Austin in 1991, where he studied X-ray emissions from a tokamak plasma. Upon completion of his PhD, Brackin began work with Phillips as a Research Geophysicist, working on crosswell seismology and elastic wave modeling of seismic data. He is an active member of the SEG, serving on the Research Committee. He recently organized the SEG Summer Research Workshop, and co-organized a workshop at the Denver SEG on Seismic Data Compression. Brackin is also active in the Geophysical Society of Tulsa, serving as President for 1997-98.

Development of the Northeast Ghaba Salt Basin, Block 3, Oman

Joseph Brannan and Stephen F. Flanagan Nimir Energy Services Ltd.

Block 3 lies in the northeast of Oman. The northwest corner of the block is underlain by part of the Ghaba Salt Basin whilst the rest of the block is dominated by the flank of the Huqf Arch. The basin formed by crustal extension during Infracambrian times and since then it has been subject to numerous tectonic events. Present day it is circumscribed by three discrete, intersecting zones of deformation which have controlled its structural evolution, resulting in significant differences in development to the main part of the salt basin.

To the east, the Huqf Arch has been a persistent high throughout the Phanerozoic. It probably developed initially as the eastern flank of the rift basin and has been enhanced by continental breakup and transform faulting along the east coast of Oman. Transpression along this zone has caused repeated episodes of uplift and erosion on the east flank of the salt basin throughout the Phanerozoic.

To the north lie the Oman Mountains which developed in response to two discrete phases of compression in Late Cretaceous and Late Tertiary time. A west/east oriented foreland basin formed in the north of the block in response to the first compressional phase. In contrast regional uplift and erosion has typified the Late Tertiary phase of compression.

To the west, the Maradi fault is a major strike-slip zone which has controlled the degree and style of inversion caused by mountain building. Its role was particularly important during the Late Tertiary phase of compression when it appears to have formed the southwestern limit of regional uplift and inversion.

As a result of these tectonic events, the salt has been repeatedly mobilized. Paleozoic flowage was mainly lateral resulting in low relief salt withdrawal basins and turtle-structures. In contrast, strongly pronounced upbuilding during Tertiary times has resulted in the development of several large domes. Severe erosion, related to thrust-induced uplift, may have been instrumental in this phase of salt movement.

The interplay of tectonics and salt movement has constantly modified basin architecture, controlling sedimentation and, more crucially, modifying trap geometries. Previous exploration in the block has mainly targeted young salt structures. As most hydrocarbon generation in the block occurred in the Paleozoic and Mesozoic such structures require re-migration for success. In the present exploration phase Nimir is concentrating on older structures, which were present prior to hydrocarbon generation, and have suffered minimal subsequent disturbance.

The evolution of the basin will be demonstrated by means of a regional seismic grid which will also show the range of plays present in the area.

Joseph Brannan is an Exploration Geologist with 16 years experience in the upstream petroleum industry. He joined British Petroleum from university in 1982 and spent 10 years working on a range of major petroleum provinces including the North Sea, North Slope, Papua New Guinea, the Sub-Andean basins and the Middle East. He joined Nimir in 1992 and since then his major areas of interest have been North Africa, the Middle East and Colombia. He is currently Geological Manager overseeing Nimir-operated acreage in Yemen, Oman and Tunisia/Libya. Joe holds a BSc in Geology from Glasgow University and a D. Phil. from Oxford University. He is a fellow of the Geological Society and a member of the PESGB.

Stephen F. Flanagan is a Senior Geophysicist with over 17 years experience in the oil industry. He joined Geophysical Services International from university in 1980 and spent 5 years on interpretation and processing projects for the client Saudi Aramco. He then joined British Petroleum and spent 8 years working on a variety of exploration and production licences both internationally and in the UKCS. In 1993 he became a consultant working for companies such as Bow Valley (UK), British-Borneo, Mobil, BP and Oryx Energy. In 1997 he joined Nimir Energy Services Ltd. where he is responsible for geophysical activities in the Oman. He holds a BSc in Geological Sciences from Leeds University.

The Sedimentology of the Haima Supergroup, Oman: Outcrop Study in the Huqf Region

Rebecca C. Buckley, Neil A. Harbury Birkbeck College, University of London and Henk H.J. Droste Petroleum Development Oman

The Huqf region is situated along the Arabian Sea coast of east-central Oman. The outcrop area is approximately 60 by 150 kilometers, and has a core of Infracambrian sedimentary rocks which are onlapped from the west by Cambrian and younger sediments. The Cambrian Haima Supergroup outcrops in a strip, trending from southwest to northeast across the Huqf region. These outcrops are lateral equivalents of the Haima Supergroup in Oman’s salt basins to the west of the Huqf region. Extensive study of these outcrops was undertaken to produce integrated lithofacies schemes and interpretation of depositional setting for each of four defined formations. A range of depositional environments are recognised: from braided fluvial, through playa, aeolian and sabkha to marginal-marine and braid-delta.

A model for the sedimentary evolution of the Haima Supergroup is proposed. This study concludes that cyclicity in the shallow-marine deposits is probably controlled by fluctuations in relative sea level, whilst climatically driven fluctuations in the paleo-water table may control the cyclicity of facies distribution in the continental part of the Supergroup. Larger-scale facies changes are probably controlled by an interplay of climatic change and changes in relative sea level.

Rebecca C. Buckley received her BA in Geological Sciences from the University of Cambridge in 1993. This was followed by a Petroleum Development Oman PhD studentship at Birkbeck College, University of London, on the Sedimentology of the Cambrian of east-central Oman. Rebecca currently works as a Production Geoscientist for Esso UK.

Neil A. Harbury (see abstract “A Regional Sedimentological Study of the Lower Cretaceous Shu’aiba Formation in Oman” on page 53 for biography and photograph)

Henk H.J. Droste joined Shell in 1984 after receiving his MSc in Geology from the University of Amsterdam. He worked as a Carbonate Geologist with Shell Research in The Netherlands and as a Sedimentologist in the Regional Studies Team of Shell Expro in London. Henk was posted to Petroleum Development Oman in 1992 where he joined the Exploration Department as a Geologist/Seismic Interpreter. He is currently working as a Production Geologist in the North Oman Development and Production Unit.

Derivation of Variable T2-Partitioning Coefficient when Core NMR Data are Unavailable

Hasan A. Bunain, Ahmed A. Latif Kuwait Oil Company Mehmet Altunbay and Daniel T. Georgi Western Atlas Logging Services

The accuracy of bulk volume irreducible (BVI) and BVI-based permeability estimates can be enhanced by processing the T2-spectrum data with the correct time-slicing. Magnetization-decay in smaller pores is faster than the larger pores. Hence, a more accurate input of T2-cutoff time reflecting the spectrum of pore sizes under investigation yields more accurate estimates of BVI and BVI-based permeability values.

Variable T2-partitioning coefficient for processing NMR-log data can be derived from the correlation of core-NMR data with capillary pressure characteristics of the same set of core plugs. However, most of the time, core-NMR data are not available due to either the physical condition of core plugs or lack of them or monetary constraints. This study explains a methodology for deriving variable T2-partitioning curve when core-NMR data are unavailable.

The proposed technique requires the availability of either historical core permeability (in-situ conditions), or FMT or RCI permeability data from the pilot well. The actual T2-cutoff time for a specific depth that corresponds to that of the core plug is determined by calculating the ratio of movable to irreducible fluid saturations for different T2-cutoff values. These ratios and the NMR-porosity are entered into the Coates equation for calculation of permeability. Then, a permeability value is computed with a constant set of coefficient and exponents for each ratio (movable to irreducible) that was obtained by changing the T2-cutoff time. This interactive process continues until an acceptable agreement is reached between the computed permeability and the core, FMT or RCI derived values. The residuals (core permeability - computed permeability) are calculated and plotted. A random distribution is sought. Any systematic departure in the residual plot indicates a poor fit, probably based on improper selection of either the T2-cutoff time or the constant and the coefficients in the Coates equation and requires an adjustment. The T2-cutoff value is decided as the actual T2-cutoff time for the subject depth when an agreement between the computed and measured permeability values and a random distribution in the residual plot are obtained. This process is repeated for each depth-level with core or FMT or RCI data. The derived T2-cutoff values are correlated with GR, PE, DT, ZDEN to establish a model equation for generating the variable T2-cutoff curve where there is no core, FMT or RCI data. The model equation yields a variable T2-cutoff curve that reflects the ever-changing characteristic of pore sizes. The variable T2-cutoff curve betters the accuracy of BVI, BVM and consequently, enhances the accuracy of computed permeability values.

Hasan A. Bunian is currently working as Superintendent of the Geophysics Department at Kuwait Oil Company. He has 19 years of petroleum oil exploration experience. Hasan received his BSc in Geology from Kuwait University in 1979.

Ahmed A. Latif is a Senior Petrophysicist with Kuwait Oil Company since 1982, having 24 years of experience in Geology, Petrophysics and Operational Geology including 4 years with Kuwait Institute for Scientific Research. He graduated from Kuwait University in 1973 and is an active member of the SPE and CSPG.

Mehmet Altunbay is a Scientist with the Reservoir Technology Group at Western Atlas Logging Services. He is working on Petrophysical Interpretation of NMR log data. Mehmet is also involved in the reservoir description aspects of wireline and core data integration. He holds BSc and MSc degrees in Petroleum Engineering from the University of Southwestern Louisiana and Middle East Technical University. Prior to his current position he worked for Core Laboratories-Technology Applications Group, Pal-Mix Inc., and Turkish Petroleum Corporation. Reservoir description, formation evaluation and formation damage prevention have been Mehmet’s main areas of interest.

Daniel T. Georgi is Manager of Reservoir Technology with Western Atlas Logging Services. Daniel holds an MSc degree in Geophysics and a PhD degree in Earth Sciences from Columbia University. Throughout his career Daniel has been involved in fundamental research, tool development and field studies. He has dealt with many aspects of formation evalution of conventional, fractured and heavy-oil reservoirs as well as open and cased hole log analysis.

Predicting Permeability: Using Mechanical Stratigraphy of Carbonate Rocks in Neural Networks is a Giant Step Closer

Mohamed N. Bushara Zakum Development Company and Laura M. Ogden SAS Institute

We present preliminary results of predicting permeability values using two sector models from a carbonate reservoir offshore Abu Dhabi, United Arab Emirates. The sectors were chosen because of their contrasting geology and reservoir properties in order to test the strength of the model. Both core and wireline log data were first scrutinized for quality and data redundancy using elementary multivariate statistics and then standardized to ensure even contribution from all variables. A benchmark neural network model was obtained using nine well data variables as inputs and six hidden neurons. Even though the model showed very good results per sector, predicting very high and very low permeability values was a problem.

Next, geomechanical layers, stylolite and open fracture density codes from cored wells were input into the neural network model. Three-dimensional geomechanical units were constructed using a merged coding system such that all uncored wells in a particular sector will have a common geomechanical strata coding with varying corresponding depths. This remarkably improved predictions and resulted in correlation coefficient between target and predicted permeability values which is an order of magnitude higher than the benchmark model. The predicted values were then conditioned with test permeability to arrive at the final numbers. We regard results of this method to be superior to results obtained by conventional methods, which use multiple regression transforms even within predetermined petrophysical rock units. This approach efficiently accounts for the low end matrix permeability caused by diagenesis or pressure solution and the exceptionally high fracture-related permeability values.

MohamedN. Bushara is a Reservoir Geologist with Zakum Development Company, Abu Dhabi, UAE. He graduated with a BSc (Honors) from the University of Khartoum, earned an MSc degree from the University of Washington, Seattle, in 1987, and a PhD from the University of Wisconsin, Madison, USA, in 1991, all in Geology. Mohamed worked for ARCO Alaska, Inc., between 1991 and 1996, in development and exploration of North Slope and Cook Inlet fields. He was a summer hire for Exxon Production Research Company in Houston, in 1989 and a visiting scholar at the Department of Energy, Washington, D.C. from 1983 to 1984. Other experience includes working on IGCP project Pan-African crustal evolution of the Nubian-Arabian shield at the Johannes Gutenberg-Universität, Mainz, Germany, 1982, Tin Tungsten exploration in granitoid ring complexes, and Wellsite formation evaluation with Chevron Overseas. Currently he is working on integrated reservoir characterization, structure and modeling. He is a member of the AGU, AAPG, GSA, and Sigma Xi.

Laura M. Ogden is the Data Mining Program Manager at SAS Institute Dubai Branch office. She is responsible for all data mining initiatives and provides consulting expertise to corporations throughout the Middle East. She has assisted companies with such tasks as using Time Series Forecasting methods to develop forecasting procedures and models and using Neural Networks to develop geological prediction models. Laura holds BSc and MSc degrees in Industrial Engineering from Georgia Institute of Technology where she specialized in Production and Logistics Systems and Statistical Process Control and Quality Assurance.

How to Turn the Geological Image of a Fractured Reservoir into a Dual-Porosity Model

Marie-Christine Cacas, Bernard Bourbiaux and Sylvain Sarda Institut Français du Pétrole

Both characterization and simulation of naturally-fractured reservoirs benefited from major advances in the recent years. On the one hand, techniques of data integration and 3-D imaging are available to build representative geologic images of fracture networks. On the other hand, multi-purpose dual-porosity simulators have been developed to deal with any scenario of reservoir exploitation. However, the “sugar lump” representation of the fractured medium used in these simulators is actually very far from geologic images. Hence, the reservoir engineer remains faced with the difficulty of parameterizing the dual-porosity model, and particularly of finding correct input data for equivalent fracture permeabilities, and equivalent matrix block dimensions.

New and systematic methodology and software have been developed to compute those equivalent hydraulic parameters: (1) a tensor of equivalent fracture permeability is derived from 3-D flow computations in the actual fracture network using a resistor network method; and (2) the equivalent block dimensions in each layer are derived from the identification of a geometrical function based on capillary imbibition.

They have been validated on simple fracture networks from reference fine-grid simulations with a conventional reservoir simulator. Their efficiency to process actual complex geological image is also demonstrated.

With such a methodology and linking software, the reservoir engineer can build a representative dual-porosity model from the geologic images resulting from field fracturing data. This optimal use of geological data will improve the reliability of dual-porosity reservoir production forecasts.

Marie-Christine Cacas has nine years experience as Research Engineer at the Institut Français du Pétrole. She received her PhD in Hydrogeology from Ecole des Mines de Paris. From 1989 to 1991 she developed a finite element code for the simulation of the dynamic behavior of flexible risers. Her research deals with the analysis and the numerical modeling of naturally fractured reservoirs. Her areas of professional interest are stochastic and geomechanical modeling of fracture rocks.

Bernard Bourbiaux (see abstract “Improved Modeling of Matrix-Fracture Transfer Simulators” on page 70 for biography and photograph)

Sylvain Sarda is a Research Engineer in the Reservoir Modeling Group of Institut Français du Pétrole (IFP). He has been working on numerical methods for fractured reservoir simulation since 1995. Before joining IFP in 1995, he was a Numerical Engineer of the services company CENERGYS for 4 years. Sylvain holds a MSc degree in Physics from ENSI-ISMRa, Caen, France.

Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates

William J. Carrigan, Peter J. Jones, Mark H. Tobey, Henry I. Halpern, Lawrence E. Wender, Saudi Aramco Richard Paul Philp and Jonathan Allen University of Oklahoma

Major reserves of gas and condensate are found in deep Paleozoic sandstone and carbonate reservoirs at Ghawar field in Eastern Saudi Arabia. These gas/condensates exhibit distinct compositional and geochemical differences that reflect (1) generation from different source rocks or facies variations within a single source rock, (2) differences in thermal maturity during generation and expulsion, (3) post-generative in-reservoir hydrocarbon alteration processes, and (4) reservoir compartmentalization, or a combination of the above. Correlation studies show that the gas/condensates were generated from the same source rock as the low sulfur, super light oils found in Paleozoic sandstone reservoirs in Central Saudi Arabia - the basal ‘hot shale’ of the Qusaiba Member of the Silurian Qalibah Formation. Thermal maturity modeling of the Qusaiba shale in the vicinity of the Ghawar structure indicates the presence of two main hydrocarbon kitchens: to the east and southwest of the structure. Within the kitchen centers, generation and expulsion of oil began more than 250 million years ago, wet gas/condensate by the start of the Cretaceous, and dry gas by the end of the Cretaceous. Early-formed structures were initially charged with oil, and have subsequently been partially to completely displaced by thermally mature gas/condensate and, in areas proximal to the kitchen centers, dry gas. Although the gas/condensate reservoirs at Ghawar have been filled for at least the last 100 million years, large geochemical variations still exist, even within individual reservoirs. Significant amounts of hydrogen sulfide are only found in carbonate reservoirs of the Khuff Formation, and result from in situ thermochemical sulfate reduction in deeper (hotter) parts of the reservoir. Carbon isotopic and gas chromatographic differences reflect slight differences in the organic facies of the source rock, thermal maturity of the source rock during generation, and separate migration pathways to the reservoir. The preservation of the geochemical differences indicates the reservoirs are compartmentalized, i.e., they are divided into individual non-communicating sectors separated by permeability barriers. Detailed geochemical characterization of the eastern Saudi Arabian gas/condensates has proven to be a very useful tool to identify hydrocarbon migration pathways, determine reservoir filling history, and evaluate the extent of fluid communication within and between reservoirs.

William J. Carrigan has been with the R&D Laboratory of Saudi Aramco for the past eight years as a Research Scientist. His areas of interest are basin evaluation, stable isotope geochemistry, and petroleum geochemistry. Prior to joining Saudi Aramco, William was with the Geological Survey of Canada and the University of Ottawa, and specialized in stable isotope geochemistry and mineral geochemistry. He received a BSc in Geology from Queen’s University and a PhD also in Geology from the University of Ottawa.

Peter J. Jones is a Research Scientist at Saudi Aramco’s Research and Development Center. Prior to joining Saudi Aramco in 1991, he worked in exploration and production geology for Mustang Production, OKC (1982-1986) and Union Pacific Resources Company, (1986-1991). Peter received his BA degree in Earth Sciences from Dartmouth College and a MSc degree in Geology from University of Oklahoma (1986). His areas of interest include basin-wide thermal maturity modeling, hydrocarbon migration timing/path assessment, and reservoir geochemistry.

Mark H. Tobey is a Research Scientist with the Lab R&D Center of Saudi Aramco. Prior to joining Saudi Aramco, Mark worked with Exxon Chemical Company as a Senior Analytical and Process Chemist. He received a PhD degree in Chemistry from Texas A&M University. His current research interests include oil fingerprinting and it applications to petroleum geochemistry.

Henry I. Halpern is a Research Scientist with the Lab R&D Center of Saudi Aramco. Henry worked with Sohio between 1981 and 1985, with ARCO between 1985 and 1989, and with Shell between 1989 and 1992 prior to joining Saudi Aramco. He received a BSc degree in Chemistry from Lafayette College in 1977 and a PhD degree in Organic Chemistry from the University of California, Los Angeles in 1981. His research interests include reservoir geochemistry.

Lawrence E. Wender is a Geological Consultant with the Area Exploration Department of Saudi Aramco. He was previously with Mobil Oil Corporation and has nearly 20 years of oil industry experience. He is currently involved in the study and exploration of the Paleozoic of Saudi Arabia. Lawrence holds a MSc degree in Geology from the University of Utah.

Richard Paul Philp is a Professor of Petroleum Geochemistry in the School of Geology and Geophysics at the University of Oklahoma. He received his BSc degree in Chemistry from the University of Aberdeen, Scotland and his PhD in Organic Chemistry in 1972 from the University of Sydney, Australia. The major theme of his research is directed at the application of organic and analytical chemistry to fossil fuel research, in particular the determination of compounds known as biomarkers found in oils and extracts of source rocks. He has also investigated the application of pyrolysis gas chromatography and mass spectrometry, and gas chromatography-isotope ratio mass spectrometry to various aspects of petroleum and reservoir geochemistry.

Jonathan Allen received his BSc degree in Chemistry from the University of Science and Arts of Oklahoma and attended graduate school at the University of Oklahoma Chemistry and Biochemistry Department. After leaving graduate school, he worked for an environmental laboratory for a couple of years. Since then he has worked for Professor R.P. Philp at the University of Oklahoma Geology and Geophysics Department as a Laboratory Equipment Technician assisting Professor Philp’s REsearch Group with various petroleum and environmental research interests, sample analysis and intrument maintenance.

Geochemical Simulation of Dolomitization in Platform Carbonate Reservoirs

Emmanuel Caspard, Etienne P. Brosse, Frans S.P. van Buchem Institut Français du Pétrole Gregor P. Eberli, University of Miami and Maurice Renard Université Pierre et Marie Curie, France

Dolomitization modifies and generally enhances the petrophysical properties (porosity and permeability) of carbonate reservoirs. Understanding the hydrological and geochemical mechanisms of this phenomenon allows for the quantification and prediction of the dolomitization process. We present a geochemical simulation model (DIAPHORE) which is tested on a dataset of Neogene deposits in the Bahamas.

The stratigraphy and mineralogy of the carbonate platform in the Bahamas has been studied in great detail (ODP Legs 101 and 166; RSMAS, University of Miami). This large subsurface dataset permits the study of the dolomitization process in a precise stratigraphical and diagenetical frame. Isotopic data show that dolomitization took place in marine or marine-derived fluids, and is closely related to the hardgrounds. The “coupled reaction-transport” model DIAPHORE, developed by the Institut Français du Pétrole, uses physico-chemical relations to describe the different mechanisms of diagenesis and their interactions. It takes into account numerous parameters such as kinetic constants for carbonate reactions, porosity, permeability, size and reactive surface of the grains, mineralogy, temperature and pressure, and the composition and velocity of fluids.

After a study of the saturation state of interstitial fluids, tests were conducted with DIAPHORE with various initial mineralogies, fluid composition, fluid-flow velocity and kinetic coefficients. These DIAPHORE simulations showed that: (a) aragonite dissolves quickly, which appears to be in good agreement with field data; (b) aragonite dissolution is controlled by kinetics, and not by the velocity of the fluid flow; (c) dolomite precipitates in large amounts (upto 100% of the mineralogical composition), which is again in agreement with field data: some recifal horizons appear entirely dolomitized; and (d) with some specifical fluid compositions, significant increase of both porosity (of about 10%) and permeability is observed. The relationships between these two parameters was described by the Kozeny-Karman law. Other laws are also available and future work will consist in calibrating these with field data. However, our data show evidence of a close relationship between permeability and dolomite, with the highest permeabilities associated with highest amounts of dolomite.

In particular, the rate of dolomitization still remains a problem. Our tests showed times ranging from 10000 years to 10 million years. This essential parameter needs to be investigated in more detail since it may elucidate the possible link between diagenesis and sea-level fluctuations.

Emmanuel Caspard is a first year PhD student at the Geology-Geochemistry Division of the Institut Français du Pétrole. He works on the integrated study of sequence stratigraphy and diagenesis of carbonates (and most of all dolomitisation), and numerical modeling of diagenetic processes. He received a MSc in Geology from the University Pierre et Marie Curie, France in 1997.

Etienne P. Brosse is a graduate from the Ecole des Mines et de la Métallurgie in Nancy (France). In 1982, he defended a PhD on the geochemistry of black-shales. He joined the Organic Geochemistry Department in the Institut Français du Pétrole (IFP) in 1983, where he has been working on the source rocks of various basins including the former USSR, Iraq and Italy. Etienne was seconded to Total in 1990-1991 for a basin modeling study on the Mahakam basin. He then initiated and developed new research activity at IFP on the numerical modeling of mineral diagenesis in reservoirs.

Frans S.P. van Buchem is Senior Research Scientist at the Geology-Geochemistry Division of Institut Français du Pétrole (IFP). He has 7 years experience in the oil industry, of which one year was spent with Elf Aquitaine Production, and 6 years with the IFP. His specialization is the study of carbonate petroleum systems, including both source rocks and reservoir facies. These studies involve the combination of sequence stratigraphy, sedimentology, organic and mineral geochemistry. Frans has a MSc in Geology and a MSc in Biology from the University of Utrecht, Netherlands (1986), and a PhD in Geology from the University of Cambridge, UK (1990).

Gregor P. Eberli is Associate Professor at the University of Miami, where he is Head of the Comparative Sedimentology and Petrophysics Laboratories. His research projects focus on sedimentology and sequence stratigraphy of carbonates and mixed systems, and petrophysics of carbonates. He received his PhD in 1985 from the Swiss Institute of Technology, Zurich.

Maurice Renard is Professor at the University Pierre et Marie Curie of Paris, where he is Head of the Stratigraphy Department. His main field of research is the chemio-stratigraphy with a special focus on carbonate trace-elements and stable isotopes.

A New Production Logging Service for Multi-phase Horizontal Wells

David Chace, Darryl Trcka Western Atlas Logging Services Olaf Bousché, Alex van der Speck Shell International Exploration and Production BV Hassan A. Al-Nasser Petroleum Development Oman

A new service specifically designed for production logging in multiphase horizontal or deviated oil producers is capable of obtaining three phase flow rates in any flow regime, any watercut, and any gas volume fraction is presented. The service combines interpretation of measurements from new downhole instrumentation and multiphase flow modeling. A new production logging instrument utilizes arrays of capacitance sensors to make across-the-borehole measurements of liquid level, hold up, and phase velocity while simultaneously making average borehole measurements of pressure, temperature, diameter and noise. The sample rate of measurements is such that variations in velocity or hold up as they would occur in intermittent flow can be tracked. Flow loop data is presented that demonstrates the tool’s capabilities under wide range of conditions. A second instrument utilizes pulsed neutron technology to measure average three-phase holdups across the wellbore. These instruments are combinable with conventional production logging tools and are conveyed on coiled tubing.

The volume of data generated by this new service requires strict quality control and a means to enforce consistency between the measured flow characteristics. Three stages of quality control are defined. First, the redundancy in the data is used to check if the instruments function is intended. Second, the relation between pressure drop, hold up and fluid velocity as captured by a multiphase flow model is used to enforce consistency between these measured quantities or to mark bad data. Third, log data can be compared to previously generated simulated logs.

David Chace, Darryl Trcka, Olaf Bousché, Alex van der Spek and Hassan A. Al-Nasser (see abstract “Pre-Job Planning of Production Logs in Multi-phase Horizontal Wells: Multi-phase Flow Model Assisted Well Log Programming” on pages 70-72 for biographies and photographs)

Sedimentology and Reservoir Geometry of the Upper Permian Upper Gharif and Lower Khuff Formations in Interior Oman: Outcrop Study in the Haushi Area

Philippe Crumeyrolle, Total CST Philippe Razin, Jack Roger, Jean-Pierre Platel Bureau de Recherches Géologiques et Minières and Jean Broutin, Universitè Pierre et Marie Curie

The Upper Gharif and Lower Khuff formations have been studied in outcrop in order to describe and understand the facies, geometry and stratigraphic pattern of the Upper Permian transgressive succession of Oman. The studied outcrop on the western flank of the Huqf Anticline in the Haushi area is an analogue to the Gharif oil-bearing reservoirs farther west in the neighboring Central Oman Salt Basin. The aim of this study is to reconstruct and understand the architecture and internal heterogeneities of reservoirs in the vicinity of producing fields. The Upper Gharif and Lower Khuff formations comprise four main successive lithological/geometrical units, informally called Units A, B, C and D. They correspond to the four main depositional systems of the Late Permian major transgressive event.

Unit A (> 50 meters thick) consists of very coarse channel sandstone bodies interbedded with variegated silty claystone. The sandstone bodies form continuous channel belts and are interpreted as braided sand sheets. They are considered as the best reservoirs of the studied sequence. Unit B (0 to 15 meters thick) consists of a complex assemblage of facies developed along low-angle accretion surfaces and corresponds to an incised valley filled with a system of coalescent argillaceous and sandy estuarine point bars showing weak tidal influences. It shows a much more complex reservoir geometry than the lower braided channels of Unit A. The valley fill of Unit B is capped by the transgressive deposits of Unit C (3 meters thick) corresponding to the basal Khuff Formation. These form a continuous tabular horizon of burrowed argillaceous sandstone showing a rapid vertical increase in marine fauna and are interpreted as sheetflood deposits in a shallow lagoon environment representing the last expression of the landward-stepping fluvial system. As the transgression continued, storm/wave clastic beds occurred, interbedded with shallow marine carbonate of Unit D. This unit is of great lateral extent and forms the seal of the Gharif reservoir.

The studied clastic Permian succession of Oman records an overall transgressive trend punctuated by two unconformities. The estuarine valley fill of Unit B is separated from the braided fluvial deposits of Unit A by a major unconformity expressed by a continuous erosion surface. The fluvial/estuarine deposits of Unit B are truncated by a transgressive ravinement surface at the base of the burrowed marine sandstone of Unit C.

Philippe Crumeyrolle is Sedimentologist with Total Oil Company. He has 8 years of experience and has worked on outcrop and subsurface case studies in siliciclastics. His main activity consists of reservoir analysis and modeling. Philippe received his PhD from the University of Bordeaux in 1987. He is member of the French NDP Association.

Philippe Razin received his PhD in Sedimentology and Tectonics from the University of Bordeaux in 1989. His research deals with tectonics and sedimentation relationships in the Pyrenees mountain belt during Mesozoic and Cenozoic times. He joined the Bureau de Recherches Gèologiques et Minières in 1990. Philippe is involved in basin analysis projects in Peritethys areas, mainly France, Morocco and the Arabian Peninsula (Paleozoic and Cretaceous of Saudi Arabia; Permian, Cretaceous and Tertiary of Oman). He is a member of the French Association of Sedimentology.

Jack Roger joined the Bureau de Recherches Géologiques et Minières in 1976. He has been involved in many geological mapping projects in Saudi Arabia and Oman, focusing on the stratigraphic and sedimentologic aspects of Mesozoic and Cenozoic units. Jack graduated from Orsay University. He is affiliated with the French Geological Society and the French and International Associations of Sedimentologists.

Jean-Pierre Platel has been with the Bureau de Recherches Géologiques et Minières since 1975. He is an experienced mapping Geologist, involved in the mapping of the Mesozoic of Aquitaine-France and of Meso-Cenozoic of Oman. He received his PhD from Bordeaux University. He is a member of the French Geological Society and of the French Stratigraphical Committee.

Jean Broutin is Professor of Paleobotany and Paleoecology at the University of Paris. He received his Doctoral Thesis from Paris University. Jean is a Specialist of Late Paleozoic micro and macroflora. He is involved in a research program focusing on the western part of the Tethys (Morocco, Spain, France, Italy and Arabian Peninsula).

Fracture Swarms in Fractured Reservoirs: Characterization, Modeling and Influence on Fluid Flow

Jean-Marc Daniel and Marie-Christine Cacas Institut Français du Pétrole

The increasing number of horizontal wells, where image logs and flowmeter profiles are available, has deeply improved the description of fluid flow in fractured reservoirs. In many of these reservoirs, only small intervals account for the main part of the production. These intervals frequently correspond to highly-fractured zones, that in some cases, are responsible for early water breakthrough. Therefore, any understanding of the geometry and genesis of these fractured zones, together with an analysis of their dynamic properties, can improve the models of fluid flow within fractured reservoir.

Based on detailed studies of outcrops, we first review the different types of fracture swarms. A particular emphasis will be laid on the foredeep of the Northern Oman Mountains where beautiful 3-D outcrops can be compared to carbonate reservoirs in the subsurface. We first demonstrate how measurements along scanlines, which give the same information than image logs, can be used to distinguish the different types of fracture swarms. We show that the study of systematic joint sets and normal faults, cutting the top of antiforms, help predict some of the geometrical attributes of these swarms, such as direction and length. When applied to reservoir characterization, this means that 3-D seismic can be used as a first approximation, however, horizontal wells are required for full descriptions.

Using the Institut Français du Pétrole fracture modeling software FRACA, we investigate the influence of the characteristics of fracture swarms on fluid flow. We show that both the geometry of the swarms and the characteristics of the underlying systematic fracture sets has to be taken into account to improve fractured reservoir management.

Mainly because of the characteristic length scale of the fluid flow associated with fracture swarms, our results identify some issues which concern fluid simulation in fractured reservoir. These issues are addressed in the conclusion.

Jean-Marc Daniel has three years experience as Research Engineer at the Institut Français du Pétrole. Jean-Marc received his PhD in Geosciences from Pierre et Marie Curie University. While preparing his PhD Thesis in the Laboratory of Geology of the Ecole Normale Superieure in Paris, he studied the formation of the Tyrrhenian Basin (Western Mediterranean Sea) using structural data and geomechanical models. During this period he taught Geology and Geophysics at the Villetaneuse University. His main interests are numerical and analogue modeling of fractured reservoir and structural analysis of fractured rocks on outcrops. He is presently developing new methodologies for multi-scaled mapping of fracture networks and advanced integrated studies of fractured reservoir.

Marie-Christine Cacas (see abstract “How to Turn the Geological Image of a Fractured Reservoir into a Dual-Porosity Model” on page 79 for biography and photograph)

Open Hole Log Limitations and its Implication in Testing Decision

Abdel Rahman R. Darwish, Ali M. Al-Amoudi and Burhan M. Irshaid Abu Dhabi National Oil Company

When arriving at a decision to test a potential hydrocarbon-bearing reservoir in an exploratory or appraisal well, several factors must be considered. These include hydrocarbon shows, descriptions of cores and ditch samples, drilling problems and, most importantly, open hole log interpretations. In some wells these factors may result in conflicting evidence or contradictory interpretations. This renders the testing decision very restrictive and could result in a new hydrocarbon-bearing zone being missed. Today logs are acquired at high costs and with advanced tools and techniques; they are considered the primary factor in determining whether to test a zone. Several case studies are shown here which are based on the interpretation of open hole logs. The cases show both examples where negative and encouraging log indications correspond with hydrocarbon-bearing tests. The paper also provides the reasons for these contradictory results so that they can be avoided in the future.

Abdel Rahman R. Darwish is a Senior Geologist with Abu Dhabi National Oil Company (ADNOC) in the Exploration Division. Prior to joining ADNOC in 1980, Abdel Rahman worked with the National Oil Corporation in Libya between 1975 and 1980. He received a BSc in Geology from Cairo University in 1974. Abdel Rahman is a member of the SEE.

Ali M. Al-Amoudi is Senior Geologist with Abu Dhabi National Oil Company. He has 17 years experience in the field of Exploration Geology in the United Arab Emirates. Ali received a BSc in Geology from Cairo University in 1979 and is a member of the SEE and SPE.

Burhan M. Irshaid received his MSc degree in Petroleum Geology from Karachi University in 1970. Burhan worked with Sonatrach for 8 years as a Well-Site Geologist. In 1979 he joined Abu Dhabi National Oil Company as Senior Operation Geologist and since 1985 has been working as Senior Reservoir Geologist.

Multi-Disciplinary Reservoir Characterization of Khuff-C Gas Reservoir in ‘Uthmaniyah Area of Ghawar Field, Saudi Arabia

Shiv N. Dasgupta and Ming-Ren Hong Saudi Aramco

Integration of recently acquired 3-D seismic data with borehole information and reservoir simulation history match results has redefined the stratigraphy in the Permian Khuff-C gas reservoir over central ‘Uthmaniyah field in Ghawar. Amplitude inversion of the 3-D seismic data shows localized high acoustic impedance near the crest of Khuff structure which is interpreted as “an island” of tight Khuff-C reservoir. On the structural flanks low acoustic impedance values, corresponding to porous, gas-saturated reservoir, were derived from seismic inversion. Based on these results, the previously interpreted stratigraphic porosity edge to the east flank in the Khuff-C reservoir has been revised. This could add upto 25% to the delineated gas and condensate reserves in the Khuff-C reservoir.

The Khuff-C reservoir in Ghawar field falls within a sequence of cyclic carbonate-evaporite deposits of the Permian Khuff Formation. The reservoir interval is comprised of interbedded, tight and porous limestone and dolomite sandwiched between thicker anhydrite-rich intervals. Syndepositional stratiform diagenetic changes influenced by the depositional environment, were responsible for Khuff-C reservoir porosity. Several wells in the north-central field area penetrated the Khuff-C reservoir. Two of these wells encountered tight Khuff-C reservoir interval. Cores from the Khuff-C in these wells show anhydrite cement filling the grainstone matrix and layers of fine-grained dolomite. From these results, a stratigraphic zero-porosity edge was originally interpreted to the east of these two wells and the eastern flank of the Khuff structure was condemned for further Khuff-C reservoir development. Reservoir simulation history match results, however, suggest extra sources of Khuff-C reservoir energy in the eastern flank. Additional 700-800 pounds per square inch reservoir pressure was computed in the model wells to the east. This can only be explained with more pore volume, larger reserves and water invasion from the aquifer.

The 3-D seismic data in the area show an abrupt termination of amplitude corresponding to the Khuff-C reservoir near these two tight wells. Model-based seismic amplitude inverse modeling was performed on the data. The amplitude inversion was target-oriented, iterative and was constrained by acoustic impedance computed from the sonic and density logs at the wells. The results indicate an increase in acoustic impedance from known, porous, gas-filled, Khuff-C reservoir to tight Khuff-C. The higher acoustic impedance is interpreted as a tight Khuff-C interval and is seen as an island with tight porosity localized at the crest of Khuff structure. The sharp waveform contrast of amplitude peak associated with porous Khuff-C and the diminishing amplitude, or in some cases, reversal of polarity from peak to trough for non-porous reservoir, provided a basis for delineating the Khuff-C reservoir using 3-D seismic data. Post-inversion analyses include layering of the acoustic impedance volume computed from the seismic data and transforming them to reservoir properties such as porosity and fluid saturation. The results of seismic amplitude inversion indicate that the Khuff-C porosity extends to the entire eastern flank of the ‘Uthmaniyah field and thus opens up a large fairway for porous Khuff-C reservoir delineation.

Shiv N. Dasgupta is currently Geophysical Consultant with Saudi Aramco. He worked with Continental Oil Co. Oklahoma (1974-1976), Seismograph Service Corporation, Tulsa (1976-1977) and Amoco Production Company in Tulsa and Houston (1977-1982) prior to joining Saudi Aramco in 1982. He received a BSc degree in Geophysical Engineering from the Indian School of Mines in 1971, a MSc degree in Geophysics from St. Louis University in 1973 and MBA from Southern Illinois University in 1975. Shiv also completed graduate studies in Petroleum Engineering from the University of Houston in 1981. He is a member of the AAPG, SEG, EAGE, SPE and the AGU. His professional interests include multi-disciplinary reservoir characterization, application of new technology for improved subsurface definition and computer application and database interconnectivity.

Ming-Ren Hong is currently Geophysical Specialist with Saudi Aramco. Prior to joining Saudi Aramco he worked with the Center for Lithospheric Studies, University of Texas at Dallas as Research Engineer (1982-1984) and Arco Oil and Gas Co. as Senior Research Geophysicist (1984-1991). Ming holds a BSc degree in Atmospheric Physics (1973) and a MSc degree in Geophysics (1977) from the National Central University, Taiwan. He received his PhD in Geophysics from the University of Texas in 1982. Ming is a member of the SEG and SPE. His professional interests include seismic modeling and inversion, reservoir characterization and integrated interpretation.

3-D Seismic Coherency Attributes for Improved Imaging of Subtle Faults and Stratigraphic Features

Shiv N. Dasgupta, Christian J. Heine and Thomas T. Hu Saudi Aramco

Coherency attributes computed from 3-D seismic data in field areas of Saudi Arabia have demonstrated a significant impact on subsurface imaging and have enhanced the quality of seismic interpretation. The coherency technique improves the imaging of geologic features in 3-D seismic data that are at sub-seismic resolution. Subtle features like fracture swarms, minor faults, and stratigraphic features like channel sands can be mapped by augmenting the conventional 3-D seismic data with coherency attributes.

Coherency is a post-stack statistical process that computes similarity or dissimilarity between neighboring seismic traces in a 3-D data volume. The amplitude data is transformed into a volume of coherency attributes where continuous reflectors show high coherency, while reflectors that are locally disrupted due to stratigraphic features like porosity edges or faults, show low coherency values. Three-dimensional visualization of coherency attributes has created a new paradigm in the interpretation of subtle geological features. Images of time slices and 3-D cube displays of conventional seismic amplitude data are compared with the identical data with coherency enhancements.

Shiv N. Dasgupta (see abstract “Multi-Disciplinary Reservoir Characterization of Khuff-C Gas Reservoir in ‘Uthmaniyah Area of Ghawar Field, Saudi Arabia” on this page for biography and photograph)

Christian J. Heine received his MSc in Geology from the University of Tennessee in 1982 and a MSc in Petroleum Engineering from Tulane University in 1990. Christian was Associate Professor at Tulane University from 1990 to 1991, and worked with Mobil Oil from 1982 to 1990. He joined Saudi Aramco in 1991. Christian is a member of the AAPG and DGS.

GEO’98: Short Course No. 1

Geostatistics in Petroleum Geology

19 April, 1998

For more information please contact:

Arabian Exhibition Management WLL, P.O.Box 20200, Manama, Bahrain

Tel: (973) 550-033; Fax: (973) 553-288; e-mail: aeminfo@batelco.com.bh

Thomas T. Hu received his BSc degree in Electrical Engineering from the National Taiwan University in 1973, and MSc and PhD degrees also in Electrical Engineering in 1978 and 1981, from the University of Houston. Prior to joining Saudi Aramco, Thomas worked with Geophysical Systems Corporation, Geophysical Development Corporation, Marathon Oil Company and Texaco. Thomas is affiliated with Sigma Xi, the IEEE and SEG. His research interests are seismic data visualization and digital signal processing.

Application of Coherency Technique on 3-D Seismic Data

Shiv N. Dasgupta, Saudi Aramco Vasudhaven Sudhakar and Anthony J. Rebec Coherence Technology Co.

Application of 3-D seismic coherency has provided improved understanding of structural and stratigraphic details of the subsurface, leading to revised 3-D geologic models. Presented here is a description of the Coherency Cube methodology and various new applications with results from Saudi Aramco fields. It is intended as both an introduction to the technology, and to demonstrate the power of its use as a complementary 3-D volume to the conventional 3-D seismic volume for 3-D seismic interpretation. This technology reveals important geologic information that may be totally overlooked using conventional processing.

The ability to measure three-dimensional spatial variations in the seismic waveform, with dip and azimuth comprehension, is an extremely powerful capability. The basic seismic waveform contains a measure of time, frequency, amplitude and absorption quantities. These vary spatially as the recorded seismic responds to lateral variations in the physical and geometric properties and lithologic facies. Measuring these combined changes in the seismic response allows the interpreter to map these changes if recorded by the seismic technique. The seismic coherency measurement, as applied here, is an attempt to capture these changes. This coherency response can be decomposed into various attributes in order to identify the components that are changing.

The application of coherency to pre-stack seismic data, to optimize the imaging of faults and fractures by selective offset contributions based on coherency is presented. The coherency technique can also be used to separate the imaging of structural effects on the shorter offsets from the pore fluid effects seen on the longer offsets. The use of coherency technology in the pre-stack data creates an interesting opportunity in the area of amplitude versus offset analysis. For example, the coherency technique can be used to establish the gradient changes of the seismic waveform across the recorded offsets. Calibrating this response across a known anomaly, such as a gas-oil contact, can be used as the diagnostic seismic fingerprint to search for similar anomalies. This has a major advantage over conventional amplitude versus offset studies as it is based on waveform response rather than on amplitude alone.

Shiv N. Dasgupta (see abstract “Multi-Disciplinary Reservoir Characterization of Khuff-C Gas Reservoir in ‘Uthmaniyah Area of Ghawar Field, Saudi Arabia” on page 85 for biography and photograph)

Vasudhaven Sudhakar is President of Coherence Technology Co. Pulsonic in Canada and is also the co-founder of Coherence Technology Company based in Houston, Texas. He received his BSc degree in Physics from Madras University, India in 1979. Vasudhaven has over 17 years experience as a Professional Geophysicist in the seismic contracting business, seismic data processing and design, with over 15 years experience in 3-D seismic. From 1990 to 1993 he worked in the R&D Department for Halliburton Geophysical Service. Starting his career in 1980 he has worked for Geophysical Service Inc., Halliburton Geophysical Services Inc. and Energy Innovations.

Anthony (Tony) J. Rebec is Technical Marketing Manager for Coherence Technology Company based in Houston, Texas. He received his BSc degree in Geology and Mathematics from London University in 1967. Tony has over 30 years experience in data acquisition and design, processing and interpretation of which 20 years were directly associated with 3-D seismic. His last 10 years have been involved with integration and exploitation of 3-D seismic data leading to reservoir characterization. Starting his career in 1967 he has worked for Geophysical Service Inc., Halliburton Geophysical Services Inc. and Western Geophysical. He is a 30-year member of the SEG and has delivered numerous presentations on various aspects of 3-D reservoir geophysics and interpretation. Tony has a broad base with global experience, including Africa and the Middle East, Far East, North Sea and Australia. He is a member of the SEG, EAEG and the PESGB.

3-D Seismic Porosity Modeling in a Shu’aiba Oil Reservoir Using a New Form of Cokriging

Lennert D. den Boer, Philippe M. Doyen Western Atlas International and Heinrich W. Rothenhoefer Petroleum Development Oman

In recent years, there has been considerable interest in the general problem of integrating seismic data in reservoir modeling applications. The geostatistical approach of cokriging has been of particular interest owing to its flexibility, in that it accounts for the statistical cross-correlation between a seismic attribute, seen as a secondary variable, and a primary variable to be mapped such as porosity. However, cokriging is still perceived as a difficult technique, since its conventional implementation requires identification of spatial cross-covariance functions and solving a system of normal equations more complex than kriging. Here, we use a new form of collocated cokriging, based on a Bayesian updating of the kriging solution, which requires neither explicit reference to cross-covariance functions nor solving a cokriging system. With this new implementation, cokriging predictions can be directly computed from kriging estimates in a very efficient manner. This is particularly useful for large 3-D grids, when studying the sensitivity of cokriging results to the degree of correlation between the primary and secondary variables.

The new form of collocated cokriging is applied to estimate the 3-D distribution of porosity and permeability within a tight carbonate oil reservoir in the Shu’aiba Formation in Oman. An acoustic impedance volume, obtained by inverting a 3-D seismic dataset, is used to guide the kriged porosity estimates away from the available well locations, based on the strong negative correlation between porosity and impedance. Porosity is then used to constrain the kriged permeability, according to the strong relationship between them. The impact of the seismic data and the sensitivity of the estimates to the seismic constraint is then assessed in a dynamic manner.

Lennert D. den Boer is a Research Geoscientist at Western Atlas International. He received a BSc degree in Geophysics from the University of British Columbia, Canada, in 1983. On graduation he joined Western Geophysical in Calgary, Alberta, as a Special Projects Geophysicist. In 1990 he was transferred to London to join the Reservoir Characterization R&D Department, where he helped develop the SigmaView geostatistical system. Lennert is currently involved in R&D for the EarthGM 3-D system and associated reservoir characterization projects.

Philippe M. Doyen received a Masters degree in Mining Engineering from the University of Louvain, Belgium, in 1982, a MSc in Geophysics from Stanford University in 1984, and a PhD in Geophysics from Stanford University in 1987. Upon graduation he joined Western Geophysical in Houston, as a Research Geophysicist. In December 1989, Philippe was transferred to Western in London where he is currently managing the Reservoir Characterization R&D Department.

Heinrich W. Rothenhoefer received a PhD degree in Geology from the University of Erlangen, Germany, in 1984. In the same year he joined BEB, a Shell/Exxon company, in Hannover, Germany, as a Reservoir Geologist. Heinrich worked as Head of Production Geology in an equity team from 1989 to 1990, and as Section Head of Reservoir Geology & Operations from 1990 to 1991. Between 1991 and 1994, he was assigned as technical adviser to an arbitration team. Since 1995, Heinrich has been working on several Shu’aiba oil fields in Central Oman.

Reservoir Quality and Water Cut Potential Using the CMR Derived Nuclear Magnetic Measurements

Robert Dennis, Schlumberger Overseas (Muscat) and Austin Boyd, Schlumberger Overseas (Dubai)

The Lower-Middle Cretaceous limestones in the Middle East, are being developed with both vertical and horizontal wells. The main reservoirs in the region vary from packstones to mudstones with associated textural and grain size variations through the vertical sequence. These variations control reservoir quality and saturations that make it difficult for engineers or geologists to select the best reservoir sections. Some of the most important oil and gas structures contain fine-grained wackestones with high irreducible water saturations that cause of the low resistivity values of 1.5 ohm-m that are recorded in the hydrocarbon zone.

To account for this, new logging programs have been implemented and integrated with the available core data. The new approach involved adding the Combinable Magnetic Resonance (CMR) and Modular Formation Testing (MFT) (dual packer) tools to the conventional suite of logging tools. The CMR tool was used to predict water cut potential and reservoir quality. The permeability results from the CMR tool’s pore size analysis were calibrated with the MDT tool’s dual packer drawdown permeability and applied for a continuous measurement. This calibration has since been validated using core data and confirmed using the MDT tool and core from four additional CMR wells. The Timur permeability equation, using the bound fluid volume from the CMR tool’s fast logging pass, was examined and validated.

The potential for water production in these fine-grained reservoir rocks is determined by comparing the bulk volume water (BVW) from the resistivity with the irreducible bound volume (Bvirr) from the CMR. These techniques are discussed and validated examples are illustrated.

Robert Dennis (Bob) is the Division Petrophysicist for Schlumberger Wireline of Oman and Pakistan and is currently based in Muscat, Oman. He is responsible for developing applications for new petrophysical measurements and is currently focusing on nuclear magnetic resonance interpretation. Since joining Schlumberger of Canada as a Field Engineer in 1974, he has held several positions in Marketing, Interpretation Development in North America along with two years at Schlumberger-Doll Research, Ridgefield, Connecticut. Before coming to Oman, Bob was project leader for facies mapping and fracture evaluation studies in the Joint Research Center of Schlumberger and the National Oil Company in India in New Delhi. He earned a BSc degree in Electrical Engineering from the University of Saskatchewan, Canada in 1973 and is a member of SPWLA, SPE and NACE as well as contributor to their publications. Bob is also member of the APEGGA in Alberta, Canada.

Austin Boyd is Chief Petrophysicist for Schlumberger’s Middle East Unit based in Dubai. He is responsible for the technical support, the introduction of new services and developing new interpretation techniques. Prior to moving to Dubai he was Product Development Engineer in the Magnetic Resonance Department at the Schlumberger Product Center in Houston. Austin joined Schlumberger in 1981 as a Field Engineer. He is a member of the SPE and SPWLA. He graduated in 1981 from Technical University of Nova Scotia with a BSc in Electrical Engineering.

Technique and Technology of Deviated and Horizontal Wells Survey Using Special Cable

Rasim N. Diyashev, Renat K. Muslimov and Arnold G. Korzhenevskiy TatNIPIneft Institute, Russia

Geophysical and hydrodynamic survey of deviated and horizontal wells (inclination angles 65° and more) presents an urgent and sophisticated problem.

World practice for delivery of geophysical tools at the bottom-hole of such wells involves technology based on application of flexible pipes which contain a geophysical cable. In Russia such technologies as “Gorizontal 1-5”, hard-and software-complex “Gorizont”, which are rather cumbersome and time consuming, have found wide application.

The firm “Neutron” has developed a special geophysical cable which provides for running in of tools into a horizontal wellbore. With the aid of this cable and using production-type equipment, geophysical surveys can be performed in horizontal wellbores of length upto 300 meters, and in the case of applying of special procedures, in wellbores of length upto 450 meters or more, both in cased and in openholes in carbonate rocks. Time expenses for geophysical surveys are considerably reduced and become commensurate with the time consumed for surveys of vertical wells of corresponding lengths.

The application of cable technology increases the array of geophysical methods for surveying horizontal wells. These include Nuclear Magnetic Resonance methods, investigations through tubing using small size tools, jet-type perforating and other techniques for drilling and operating wells.

According to the results of the survey, both conventional filtration parameters of formations and composition of rocks, and their fluid saturation, are determined.

Cable design and technology for carrying out surveys in horizontal wells are protected by RF patent. Using this cable JSC “Tatneftegeophysica” has carried out surveys of more than 100 horizontal wells for Russian oil companies like Tatneft, Udmurtneft and Samaraneftegas. Results of these tests will be discussed.

Rasim N. Diyashev is currently Deputy Director of TatNIPIneft and Chairman of the Geology and Development Section and a member of the Scientific Council with TatNIPIneft Institute. He has been Head and member of several commissions on examinations of the state of development of giant oil fields. His interests include the study and development of multi-layer oil fields with complicated geological structures and complex development of heavy oils and bitumen reserves, including geology, production and refining. Rasim is currently investigating consequences of flooding of heterogeneous reservoirs at the micro level. He is a Professor at Bashkortstan State University and a member of the Russian Academy of Natural Sciences. He is a member of the SPE, AAPG and Vice President of the International Consulting Company on Oil and Gas. He is the author of 200 published works and manuscripts including monographs, thematic reviews, text books and about 40 inventions. Rasim is an Honored Scientist of the Republic of Tatarstan and Russia and an I.M. Gubkin Prize winner.

Renat K. Muslimov is currently a Professor at Kazan State University. He has nearly 40 years of experience in oil exploration, oil field geology, improvement of the processes of oil fields development, application of the advanced methods of monitoring and control of deposits depletion, application of secondary and tertiary enhancement oil recovery methods, increase of efficiency of production of hard recoverable oil reserves and recovery of natural bitumens. Renat is a member of the Development Section and Drilling Expert Council of Russia’s Ministry of Fuel and Energy, member of south-Ural Department of the Academy of Mining Sciences of Russia, member of Scientific Council of the Department of Nuclear Physics of the Russian Academy of Natural Sciences, member of the Academy of Mining Sciences of Russian Federation, Academy of Mineral Sciences and Academy of Sciences of the Republic of Tatarstan and an honorary member of Houston Geological Society. Renat is also a member of the editorial board of “Neftyanoye khozyajstvo” journal. He is the author of more than 400 published papers, more than 20 monographs and more than 100 inventions. For outstanding contribution to the oil industry in his country and the Republic, Renat has been awarded the Academician Gubkin Prize (1982), Ministry of Oil and Gas Industry of the USSR Prize (1989 and 1991), State Prize of the Republic of Tatarstan (1994) and Government of Russian Federation (1996).

Arnold G. Korzhenevskiy graduated as Geophysicist from Petroleum Technical School in Oktyabrskiy in 1959. Arnold worked as Chief Engineer at Bugulminsky Field Geophysical Enterprise between 1968 and 1977. He joined Tatnefte-geophizika as Head of the Department of Field Geophysics between 1977 and 1985 and later as Chief Engineer. He holds a PhD degree in Technical Sciences from Oil and Gas State Academy in Moscow. His scientific interests are downhole logging - logging of vertical, deviated and horizontal wells in the process of their drilling and operation. He has published more than 67 papers on this subjects and 17 inventions. Arnold has been awarded bronze and silver medals for Exhibition of Economic Achievements and a badge for Outstanding Oilman of USSR.

Stratigraphy of the Lower Paleozoic Haima Supergroup of Oman

Henk H.J. Droste Petroleum Development Oman

Following the discovery of significant gas/condensate reserves in Lower Paleozoic clastics in Central Oman a regional geological review using all available well data and a set of regional seismic lines was carried out by Petroleum Development Oman. The objective of this study was to support further appraisal and exploration activities. A chronostratigraphic framework of regional correlatable major flooding surfaces improved the understanding of the stratigraphic relationship between the different units and the regional distribution of the reservoir seal pairs. The interval of interest, the Cambrian to Lower Silurian Haima Supergroup, is a late syn- to post-rift siliciclastic infill of an extensive graben system. The depositional setting was initially continental but higher in the sequence of marine deltaic setting prevailed. The sequence is characterized by the occurrence of laterally extensive sand sheets typical of pre-vegetational times but difficult to interpret sedimentologically. At least six major transgressive regressive cycles can be recognized which can be regionally correlated. Marine intercalations are limited to Central and North Oman. The clastic influx into the grabens was initially of local origin but as the grabens filled up the sediments were predominantly derived from a southern source.

Henk H.J. Droste (see abstract “The Sedimentology of the Haima Supergroup, Oman: Outcrop Study in the Huqf Region” on page 76 for biography and photograph)

Editor’s Note: The above paper was published in GeoArabia in Volume 2, Number 4, December 1997, pages 419-472.

Adverse Changes in the Response of an Areal Geophone Array Caused by Commonly Occurring Perturbations in Phone Positions

Mark S. Egan Geco-Prakla / Schlumberger

Geophone array patterns are designed for the purpose of suppressing ground roll. If phones are not planted in the exact locations prescribed by a given design, the nature of the suppression is changed from that intended. This study examined the negative aspects of that change.

The reference array used in the analysis was composed of 72 elements and measured 50 by 50 meters. The magnitudes of the phone position errors were distributed in a Gaussian fashion. Several experiments - with different standard deviations - were considered. The azimuths of the errors were distributed uniformly throughout 360 degrees. An ensemble response of all the receiver arrays contributing to a Common Depth Point stacked trace was computed for each experiment. Each such response was then compared with the envelope of the ideal response.

When the small amount of mispositioning caused by human error was modeled, it was found that the degradation to the ensemble response was negligible for spatial wavelengths greater than 16 m. For wavelengths shorter than that, the degradation occurred only at one azimuth - and that azimuth was oblique to the in-line and crossline directions.

When receiver positions were perturbed a bit further - as would be the case when trying to avoid placing phones in vegetation, deterioration was noticeable only at wavelengths shorter than 20 meters - and even then, the deterioration occurred at only two oblique azimuths.

Discussions in the full text conclude that phone positioning errors of the magnitude typically witnessed today while acquiring data in Middle East desert environments do not endanger the integrity of the final processed product.

Mark S. Egan is the Middle East/North Africa Division Geophysicist for Geco-Prakla / Schlumberger, stationed in Dubai. Prior to this assignment, he worked for 5 years as the Area Geophysicist in Dhahran, and prior to that he was in Houston where he started in 1975. Mark holds a PhD in Geophysics, an MSc in Acoustics and a BSc in Physics. He is a member of the SEG, EAGE and SPE.

Effect of Both Formation Water and Hydrocarbon Fluid Saturation on Acoustics of Reservoir Rocks

Abdel Moktader A. El Sayed Ain Shams University, Egypt Mahmoud H. El Batanony and Ahmed Salah Egyptian Petroleum Research Institute

Twenty-eight carbonate and sandstone core samples have been obtained from the Upper Cretaceous Abu Rawash and Bahariya formations encountered in a drilled well in the northern part of the Egyptian Western Desert. They were subjected to complete petrophysical investigations including porosity, permeability, wettability, capillarity, and pore size distribution.

Comprehensive Compressional (Vp) and Shear (Vs) wave velocities were measured in the samples using ultrasonic wave propagation. Saturation levels included: (1) completely dry; (2) partially-saturated with formation water levels at 35%, 50% and 70%; and (3) fully saturated with water and/or crude oil. Robust and reliable relationships were obtained and these can be applied in either exploration or production. The relationships between fluid saturation and both Vp and Vs indicate a strong correlation. The relationship between Poisson’s Ratio and fluid saturation can be used to detect hydrocarbon-bearing rocks and to trace oil/water contacts.

Abdel Moktader A. El Sayed received his BSc (Honors) degree in Geology in 1972, MSc degree in Petrophysics in 1976 from Ain Shams University and PhD in Petroleum Geology from the Hungarian Academy of Sciences in 1981. Abdel Moktader was Assistant Lecturer between 1972 and 1977, and Associate Professor of Petroleum Geology and Reservoir Geophysics between 1988 and 1994 at Ain Shams University. He was seconded to Qatar University as Lecturer and Associate Professor of Petroleum Geology between 1985 and 1989. He is currently a Professor in Reservoir Geophysics and Petroleum Geology at Ain Shams University. Abdel Moktader is a member of the AAPG, Egyptian Geological Society, Egyptian Geophysical Society, Egyptian Petroleum Exploration, Egyptian Sedimentary Society and the Hungarian Geophysical Society.

Mahmoud H. El Batanony is currently Head of the Production Department at the Egyptian Petroleum Research Institute (EPRI). He received BSc and MSc degrees in Petroleum Engineering from Cairo University in 1971 and 1976. Mahmoud acquired a PhD in Petroleum Engineering from AZI Institute, USSR in 1982. He worked as Research Assistant in the Petroleum Unit with the National Research Center between 1972 and 1976 and as Assistant Teacher in the Oil Production and Petrophysics Laboratories at AZI Petroleum. Mahmoud had also worked part-time as Consultant Engineer with Bapetco Oil Company and as Petroleum Engineer with Gulf of Suez Petroleum Company. He is a member of the SPE of AIME, Production Committee in EGPC, Production and Exploration Committee in ASRT, EPRI Board and Applied Research Committee at the Ministry of Scientific Research and Technology.

Ahmed Salah received his BSc degree in Geology from Ain Shams University, Cairo. Ahmed also holds a Diploma in Petroleum Geology (1994) from Cairo University. He is currently working with the Egyptian Petroleum Research Institute (EPRI) as Advanced Rock Properties Laboratory Supervisor. Prior to his employment with EPRI, Ahmed worked as Micropaleontologist with the Geological Museum in Cairo, as Field Geologist with the Geological Survey of Egypt, as Core Analyst with NL Erco, and as Laboratories Supervisor with Core Laboratories, Egypt.

Recent Discovery Confirms Stratigraphic Trap Potential in the Permian Unayzah Formation of Central Saudi Arabia

Daniel S. Evans, Bassam H. Bahabri and Ahmed M. Al-Otaibi Saudi Aramco

A recent discovery in Central Saudi Arabia of Arabian Super Light oil confirms stratigraphic trap potential in the Early Permian Unayzah Formation and demonstrates another successful application of 3-D seismic in the region. Located about 175 kilometers south of Riyadh, the Usaylah-1 discovery well targeted the updip pinch-out of the Unayzah clastic section on the east flank of the Hawtah structural trend. The seal is the basal shales and siltstones of the Khuff and Unayzah formations and the source rock is the Lower Silurian Qusaiba Shale.

The well encountered an oil column of 31 feet in an upper Unayzah eolian dune facies. The areal distribution of the productive sand had been mapped with a 3-D seismic survey prior to drilling the well. Seismic horizon slices and relative amplitude maps at the target reflection clearly delineate the trap. The oil-productive Unayzah sandstone is imaged as a high-amplitude reflection in an isolated area of approximately 8 square kilometers.

Seismic isochron maps are proving effective in identifying additional areas of stratigraphic potential in the region. Upper Unayzah sandstones are present in the paleo-structural lows (isochron thicks) and are absent on the paleo-highs (isochron thins) due to both non-deposition and erosion.

Daniel S. Evans is currently Geological Specialist in the Central Area Exploration Division of Saudi Aramco developing prospects along the recently discovered Hawtah Trend in Central Arabia. Dan worked as a Groundwater Geologist between 1970 and 1975 and joined Aramco in 1975 where he worked on a variety of assignments for the Exploration Department until 1981. He then joined Tenneco Oil Co. as an Exploration Geologist from 1981 to 1984. Between 1984 and 1989, he worked for an independent oil operator based in San Antonio, Texas. He rejoined Saudi Aramco in 1989. Dan holds BA and MA degrees in Geology from the University of Texas at Austin.

Bassam H. Bahabri is currently the Chief Explorationist of the Central Area Exploration Division of Saudi Aramco. For the last 16 years, Bassam has been involved in several geological and exploration projects. As part of his career development, he participated in exploration assignments with Exxon, Texaco and Chevron. Bassam graduated with a BSc in Geology from King Saud University in Riyadh in 1981. He also obtained his DIC/MSc from Imperial College in Petroleum Exploration in 1993.

Ahmed M. Al-Otaibi received a BSc degree in Engineering Geology from King Abdulaziz University in Jeddah in 1990 and a MSc in Geology from Keele University, UK in 1993. Ahmed has been working on various projects including reservoir characterization, geostatistical reservoir modeling and exploration since he joined Saudi Aramco in 1990. He is currently a member of the Stratigraphic Trap Exploration Team, Central Saudi Arabia.

Editor’s Note: The above paper was published in GeoArabia in Volume 2, Number 3, September 1997, pages 259-278.

Infracambrian Salt Basin in the Western Rub’ Al Khali, Saudi Arabia

Mohammad I. Faqira and Ali Y. Al-Hawuaj Saudi Aramco

An Infracambrian salt basin has been identified in the western Rub’ Al Khali based on 2-D seismic data and is supported by low gravity and strong structural growth over the salt. This basin developed in a subsiding graben located along the extension of the northwest-southeast trending Najd fault system. The Najd fault system consists of west-stepping left-lateral, strike-slip faults, with rhomb-shaped basins developed between the faults. This basin probably developed at the same time as other salt basins in the southern Gulf and Oman salt basins. Salt growth is evident on the 2-D seismic data, and it started during the Early Cambrian and continued until the Late Cretaceous.

The hydrocarbon potential of the Infracambrian salt structures is high due to (1) the potential presence of Infracambrian source rocks equivalent to those in the Huqf Group of Oman as well as the known source rocks of the Silurian Qusaiba shale; (2) the early growth of salt structures that may capture any migrated hydrocarbon and preserve porosities from destruction by diagenesis; and (3) the preservation of these structural traps throughout subsequent geologic history.

Mohammad I. Faqira is an Explorationist with Central Area Exploration of Saudi Aramco since 1994. Mohammad acquired a BSc from King Abdulaziz University in 1985 and a MSc from the Colorado School of Mines in 1991. He joined Saudi Aramco in 1987 and since then worked for Geophysical Processing, Red Sea Area Exploration and Central Area Exploration. Mohammad is currently working in the Western Rub’Al Khali area.

Ali Y. Al-Hawuaj is Chief Explorationist for the Eastern Area with Saudi Aramco. He has over 18 years of experience with Saudi Aramco, mostly in exploration and exploration management. Ali holds a BSc degree in Geology from King Fahd University of Petroleum and Minerals and is a member of the AAPG and DGS.

North Oman Salt Flank Diapir Exploration

Tom Faulkner Petroleum Development Oman

Salt diapir flank traps are a mature exploration target in many parts of the world but are, as yet, untested in Oman. The upside potential for diapir flank traps appears promising as considerable reserves have already been booked in the crestal anticlines above the diapir heads such as the Ghaba North.

Recent activities over six key diapirs in the Ghaba Salt Basin has increased our understanding of the diapir flank play and its uncertainties to the point where it is now appropriate to drill. Numerous play opportunities are envisaged as the Infracambrian Ara salt (part of the Huqf Supergroup) rises up from as deep as 10 kilometers and locally reaches the present surface. Exploration targets include the Natih, Shu’aiba, Al-Khata, Gharif and Haima.

Tom Faulkner (see abstract “The Athel Play in Oman: Controls on Reservoir Quality” on page 61 for biography and photograph)

Challenges in Carbonate Reservoir Characterization by Integrating Horizontal Well Data: A Case Study from Dukhan Arab-C Reservoir, Qatar

Jorge S. Gomes and Ali M. Said Trabelsi Qatar General Petroleum Corporation

The Arab-C reservoir, which is one of the main oil reservoirs in the giant Dukhan field, consists of a stratified sequence of limestones, dolomites, and some anhydrites representing lagoonal, tidal flat, and sabkha environments. In terms of overall reservoir properties, and for field development purposes, the reservoir is divided into two units: the Upper Arab-C Unit (UAC) is more stratified (higher cyclicity) and has relatively low reservoir quality, while the Lower Arab-C Unit (LAC) is less stratified, and exhibits much better reservoir quality. Average thickness is about 85 feet, average porosity is 15-20%, and permeability is variable. The reservoir performance to date is dominated by an interval of 10 to15 feet at the base of the LAC. The average permeability of this basal grainstone is about 250 mD compared to a reservoir average of 30 mD. Because of the reduced contrasting permeabilities of the UAC relative to the LAC, the UAC is being developed with horizontal wells.

Data derived from horizontal wells, namely cores, serve as an excellent source of information in improving the description of this reservoir, particularly with respect to lateral variations of key genetic units and their petrophysical trends. The small-scale spatial variability of reservoir properties can be captured with horizontal variograms. However, the integration of vertical and horizontal well variograms provide important challenges in reservoir description. By combining these variograms with ones derived from vertical wells, it is possible to capture different scales of heterogeneity.

In this paper we explain how borehole images, petrographic analysis, and conventional electric logs along horizontal wells are being integrated with spatial correlation models to improve the stochastic reservoir description of this heterogeneous reservoir. We also explain how to identify facies, record their lateral extent and orientation, their respective petrophysical variabilities and locate fractures. The current reservoir description models for the Dukhan Arab-C reservoir are reinforced by valuable information derived from these new horizontal wells.

Jorge S. Gomes joined Qatar General Petroleum Corporation (QGPC) in 1993 and is currently the Head of a Field Development Team. He has been in the industry for over 17 years in a variety of assignments with British Petroleum, EDMA, PECTEN and PARTEX. He holds BSc and MSc degrees in Geology from Oporto University (Portugal) and a MEng in Petroleum Engineering from Herriot-Watt University, UK. His professional interests are Middle East Mesozoic carbonates, deterministic and stochastic modelling of carbonate properties, and the application of 3-D geologic models in reservoir simulation and field development.

Ali M. Said Trabelsi is a Reservoir Geologist/Sedimentologist with Qatar General Petroleum Corporation (QGPC). Before joining QGPC, he was Vice-President of Petro-Reservoir Characterization, Inc. in Houston. He also worked for David K. Davies and Associates in Houston, 3-D Exploration Inc. and Exxon. Ali has consulted for many oil companies in Houston including Exxon, Enron, Mitchell Energy, Seagull Energy, United Energy Partners and Ecopetrol in Colombia. Ali received his MSc and PhD degrees from Texas Tech University.

Plate Tectonic Control of Petroleum Occurrences of the Arabian Peninsula

Ingeborg Guba Sultan Qaboos University, Oman

The geological history of the Arabian Peninsula saw a series of very fortunate geological processes, which led to an accumulation of 645 billion barrels of crude oil, accounting for nearly 70% of the world’s total recoverable oil reserves. The various geological conditions needed for these huge hydrocarbon concentrations are all provided by plate tectonics.

This paper investigates the plate tectonic history of the Arabian Plate and its relationship to the basins in which source rocks of sufficient thickness could accumulate, as well as to conditions of maturation and migration. In particular, the development of structural traps along the northeastern plate boundary parallel to the Arabian Gulf are highlighted.

The Arabian Plate is currently drifting by more than 2 centimeters per year to the northeast, where it crushes against the Eurasian Plate to form the Zagros-Taurus collision zone. This drift of the plate means enormous horizontal stress on the rocks, the deformational effects of which can be recorded throughout the Arabian Peninsula.

The constellation of stresses caused by the plate tectonical movements enables the petroleum geologist to predict the location and extension of unexplored sedimentary basins, the geometry of yet unknown structural traps, and the presence, attitude, and density of fractures in new oil fields.

Ingeborg Guba earned a PhD degree in Geology from Technical University Clausthal in Germany. She has worked as Geologist for uranium mines in Germany and as Consultant for iron mines in Brazil. Ingeborg has taught at Yarmouk University in Jordan, and teaches at present at the Department of Petroleum & Mining Engineering, College of Engineering at Sultan Qaboos University in Oman.

GEO’98: Field Trip

Holocene Carbonates and Evaporites of Abu Dhabi

23-25 April, 1998

For more information please contact:

A.S. Alsharhan, P.O.Box 17325, Al Ain, UAE

Fax: (971 3) 611-601

e-mail: Sharhan@nyx.uaeu.ac.ae

Petrophysical Characteristics and Hydrocarbon Trapping in the Triassic Reservoirs of the Oued Mya Basin, Algeria

Nacer E. Guellati Sonatrach Exploration

The Oued Mya basin is located on the north part of the Saharan platform. The area lies between the giant Hassi R’Mel gas field and the Hassi Messaoud oil field. Since the discovery of the giant Hassi R’Mel gas field in 1956 in the Triassic reservoirs, many accumulations of oil have been found in these reservoirs, such as Haoud Berkaoui, Benkahla, Oued Noumer, Djorf, Guellala, Oulouga and Boukhzana. The lower part of the Triassic is formed by clastic sediments, sometimes with intercalations of volcanic rocks in the lowest member, while the upper part is essentially composed of thick and widespread evaporites, mainly salts that constitute a seal for the Triassic reservoirs. The Triassic clastic formation is divided into four main lithologic members which are called from base to top: Série inférieure, T1, T2, and Argileux inférieur.

The ‘Série inférieure’ and ‘T1’ members are the best reservoirs as they correspond to fluvial deposits. The ‘T2’ Member has usually fair to poor reservoir characteristics because the sandstones become more shale- and salt-cemented. The ‘Argileux’ Member is mainly composed of shales.

The petrophysical characteristics of the reservoirs are controled by the depositional environment, sandstone sources, the petrographic composition, burial and diagenetic phenomena. The porosity decreases with depth because of compaction with burial and also by cementation. Besides quartz overgrowth cement, illite, anhydrite, dolomite and salt cement are present in significant rates to reduce or obstruct the pore spaces. Porosity gain occurs by dissolution phenomena.

Many observations confirm that hydrocarbon trapping prevented further quartz cementation. Hydrocarbon traps are structural, stratigraphic and mixed type in relation with the geometry of the sand bodies. The source rock is the Silurian-rich organic “hot shales”. The expulsion and migration started since the Cretaceous.

Nacer E. Guellati graduated as Geologist Engineer from the Algerian Petroleum Institute in 1982. He joined Sonatrach in the same year and is currently Chief Geologist of the Exploration Division.

Nuclear Magnetic Resonance Logging in Petroleum Development Oman, Experience to Date

Asbjorn Gyllensten Abu Dhabi Company for Onshore Oil Operations (previously Petroleum Development Oman)

The perceived value of recent developments in Nuclear Magnetic Resonance (NMR) logging technology lies mainly in its potential to reduce well testing by providing log-derived producibility data and permeability input to reservoir models, with the ultimate aim to locate the remaining oil in mature fields.

The first NMR-trials in clastic environments in South Oman in 1993 confirmed the limitations of “traditional” NMR log-interpretation in heavy, viscous crude, where the tool can no longer differentiate between clay-bound water and movable oil. Careful analysis of the data led, however, to a new method to determine oil saturation using diffusion information. Subsequent improvements in NMR-logging tools and interpretation techniques, together with a series of core analyses and feasibility studies, provided encouragement to embark on a second round of trials in 1995/96. These new studies focused on light oil applications. Residual Oil Saturation (ROS) determination in clastic reservoirs was successful and NMR-logging was extended to carbonate formations in North Oman.

In order to reduce operating costs it is important to maximize the value of our data-acquisition strategies. Establishing a reasonable expectation of technical success up front – before committing to mobilization of expensive new sensors – facilitated the introduction of this new technology in our operations. On the basis of the results of these trials we can now map out areas where NMR-logs can complement conventional logging tools and where we need to focus on further research and development.

Asbjorn Gyllensten graduated from Norway’s Technical University in Trondheim with a MSc in Electrical Engineering and worked for Schlumberger in the Far East and Africa as a Logging Engineer. In 1978, Asbjorn joined Shell after completing an MBA at INSEAD in Fontainebleau, France. In the Hague he provided petrophysical support for the Shell Group Operating Companies and Single String Ventures before he transferred to Petroleum Development Oman (PDO) as a Petrophysicist. From 1983 to 1987 he worked in London for Shell EXPRO UK as a Senior Petrophysicist responsible for Southern North Sea gas fields, exploration support and special core analysis. He then moved to Shell Nigeria as Head of Petrophysics and Petroleum Engineering Area Team Leader in Warri, spearheading the South Forcados Area Development. In 1993 Asbjorn returned to PDO as Team Leader Exploration Petrophysics, responsible for evaluation, completion and testing 35-40 wells/year. He recently transferred to Abu Dhabi Company for Onshore Oil Operations in Abu Dhabi, United Arab Emirates as Petrophysical Coordinator, Petroleum Development Division. Asbjorn is a member of the SPWLA and SPE and serves on the 1998 SPE Well Logging Technical Committee.

Geochemical Evidence for Reservoir Compartmentalization in Central Arabian Paleozoic Reservoirs

Henry I. Halpern, Mark H. Tobey, William M. Petersen, William J. Carrigan, Peter J. Jones, Mohammad R. Al-Khadhrawi, Mohammad A. Al-Amoudi and Hani O. Al-Ohaily Saudi Aramco

Geochemical and geological interpretations are integrated to understand intra-reservoir fluid communication at five fields in Central Saudi Arabia. Well control at four of these fields Dilam, Raghib, Abu Rakiz, and Abu Markhah is limited. Therefore, the additional insights gleaned from the geochemistry of the hydrocarbon fluids recovered are particularly important for future delineation drilling decisions at these fields. The application of stable isotope geochemistry, rock pyrolysis and well-log interpretations, and hydrocarbon chromatographic signature techniques have shown that the oils at two Dilam wells may be in fluid communication (although they are interpreted to be reservoired in different formations), but the gas/condensates at the two wells are not in communication. Additionally, the oil and gas at one of the Dilam wells do not appear to be in fluid communication, and the gas reservoirs at Raghib and Dilam are not in communication. A reservoir discontinuity exists within the Unayzah at Abu Markhah, which precludes fluid communication between the two Abu Markhah wells. Isotopic differences exist between the Abu Markhah and Abu Rakiz fluids, as well.

At Nuayyim field, oils from the three reservoirs, Basal Khuff Clastics, Unayzah-A and Unayzah-B exhibit highly variable gas chromatographic fingerprinting signatures. In addition, several of the Basal Khuff Clastics crudes have extremely light carbon isotopic signatures and distinctly different fingerprints than any of the Unayzah oils. These differences can be related both to in-reservoir alteration, as well as to the timing and mechanism of emplacement of the oils. The unusual oils found in several of the Khuff Clastics tests are likely due to different stages and/or different source areas (kitchens) of hydrocarbon generation, migration, and emplacement within Central Saudi Arabia. Further, the Khuff reservoir at two Nuayyim wells cannot be in communication with the underlying Unayzah. The gas chromatographic fingerprints of the Unayzah-B oils form a tight grouping suggesting a high degree of reservoir connectivity. Fingerprints of Unayzah-A oils are variable, strongly implying that the reservoir is compartmentalized. Compartmentalization is expected, given the presence of at least some low permeability units within the Unayzah-A reservoir, and some extensive non-reservoir facies in the Basal Khuff Clastics reservoir. These expectations are confirmed by differences in oil composition.

Henry I. Halpern and Mark H. Tobey (see abstract “Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates” on page 80 for biography and photograph)

William (Bill) M. Petersen is a Geophysicist with the Area Exploration Department of Saudi Aramco. Prior to joining Saudi Aramco in 1991, Bill worked with Seismograph Service Corp. (1967-1976); American Independent Oil Company (1976-1979); Amoco (1979-1986); and Geo-Services International (1986-1991). He received a BSc degree (1964) in Earth Sciences from the Massachusetts Institute of Technology and a MSc degree in Geophysics from the University of Houston in 1991.

William J. Carrigan and Peter J. Jones (see abstract “Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates” on page 79 for biographies and photographs)

Mohammad R. Al-Khadhrawi has been a Research Scientist with the Geochemistry Unit of the Lab R&D Center in Saudi Aramco since November 1991. He received a BSc degree in Industrial Chemistry in 1991 and a MSc degree in Chemistry in 1996. Mohammad has been working on various research projects in reservoir geochemistry (continuity and fluid contacts studies) as well as exploration geochemistry in Central and Eastern Saudi Arabia.

Mohammad A. Al-Amoudi has been with Saudi Aramco since 1988. He is a Laboratory Technician with the Lab R&D Center of Saudi Aramco.

Hani O. Al-Ohaily is a Laboratory Scientist with the Lab R&D Center of Saudi Aramco. He received a BSc degree in Chemistry from King Saud University in 1984. His research interests include reservoir fluid properties (similarities and variations).

The Karim Oilplay: Cambrian Alluvial-Lacustrine Deposits in South-Central Oman

Christel Hartkamp-Bakker Petroleum Development Oman Luppo Kuilman Saga Petroleum (previously Shell International) and Heiko W. Oterdoom Petroleum Development Oman

Along the eastern flank of South Oman, in a mature exploration area, drilling recently demonstrated a new successful play in the alluvial-fluvial sediments near the top of the Huqf Supergroup. These sediments belong to the Lower Cambrian Karim Formation, a unit long known for its oil shows but considered a waste zone. The first commercial discovery, Khaleel-1, tested 500 m3 30° API oil/day in the Karim fairway from fluvial reservoirs. At present the Karim Formation cannot be resolved on seismic data, and structure maps of the Huqf-Karim interface, the base reservoir, are used for prospect mapping. A regional stratigraphic-sedimentological study led to the present success.

The Karim Formation records deposition during a late syn-rift transpressional event in the Early Cambrian (Nadi strike-slip related) before the onset of a thermal sag. The study revealed three major alluvial fans shedding from the southwest to northeast, onlapping onto the South Oman Salt Basin. Formation Micro Indicator (FMI) paleo-current data indicate a northeastern-directed drainage pattern. This is confirmed by the overall Net/Gross trend, which decreases in accordance with the drainage patterns. The two northern fans inter-finger with heterolithic lacustrine shales, and, here, the Karim is composed of regionally correlatable retrogradational and progradational cycles of alluvial fan channel complexes. In these fans the Karim is subdivided into three members, of which the basal Khaleel Member consists of fluvial sheet sandstones and forms the reservoir. The overlying Irad Member consists of fluvial channel sands, fining-up into floodplain fines to playa lake shales, acts as seal. The uppermost Runib Member consists of sheet/channel sandstones alternating with playa deposits and represents a waste zone.

Traps, presently draping the pre-salt topography, were generated and charged following multiple phases of salt withdrawal and dissolution. Production data indicate that structures are compartmentalized by faults, clearly expressed both on seismic and FMI data.

The Karim play has three critical success factors: (1) reservoir-seal development: the presence of reservoir sands overlain by a well-developed seal is limited to the southwest part of the Karim basin; (2) oil quality: there is a clear API-depth trend and oil becomes more viscous towards the east flank; and (3) reservoir quality: reservoirs become tighter with depth towards the basin.

These critical success factors are being used to rank 20 prospects and leads remaining and guide the exploration strategy for the play.

Christel Hartkamp-Bakker is an Operational Sedimentologist at Petroleum Development Oman (PDO). After joining PDO, she worked on basin studies and Formation Micro Indicator analysis. Christel obtained a MSc in Geology from the University of Utrecht in 1987 and a PhD in Petroleum Geology from the University of Technology in Delft in 1993.

Luppo Kuilman has recently been assigned to Saga Petroleum, Norway. He worked with Shell International for 12 years in various geological environments as Seismic Interpreter. He received a MSc degree in Geology from the Free University in Amsterdam in 1985.

Heiko W. Oterdoom is Head of Operations in Petroleum Development Oman’s Exploration Lab. After joining Shell, he worked on source rock characterization in KSEPL and with oil shales in SIPM. Heiko has worked as a Team Geologist in Norway, Thailand and The Netherlands, in NAM also as a WSPE. He obtained a PhD in Petrographyfrom the Federal Institute of Technology, Zurich in 1981.

A Review of NMR-Derived Permeability in Saudi Arabia Carbonates

Talal H. Hassoun, Robert Ballay, Hilal Al-Waheed Saudi Aramco and Laurent Moinard Schlumberger Middle East

Conventional well logs measure parameters related to static rock properties, such as porosity and lithology. Permeability, being a dynamic phenomenon, is difficult to estimate from these parameters. Empirical transforms have been established, which relate permeability to porosity and other static properties. These transforms provide satisfactory results in clastics, but often fail in carbonates where rock texture in combination with porosity is more significant than porosity alone. The Nuclear Magnetic Resonance (NMR) log, which measures the distribution of pore sizes in the rock, and gives an indication of texture and facies type, allows a more accurate estimation of permeability.

Over the years, Saudi Aramco has recorded NMR logs in some of the most prolific carbonate producers in Saudi Arabia. In this paper, we present the results to-date of the effort to derive permeability from well logs. Five different carbonates formations from wells in three different fields are considered. NMR-derived permeability is compared to core data and a traditional, historically-calibrated, permeability-porosity transform. Although the core/NMR database is, at present, not large enough to permit definitive conclusions, we observe an improvement in using the pore size indication from NMR in the estimation of permeability.

Talal H. Hassoun holds MSc degrees in Petroleum Engineering and in System Engineering. He has worked in reservoir engineering in Libya and Houston (Gulf Oil Corporation). Talal joined Saudi Aramco in 1979 and held assignments in reservoir management for twelve years, production engineering for one year, and is presently in reservoir description.

Robert Ballay holds a PhD in Theoretical Physics. He has taught physics in two universities and held petrophysical engineering assignments in Texas, Alaska, Indonesia, California and Saudi Arabia.

Hilal Al-Waheed graduated from the University of Tulsa with a BSc in Petroleum Engineering in 1984. He has worked in production and drilling engineering. Hilal joined the Reservoir Description Division of Saudi Aramco in 1987.

Laurent Moinard is a Petrophysicist with Schlumberger, based in Al-Khobar, Saudi Arabia. After four years as a Field Engineer in the Middle East, he has been working on log evaluation for the last twenty years in Europe, North America, India and the Middle East.

Advances in Seismic Acquisition in Saudi Arabia

Richard Hastings-James and Abdulmohsin Y. Al-Dulaijan Saudi Aramco

During 1997 Saudi Aramco reached its highest level ever of seismic crew activity, with eight 2-D seismic crews and two 3-D seismic crews deployed in the field. This has resulted in the acquisition of about 24,000 kilometers of 2-D and about 2,500 square kilometers of 3-D seismic data.

This paper describes several acquisition techniques that have been developed and implemented by Saudi Aramco over the past year in support of exploration and reservoir development activities. They include 2-D swath acquisition primarily for use in areas with imaging problems, 2-D offend acquisition using small group intervals for improved stratigraphic resolution, and 3-D split double zig-zag swath acquisition that results in excellent source-to-receiver offset and azimuthal distributions.

The 2-D techniques presented assume the availability of 480 recording channels, which is now the Saudi Aramco standard 2-D crew configuration. The new 3-D split double zig-zag technique will work with any 3-D crew.

Data examples will be used to show that, if used appropriately, these various techniques have the potential to enhance data quality at a modest increase in cost.

Richard Hastings-James is currently Geophysical Consultant with Saudi Aramco. He has 17 years of exploration industry experience, 12 of which were with Amoco Production Company in Canada, Houston and various locations throughout Africa and the Middle East. Prior to that, Richard was an Associate Professor at the Technical University of Nova Scotia, Canada and a Research Fellow at Pembroke College, Oxford. He has been with the Geophysical Data Acquisition Division of Saudi Aramco since 1992. Richard has a BEng degree in Electrical Engineering from the Technical University of Nova Scotia and a PhD from Trinity College, Cambridge. He is a member of the SEG and Dhahran Geological Society.

Abdulmohsin Y. Al-Dulaijan has been with Saudi Aramco for 16 years and is currently the Chief Geophysicist of the Geophysical Data Acquisition Division. He has BSc and MSc degrees in Physics from Baghdad University. Abdulmohsin also holds an MSc in Engineering Geosciences (1985) from the University of California, Berkeley, and a PhD in Geophysical Engineering (1991) from Colorado School of Mines.

Peri-Glacial Dune Sand Reservoirs of the Permian Unayzah Formation, Central Saudi Arabia

Christian J. Heine, Saudi Aramco Kenneth W. Glennie and Brian P.J. Williams University of Aberdeen

The recognition of Permian-age eolian sandstone was an important milestone in the evaluation of the Unayzah reservoirs in Central Saudi Arabia. To date, 15 fields have been discovered along the trend where the primary producing horizon is the Unayzah Formation. Borehole image data from the distinctly eolian reservoirs indicate a dominant wind direction from west to east, which holds true for all the sandstone recognized as eolian. A reconstruction of the Arabian Plate during the Permian suggests the eolian transport direction would fit with the present location of the “roaring Forties”, a dominant southeast wind direction in the southern hemisphere south of the 30th parallel, which would make the Unayzah Formation a southern hemisphere cold-climate desert (“present is key to the past”). This observation is consistent with the documented (Permo-Carboniferous) glaciogenic sequences of the Al-Khlata Formation of southeast Oman, and is roughly coeval with the Permian (Rotliegend) tropical desert conditions over northwest Europe. An eolian peri-glacial depositional model links the Unayzah Formation of the Saudi Arabia to the Permian glaciogenic Al-Khlata Formation of Oman in time.

Christian J. Heine (see abstract “3-D Seismic Coherency Attributes for Improved Imaging of Subtle Faults and Stratigraphic Features” on page 85 for biography and photograph)

Kenneth W. Glennie received his BSc and MSc degrees from Edinburgh University. He then spent the next 32 years as an Exploration Geologist with Shell, working in New Zealand, Canada, Nepal, Oman, Iran and Turkey before spending 15 years on the North Sea geology based in London. He retired from Shell in 1987, and he is an Honorary Lecturer at Aberdeen University, spending part of each year since 1990 working on the desert of southeastern Arabia and maintaining his interest in the Oman Mountains. He is a member of the AAPG and Geological Society of London, Edinburgh, Aberdeen and The Netherlands.

Brian P.J. Williams obtained a BSc (Honors) in Geology and a PhD in Sedimentology from the University of Wales. From 1964 to 1970 he worked as a Post-doctoral Research Fellow at the University of Ottawa, Research Fellow at the University of Wales, and a Senior Hydrogeologist for the Water Resources Board in Reading. From 1970 onwards Brian was a Lecturer, Senior Lecturer and Reader in Sedimentology in the Department of Geology, University of Bristol. In 1988, Brian became Professor in Petroleum Geology at the University of Aberdeen where he is the Director of the MSc course in Petroleum Geology. His current research interests include hydrocarbon reservoirs in Australia, Canada, Texas and the North Sea; non-marine clastic sedimentology and basin analysis. Brian is a member of the Institute of Petroleum, SPE, PESGB, AAPG, Society for Sedimentary Geology, International Association of Sedimentologists and the Geological Society of London.

Distribution and Formation of Pyrobitumen in Haima Reservoirs in North Oman

Alain-Yves Huc, Institut Français du Pétrole and Peter J.R. Nederlof Petroleum Development of Oman

Occurrences of bitumen affecting the porosity has been reported in the Cambro-Ordovician reservoirs of the Haima supergroup of North Oman. The considered geographical area encompasses the Fahud Salt Basin, the Makarem-Mabrouk High and the Ghaba Salt Basin.

According to their geochemical properties, including insolubility in organic solvents, elemental analysis, spectroscopy, reflectivity, these bitumens can be recognized as pyrobitumen which derive from the thermal cracking of a previous charge of oil. Besides pyrobitumen the studied reservoir rocks contain variable amount of extractable organic material. Isotopic signatures show that (1) regionally the pyrobitumens have different genetic origins, that is, oil is sourced by the Huqf Formation in Jaleel and Al Bashair wells and oil derived is from the so-called Q and B source rocks in Saih Rawl and Farha wells; and (2) in the studied reservoirs the associated extractable organic matter is genetically not related to the pyrobitumen and derive from different source rocks. This observation implies a complex infilling history of the considered reservoirs with several hydrocarbon charges involved in the process.

As far as their microscopic distribution is concerned the pyrobitumen occurs as pore filling particles or as pore lining films. The impact on the porosity alteration is highly variable and the volumetric amount of pyrobitumen ranges from less than 1% up to 40% (in the Jaleel well) of the pore volume.

Based on numerical modeling of oil cracking the onset of pyrobitumen generation in the studied wells is postulated to be a recent event in the basin history (less than 50 million years). According to pyrolysis experiments performed on several types of oils, regarded as possible precursors for the pyrobitumen, we infer that the amount of formed pyrobitumen is directly related to the quantity of NSO compounds present in the precursor oil. In this respect fields which exhibit unusual quantity of pyrobitumen are assumed to have hosted oil with a very high gravity. Such a situation can be the result of the biodegradation of an initially conventional oil.

Schematically the regional tectonic history includes a first burial phase related to Infracambrian to Ordovician periods of rifting followed by an important phase of erosion, caused by a very broad uplift of eastern Oman during Late Paleozoic. The subsequent phase of burial leading to the present day depth has been initiated by the break-up of the Gondwana and the creation of the northeastern and southeastern passive margins of the Arabian Plate. In this tectonic framework a reservoired charge of oil which has been emplaced during the first burial event and which has been uplifted to a sufficiently shallow depth corresponds to a favorable situation for biodegradation to take place. In this situation formation of high gravity oil accumulation (and possibly tar sand) can be expected. Upon the subsequent phase of burial this heavy oil eventually will undergo thermal cracking and be transformed into a pyrobitumen-rich reservoir. This scenario which is proposed to account for the high pyrobitumen content of Jaleel and Al Bashair wells has been simulated by numerical modeling.

The regional implication is that the pyrobitumen occurrence and importance can be tentatively predicted by identifying the age of the first reservoir charging and by assessing the depth reached by the reservoir during uplifting. Reservoirs which have been charged before the uplifting and which have been brought to shallow depth before Mesozoic-Cenozoic burial are likely to exhibit porosity plugged by substantial amount of pyrobitumen. Reservoirs initially charged after the uplifting phase, or which have never reached shallow depth during uplifting, will exhibit only subordinate amount of pyrobitumen owing a sufficient thermal history. Consequently usual basin modeling, including mapping of regional backstriping and hydrocarbon generation timing, is a potential predictive tool for pyrobitumen occurrence in north Oman.

Alain-Yves Huc joined Institut Français du Pétrole in 1981 and is currently Head of Organic Geochemistry. Alain was educated at the University of Nancy, France, and received his PhD in Organic Geochemistry from the University of Strasbourg, France, in 1978. He spent a year and a half as a postdoctoral fellow at Woods Hole Oceanographic Institution, USA, and two years as a CNRS researcher at the Applied Geology Department of the University of Orléans, France. He is a member of the AAPG, EAOG, EAPG and ALAGO and has published more than 80 papers on geological and geochemical subjects.

Peter J.R. Nederlof is a Geochemical Consultant with Shell with 18 years of oil industry experience in Europe, North America and the Middle East. Peter was previously Team Leader of Regional Studies in Petroleum Development Oman. Before joining PDO in 1992, he was employed by Shell Canada and Shell Research in The Netherlands. Peter’s main interests lie in the field of reservoir geochemistry and hydrocarbon habitat studies. He obtained a PhD in Chemistry from the University of Amsterdam and did a Post Doctorate at Stanford University. Peter is a member of the Board of the European Association of Organic Geochemists and an active member of the AAPG and the American Chemical Society. Peter has been a member of the Editorial Advisory Board of GeoArabia since its launch in 1996.

Correlation Between Geomorphological Lineaments and Fractures Observed in Outcrop with Subsurface Faults in the Mauddud Formation, Awali Anticline, Bahrain

Inga Hustedt, Joerg E. Mattner Western Atlas International and Yayha M. Al-Ansari Bahrain National Oil Company

Fractures and small-scale faults commonly cause production problems during advanced depletion stages of hydrocarbon reservoirs. Detailed knowledge of fractures and faults prior to the occurrence of early water/gas ‘breakthrough’ (or bypassed oil) allows for optimization of reservoir management. The Awali Anticline has excellent large-scale surface/bedrock exposures. In addition the long production history and drilling activity has resulted in detailed subsurface fault maps of shallow reservoirs. This study compares and correlates the subsurface faults with structural features of various scales from strata exposed in the Awali Anticline. The comparison incorporates trend statistics, fractal dimensions, length distribution, parent-daughter relationships and aerial density of structural features. This is a unique possibility to evaluate the extent to which structural outcrop/surface data can aid in the prediction of fractures and faults in the subsurface of the Arabian Gulf region.

Inga Hustedt graduated in 1996 from the Technical University of Clausthal (Germany) in Geology. During her studies she worked on assignments in the department of Petroleum Geology. Her thesis was an industry project examining the occurrence of tectonic elements and their connection to hazardous surface gas flows in the coal mining district of Ruhrgebiet, Germany. Prior to moving to Bahrain as an independent geologist in 1997, she worked as a consultant in environmental engineering.

Joerg E. Mattner (see abstract “Integrating Fluid Flow and Borehole Imaging Data in Fracture Characterization, Hanifa Reservoir, Abqaiq Field, Saudi Arabia” on page 44 for biography and photograph)

Yayha M. Al-Ansari received his BSc in Geology from Qatar University in 1993. He joined the Bahrain National Oil Company as a Trainee Geologist in September, 1993. Later he worked as Development Geologist for three years and was involved in reservoir characterization and formation evaluation research. He is currently working as Exploration Geologist in onshore and offshore areas.

Cycles of Generation, Migration, Accumulation and Destruction of Hydrocarbons in Iraq

Muhammad W. Ibrahim Target Exploration Consultants

Syndepositional bitumen pebbles in some Cretaceous rocks of Iraq indicates generation, migration, accumulation, seepage, and destruction of some paleo-oil traps before and during the Cretaceous.

In view of surface and subsurface rock evidence, there should have been significant source rocks, older than the acclaimed Balambo Formation responsible for generating hydrocarbons before the Cretaceous.

However, published geochemical source rock analyses not only estimate a Miocene-Eocene times for the onset of oil generation, but also predict a total volume of generated hydrocarbons that is less than the proven in-place hydrocarbon reserves in Iraq.

Cycles of hydrocarbon generation, migration, accumulation and destruction were modeled to account for the presently entrapped hydrocarbons and the predecessors of the Cretaceous syndepositional bitumen pebbles in Iraq.

Muhammad W. Ibrahim holds a BSc degree in Geology and MSc and PhD degrees in Petroleum Geology. He has more than fifteen years experience in exploration and development geology. Muhammad is currently Regional and Development Geologist with Target Exploration Consultants, UK. He has also worked as Geologist with Lasmo Grand Maghreb and Lasmo International, London, in 1991, and with Mobil Oil Libya/Veba Oil Operations in Tripoli, Libya. Muhammad was Assistant Professor and Head of Department of Petroleum Geology at King Abdul Aziz University, Jeddah between 1978 and 1980. Muhammad is a member of the Iraqi Geological Society, AAPG, PESGB and COGS.

Paleozoic Hydrocarbon Potential of Western Iraq

Muhammad W. Ibrahim Target Exploration Consultants

Regional stratigraphy, tectonics, source, reservoir and cap rocks of northern Arabia were integrated to assess hydrocarbon potential of the inverted Paleozoic intracratonic basins of western Iraq (area south of latitude 35N and west of longitude 43E). Oil discoveries in western Iraq were made by MPC before 1960 in the vicinity of a large oil seepage at Hit (Heet) in the east-northeastern part of the study area. A giant Paleozoic gas-condensate field was discovered by Iraq’s Oil Exploration Co. in 1993 at well Akkas-1. Exploration success has been exceptionally high in western Iraq with excellent discovery/dry hole ratio of 5/3 to 7/1 (commercial discovery/dry hole ratio to producible discovery/dry hole ratio). Within the study area 13 proven immature to frontier plays in Paleozoic, Mesozoic and Cenozoic rocks have been recognized, and there are over 68 areas of interest containing more than 70 undrilled surface and subsurface structures. Total ultimately proven recoverable reserves in the studied area in western Iraq are estimated to be more than 1.2 billion barrels of heavy oil to condensates. This estimate does not include large asphalt deposits at Hit and natural gas reserves at Akkas-1.

Muhammad W. Ibrahim (see abstract “Cycles of Generation, Migration, Accumulation and Destruction of Hydrocarbons in Iraq” on page 102 for biography and photograph)

The Hydrocarbon Charge to the Bishri Block, Palmyrides, Syria: An Integrated Multi-disciplinary Study

James Illiffe, PGS Tigress (UK) Ltd. Carl Blackstock and Ian Bulley PGS Reservoir (UK) Ltd.

The Bishri Block is a prominent topographic high located on the eastern end of the Palmyrides fold belt in Syria. Bishri has proven hydrocarbons in the Lower Cretaceous Rutba and Hayan Formations, and an asphalt mine at the surface. The objective of the study was to assess the further hydrocarbon potential of the area by determining the geological evolution of the block in relation to where and when hydrocarbons generated, and how they migrated into the Bishri Block.

The timing of the various fault directions and movements were ascertained from detailed interpretation of high quality 3-D seismic over the block. The movements on the Bishri Block were placed into their regional geological and structural setting using regional 2-D seismic data and well interpretations which was also included in the basin modelling analysis using the PGS HEDERA basin modeling system.

A local hydrocarbon charge hypothesis was precluded since; reservoir rocks in Bishri are stratigraphically below the expected, highly oil prone, Upper Cretaceous source rocks; fault throws are generally minor, with significant strike-slip elements not favoring downward migration; and that modeling predicts source rock to be immature within the block. However, simulation of the regional cross-sections indicates that the adjacent Euphrates Graben containing a thick and stratigraphically broad source rock section, produces hydrocarbons into the Upper Cretaceous carrier system, which then steps down into the Lower Cretaceous reservoirs and carrier systems at the locations of major rift margin normal faults.

The Bishri Block formed as a large fold in Early Eocene times, and modeling indicates hydrocarbon charge from the east and northeast occurred from the Eocene through to Miocene times. Late Pliocene movements not only switched off the charge, but also likely breached seals and redistributed the hydrocarbons into their present accumulations, which is further modified by significant hydrodynamic groundwater flow. The provenance of the oils suggests a westwards filling and spilling history, with further exploration implications.

James Illiffe received his BSc degree (Honors) in Geology from Swansea College, University of Wales in 1982, his MSc and PhD in Geology from the University of South Carolina in 1985 and 1991 respectively. For the past six years as Manager of Basin Modeling for PGS Tigress, he has been the technical expert developing HEDERA, a commercial basin modeling software system. He has worked on many integrated exploration studies, including the Atlantic Margin from Ireland to Norway, Mozambique, Sudan, Gulf Coast USA, Egypt and Syria. James is presently working as Geological Advisor in the Integrated Service Group of Conoco Inc., in Houston, Texas, USA.

Carl Blackstock graduated with a Geology degree from Exeter University in 1980. He joined British Petroleum as an Interpretation Geophysicist and worked in the UK, Ireland and China, principally on exploration acreage. In 1991 Carl joined a UK Consultancy (now part of PGS Reservoir) and has worked extensively on exploration and development projects worldwide. He is currently Manager of Geophysics at PGS Reservoir, UK.

Ian Bulley graduated from Reading University in 1983 and worked in the UK and Libya before gaining an MSc in Petroleum Geology in 1988. He has since worked at Amoco, Hunt Oil and PGS reservoir Ltd. After an initial period working on the North Sea, he has spent the last 3 years in the Middle East specializing in reservoir and development geology. Ian is currently in western Australia working on the exploration potential of the Carnarvon Basin.

The Paleozoic Succession of the Tabuk Basin in Saudi Arabia: Lithostratigraphy, Sedimentology and Sequence Stratigraphy

Dominique Janjou, Philippe Razin Bureau de Recherches Géologiques et Minières Mohammed A. Halawani Deputy Ministry for Mineral Resources, Jeddah Robert Wyns Bureau de Recherches Géologiques et Minières and Abdallah M.S. Memesh Deputy Ministry for Mineral Resources, Jeddah

Outcrop studies during geological mapping in the Tabuk Basin have led to a lithostratigraphic and sedimentologic revision of the Cambrian to Middle Devonian succession. The vertical facies succession makes it possible to define depositional sequences of different frequencies and a revised hierarchy of the groups, formations and members, and of their associated disconformities and unconformities is proposed. The stacking pattern describes the four major transgressive-regressive cycles that characterize this northern margin of Gondwana. (1) The Cambrian cycle, which unconformably overlies the irregular surface of the Arabian Shield, comprises a basal alluvial conglomeratic sandstone unit overlain by a mixed sand-flat - eolian sandstone complex (Siq Formation). (2) The lower boundary of the Upper Cambrian-Upper Ordovician cycle corresponds to an angular unconformity. This cycle begins with a very thick fluvial sandstone sequence (Quweira Formation and Saq Sandstone) that corresponds to a vertical aggradation of braided alluvial systems showing tidal influences at the top. This unit is abruptly overlain by transgressive wave-to tide-dominated deposits of the lower Qasim Formation (Hanadir and Kahfah members), followed by offshore facies at the base of the Ra’an member that reflect the maximum flooding of this cycle. The seaward-stepping offshore to shoreface/foreshore sequences of the Ra’an to Quwarah Members represent the regressive part of the cycle, the upper boundary of which is marked by a major erosional surface related to Late Ordovician glacial processes. (3) The Late Ordovician-Silurian cycle begins with unconformable glacial deposits of the Sarah Formation preserved in several paleochannels incised into the Qasim Formation and Saq Sandstone. This glacial complex is bounded at the top by a discontinuity (onlap surface) that marks the major rise of sea level and correlative major flooding related to deglaciation during the Early Silurian. A thick aggrading then prograding unit of storm- to wave-dominated shelf deposits accumulated until the end of the Silurian (Qalibah Group). A major erosional surface bounds this third cycle. (4) The Devonian cycle begins with the fluviatile sandstone sequences of the Tawil Formation (Lochkovian?); first aggrading then backstepping, these sequences record a relative rise of base level. The continuation of this process led to the development of a mixed lagoonal environment with deposition of the Jauf Formation (Lower Devonian), the transgressive peak being marked by the Hammamiyat Limestone Member. The overlying siliciclastic bay to estuarine deposits mark the beginning of the regressive trend that resulted in the accumulation of fluviatile sequences of the Al Jubah Formation (Middle Devonian). The top of this cycle cannot be characterized because of the lack of younger formations exposed in the Tabuk area. The detailed sequence stratigraphy of each of these transgressive-regressive cycles, based on precise sedimentologic studies, could provide a reliable basis for subsurface correlations.

Dominique Janjou received his PhD degree in Geodynamics and Structural Geology from the University of Paris in 1981. He joined the Bureau de Recherches Géologiques et Minières (BRGM) in 1982. He was involved in mapping programs in France (Brittany), Saudi Arabia (Wajid Sandstone), Haiti (West Indies), Oman (Hawasina nappes), and mapping of the Paleozoic rocks of Tabuk Basin from 1990 to 1996. Dominique is currently working on GIS and digital maps.

Philippe Razin (see abstract “Sedimentology and Reservoir Geometry of the Late Permian Upper Gharif and Lower Khuff Formations in Interior Oman: Outcrop Study in the Haushi Area” on page 82 for biography and photograph)

Mohammed A. Halawani currently works as a Geologist in the Deputy Ministry for Mineral Resources Mapping Department. He received his BSc degree from the Faculty of Earth Sciences at King Abdul Aziz University, in 1981, after which he worked on different projects in the Arabian Shield. Since 1990, he has been involved in several mapping projects of Phanerozoic rocks, especially in the Paleozoic of north and northwest Saudi Arabia.

Robert Wyns received his PhD degree in Tectonics from the University of Paris in 1980. He joined the Bureau de Recherches Gèologiques et Minières (BRGM) in 1981. He worked mainly on the Hercynian Belt in western France during the 1980s. He was involved in the geologic mapping program of the Sultanate of Oman between 1989 and 1992, and in geologic mapping in Saudi Arabia between 1992 and 1994. Robert has been in charge of research and development projects on surficial deposits characterization and mapping in France since 1995. He is a member of the French Geologic Society, and the Scientific Council of the French National Research Program.

Abdallah M.S. Memesh currently works as a Geologist at the BRGM Mapping Department. He received his BSc from the Faculty of Earth Sciences at King Abdul Aziz University in 1993. Since 1994, he has been involved in mapping projects of Phanerozoic rocks, especially in the Paleozoic strata of north and northwest Saudi Arabia.

The Upper Ordovician Glacial-Related Deposits in Northwestern Saudi Arabia: New Data

Dominique Janjou Bureau de Recherches Géologiques et Minières Mohammed A. Halawani Deputy Ministry for Mineral Resources, Jeddah Robert Wyns, Philippe Razin, Denis Vaslet Bureau de Recherches Géologiques et Minières and Abdallah M.S. Memesh Deputy Ministry for Mineral Resources, Jeddah

As a result of geologic mapping in the Tabuk Basin, the Late Ordovician glacial-related deposits were studied between Tabuk and Bayda Nathil, over a distance of 500 kilometers (km) from east to west. Rapid and frequent lateral changes in facies are recorded within the glacial-related deposits, as well as vertical repetition of facies in several sections, this spatial organization impedes the use of lithofacies for identifying distinctive different formations in the area.

In the eastern part of the Tabuk Basin (Bayda Nathil - Jabal Misma area), the Sarah Formation consists of four successive lithologic units bounded by major glacial surfaces, and lies unconformably over the Qasim and Saq formations. The first unit of the Sarah Formation that fills the incised paleovalleys consists of channelized fluviatile sandstone that locally mimics the Saq Formation and shows traction structures such as trough cross-bedding. This first sandy unit is bounded by a glaciated upper surface showing a typical “roches moutonnées” structures. Above this surface, the second unit consists of green siltstone, channelized sandstone, and “exotic” blocks of igneous rocks. It is eroded at the top by a second extended glacial surface. The third unit is represented by a massive unit of sandstone with huge water-escape structures, capped by a third discontinuous glacial surface. The fourth unit consists of fine-grained pink homogeneous sandstone-bearing few like-tigillites burrows. In that area, the topmost beds of the formation are probably cut by a Mesozoic erosional surface.

To the west, in the Tabuk area, Sarah Formation deposits fill narrow incised paleovalleys running north-south along more than 30 km. The filling material generally consists of “boulder-clays”-like siltstone at the base covered by massive units of turbiditc sandstone. This succession resembles the succession of Sarah and Zarqa formations as it is described in Central Arabia. However, northwest of Tabuk, we observed the superimposition and intersection of two successive incised paleovalleys, filled by similar lithologic sequence. Locally, dip-cavitation features occur below the Sarah Formation. Such “karst-type” features dug into the Qasim Formation and can reach a depth of 80 meters west of Tabuk. In the same area extended networks of clastic dykes (approximately 50 km long) cuts the Paleozoic substratum, the development of such structures is interpreted to be in relation with glacial-related environment and contemporary orientation of the regional field stress.

Dominique Janjou, Mohammed A. Halawani and Robert Wyns (see abstract “The Paleozoic Succession of the Tabuk Basin in Saudi Arabia: Lithostratigraphy, Sedimentology and Sequence Stratigraphy” on pages 104-105 for biographies and photographs)

Philippe Razin (see abstract “Sedimentology and Reservoir Geometry of the Late Permian Upper Gharif and Lower Khuff Formations in Interior Oman: Outcrop Study in the Haushi Area” on page 82 for biography and photograph)

Denis Vaslet is employed by the Bureau de Recherches Gèologiques et Minières. He is responsible for the cover rocks mapping project of the Saudi Arabian Directorate General for Mineral Resources. He has been involved in the complete litho-stratigraphic revision of the Phanerozoic rocks of Saudi Arabia, particularly the lower Paleozoic. Presently, Denis is currently in charge of the basic geology and geophysics department at the French Geological Survey which includes the program of geological mapping of France.

Abdallah M.S. Memesh (see abstract “The Paleozoic Succession of the Tabuk Basin in Saudi Arabia: Lithostratigraphy, Sedimentology and Sequence Stratigraphy” on page 105 for biography and photograph)

Sequence Stratigraphy and Computer Simulation of the Khuff Formation (Late Permian-Early Triassic), Saudi Arabia and Other Gulf Countries

Kurt W. Johnston, Christopher G. Kendall University of South Carolina and Ibrahim A. Al-Jallal Saudi Aramco

The Khuff Formation ranges in age from Late Artinskian through the Scythian and consists of carbonates, evaporites and minor clastic lithologies. These were deposited on a broad, shallow shelf and lithologic facies include siliciclastics, mixed evaporite carbonates and siliciclastics, restricted evaporitic carbonate shelf, shallow carbonate shelf, organic reefal and argillaceous deep marine carbonates. Sequence stratigraphy and a computer simulation were applied to interpret the Khuff Formation.

In Arabia, the formation is divided from base up into the siliciclastic Khuff E, and the carbonate/anhydrite Khuff D, C, B and A units. It contains eight third-order sequences, six of which contain relatively thick accumulations of anhydrite. Basal sequence boundaries are placed at the base of the anhydrite, which is interpreted to collect in lowstand systems tracts on the shelf. Not all of the sequences within the Khuff Formation have this basal lowstand anhydrite.

The Khuff sequences were simulated with Schutter’s chart (personal communication) to simulate the Permian portion, while the Triassic portion was simulated using the Haq et al. (1988) chart. Subsidence rates during simulation were kept constant, reflecting the uniformity of the sedimentology of the section for the 21 million years duration of deposition. Carbonate rates increased from zero centimeter/1,000 years at 300 meters, to 2 centimeters/1,000 years at 20 meters, to 12 centimeters/1,000 years at the surface. The Khuff Formation has limited biostratigraphic age control, but coupling these ages with a sea level curve provides a method for dating its sequences. These sequence dates were tested with the simulation and used to date the five informal members of the Khuff Formation. The simulation suggests that the Khuff E is contained within the Khuff D Member.

Kurt W. Johnston is currently a PhD candidate at the University of South Carolina. His research is focused on the Cretaceous sedimentary section of offshore South Africa. Kurt is currently interpreting the sequence stratigraphy of this area using seismic data supplied by Soekor. Kurt holds an MSc degree from Bayler University of Texas.

Christopher G. Kendall is Professor of Geology at the University of South Carolina. He has worked extensively in the oil industry and academia. His research interests and publications have concentrated on the Arabian Gulf. Starting his career in carbonate sedimentology and petrology, Christopher is interested in sedimentary simulations and sequence stratigraphy with numerous publications on these topics.

Ibrahim A. Al-Jallal has 17 years of experience in the oil industry in Saudi Aramco. His work experience varied from basic development geology to complex reservoir geological studies and predictions. His PhD thesis was on the Khuff Formation, its depositional environment, reservoir development, carbonate petro-physical characters with wireline logs and overall reservoir layering and characterization. Ibrahim recently extended his Khuff study to include the entire Arabian Plate to determine Khuff gas potential areas in the Gulf countries. Ibrahim is currently the Chief Geologist of Geological R&D at Saudi Aramco. Ibrahim is a member of the Advisory Board of GeoArabia.

Exploration Implications of Basin Modeling Studies on Known and Potential Source Rocks in the Rub’ Al-Khali, Saudi Arabia Using BasinFlow

Peter J. Jones, Henry I. Halpern, William J. Carrigan, Saudi Aramco Jay E. Leonard, Marshall W. Titus Platte River Associates Mohammad R. Al-Khadhrawi and Ibrahim A. Al-Ghamdi, Saudi Aramco

Major exploration and development efforts in the Rub’ Al-Khali of Saudi Arabia, have resulted in the need to revisit the historical database with current geochemical techniques. These efforts are directed towards developing new exploration play concepts, as well as, refining the existing ones. Within the area of interest, known productive intervals are found in the Lower Cretaceous and Jurassic. Potential and known source rocks in the area range from the Cretaceous to the Paleozoic in age. For example, the Safaniya Member of the Lower Cretaceous Wasia Formation is found to have intervals in excess of 100 feet with Total Organic Carbon (TOC) up to 9.6% and Hydrogen Indices (HIs) up to 500 mg HC/gTOC.

Recent advances in basin modeling software facilitate modeling in one, two and two and one-half dimensions (map view). This approach allows the explorationist to integrate basin modeling studies throughout the area of interest much more efficiently. These studies can then be used to formulate the hydrocarbon charge history of the basin. Basin models, in this study, were constructed using Platte River Associates’ BasinView and BasinFlow software.

This study integrates a variety of geochemical and geological data, in order to assess the source characteristics of various source rock candidates, as well as, the variation of thermal maturation history for various source intervals throughout time.

Peter J. Jones, Henry I. Halpern and William J. Carrigan (see abstract “Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates” on pages 79-80 for biographies and photographs)

Jay E. Leonard is President of Platte River Associates, Inc. He has over 25 years experience in computer technology, petroleum exploration, and technology transfer with extensive experience with the evaluation, development and utilization of petroleum industry software. He also has experience with database design and application, numerical basin modeling, and numerical and statistical techniques. After receiving his PhD from Boston University in 1976, he served on the faculty at Rensselaer Polytechnic Institute and Bryn Mawr College. Jay has worked for Amoco and Getty Oil. He was an Editor and regular Columnist for GeoByte magazine, served as Chairman of the AAPG Computer Applications Committee, has been a keynote speaker for several major petroleum industry functions, and has over 80 publications in refereed journals. He currently advises in technology issues for several oil companies.

Marshall W. Titus is a Senior Staff Geologist with Platte River Associates, Inc. He has 15 years of basin modeling and petroleum exploration experience. Before joining Platte River Associates in 1993, Marshall worked with Shell on hydrocarbon charge, basin modeling, and exploration projects in the Gulf of Mexico and North Alaska. He received a BSc degree in Geological Sciences from the University of Texas at Austin in 1979 and his MSc degree in Geology from the University of Houston in 1984. One-dimensional and multi-dimensional basin modeling as an application to hydrocarbon exploration remain his interest.

Mohammad R. Al-Khadhrawi (see abstract “Geochemical Evidence for Reservoir Compartmentalization in Central Arabian Paleozoic Reservoirs” on page 96 for biography and photograph)

Ibrahim A. Al-Ghamdi is an Exploration Geologist working with the Exploration Organization in Saudi Aramco since 1985. He has worked in area exploration, reservoir geology and wellsite, and in special projects including reservoir modeling with Exxon in 1989. Most of his work concentrated on carbonates of the Jurassic and the Cretaceous of Saudi Arabia. Ibrahim is interested in carbonates, sequence stratigraphy, artificial intelligence, geostatistics and field geology.

60th EAGE Conference &Technical Exhibition

8-12 June, 1998

For more information please contact:

EAGE Business Office

P.O.Box 298

3700 AG Zeist, The Netherlands

Tel: 31 30 696-2655; Fax: 31 30 696-2640

A Conceptual Model for Super Permeability in Uthmaniyah Field

Tom Keith, John C. Cole, Saudi Aramco Joerg E. Mattner, Sait I. Ozkaya and Kyle A. Waak, Western Atlas

The Ghawar field has been subject to a high flow phenomena known as “Super-K” since very early in its production history. The term was originally coined by geologists and engineers working in the field to describe extremely high flow confined to thin intervals usually on the order of 4 to 5 feet in thickness. A good working value for “Super-K” has been generally accepted as 500 barrel/foot/day. Initially, core studies and log data suggested a model in which a single, stratigraphically- controlled, facies was accountable for the vast majority of instances of extreme flow. Open fractures intersected by the wellbore were held responsible for the remaining cases. However, subsequent studies revealed more diversity in the stratigraphy, lithology, and flow characteristics of the so-called “Super-K” facies than a purely stratigraphic explanation could reasonably account for.

A conceptual model for “Super-K” is proposed in which the original stratigraphic model is integrated with a more pervasive vertical fracture system to explain the observed diversity. Recent 3-D seismic and image logging results are presented in support of the model and the potential impact of the model on other aspects of reservoir characterization and management is discussed.

Recent image logging results in the Ghawar field supports a more significant role for fractures than had previously been suspected. Although a quantitative definition of the term has been put forth in a number of previous articles, its actual occurrence is probably best described in qualitative terms. Its primary characteristic is simply confined flow usually accounting for upwards of 60% of total fluid production within a few feet. The origin of the flow and the geometry of the structures responsible play an important role both in the short-term goal of designing water shut-off procedures to prevent premature breakthrough and in the planning of longer range drainage strategies.

Previous models put forth to explain this behavior have been based on stratigraphic distribution of high permeability dolomites and oolitic grainstones with fractures responsible for only a small percentage of high flow zones. Although this serves to explain the wellbore characteristics of a high percentage of zones correlating with high flow, core description and log data suggests that there is sufficient diversity in both the lithology and stratigraphy of “Super-K” to bring a two-dimensional explanation into doubt. This is especially true when the lack of areal correllatability of “Super-K” is considered. Nor, do they explain the lack of consistency in “Super-K” facies when the total body of data is examined. Core studies have indicated that there are several lithotypes which exhibit extreme flow behavior.

Closer examination of core data reveals that although these lithologies are present in many of the “Super-K” zones, the majority of occurrences of these lithologies do not exhibit extreme flow behavior and that in fact there are a wide range of rocktypes which, although permeable, are genetically unrelated to the oolitic grainstones and are not dolomitized.

Tom Keith received his BSc degree in Geology from the University of Texas at Austin in 1976. He has worked with Saudi Aramco since 1980 and has spent most of the time on reservoir geology and geocellular modeling in all of Saudi Aramco’s eastern area fields. His most recent efforts have been concerned with the impact of fractures on fluid flow in the Ghawar Field.

John C. Cole has been with Saudi Aramco since 1991 where he is Production Geologist specializing in 3-D modeling and reservoir characterization. Between 1980 and 1986, John was with Texaco and then joined BP International. He has worked in the North Sea, North Africa and the Far East. He obtained a BSc in Geology in 1979 and an MSc in Structural Geology in 1980 from Imperial College, London. He is a member of CSPG, the AAPG and APEGGA. John is particularly interested in reservoir characterization of carbonates.

Joerg E. Mattner and Sait I. Ozkaya (see abstract “Integrating Fluid Flow and Borehole Imaging Data in Fracture Characterization, Hanifa Reservoir, Abqaiq Field, Saudi Arabia” on page 44for biographies and photographs)

Kyle A. Waak is a Senior Log Analyst with Western Atlas Logging Services in Saudi Arabia where his primary responsibilities are interpretation of borehole imaging and magnetic resonance logs. He has held various engineering, sales, management and log analyst positions throughout his career with Western Atlas in West Texas/Southeast New Mexico, the Rocky Mountains and Venezuela. Kyle holds a BSc degree in Petroleum Engineering from Texas A&M University and is a member of the SPE and SPWLA.

Sedimentologic and Sequence Stratigraphic Framework of the Shu’aiba Reservoir, Idd el Shargi North Dome, Qatar

Charles Kerans Bureau of Economic Geology The University of Texas at Austin

The Aptian (Cretaceous) Shu’aiba reservoir at Idd el Shargi North Dome (ISND) was developed as a localized area of shoal-water facies on top of a salt-rooted deep structure on the Shu’aiba deep ramp. The stratigraphic model for the Shu’aiba reservoir at ISND developed here differs from many of the other Shu’aiba fields because it emphasizes depositionally controlled rock fabric changes rather than diagenetic leaching at the post-Shu’aiba unconformity as a primary control on reservoir quality. The integration of modern sequence stratigraphic techniques of cycle hierarchy definition and stacking pattern analysis, coupled with a regional paleogeographic model, demonstrates the evolution of ISND from a sub-storm wave base deep ramp accumulation to an asymmetric shoal with distinct windward-leeward facies control at or just above fair-weather wave-base.

The Shu’aiba at ISND together with the Hawar shale represents one long-term (3rd-order?) 400-foot thick composite sequence that can be subdivided into four (Shu’aiba D lowest, Shu’aiba A highest) symmetrical high-frequency sequences (HFS) that in turn are composed of small-scale high-frequency cycles. The Shu’aiba is dominated by mud-dominated rock-fabric facies with minor Orbitolina of deep ramp origin. Maximum flooding surfaces of the high-frequency sequences and selected cycle-base flooding surfaces define the main vertical heterogeneities in this reservoir and should be preserved in any layering scheme that attempts to accurately represent fluid flow.

The upper portion of the Shu’aiba B HFS and the entire Shu’aiba A HFS comprise the main reservoir interval at ISND, the lower units being either in the water leg or of too low a reservoir quality. Detailed correlation of individual high-frequency cycles throughout the field using logs and facies descriptions from 15 cored wells allowed documentation of the last stages of evolution of this depositional structure. During deposition of upper ‘B’ cycles a general northwest to southeast thinning and deepening of facies indicates minor syndepositional tilting to the northwest. Southeast tilting coupled with aggradation into fair-weather wave base during deposition of the ‘A’ resulted in deposition of a shoal complex with a northwestern windward coral-rich rim and dasyclad-Orbitolina grain-rich cap that controls improved reservoir quality. Onlap by Bab facies shows no clear evidence of subaerial exposure or meteoric leaching.

Charles Kerans is a Senior Research Scientist at the Bureau of Economic Geology, the University of Texas at Austin where he has worked since 1985. Charles received his BSc degree in Geology from St. Lawrence University in 1977 and PhD degree in Geology from Carleton University in Ottawa, Canada in 1982. He served as a Senior Research Fellow in Western Australia between 1982 and 1985 during which time he worked on Devonian reef complexes of the Canning Basin. In 1985 Charles joined the Bureau of Economic Geology’s University Lands Reservoir Characterization Program, focusing on Ellenburger and San Andres units of the Permian Basin. From 1988 to 1991 he helped initiate and directed the Bureau’s San Andres/Grayburg Reservoir Characterization Research Laboratory (RCRL) and is currently a Senior Research Scientist on the RCRL staff. His research emphasis is on integrated reservoir characterization studies that utilize a sequence stratigraphic framework. Currently, research is focused on developing advanced sequence stratigraphic models for Cretaceous carbonate reservoir strata using outcrop data from Texas and subsurface data from the Middle East. Charles has received several awards for best paper since 1988.

Origin of Limestone-Black Shales Bedding of Lower Carboniferous Limestone from Semnan Area, Central Alborz, North Iran

Kaveh Khaksar Geological Survey of Iran

The Lower Carboniferous (Tournaisian) marine strata in the Semnan area (eastern part of Central Alborz) consist of limestone with black shale interbeds. The limestone-shale interbeds occur in a cyclic pattern. In the measured sequence, the limestone beds have an average thickness of 30-40 centimeters and the black shale layers 10-20 centimeters. The maximum thickness measured is 58 centimeters. The regular alternation of limestone with black shale could have formed from a uniform primary sediment.

The mechanism responsible for the cyclical interruptions of limestone are most likely related to climate. This, in turn, is influenced by the Earth’s orbital perturbation through fluctuations in the volume of polar ice, probably the immediate cause of these sedimentary cycles. Depositional rates indicate that the bundles represent about 19,000 to 23,000 years, corresponding to short precessional cycle.

Kaveh Khaksar received his MSc degree in Geology from the University of Palermo, Italy in 1989 and PhD degree in Geology from the University of Granada, Spain in 1994. Kaveh is a member of the Scientific Board and Head of Scientific Communication and Scientific Services Office of Soil Conservation and Watershed Management Research Center and Expert of Geological Survey of Iran. He has published more than 10 research papers and scientific reports.

Carbonate Faciolog from Basic Openhole Logs

Anwar S. Khalaf Bahrain National Oil Company

Defining carbonate facies from wireline logs has always been a very difficult task to achieve. This paper proposes an easy approach for mapping the carbonate facies from the most basic openhole logs, the Dual Lateralog and the neutron-density logs.

The conceptual modeling on which the methodology was developed is based on the fact that the various carbonate facies will have different responses when logged by the DLL-MSFL tool. Furthermore, these facies will have different invasion profiles that would facilitate the task of mapping them.

Within each facies the relationship between porosity and permeability is directly proportional. In other words the definition of the various facies from the wireline logs will make the task of converting the log porosities into effective permeability values relatively easy. The successful application of the technique for characterizing the most permeable facies in the Khuff Formation was completed and the results were validated against the production profiles as measured by the Production Logging Tool. The match between the two sets of results is excellent.

Anwar S. Khalaf is Manager of Exploration and Development at the Bahrain National Oil Company. Anwar graduated from Kuwait University with a BSc degree in Geology in 1976.

New Insights to the Holocene Carbonate-Evaporite Environments of Abu Dhabi

Anthony Kirkham Reservoir Characterization, Research & Consulting, Inc.

Easier access to most parts of the Abu Dhabi coastline, combined with satellite imagery, has enabled a more detailed examination of the Holocene strata than was possible twenty or thirty years ago when the area was recognised as a key to understanding ancient, shallow marine, carbonate-evaporite environments. Whilst the basic principles of coastal progradations documented in those early days are still valid, they portrayed an oversimplified picture of the Holocene coastal geomorphology and sabkha sedimentology. New data re-emphasises the importance of Miocene and Pleistocene strata in forming antecedant topography which imposed depositional complexity on the Holocene system. Former Holocene shorelines can now be mapped with greater clarity and reveal its highly embayed nature. The Holocene transgressive limits are locally re-defined. Some palaeo-highs, that formed earlier Holocene peninsulas, have been completely removed by aeolian deflation. Contrary to what is commonly perceived from the literature, sabkha anhydrite does not occur as a continuous, widespread horizon. Difficulties that many geologists have experienced in locating anhydrite are largely due to there having been two distinct phases, but their distributions are now largely predictable by remote sensing. The later phase has historically formed a basis of idealised progradational “sabkha cycles” and is indeed regressive, but the earlier and more abundant anhydrite is transgressive and compels geologists to more carefully consider depositional models involving peritidal evaporites. Relative sea level changes and aeolian deflation have combined to impose a very high degree of complexity which would be difficult to understand in such a thin stratigraphic interval in the subsurface. Apart from the world-renowned tidal oolite deltas formed seaward of the ebb tidal channels between barrier islands, Holocene tidal embayments also provided potential for oolite development such as adjacent to the definitive “Evans line” near Abu Dhabi Island. A present day, analogous oolith factory is described from a tidal embayment in western Abu Dhabi.

Anthony Kirkham (see paper “Pleistocene Carbonate Seif Dunes and their Role in the Development of Complex Past and Present Coastlines of the U.A.E.” on page 32 for biography and photograph)

The Permo-Carboniferous Glaciogenics (Al Khlata Formation) of Oman: A Fresh Look at an Old Problem

Richard Knight and Christel Hartkamp-Bakker Petroleum Development Oman

One of the key challenges that has faced oil exploration and production from the Permo-Carboniferous glacial deposits (Al Khlata Formation) in South Oman, has been uncertainties associated with the distribution, evolution and stratigraphy of the Al Khlata Formation through time. A recent study, based on a network of 26 basin-wide correlation panels, has attempted to address such issues. Biostratigraphical data have proved the critical element to unraveling this unit: at present the sequence is divisible into 3 broad subunits (P9, P5 and the youngest P1), based on palynology.

The oldest (P9) Al Khlata sequences clearly reflect a phase of rapid sedimentation and high accommodation in South Oman. The P9 unit is Late Carboniferous in age, and can exceed 100s of meters in total thickness. Climatically, this was a period of (in part) extremely dry, cool conditions. The P9 landscape was highly irregular, with immense contrasts in relief (‘U-shaped valleys’). These were probably formed through an interplay of glacial erosion, salt dissolution/withdrawal and accentuated by rifting in the Neotethys. Sedimentologically, P9 sequences are characterised by fluvial, deltaic, and minor glaciogenic phases in deposition. Stacked outwash braidplain deposits (‘valley trains’) are prominent, regionally extensive features, and tend to occur towards the latter part of this period. These braidplain deposits herald the dawn of a major period of ice advance.

By Latest Carboniferous/Early Permian times (P5), the topographic variation across South Oman was markedly diminished. The P5 period was one of extensive ice action, as evidenced by widespread, cannibalised glaciogenics, and areas missing appreciable stratigraphy. Available floral data suggests that, at times, this was a relatively warm period, with high moisture levels. These observations probably relate to warmer interglacials. P5 sequences tend to be thin (<50-100 meters), highly sporadic in their occurrence and very difficult to correlate. Besides glaciogenics, localised aggradational fluvial stacks and delta systems occur intermittently.

Towards the end of the Al Khlata deposition (P1) in Early Permian (Asselian/Sakmarian) times, the South Oman landscape was presumed to be virtually a level peneplain. Localised deltas and isolated fluvial systems signified the final demise of ice activity in Oman. The latter is defined by a widespread, blanketing diamictite, which tends to directly underlie two regionally extensive, freshwater ‘Rahab’ lake systems. The oldest lake covered virtually all of South Oman (at least 340 by 150 kilometers), and reflects the major base-level rise associated with pronounced melting of any remnant ice caps/sheets. Good analogues for these lake systems can be found preserved in Quaternary sediments from Scandinavia and North America. The youngest lake system was more fragmented, and developed into four localised depocentres (centred on Bahja, Mukhaizna, Nimr and Dhiab). Overall the climate was warming up dramatically (reflected in the establishment of a cycad-prone land flora), prior to deposition of the overlying Gharif Formation.

As a consequence of this study, there is a better understanding of the genetic relationships and evolution of the Al Khlata deposits in this region. This has allowed areas to be risked and exploration initiatives/resources aligned accordingly.

Richard Knight graduated with a PhD in Palynology from Southampton University in 1990. On joining Shell that year, he was assigned to the Stratigraphy Section based in The Hague. In 1993 Richard joined Petroleum Development Oman as an Operations Geologist, and moved a year later to head Exploration’s Palynology/Ops Geochemistry Unit. He is now an Interpreter in North Oman’s Frontier Gas Team.

Christel Hartkamp-Bakker (see abstract “The Karim Oilplay: Cambrian Alluvial-Lacustrine Deposits in South-Central Oman” on page 97 for biography and photograph)

The Challenge of South Oman’s Athel Silicilyte

Stuart D. Lake, Pascal D. Richard, Muatsam Al-Raisi and Hannat Al-Hinai Petroleum Development Oman

The Late Proterozoic, Early Paleozoic rift basins of South Oman are filled with thick syn-rift salts. A Cambrian petroliferous rock has been found within these salt sequences: the Athel silicilyte. It is both a source rock and a reservoir, and this unusual combination, combined with the intra-salt setting, introduces significant challenges. The large number of prospects and large proven in-place volumes have the potential to significantly impact Oman’s hydrocarbon resource base (both for oil and gas).

Thick tight water-bearing petroliferous source rocks within the Ara Group have been recognized since 1972 (Amal-1) along the shallow Eastern Flank of South Oman where the salt seal has been removed by salt dissolution, however its reservoir potential was not recognized until 1989 when the first Athel silicilyte oil discovery was made within the South Oman Salt Basin at Al Noor-1 fully encased in salt and overpressured. The promising, but low rates (44m3/d) of 48° API volatile sour oil led to further appraisal. After establishing a stable oil rate of 100 m3/d (GOR 300 m3/m3 and 1.5% H2S in gas) from a recompletion on Al Noor-2 (late 1994) 15 million m3 oil reserves were considered proven with significant untested upside potential. Subsequent appraisal wells and testing gave further encouragement to assess the potential of this new play through an aggressive 15-well exploration and appraisal campaign.

The reservoir is composed of an interbedded sequence of porous and non-porous (irregularly laminated micro-crystalline silica and dolomitic cemented) silicilyte with an average layer thickness which is smaller than 1 meter.The average micro porosity is some 22 pu but the permeabilities are very low, in the order of tens of micro Darcy. Given these thicknessess/reservoir properties and the absence of any reservoir analogues, extensive use of borehole imaging logs is made to unravel the reservoir sequences. Geochemical analyses have established the Athel silicilyte as a world class source rock; it is probably the source for much of South Oman’s oil. The entire unit is self-charged, being encased within thick Cambrian salt and lying at depths between 2,500 and 5,000 meters. In areas where the salt seal has been breached, the Athel oils have migrated to shallower and younger rock formations.

Seismic data over much of South Oman was historically insufficient to map out intra-salt reflectivity or indeed even to map top salt with any confidence. The combination of gravity data and long-cable seismic data (up to 10 kilometers) to improve imaging at depth led to the identification of numerous intra-salt leads. The initial calibration of these leads was based upon their look-alike nature to Al Noor, however the subsequent exploration campaign has shown that this alone is not sufficient especially in areas in close proximity to carbonate platforms, areas of intense intra-salt imbriction or Western Margin sourced intra-salt clastics.

Regional geological data initially indicated that the silicilyte facies of the Athel Formation was widespread in its distribution. It was then believed that apart from the basin margin and a broad trend along the Birba High, where carbonate facies appear to occur, that much of the rest of the salt basin may contain rafts or slabs of silicilyte. The drilling campaign has shown that contrary to the original perception, the Athel is neither uniform nor regional in extent. Well data also make the complexity of the reservoir apparent, both from a static and a dynamic perspective. Patchy occurrences, variable thickness and associated lithofacies, in combination with new seismic data, indicate that the Athel silicilyte could have been deposited in narrow northeast-southwest trending half-grabens (mini-basins) within an active Cambrian rift system. These basins were controlled by reactivated basement faults which influenced both intra-salt sedimentation and subsequent halokinesis. These former mini-basins (now positive “inverted” highs) are locally modified by halokinetic processes. This structural interpretation is confirmed and can be replicated by scaled sandbox experiments and finite element modelling studies. The recognition of these “inverted” structures have allowed the operator to plan seismic campaigns and to target wells more effectively. Since 1989, Athel Silicilyte has now been identified in 5 separate structures, of which three have significant hydrocarbon columns >200 meters (Al Noor 1, 2, 4, 5, 6; Al Shomou 1, 2, 3 and Marmul NW-7). Presently a Phase one pilot project is underway on the Al Noor field by drilling a series of development wells and a 1,500 m3/day surface facility.

However the Athel silicilyte still carries significant risks and technological challenges, including the need to improve sesimic data quality, find better reservoir, reduce costs and achieve a breakthrough in reservoir productivity, the new model and new ideas being generated go a considerable way to reduce the risks and to assess more fully the ultimate potential of the Athel.

Stuart D. Lake obtained his PhD in Geology from Durham University in 1985. Stuart joined Shell in 1986 as a Geologist and served in various assignments as a Geologist, Seismic Interpreter and Team Leader with Shell companies in The Netherlands, USA, United Kingdom and Egypt before joining Petroleum Development Oman in 1993 as Team Leader Regional Studies. Stuart then joined the Frontier South Exploration Team as the Athel Theme Coordinator in 1996. He has recently become Team Leader for the North Netherlands Gas Team in the NAM. Stuart is a member of the AAPG and PESGB and has published more than 10 technical papers on basin inversion, remote sensing, thermo-mechanical modeling, field and petroleum geology.

Pascal D. Richard (see abstract “Integrated Haushi Hydrocarbon Habitat Study in North Oman” on page 147 for biography and photograph)

Muatasam Al-Raisi obtained his BSc in 1991 from Penn State University, USA. Muatasam joined Petroleum Development Oman in 1991 as Exploration Geologist before he obtained an MSc in Geological Sciences from the Colorado School of Mines in 1994. Muatasam is currently working as an Exploration Geologist with the Frontier South Exploration Team. Muatasam has published papers on Sedimentary Geology.

Hannat Al-Hinai received his BSc in Geophysics in 1988 from the University of Tulsa, and obtained his MSc in Petroleum Geology from Oxford Brookes University in 1994. Hannat worked as Seismic Processor for Petroleum Development Oman from 1989 to 1993. He is currently working with the Frontier South Exploration Team as a Seismic Interpreter.

Inverse Stratigraphic Model for the Carbonate Production Estimation-Application to an Oman Outcrop

Saiida Lazaar, Gregory Blokkeel, Didier Granjeon and Dominique Guérillot Institut Français du Pétrole

This study is devoted to the numerical inversion of stratigraphic model parameters. Our principal goal is to identify the model parameters, such as the sediment supply (carbonate production) and the transport coefficients which control the way sediments are eroded, transported and deposited throughout the sedimentary basin. These parameters are related to a forward 3-D multi-lithologic stratigraphic model. Our numerical study allows us to match the real well data from the Oman carbonate platform.

This work presents a semi-automatic inversion method which is an extension of the one presented at GEO’96 and in GeoArabia, ‘Three-Dimensional Carbonate and Siliciclastic Forward Modeling’, v. 1, p. 144, 1996 where the identification of the carbonate production was realized via a trial-and-error method.

To illustrate the method, this study will involve numerical results of the forward and the inverse model in a mono-lithological case. The inverse model corresponds to optimization techniques using a gradient descent method which minimizes the difference between model predictions and observations.

Saiida Lazaar joined the Geology and Geochemistry Research Department of Institut Français du Pétrole after completing her PhD. Her research interests are numerical analysis, sedimentary basin modeling, inverse methods, turbulence, fluid mechanics and the design and implementation of wavelet fast algorithms for solving some numerical problems. Saiida holds a PhD in Applied Mathematics from the University of Provence, France.

Gregory Blokkeel is working on his MSc degree in Applied Mathematics and Mechanics at Bordeaux University, France. His research interests are applied mathematics and combustion.

Didier Granjeon is a Geologist in the Production Geology Group at Institut Français du Pétrole. He holds a Civil Engineer’s degree in Geology from Ecole des Mines de Paris and a PhD in Geology from Rennes University, France. His research interests are in the geosciences and deterministic approach applied to 3-D basin modeling.

Dominique Guérillot holds a PhD in Applied Mathematics from the University of Provence. He joined Institut Français du Pétrole (IFP) in 1982 where he worked with the Reservoir Characterization Team. He then became Project Manager for “Fluid Flow in Heterogeneous Reservoir”. Dominique is currently the Director of the Geology and Geochemistry Research Department at IFP. His areas of professional interest are in applied mathematics and physics, modeling in geoscience, reservoir engineering and characterization, fluid flow in heterogeneous porous media, numerical simulation, up-scaling and inversion methods, and software development.

Interpreting Regional Seismic Amplitudes in a Central Saudi Arabian Sandstone Reservoir

Jia J. Lee, Ahmed M. Al-Otaibi, Maher I. Al-Marhoon and Daniel S. Evans Saudi Aramco

A relatively shallow sandstone oil reservoir was recently discovered in Central Saudi Arabia. Regional seismic amplitudes mapped through the reservoir from 3-D RAP stack data volume were found to be characterized by large amplitude variations and trains of high amplitude pockets.

Exploratory drilling based on amplitude bright spots showed some initial success. However, results of further drilling found little correlation between the high amplitude zones and hydrocarbon accumulation. A study through seismic modeling and inversion was carried out to investigate the occurrence of high amplitude anomalies and their implications for hydrocarbon potential in the area. While porosity was shown to be the dominant factor for amplitude behaviors, it takes combined effects from porosity, tuning and the fluids to create the observed high amplitudes. Modeling of seismic amplitude in zones with known porosity was shown to provide indications of optimally tuned sand thickness, hence presence of potential reservoir-quality sands in the area. The modeling results were also compared with observations inferred from inversion study. Pre-stack amplitude analysis as a function of offset, along with other attribute analyses, were also examined but were found less diagnostic for amplitude patterns in the study area.

Jia J. Lee is currently Geophysical Specialist with the Geophysical Department of Saudi Aramco. He is involved with special seismic processing and integrated studies of exploration problems. Prior to joining Saudi Aramco in 1992, Jia was with ARCO for nine years engaged in seismic exploration and development on worldwide prospects. He received his MSc in Geophysics from Columbia University and a PhD from Penn State University.

Ahmed M. Al-Otaibi (see abstract “Recent Discovery Confirms Stratigrahic Trap Potential in the Permian Unayzah Formation of Central Saudi Arabia” on page 92 for biography and photograph)

Maher I. Al-Marhoon (see abstract “Application of Multi-Seismic Attributes in Estimating Reservoir Properties” on page 52 for biography and photograph)

Daniel S. Evans (see abstract “Recent Discovery Confirms Stratigrahic Trap Potential in the Permian Unayzah Formation of Central Saudi Arabia” on page 92 for biography and photograph)

Integrated Borehole Image Analysis as Input to 3-D Modeling

Xavier Y.A. LeVarlet, Peter Audretsch and Stuart K. Arnott Petroleum Development Oman

Approximately half of all the oil produced in the Bahja-Rima area of Central Oman (25,000 m3/d from 33 fields) is derived from glacial and fluvial Al Khlata and Gharif reservoirs of Permo-Carboniferous age. Field development strategies depend heavily on reservoir type and associated facies. 3-D geological modeling studies are currently underway for several large fields in order to improve our understanding of reservoir architecture and uncertainties. It is planned to extend these studies to cover all fields in the area.

Characterization of depositional facies from conventional log data, which is one of the key issues to enable the construction of robust 3-D geological models, remains a challenge. An integrated regional study has been carried out to improve our regional depositional facies model for the Gharif reservoir. This has involved interpretation of all Gharif borehole images (approximately 25 wells), description of all Gharif cores (1,350 meters) in the area, and the search for appropriate outcrop analogues. The Al Khlata study is currently more limited to borehole image interpretation calibrated with core data. This paper summarizes the results of the borehole image analysis study carried out by Petroleum Development Oman (PDO), Schlumberger and Western Atlas in 1997.

A step-by-step approach is used to identify and interpret structural dip, lithology, ‘borehole image lithofacies’ and ‘tentative borehole image facies’ from high resolution image data. Lithological description is derived from conventional open hole log data using a multivariate histogram technique. The lithological boundaries are adjusted against the high resolution image data. Bedding planes are interactively picked from the geological workstation image, allowing identification of structural dip, irregular lamination, soft sediment deformation, foresets, set boundaries and bed boundaries. Both lithological description and bedding information is used to derive the ‘borehole image lithofacies’. Tentative ‘borehole image facies’ (i.e. channels, crevasse splays, sheetfloods, etc.) are then identified using criteria proposed by the PDO geologists based on calibration with core interpretation.

Results of the study comprise interpreted genetic reservoir elements with paleo-current indications for use in 3-D geological modeling, structural dip for structural mapping and quantification of the present day horizontal in situ stress for reservoir fraccing. Future work includes further integration of core and outcrop studies to refine the criteria used in depositional facies interpretation and to provide a better interpretation of paleo-current indications. In addition a neural network approach may also result in a more reliable interpretation.

Acknowledgments: The authors would like to thank H. Koelemij (PDO), O. Schoenicke (Schlumberger), J. Mattner, I. Ritters and L. Qobi (Western Atlas), K. Higgs and J. Thompson (Robertson) for their contribution.

Xavier Y.A. LeVarlet is a graduate of the Ecole Nationale Supérieure du Pétrole et du Moteur (Institut Français du Pétrole) in Rueil Malmaison, France. He joined Shell as a Production Geologist in 1994. Following an initial assignment in Oman Xavier spent two years at KSEPL before joining the Production Geology Section of NAM’s Business Unit Oil in 1991. He was posted back to Petroleum Development Oman in 1996 as a Production Geologist in Central Oman with an active participation in 3-D geological reservoir modeling studies.

Peter Audretsch received a BSc in Geology from the University of Calgary, Canada in 1982. Between 1982 and 1992 he worked as an Exploration Geologist for Petro-Canada working on Western Canadian and International ventures. In 1992 Peter joined Shell International and was posted to Petroleum Development Oman in Exploration. Peter is currently Production Geology Section Head in the Bahja-Rima area Development team.

Stuart K. Arnott is currently a Production Geologist with Petroleum Development Oman, working mainly on 3-D modeling of fluvial Gharif reservoirs. He previously worked for Shell in Holland and Britoil in the U.K. Stuart holds a BSc in Physics/Geology from the University of Glasgow and a PhD in Seismology from the University of Durham.

Runib Field: A Fit-for-Purpose, Integrated 3-D Static and Dynamic Modeling Study

Xavier Y.A. LeVarlet, Joniek I. Hage and Patrick van Daele Petroleum Development Oman

The Runib field in Central Oman has produced 3 million m3 of oil from the glacial and fluvial Haima and Al Khlata reservoirs of Palaeozoic age. Current net oil production is 1,300 m3/day at 82% BSW mainly from horizontal wells. The estimated field STOIIP is 30 million m3. The oil is viscous (20° API) and is produced by a strong bottom/edge water drive. Booked ultimate recovery is 6 million m3. An integrated study has been carried out with the aim of optimising the field development strategy and maturing additional reserves.

A detailed 3-D reservoir geological model of the Haima and Al Khlata formations at Runib field was constructed using GEOCAP Shell software. The latest seismic interpretation and petrophysical data were used in the study. The 3-D reservoir models consist of complex geometries of Al Khlata-filled valleys and Haima pods. The 3-D models were used to assess the distribution of reservoir properties within the flow units and to prepare input data for the reservoir simulation study. Although the full range of geological uncertainties was investigated, at the end only the most likely model was provided for the dynamic modeling.

The static geological model was upscaled and transferred into the dynamic model using Shell’s proprietary Reduce and MoReS software. Full field and key single well history matches were obtained to provide confidence in the simulation model. Only modest modifications to the geological model were required. The dynamic model was then used to evaluate the evolution of Equivalent Oil Column with time, which in a heavy oil environment with bottom water drive, is used to plan development and infill wells. Furthermore, the model was used to assess the best development strategy to arrive at the most favorable economics.

The main results of the integrated study are: (1) the 3-D geological model results in a better understanding of 3-D geometry of flow units and the reservoir property distribution within the flow units; (2) the main geological uncertainties were evaluated; (3) a more economical field development strategy has been generated; and (4) reserves have been matured.

Acknowledgments: Authors would like to thank D. Adenuga and A. Al-Shamaki for their contribution.

Xavier Y.A. LeVarlet (see abstract “ Integrated Borehole Image Analysis as Input to 3-D Modeling” on this page for biography and photograph)

Joniek I. Hage obtained a MSc degree in Physics from the Free University of Amsterdam and a PhD in Natural Sciences from the University of Leiden. He joined Shell in 1991 to work in KSEPL in drilling engineering research for two years, improving kick detection systems. Joniek then moved to reservoir engineering to work on improved recovery processes in naturally fractured reservoirs. He was posted to Petroleum Development Oman in January 1997 as a Reservoir Engineer of the Bahja/Rima area where he is currently responsible for the development and operational reservoir engineering aspects of fields with a widely varying range of properties.

Patrick van Daele obtained an MSc in Geology from the University of Louvain, Belgium, on the subject of clay mineralogy. He joined Shell in 1993 and has since been working in Bangladesh, Tanzania, Oman and Nigeria in the Exploration and Production function as a Geologist and Seismic Interpreter. He is currently the Senior Production Seismologist in Petroleum Development Oman, looking after acquisition, processing and interpretation of 3-D projects in South Oman.

The 3-D Megagrid in PDO: A 3-D Data Management Concept for Seismic Processing, Workstation Support and Interpretation

Maarten Ligtendag Petroleum Development Oman and Luppo Kuilman Saga Petroleum (previously Shell International)

The concession of Petroleum Development Oman (PDO) is covered with some 30,000 square kilometers of 3-D seismic data, consisting of some 90 individual surveys, acquired and processed since 1984. With the 3-D coverage rapidly growing, more and more continuous coverage over large parts of the PDO concession was established. Traditionally, surveys were processed on a survey by survey basis, each with their own seismic datum, incorporating some data of neighboring surveys wherever possible. This approach resulted in patchwork of, often overlapping, stand-alone 3-D projects all with different datums, amplitude normalizations and processing histories (reflecting the continuous improvements made over the last 13 years in 3-D processing and acquisition technology).

PDO strongly believes in the value of large integrated interpretation projects and the information that can be gained by using them. The commitment to follow up on this strategy can be illustrated by the most recent major project (3-D MEGA Project) from the processing department addressing PDO’s 3-D database as described above.

As part of the 3-D MEGA Project all individual seismic surveys acquired to date in the PDO concession area have been merged. Processing issues addressed were: redatuming of the seismic data according to the two new standard seismic datums defined for North and South Oman (replacing the 15 different datums previously in use), amplitude normalization between the various 3-D surveys, and phase correction (all data is now zero-phase). The concession area has been split-up into four separate MEGA 3-D-grids according to the dominant acquisition direction. Within each MEGA a consistent inline and crossline numbering is used and the data is stored in cubes of 10 by 10 kilometers. Processing of newly acquired seismic will follow the same procedures, meaning that it will be easy to build up new even bigger MEGA projects as new data becomes available.

The seismic data of the Megacells is on-line available on a high density mass data storage system, and thus facilitates fast data loading and efficient project definition and project management on the interpretation workstations.

This poster elaborates further on some practical aspects of the Megagrid concept, and highlights several benefits of such an approach for processing, workstation support and seismic interpretation.

Maarten Ligtendag graduated in 1988 in Applied Geophysics from the Faculty of Mining Engineering at Delft University of Technology. He joined Shell International in 1989 and worked as a Seismic Processing Geophysicist at Shell Expro, London until 1993. After a one year posting to Shell Australia working in seismic data processing, Maarten was transferred to Petroleum Development Oman to take up the position as a Seismic Processing Controller.

Luppo Kuilman (see abstract “The Karim Oilplay: Cambrian Alluvial-Lacustrine Deposits in South-Central Oman” on page 97 for biography)

Geostatistical Porosity and Permeability Modeling Using 3-D Seismic and Log Data, A Carbonate Reservoir Example

Tien-when Lo, Chris W. Grant RC Squared Consulting Bill Keyser and Thomas Chen Texaco Inc.

The objective of this project is to assess the risk of drilling a series of horizontal wells by building and analyzing log scale (1-foot resolution) 3-D porosity and permeability models constrained by 3-D seismic data and log data.

Porosity and permeability models were built with the following steps: (1) Generate high resolution 3-D impedance model with stochastic seismic inversion. The stochastic seismic inversion algorithm used in this project is a full waveform stochastic inversion. It uses sonic and density logs as hard data and 3-D seismic data as soft data. Instead of using a finite number of seismic attributes to guide the inversion, it builds an impedance model that will recreate the full 3-D seismic data. Since this algorithm honors the full waveform, it theoretically honors all the seismic attributes. (2) Generate high-resolution porosity models with co-located cokriging, using porosity logs as hard data and the impedance model generated in the previous step as soft data. Because the correlation between porosity and impedance varies within the field, this project used a correlation coefficient map, instead of a single correlation coefficient. (3) Convert porosity models to permeability models with “cloud transform”. This cloud transform is based on a cross-plot between core permeability and log porosity.

After building a series of equally probable porosity and permeability models, the risk of drilling certain wells can be assessed. The drilling engineers specified certain drilling constraints and defined several well trajectory criteria. A series of virtual wells were “drilled” through the porosity and permeability models. Each virtual well is then ranked based on the pre-defined well trajectory criteria.

The predictions made by these virtual wells were shortly confirmed by real wells. This accurate prediction is probably due to the fact that the high-resolution porosity and permeability models are realistic, and they reflect true reservoir heterogeneities.

Tien-when Lo is Manager of Seismic Applications with RC Squared Consulting. He received his PhD in Geophysics from Massachusetts Institute of Technology in 1988. From 1988 to 1996, he was with Texaco Exploration and Production Technology Department. He joined RC Squared Consulting in 1997. His principal interests are seismic inversion, stochastic reservoir modeling, and reservoir management.

Chris W. Grant has been a Research Geologist with Chevron and has been involved in the fields of stratigraphy and geostatistics. He received a BSc in 1985 from California State University and an MSc from Long Beach State University in 1991 in Geology. Chris was the recipient for the Outstanding Thesis award in the School of Physical Sciences in 1991. He is interested in areas such as Quantitative Reservoir Modeling and Sedimentation and teaches Chevron’s basic and intermediate Geostatistics courses.

Bill Keyser and Thomas Chen - biographies and photographs are unavailable.

Sonic Data While Drilling Increases Drilling Precision

Richard Logan and Ron Deady Halliburton Energy Services

Technology has recently been developed in logging while drilling (LWD) that provides a significant new aid to geological steering during drilling. The LWD sonic tool provides real-time data that is used to correlate seismic data with drilling data. The tool uses a two-transmitter, four-receiver array to measure acoustic waveforms and determine compressional and shear wave slowness in subsurface formations. Besides transmitting essential data to the surface in real-time, the device also stores more complete data in downhole memory for later retrieval and further analysis.

The real-time data is used to generate a synthetic seismogram for immediate refinement of the geological model upon which the drilling program is based, thereby helping improve precision in well-steering. The real-time data can also be used for timely estimation of pore pressure, contributing potentially important safety information for the drilling operations.

This paper will give a brief overview of the new technology and will focus on its application to drilling operations. Field examples will be presented demonstrating the applications.

Richard Logan is a Technical Specialist, LWD Drilling Systems, with Halliburton Energy Services in Houston. He received a BA degree in Chemistry from the University of Missouri and has 20 years experience in the petroleum industry. Before joining Halliburton, Richard held various field, technical sales, marketing, and management positions with Schlumberger and Baker Hughes Inteq throughout North America. He is a member of the SPE, SPWLA and AADE.

Ron Deady is a Subject Matter Expert with Halliburton Energy Services in Houston. He holds a BSc degree in Geology from Northern Illinois University. Before joining Halliburton, Ron held various field and staff positions with Anadrill Schlumberger and Baker Hughes Inteq. He is a member of the SPE and SPWLA.

Exploration Scale Structural Controls on Carbonate Ramp Trends: New Insights from the Kuwait-Saudi Arabian Coast of the Northern Arabian Gulf and Northern Yucatan, Mexico

Anthony J. Lomando Chevron Overseas Petroleum

New observations on wave dominated ramps from the Kuwait-Saudi Arabian Coast of the northern Arabian Gulf and the northern Yucatan, Mexico, indicate that exploration scale facies distribution trends are strongly influenced by structure.

Wave dominated ooid rich Holocene and modern ramp deposits from the southern Kuwait-northern Saudi Arabia coastal regions provide a complimentary model to the classic tide-dominated ramp system of the Trucial Coast, United Arab Emirates. Orientation of the Kuwait coastline parallel to prevailing northwesterly Shamal wind direction, as opposed to perpendicular in the UAE, appears to be the main control on tide versus wave- dominated systems. The locations and trend orientations of strand plains, sabkhas, and channels are related to fold noses which trend perpendicular to the coastline.

The northern Yucatan Ramp extends from the Holbox barrier island complex on the east for over 300 kilometers to the Chicxulub impact crater site (K/T boundary impact site) in the west. The major longshore transport along this skeletal-dominated ramp is east to west. This is provided by a northeast prevailing wind direction which impinges on this microtidal system at an oblique angle and the Yucatan current which flows east to west as it passes from the Caribbean to the Gulf of Mexico. Long barrier island trends protect lagoons that vary from normal marine to hypersaline. Barrier island styles, relative positions on strike and lagoon character change with changes in location of fault/fracture zones and regional arches.

In both cases, exploration and reservoir scale trend geometries are not linear with changes in characteristics controlled by synsedimentary faults, folds, and fracture zones which control antecedent topography and subsidence. These geometries are repetitive and, therefore, predictable if extended to applications in the Jurassic and Cretaceous of the Middle East especially in the search for stratigraphic traps.

Anthony J. Lomando completed his graduate studies in 1979 at the City University of New York where he worked on the Jurassic ramp carbonates of the U.S. Gulf Coast. The next eight years were spent in exploration and development in the Permian Basin and the Jurassic and Cretaceous systems of the Gulf Coast. For the past nine years, Tony has been the Staff Carbonate Specialist for Chevron Overseas Petroleum assisting in the exploration and development, description and characterization of carbonate plays and reservoirs worldwide. Tony has conducted many Carbonate schools and seminars for Chevron, its partners and associates in Russia, Kazakhstan, Mexico, Congo, Angola, China, Kuwait, the U.K. and U.S. He has authored over 40 papers and abstracts dealing with all aspects of carbonate exploration and reservoir management and is an associate editor of the AAPG Bulletin and the Journal of Sedimentary Research.

The Application of Modern Carbonate Depositional Systems in Reservoir Geostatistics

Anthony J. Lomando, Henry A. Legarre and Eberhard Gischler Chevron Overseas Petroleum

Our industry continues to become more reliant on geostatistics and reservoir simulation to provide critical information for sound business decisions. Spatial geostatistical analyses of modern systems provides insights into reservoir characterization for simulation. Spatial variograms from modern data sets can provide constraints and guidelines for spatial distribution of reservoir properties (porosity, permeability, saturation, etc.) that can significantly increase the accuracy of reservoir simulations.

Reefs and reef margins on carbonate platforms are well studied but the vast majority of reserves in oil and gas reservoirs are stored in platform interiors and, until now, our detailed knowledge of these systems was poor at best. Four modern isolated carbonate platforms from the Belize-Yucatan Province of Central America were studied. Each platform example represents different types of flow units and barriers common in carbonate fields. The results provide critical insights into models for reservoir flow unit architecture and heterogeneity.

The Lighthouse and Chinchorro platforms are grainstone-packstone dominated with abrupt facies partitioning and pronounced facies anisotropy and serve as models for high energy grainstone reservoir flow units. The Glovers Platform interior is dominated by over 850 patch reefs surrounded by wackestone to grainstone sediments and serves as an example of a very heterogeneous isotropic flow unit. The Turneffe Platform is characterized by mud-dominated lagoons punctuated by channels and sparse patch reefs. Turneffe serves as an example of an intra-reservoir barrier or baffle but highlights critical regions in reservoir flood situations where cross flow might be expected.

The Chinchorro Platform provides a representative example of how this process works. Full platform analyses provides a set of anisotropy orientations and ranges that could be used to distribute properties of a single flow unit. Subdivision of the platform into subareas show distinctly different directional trends and also some differences in range characteristics. The importance is that it is an areally continuous data set that allows for unlimited variation in sample size for testing geostatistically significant spatial distributions of a variety of properties.

Anthony J. Lomando (see abstract “Exploration Scale Structural Controls on Carbonate Ramp Trends: New Insights from the Kuwait-Saudi Arabian Coast of the Northern Arabian Gulf and Northern Yucatan, Mexico” on page 121 for biography and photograph)

Henry A. Legarre is a Research Geologist on the Geostatistics Team at Chevron Petroleum Technology Company in La Habra, California. Prior to his current assignment, he was a Development Geologist with Chevron USA. Previously employed by Scripps Institute of Oceanography and Woods Hole Oceanographic Institution, Henry’s research has involved organic and inorganic geochemistry, clay mineralogy, hydrogeology, clastic, diagenesis, and surface ocean biogeochemical processes. He received his MSc degree, with distinction, from San Diego State University, in Geological Sciences.

Eberhard Gischler received a BSc degree in October 1984. In February 1991 he received a PhD in Geology and Paleontology. After receiving his PhD, Eberhard took a two-year post-Doctoral position at the University of Tübingen followed by two years at the University of Miami to study modern carbonate environments of Belize and Florida. During his time at the University of Miami, Eberhard worked on the Holocene sediments facies and development of the Belize atolls Glovers Reef, Lighthouse Reef, and Turneffe Islands and also studied the condition of reefs and reef-building corals in south Florida and the Bahamas. Currently Eberhard is an Assistant Professor of Geology at the University of Tübingen, Germany.

Rock Fabric Approach to Petrophysical Quantification of Geologic Descriptions: Shu’aiba (Middle Cretaceous) Reservoir, Idd El Shargi Field, Offshore Qatar

F. Jerry Lucia Bureau of Economic Geology, The University of Texas at Austin

A key step in constructing a reservoir model is the conversion of descriptive geological interpretations to numerical engineering data. In this study of the Shu’aiba reservoir, Idd el Shargi field, offshore Qatar, quantification of geologic descriptions is accomplished through fundamental rock-fabric/petrophysical relationships. The Shu’aiba reservoir in the Idd el Shargi field, has been characterized by three rock-fabrics based on core and thin section study. Most of the reservoir can be characterized as an Orbitolina microporous wackestone to mudstone (type 3). Toward the top of the reservoir, fabrics are pellet wackestones and pellet grain-dominated packstones (type 2). Algal and coral allochems are abundant in some areas near the top of the reservoir forming a mud-dominated or grain-dominated packstone fabric. These allochems have been dissolved to form grain molds. Microfractures in the lime-mud matrix connect the molds and produce a touching-vug pore geometry (type 1). Each rock-fabric has a unique porosity-permeability transform. Microporous wackestone is the poorest reservoir rock. As the lime-mud becomes more pelleted the porosity-permeability relationships improve. The combination of microporosity, moldic pores, and microfractures produces an additional improvement in permeability. The microporosity is believed to be the result of mineralogical stabilization and compaction of lime-mud. Molds of algal and coral allochems are evidence for dissolution and most likely result from dissolution of unstable aragonite and reprecipitation of stable calcite cement during burial. The microfractures that connect the moldic porosity are suggested to have formed by collapse during burial.

Rock-fabrics types 1, 2, and 3 can be identified by cross-plots of water-saturation, porosity, and reservoir-height. For a given porosity and height, water-saturation increases from type 1 to type 3. Quantification of the saturation model for rock-fabric type 3 was accomplished through analysis of sixteen capillary pressure curves. Excellent matches between the saturation model and Archie saturations were obtained for microporous wackestone intervals in crestal wells using a zero-capillary-pressure level of 5,300 feet. Higher Archie than model saturations where found in flank wells, and may result from increased clay/organic content on the structural flanks.

Rock-fabric-specific porosity-permeability transforms are used to calculate permeability, and the resulting permeability profiles match well with core analysis. The vertical permeability profiles form the basis for construction of a 3-D permeability model of the Shu’aiba reservoir.

F. Jerry Lucia is a Senior Research Fellow at the Bureau of Economic Geology, The University of Texas at Austin. He acquired a BSc degree in Engineering in 1952 and MSc degree in Geology in 1954 from the University of Minnesota. His technical expertise includes origin and distribution of carbonate strata, petrophysics, and petroleum geology. Before joining the Bureau on 1985, he was a Consulting Geological Engineer for Shell Oil Company assigned to the Head Office. Jerry retired in 1985 with 31 years experience as a Geological Engineer with experience in research and operations. He is currently co-principal investigator of the Characterization Research Laboratory. Project areas include the Permian Basin and the Middle East. He has received awards for Best Paper from AAPG Wallace E. Pratt Memorial in 1994 and 1995 and Distinguished Service Award from West Texas Geological Society in 1993. Jerry is an active member of the AAPG, SPE, and the Society of Sedimentary Geologists, and is a Fellow in the Geological Society of America.

Improved Characterization of the Unayzah Reservoir, Central Arabia, from 3-D Seismic with Stratigraphic Inversion and Statistical Pattern Recognition

Costas G. Macrides, Ahmed M. Al-Otaibi, Marty Rademakers Saudi Aramco Claude Blanchet, Pierre-Yves Déquirez and Frédérique Fournier Institut Fran•ais du PŽtrole

3-D seismic provides crucial information for better reservoir characterization, particularly in highly heterogeneous depositional environments. This is the case for the Unayzah fluvio-deltaic sandstones where limited well control is not sufficient for defining the reservoir behavior in the interwell areas. However, lithostratigraphic interpretation of seismic data should incorporate geological knowledge for better constraining the interpretation and ensuring the consistency of all available data. This paper demonstrates a joint application of stratigraphic inversion and pattern recognition to a 3-D data set covering an area of 500 square kilometers over the Unayzah reservoir in Central Arabia. The main steps are described as follows:

  • (1) Well to seismic data calibration: This step is very important for extracting a wavelet ensuring a good tie between the synthetics at wells, from logs, and the neighboring real traces. A methodology based on multi-well multi-trace calibration is applied to ensure the extraction of a robust and stable wavelet over the entire study area. This wavelet is used for stratigraphic deconvolution followed by picking of the main seismic events.

  • (2) 3-D post-stack stratigraphic inversion with a priori information: Geological information is introduced in the inversion process by means of an a priori impedance model. This model is built by interpolation of impedance logs, at wells, in a manner that honors the geometry of correlation surfaces defined from picked seismic horizons and depositional knowledge. The inversion algorithm is based on a full 3-D scheme that allows the integration of vertical as well as lateral seismic information in both inline and cross-line directions, thus ensuring a high degree of spatial consistency. The resulting acoustic impedances are another step towards the lithologic interpretation of seismic amplitudes.

  • (3) Application of statistical pattern recognition techniques for providing a geological interpretation of the inversion results: The translation of seismic-derived acoustic impedances into geological properties of the reservoir is not simple, because of the limited seismic bandwidth and indirect relationship. Thus, a statistical interpretation is proposed with a methodology that combines seismic attributes with supervised and unsupervised pattern recognition techniques. The interpretation is based on the detection of variations of the seismic character within a time window corresponding to the reservoir interval. Techniques such as cluster and discriminant analyses are employed to statistically classify the seismic character into seismic facies. One strong point of the methodology is that uncertainties in the interpretation are quantified through computation of probabilities of assignments to the various facies. The final seismic facies maps with their accompanying uncertainties maps are powerful for predicting the reservoir lateral variations, and thus defining new well locations, and/or new prospects.

Costas G. Macrides received a BSc in Physics from the University of Athens in 1980, a MSc in Geophysics in 1983 and a PhD also in Geophysics in 1987 from the University of Alberta. He has been an Assistant Professor at the University of Manitoba and a Senior Research Geophysicist with Seis-Pro and Consultants in Calgary. Costas joined the Geophysical Research and Development Division of Saudi Aramco in 1993. His interests include seismic tomography, refraction statics, AVO and multi-component seismology in oil exploration. He is a member of the SEG and EAGE.

Ahmed M. Al-Otaibi (see abstract “Recent Discovery Confirms Stratigraphic Trap Potential in the Permian Unayzah Formation of Central Saudi Arabia” on page 92 for biography and photograph)

Marty Rademakers is a Geophysicist with the Area Exploration Department of Saudi Aramco. Prior to joining Saudi Aramco in 1996, Marty worked with Templeton Energy (1981-1983); LASMO (1983-1992); and Plains Resources (1992-1996). He received a BSc in Geology from State University of New York in 1978 and an MSc in Exploration Geophysics from the University of Tulsa in 1981.

Claude Blanchet has worked for Institut Français du Pétrole (IFP) in Rueil-Malmaison, France for 35 years. She is currently Geoscience Technician with the Reservoir Seismic Group. She previously had been working with the Remote Sensing Group of IFP. Claude’s current interests include signal estimation well to seismic calibration and stratigraphic inversion.

Pierre-Yves Déquirez is currently a Research Geophysicist with the Reservoir Seismic Group of the Geophysical Division at Institut Français du Pétrole (IFP) in Rueil-Malmaison, France. He is also involved in reservoir studies and applies IFP’s post-stack inversion tools to basins worldwide in cooperation with various petroleum companies. Before joining the Reservoir Seismic Group, Pierre-Yves worked for three years with the Marine Acquisition Team of IFP, dealing with on-board data acquisition quality control softwares. Pierre-Yves is a graduate of Institut de Physique du Globe de Strasbourg and of École Nationale Supérieure du Pétrole et des Moteurs (1983). He is a member of the EAGE, and his main areas of interest are integration of surface and borehole data, and seismic data processing and interpretation for reservoir characterization.

Frédérique Fournier is currently Leader of the Reservoir Seismic Project in the Geophysical Division of Institut Français du Pétrole (IFP) in Rueil-Malmaison, France. She worked as a Research Geophysicist for Elf Aquitaine Production between 1985 and 1990 before joining IFP. Frédérique received degrees from Ecole Nationale Supérieure de Géologie de Nancy in 1983, and from Ecole Nationale Supérieure du Pétrole et des Moteurs in 1985. She holds a PhD degree from Institut National Polytechnique de Lorraine. Her current interests include multivariate statistics, geostatistics, signal processing and seismic interpretation for reservoir characterization.

Plio-Pleistocene Clastic Reservoirs of the Offshore Nile Delta, Arab Republic of Egypt

Steven J. Maddox, Neil Hodgson, John L. Swallow, Elizabeth M.M. Loudon and Kambeez Sobhani British Gas

In the last few years, a prolific new gas play has been discovered and exploited in the offshore Nile Delta, Egypt. British Gas is a leading player, with three large operated concessions in the southern Mediterranean Sea.

Although this play is phenomenally successful (with an almost 100% success rate), it is challenging for exploration and development/production, due to the shallow, undercompacted and unconsolidated nature of the reservoirs. The shallow and unconsolidated sands are however, ideal for observing direct hydrocarbon affects on seismic, a fact which has contributed greatly to the amazing success rate.

The reservoirs are very young (Plio-Pleistocene), and are only circa 0.5-4 million years in age. They are generally quite unconsolidated and undercompacted and sand production during testing is common. Coring is a also a challenge and to date competitor operations have had mixed success.

In addition to the above problems, the reservoirs are variably pressured, depending on environment of deposition, reservoir connectivity and depth. In general, the Plio-Pleistocene is normally to slightly overpressured, particularly in the shelfal areas. Abnormally pressured sands have been encountered by competitors however (eg. ca.13+ppg sands at <1,800 meters) and these pose a significant well control and design problem. These overpressured sands appear to be either isolated deeper marine sands, or sands in communication with deeper pressures via faults.

The pressure regime is also important in reserves estimation as it impacts on the formation volume factor, leading to under or over estimation of volumes if the correct pressure regime is not prognosed.

Steven J. Maddox has worked as a Geologist in the oil and gas industry for nearly 10 years with British Gas E&P and British Petroleum Exploration. Prior to this he gained a BSc degree from the University of Hull in England and a PhD from the University of Edinburgh, Scotland. Steven has worked extensively on hydrocarbon exploration and development in the North Sea and Atlantic Margin, and internationally in Southeast Asia, North Africa and the Middle East.

Neil Hodgson has worked as a Geologist in the oil and gas business for over 10 years with British Gas E&P and British Petroleum Exploration. He graduated from the University of Manchester and received a PhD from the University of Leicester. Neil worked in the UK Continental Shelf with BP Exploration and BG E&P, before becoming Exploration Manager for British Gas in Cairo,

Egypt.

John L. Swallow has worked as a Geophysicist in the oil and gas business for over 15 years with the British Geological Survey, Total Oil Marine and British Gas E&P. He graduated from the University of Leeds and has worked on the UK Continental Shelf and was posted with Total for several years in Venezeula. Since joining British Gas, he has worked primarily on Egypt and is now sub-surface team leader for exploration at British Gas’s head office in the UK.

Elizabeth M.M. Loudon graduated with a BEng in Electro-Mechanical Engineering from Aston Univeristy in 1992 and an MSc in Petroleum Engineering from Imperial College London in 1993. Elizabeth joined British Gas in 1993 and has worked as a Petroleum/Reservoir Engineer on a variety of Egyptian and UK Continental Shelf assets. She has also worked in Egypt for the ZAFCO Petroleum Company.

Kambeez Sobhani has over 25 years oil and gas company experience in Iran and the UK. He worked for BNOC/Britoil and Hamilton Brothers on a variety of projects, before joining British Gas in 1988. Kambeez has worked as a Petroleum Engineer, but is currently Principal Petrophysicist working on a variety of assets in Italy, the Middle East and North Africa. Other experience includes UK Continental Shelf and Southeast Asian oil and gas projects.

Stylolites and Related Features: Their Implications on Near-Wellbore Flow Behavior, Examples from Arabian Gulf Reservoirs

Joerg E. Mattner and Sait I. Ozkaya Western Atlas International

Stylolites are the result of solution processes found in carbonate rocks. In the Arabian Gulf region, extensive and pronounced stylolitisation is observed in many hydrocarbon reservoirs. These phenomena are commonly associated with prominent tension gashes, brecciation, and cemented zones. Such features, in conjunction with the stylolites, cause changes in the near-wellbore flow regime. High resolution image logs, production logs and core examples are utilized to demonstrate the wide spectrum of features and their effects on fluid flow.

Joerg E. Mattner and Sait I. Ozkaya (see abstract “Integrating Fluid Flow and Borehole Imaging Data in Fracture Characterization, Hanifa Reservoir, Abqaiq Field, Saudi Arabia” on page 44 for biographies and photographs)

Unbiased Target Prediction Using Global Seismic Inversion

Kim G. Maver, Helle Wagner degaard A/S and Clare N. Baldock Digicon Geophysical Ltd.

A 3-D seismic survey acquired in offshore Abu Dhabi has been processed by Digicon Geophysical Ltd. and seismic inversion for acoustic impedance has been performed by ⁻degaard A/S.

A potential carbonate reservoir is encountered by three wells. The seismic data associated with the potential reservoir exhibit a substantial variation indicating a non-homogenous reservoir.

The aim of the seismic inversion project is to predict the lateral variations of the target zone without biasing the final results. This is possible by using the ISIS seismic inversion technique, which is not constrained by well logs or a detailed starting model. As the method is a 3-D multi-trace global optimization technique, it is furthermore very robust towards noise.

By performing seismic inversion, acoustic impedance data are obtained. The acoustic impedance data are easier to interpret and give better information about lateral variations in lithology compared with the seismic data. Furthermore, the acoustic impedance data can be correlated directly with the well logs. Since the well logs are not used directly in the seismic inversion process, the results can be verified by comparison with the well logs. For this project, the well logs show a near optimal match with the acoustic impedance results verifying the validity of the seismic inversion.

The acoustic impedance results indicate substantial lateral variation in the thickness of the target zone and the acoustic impedance variations within this zone may furthermore be indicative of substantial variations in reservoir quality.

Kim G. Maver graduated in 1989 from Copenhagen University with a MSc in Geology and in 1996 with a PhD in Geology. Kim is currently the Deputy Managing Director of Ødegaard A/S. He has worked 5 years for the Danish Geological Survey as a research assistant specializing in seismic modeling. For the last 4 years he has worked for Ødegaard A/S specializing in seismic modeling and seismic inversion.

Helle Wagner graduated in 1993 from Copenhagen University with a MSc in Geophysics and in 1997 with a PhD in Geophysics. Helle is currently employed as an Inversion Specialist in the consultancy department at Ødegaard A/S. Before working with Ødegaard A/S, Helle worked on her PhD, the topic being global seismic inversion.

Clare N. Baldock graduated in 1982 from the University of Bath with a BSc in Physics and Geophysics, and is currently the Senior Geophysicist responsible for data processing at Digicon Geophysical Ltd. ’s processing centre in Abu Dhabi. She has 15 years seismic data processing experience from a wide variety of data environments. In the last 7 years, she has specialized in land data processing, with emphasis on work acquired in the Middle East. Clare is currently supervising the processing of a large, complex transition zone survey for Abu Dhabi Company for Onshore Oil Operations and partners, together with several other land and marine projects from the Middle East.

In Search of the Precambrian/Cambrian Boundary in the Huqf Sedimentary Rocks, Oman

Margaret McCarron University of Oxford

The Huqf Supergroup is deposited on rifted Pan-African basement. The rift basin was infilled with a thick diamictite unit and overlain by a 12-meter thick cap carbonate. Further sagging enabled the deposition of two siliciclastic/carbonate units before a second episode of rifting began with the subsequent deposition of the Ara/Fara Formation. Granodiorite dykes beneath the diamictites give a Rb/Sr date of 554±10 million years (Dubreuilh et al., 1992) while Cloudina fossils have been found in the Ara Formation indicating a Vendian to Tommotian age for the Ara. A Pb/Pb date 529±16 have also been acquired from Birba carbonates (PDO unpublished data). Thus an Infracambrian age for the Huqf Supergroup is inferred.

Detailed sedimentological studies, including biostratigraphy in conjunction with stable isotope geochemistry (chemostratigraphy), is presently being carried out with a view to elucidating the position of the Precambrian/Cambrian boundary. Skeletal fossils to confirm age are missing owing to hypersaline conditions in Oman which prevented its colonization by index skeletal fossils and trace fossils. However, putative fossil markings have been found above the cap carbonate within the Masirah Bay Formation, which are comparable with those found in Ediacarian rocks elsewhere.

Carbon isotopes show negative-positive peaks at two places within the succession. A pronounced negative peak is possibly correlative with the feature “W” recognized at the Precambrian/Cambrian boundary in Mongolia, Siberia, Iran and the “N” interval recognized in Namibia, Spitsbergen and northwest Canada. Preliminary strontium isotope data indicates a trend toward more radiogenic values throughout the sequence which is comparable with trends seen in other reference sections but differs in being isotopically heavier. This problem is currently under investigation.

Margaret (Gretta) McCarron is currently studying for a D.Phil at the University of Oxford. The Huqf Supergroup in Oman is the subject of her research, which includes the sedimentology of surface exposures in Central Oman and the Oman Mountains. She is using stable isotope geochemistry to define the chronostratigraphic framework of the Supergroup. Gretta graduated from Queens University, Belfast with a BSc (Hons.) in 1995.

From Noise Attenuation Towards Signal Preservation

Andrew McGinn, Erik Kleiss and Rini M. Klaassen Petroleum Development Oman

Petroleum Development Oman (PDO) processes in-house approximately 4,200 square kilometers of new 3-D and 3,800 kilometers of new 2-D land data per year acquired with vibroseis. The seismic processing has historically been targeted at structural plays and has concentrated on noise and multiple attenuation.

However there are potential exploration and production objectives where amplitude control, increased temporal and spatial resolution, together with a stable phase wavelet would be beneficial. Therefore the processing methodology has been examined in an attempt to perform more deterministic rather than statistical processing and to concentrate on signal preservation and phase stability rather than noise attenuation.

The new processing sequence which has been developed can now achieve our goals. Numerous reprocessing trials on 2-D and 3-D data have conclusively demonstrated that major gains can be achieved by following the methodology and all new data in PDO can now be processed in this fashion. The deterministic approach, with suitable flexibility to handle low S/N ratio data, will be presented, together with examples of the resultant data quality.

In the past, performing ÔdeterministicÕ processing was not considered viable for PDOÕs data, the emphasis was on noise control with strong K/F filters (sometimes in both shot and receiver domain) and several passes of trace scaling. Changing the emphasis to wavelet and amplitude preservation meant that the processing sequence would follow a similar sequence to that employed on marine data within Shell. Namely, Earth deabsorption and signature deconvolution, but coupled with a more rigorous surface consistent amplitude scaling than commonly used on marine data.

The main changes between 1996 and 1997 are:

1996 sequence:

  • - F/K filter, 1750m/s, fully tapered, 48dB attenuation

  • - two gate, single trace gapped DBS

  • - 1s or 2s trace scaling pre- and post-stack

  • - multiple attenuation with initial velocities

  • - DMO velocity analysis

  • - DMO and stack

  • - migrate

  • - phase only deabsorption and zero-phase

1997 sequence:

  • - F/K filter, 1750m/s, 30% flat, 48dB attenuation

  • - phase and amplitude deabsorption, maximum 24dB boost

  • - zero-phase

  • - single gate, single trace gapped DBS

  • - angle consistent scaling

  • - surface consistent scaling

  • - DMO, pre-stack output

  • - multiple removal after final velocity analysis

  • - stack

  • - migrate

The 1997 sequence is considered to be the first stage in the development of more controlled processing. Preliminary work has already indicated that the DBS can be replaced by a residual deconvolution which takes into account the deterministic wavelet manipulation performed. It is also the intention to perform this residual deconvolution in a surface consistent manner. Work is also ongoing to modify or even completely remove the K/F filter.

All test processing has been carried out with ShellÕs SIPMAP processing package. Compagnie GŽnŽrale de GŽophysique’s software is then tested in order to emulate the required steps, and if necessary modifications are requested.

The 1997 sequence can be implemented in all production processing. The angle consistent scaling was essential before the surface consistent scaling became stable. Previous attempts at surface consistent scaling failed due to the inherent amplitude decay on the records, so that a solution for amplitudes at one time level either over or under compensated the amplitude behavior at other levels.

Unfortunately data quality does not allow all seismic data to be treated in this manner. Therefore prior to DMO the surface consistent information is analyzed to determine if the S/N ratio is too low for such techniques to succeed, in which case scaling or filtering is employed to stabilize the noise present, resulting in a loss of relative amplitude information.

The more deterministic processing sequence has already demonstrated its value with broadband, relative amplitude data being delivered to the interpreters. As well as the direct benefits from de-absorption, zero-phasing etc, subsequent steps i.e., statics and velocity analysis improve. Poor data areas where the full surface consistent scaling approach is not valid, still benefit from the new wavelet manipulation.

Andrew McGinn is a senior geophysicist with Shell International E&P, currently working in Petroleum Development Oman (PDO) in seismic processing QA. Prior to his posting to PDO in September 1996, Andrew supervised acquisition and processing of seismic data in a variety of locations for the Shell Group. He has 17 years geophysical experience and holds BSc and PhD degrees in Mathematics from the University of Southampton.

Erik Kleiss joined Shell in 1985, leaving Delft University of Technology where he obtained a PhD in Reactor Physics. Until 1990 Erik worked in the Experimental Seismic Processing group in the Shell E&P research laboratory in Rijswijk, Holland, on a variety of subjects, the last few years being engaged in setting up 3-D depth migration. Thereafter he went to Warri in Nigeria as 3-D Processing Geophysicists and filled positions in Port Harcourt as Section Head Contractor Processing and as Head of Seismic Processing. In 1994 Erik moved to Petroleum Development Oman as Head of Seismic Data Processing.

Rini M. Klaassen graduated from HTS Vlissingen as an Electrical Engineer in 1974 and joined Shell in 1978. After spending four years in experimental processing in KSEPL and following Wetenschappelijk Reken courses at the Delft University, Rini moved to Oman as a Seismic Processor and was later transferred to SIPM were he was involved in both land and marine 3-D processing. He is currently team leader of the SIPMAP seismic processing group in Petroleum Development Oman.

AAPG Annual Meeting

17-20 May, 1998

For more information please contact:

AAPG Conventions Department

Tel: (918) 560-2679; Fax: (918) 560-2684

3-D Land Acquisition Geometry: What is the Best Compromise Between Cost and Quality?

Julien Meunier, Jean-Jacques Postel, Michel Denis and Claude Vuillermoz Compagnie GŽnŽrale de GŽophysique

If cost and turnaround time were irrelevant, we might all agree that the ideal 3-D acquisition geometry would be a disk centered on the source-point. The radius of the disk would be wide enough to include all the reflected energy. The source and receiver geometry would be isotropic (disks), and the station interval would be the same in both the X and Y directions. Finally, the source interval would be the same as the station interval (in both the X and Y directions).

In a conventional Common Mid-Point approach, such a geometry would result in 4 families of bins, all with the same offset distribution and with an azimuth distribution rotated 0°, 90°, 180° and 270°. However, to make cost savings, this ideal geometry would be impaired in 3 ways: (1) spatial sampling of the disk; (2) reduction in its shape; and (3) source and receiver pattern anisotropy. All of these will have a negative impact on the final seismic image.

Spatial sampling: Most 3-D designs use different sampling intervals in the in-line and cross-line directions; source and receiver grids are defined by station and line intervals. The average station density is inversely proportional to their product. It may not be the same for the cost.

The station interval is usually twice the bin size. It is chosen short enough to avoid spatial aliasing. The line interval is a major parameter of the acquisition foot print. It defines the number of families of bins with different offset and azimuth distributions. Due to processing limitations, the variation in these distributions results in the distortion of the amplitude and phase of the average seismograms in each bin.

Reduction in shape: Besides the awkwardness of a disk geometry in a marine environment, recording all the stations within a circle around a land shotpoint requires a very high number of recording channels. The disk is more often than not changed into a rectangle and acquisition symmetry is therefore reduced. The consequences of this reduction depend upon the seismic conditions (weathered layer variations resulting in static anomalies, presence of ground roll, multiple reflections, anisotropy, complex tectonics).

Moreover, in order to reduce station deployment costs, several source-points are recorded through the same receiving patch. This reduction results in an increase in the number of bin families with different offset azimuth distributions.

Source and receiver anisotropy: For various reasons, it is impractical to use isotropic arrays. Though it is sometimes possible to use a single source-point and a single receiver-point, it is more usual to use linear arrays. This simplification will make source-generated noise - and, to a lesser extent, reflected signal - more dependent upon azimuth.

After a theoretical analysis detailing the first two previous points, this paper will compare the response of ten 3-D geometries, first on a flat geology, and second on a diffracting point. Although we cannot claim to obtain a firm answer to the title question, a correlation between theoretical signal-to-noise ratios and cost estimate ratios for different 3-D geometries will be analyzed, and trends deduced.

Reducing costs is certainly a very reasonable requirement when designing a 3-D acquisition geometry. It is also desirable to evaluate the risk associated with the corresponding departure from the ideal geometry. Such an evaluation can be performed prior to acquisition using such an analysis.

Julien Meunier is R&D Geophysicist with Compagnie Générale de Géophysique. He graduated from the Institut Polytechnique in 1971. Julien’sprofessional interests are 3-D seismic acquisition and processing.

Jean-Jacques Postel is currently Research and Engineering Manager - Land and Shallow Water Acquisition with Compagnie Générale de Géophysique. He graduated from Ingenieur Ecole Centrale de Lyon in 1978. Jean-Jacques’ professional interests are seismic acquisition methods and equipment, seismic processing. He is a member of the SEG, EAGE and AFTP.

Michel Denis is currently Area Geophysicist with Compagnie Générale de Géophysique. He received a PhD degree in Mathematics from the University of Paris in 1978. Michel is interested in 3-D processing and 3-D design. He is a member of the SEG and EAGE.

Claude Vuillermoz is the Chief Geophysicist for Compagnie Générale de Géophysique (CGG). His interests are focused toward the various applications of modern seismic, particularly 3-D, repetitive 3-D, 3-D-3C, AVO, Inversion, as essential elements for reservoir characterization and integrated reservoir studies. Claude has spent his entire 29-year career with CGG, where he has been assigned to various positions in acquisition, processing and interpretation. From 1964 to 1974, his experience with CGG included operations in Europe, Indonesia, Africa, Canada as Party Chief, supervisory and technical management. From 1974 to 1976, he was Processing Center Manager in Gabon, Africa. From 1976 to 1981, he was Processing Center Manager in Calgary, Canada. From 1981 to 1989, he was Chief Geophysicist for North America and Processing Center Manager in Denver, Colorado. From 1989 to 1992, he was R&D Manager of North America, in Houston, Texas. Claude holds a MSc degree from the University of Lyon, a PhD degree in Geology from the University of Grenoble, an Engineering degree from ENSPM, the post graduate School of Petroleum at Institut Français du Pétrole in the exploration branch. He has contributed to numerous publications and is a member of the SEG, EAEG, AAPG, DGS and HGS.

Source Rock Distribution and Thermal Maturity in the Southern Arabian Peninsula

Penelope Milner Phillips Petroleum Company

The purpose of recent work in the southern Arabian Peninsula has been to investigate the source potential of deeper horizons such as the Paleozoic. A variety of newly drilled and older wells together with exclusive and nonexclusive reports have been used in order to develop new maturation and migration models for newly emerging plays, and to develop a better understanding of the subsidence and maturation history of a large and diverse area.

It has been possible to conduct comprehensive burial history modelling for a number of Oman, Saudi Arabia and the United Arab Emirates wells. This, together with modelling of hypothetical wells derived from structure maps has improved our understanding of oil and gas-prone source rocks for Cretaceous, Jurassic and Paleozoic strata. The resultant maturity distribution has been developed with the aid of a robust structural model for the southern Arabian Peninsula.

In tandem with this study, available core and cuttings data have been analyzed to measure total organic content, maturity and pyrolysis parameters using proprietary techniques. The rock evaluations have been used to supplement the existing database and to map source rock quality. The proprietary artificial intelligence program ÔSource Rock AdvisorÔ has been used to evaluate some of these rock samples, and the data input, evaluation, and results obtained will be demonstrated on a laptop computer.

Integration of source rock quality and maturity maps resulting from this study has improved regional understanding of Oman, Saudi Arabia and the United Arab Emirates. It is planned for this work, together with reservoir distribution studies, to assist in the process of acreage acquisition in the Middle East.

Penelope Milner obtained a first degree in Geology and second degree in Geophysics in the early 1980s. After a short position with a seismic contractor she joined Phillips Petroleum Company in 1984. Penelope’s assignments have included a lengthy spell in the North Sea on the Southern Gas Basin Hewett Field development, and also on regional “Yet-To-Find” studies in the Central Graben. In the last two years she has led a UK-based team reviewing Middle East potential. She has presented papers previously at the 1993 Society of Petroleum Engineers conference and at the 1995 UK Landmark Users Conference.

Geological Constraints on the Pre-Khuff Hydrocarbon Prospectivity, South-Central Onshore Abu Dhabi

Awad A. Mohamed Abu Dhabi Company for Onshore Oil Operations

The term pre-Khuff clastics is conventionally used to describe the Late Carboniferous to Permian non-carbonate sediments, unconformably underlying the Permian strata. These clastics were found to be hydrocarbon-bearing in offshore Abu Dhabi, area A. However, they are devoid of significant hydrocarbon shows and have not warranted testing so far in onshore Abu Dhabi.

Integrated well data were analyzed from four wells located in a profile running from southern onshore Abu Dhabi to the south, to area B in offshore Abu Dhabi to the north. The reservoir diagenesis, rock facies and depositional environments were delineated, and appreciable differences that favored the reservoir quality in the offshore area are recognized. In addition, the study investigated the regional geology of the area, maturation and burial history, and the local and regional heat flow regimes.

The pre-Khuff clastic sandstone facies in southern onshore Abu Dhabi, area C, is comprised of fluvial deposits in contrast to eolian sands in the offshore area. Significant textural and petrographic variations are evident between the two sandstone facies. The fluvial deposits are fine- to medium-grained, poorly sorted with markedly poor reservoir quality due to silica dissolution, feldspar alteration, bioturbation and the presence of authigenic clay minerals. On the other hand, the dune foresets facies of the eolian sands reflect a better sorting and higher quartz-grain ratio with an overall favorable petrophysical characteristics.

Regional heat flow modeling and burial history analyses clearly indicate that the pre-Khuff clastics and their potential hydrocarbon content in the Shah area were subjected to much higher temperatures than in the offshore area. Intense physical conditions of temperature and pressure have placed these sediments and any possible hydrocarbon content below the gas generation window and possibly into the metagenesis stage in the Shah area.

Awad A. Mohammed is a Staff Geologist with Abu Dhabi Company for Onshore Oil Operations (ADCO). Prior to joining ADCO in 1991, Mohammed was with United Arab Emirates University (1990-1991) and with the Chevron Companies from 1979 to 1989. He has a BSc (Honors) in Geology (1979) and received his MSc and DIC in Petroleum Geology from Imperial College, London in 1983. Mohammed is a committee member and Assistant Secretary of the Society of Explorationists in the Emirates and is a member of the AAPG.

Fracture Identification Using Borehole Acoustic Measurements in Crystalline Rocks: A Case Study

Saad Hassan Mohamed Belayim Petroleum Company and Ehab A.R. Negm Halliburton Energy Services

Recent developments in borehole acoustic measurements have led to improved evaluations of fractured formations. Different techniques analyzing the effect of fractures on travel time and acoustic wave from amplitude were used, and the resultant changes due to rock deformation were interpreted in terms of position, orientation, density, and production potential.

Data derived from acoustic measurements in a lower Eocene fractured limestone in East Belayim field, Sinai, Egypt, were analyzed in terms of fracture delineation and potential flow zones. A Circumferential Acoustic Scanning Tool for borehole imaging measurements was used to measure the position and orientation of fractures in the borehole. 2-D and 3-D gray-scale and colour image maps covering 360 degrees of the borehole were studied in terms of changes in both ultrasonic travel time and amplitude. Anomaly, discordance, and high amplitude sinusoidal waves were marked, natural fractures were distinguished and their orientation, density, and effectiveness for productivity described. Full Wave Sonic tool measurements were run in compressional, shear and stonely modes. Compressional and shear wave slowness was analyzed to measure the stress field around the borehole. Stonely and shear wave slowness, along with the density data, were used to identify areas of possible fractures and permeability based on the Stonely/elastic Stonely resemblance technique. Stonely wave slowness measurements were subjected to amplitude, reflection and energy loss analysis techniques to identify fractures zones. Open hole porosity measurements were used to delineate potential flow zones.

The output from all tools were correlated and fractures were delineated, studied and confirmed. Other correlation was carried out with gas chromatography and mud logs and their usefulness is assessed for use in the study. This paper uses a case study to emphasise how we may use acoustic measurement to study fractured formations and evaluate their production potential.

Saad Hassan Mohamed graduated from Cairo University. He is currently working with Belayim Petroleum Company’s Log Analysis and Petrophysics Division. Saad worked on Wellsite and Operations Geology in the Gulf of Suez and Nile Delta. He was seconded to IEOC to work in the Qantara area. Saad is well-experienced in the latest wireline logging and logging while drilling techniques including computer- based formation evaluation. He is a member of the Society of Professional Well Log Analysts.

Ehab A.R. Negm graduated with a Diploma in Applied Geophysics from Cairo University in 1987. He is currently Senior Log Analyst for Logging and Perforating with Halliburton Energy Services in Egypt. Ehab also worked with Gulf of Suez Petroleum Company as Petrophysicist in the Exploration Department between 1987 and 1991. He is a member of the Society of Professional Well Log Analysts.

The Upper Jurassic (Najmah) Hydrocarbon System of West Kuwait

Leonard V. Moore, Deborah Gilbert Exxon Exploration Kuwait Inc. Alaa Al-Ateeqi and Yousef Al-Zuabi Kuwait Oil Company

The prospectivity of the Upper Jurassic hydrocarbon system of West Kuwait has been defined based on the results to date of a joint technical study between Kuwait Oil Company and Exxon Exploration Kuwait Inc. The primary goal of this study is to define the potential for light oil similar to the Kra-Al-Maru (KM-1) discovery, which tested 49.5° API oil from the Najmah Formation. This requires stratigraphic definition of the oil prone source facies within the Najmah, mapping the areal extent of these facies, maturation/migration timing, drainage fill and spill modeling, and trap timing.

Detailed sequence stratigraphy of the Upper Jurassic section in West Kuwait identified eight distinct depositional systems tracts based on core and log analysis. Sampling of cores from these units for source potential (Total Organic Content, RockEval and thermal maturity) identified source-rich highstand and transgressive systems tracts with up to 19% original TOC and HI’s over 700 mgHC/gmC interbeded with non-source to poor quality source rock facies. Oil extracts from selected source-rich core samples have been correlated to reservoired Najmah oils at Kra-Al-Maru, Minagish and Umm Gudair.

Interpreted well logs have been tied to regional 2-D seismic across West Kuwait and to 3-D surveys at Minagish field and the Kra-Al-Maru discovery area. These data sets, along with well-specific burial history and thermal models have defined a prospective area for light oil in West Kuwait. In addition, datumed seismic horizons tied to migration timing derived from modeling studies, and overlain by drainage flow lines indicate the light oil at Kra-Al-Maru arrived within the last 10 million years, from basinal area to the north and northeast. To the south-southeast, along the greater Kra-Al-Maru Trend, there is an increasing risk for discovering indigenously generated heavier oils.

Leonard V. Moore is a Senior Exploration Geologist with Middle East Venture Development, Exxon Exploration Company in Houston, Texas. He has over 20 years of international experience including postings to London, Singapore, Bangkok and Dhahran, Saudi Arabia. His specialization is in source rocks and hydrocarbon systems analysis. Leonard holds degrees in Geology from the University of Connecticut and Southern Methodist University in Dallas, Texas.

Deborah Gilbert received BSc and MSc degrees in Earth Sciences from Adelphi University in New York. She has worked for Exxon Exploration Company and its various affiliates since 1977 focusing on regional oil, source and maturation studies in the Gulf of Mexico, southeast Asia, Eastern Europe, the former Soviet Union and the Middle East.

Alaa Al-Ateeqi (see abstract “Impact of 3-D Seismic Surveys on Minagish and Umm Gudair Fields Development, Kuwait” on page 42 for biography and photograph)

Yousef Al-Zuabi is currently a Senior Geophysicist with Kuwait Oil Company. Yousef has 12 years experience in petroleum and exploration activities. He received his BSc degree in Geology from Kuwait University in 1985.

Regional Structural Style of the Central Oman Mountains: Jebel Akhdar, Saih Hatat and the Northern Ghaba Salt Basin

Van S. Mount and Roderick I.S. Crawford ARCO International Oil and Gas Company

A pair of regional, north-south trending, structural cross-sections over the Saih Hatat and Jebel Akhdar anticlines in the central Oman Mountains have been constructed based on surface, well, and seismic data. The cross- sections extend to the south to include the northern end of the Ghaba Salt Basin and the northern portion of the Musallim High, respectively. The incorporation of subsurface data from south of the Oman Mountains into the cross-sectional interpretations have important ramifications regarding the structural style of the Saih Hatat and Jebel Akhdar anticlines, and differences in the pre-Permian section exposed in their cores.

Large-scale structural geometries observed on the cross-sections suggest that the Saih Hatat and Jebel Akhdar anticlines are basement-involved compressional structures, underlain by north-dipping, high-angle, blind, reverse faults located beneath their southern limbs. Latest compressional deformation involving the high-angle reverse faults is interpreted as Early Tertiary, implying that pre-Permian strata and Permian-through-Upper Cretaceous strata exposed in the Saih Hatat and Jebel Akhdar anticlines were arautochthonous (uplifted over the reverse fault, but not displaced laterally a far distance) in this deformation event. The allochthonous Hawasina and Sumeini sedimentary rocks and the ophiolite complex are interpreted to have been emplaced onto the platform carbonate in the Late Cretaceous and to have also been arautochthonous during the Early Tertiary deformation. The interpretation also indicates a major Late Paleozoic compressional event affecting the pre-Permian section exposed in the cores of the Saih Hatat and Jebel Akhdar anticlines.

The southern portions of the Saih Hatat and Jebel Akhdar structural cross-sections extend into the northern Ghaba Salt Basin and the northern part of the Musallim High, respectively. As constrained by subsurface well and seismic data, the pre-Permian section in the Ghaba Salt Basin consists of a thick (>4 kilometers) sequence of Cambrian-through-Silurian, predominantly non-marine-to-shallow marine, clastics (Haima Supergroup). In contrast, out of the Ghaba Salt Basin, in the Musallim High region, the Haima Supergroup is generally less than one kilometer thick, and interpreted to thin to the north. The fundamental difference in the pre-Permian strata exposed in the cores of the Saih Hatat and Jebel Akhdar anticlines is the thick (>3.4 kilometer) section of Ordovician age shallow marine strata (Amdeh Formation) present in the Saih Hatat anticline, but absent in the Jebel Akhdar anticline. In our interpretation the thick shallow marine clastics exposed in the Saih Hatat anticline represent the northern extension of the Early Paleozoic Ghaba Salt Basin, which has been uplifted over a high-angle reverse fault in the Early Tertiary deformation event. The cross-section through Jebel Akhdar is located to the northwest of the Ghaba Salt Basin, along the Musallim High, and therefore, the thick sequence of Ordovician strata was not deposited and is not observed in the Jebel Akhdar structure.

Van S. Mount received a BA degree in Geology from Hamilton College and PhD in Structural Geology from Princeton University. He joined the Structural Geology Research Group at ARCO Exploration and Production Technology Company in 1989 where his work concentrated on quantitative analysis and interpretation of complexly deformed prospect-scale structures. Van is presently at ARCO International Oil and Gas Company where he is working as an Exploration Geologist in the Middle East Exploration Group.

Roderick (Rod) I.S. Crawford graduated from the University of Wales with a BSc in Geophysics. Initially he was employed in seismic acquisition and processing at Geoteam Ltd., UK, later moving into seismic interpretation. As a Consultant he specialized in mapping structurally complex areas. He joined ARCO British Ltd. in 1991 where he has continued to work challenging exploration and development projects. Presently Rod is seconded to the Middle East New Ventures and Operations Group, ARCO International Oil and Gas Company.

Hydrocarbon Accumulations Associated with Halokinesis in the Marib-Shabwa and Tihama Basins of Yemen

Abdul Sattar Othman Nani Ministry of Oil and Mineral Resources, Yemen

Oil and gas fields have been discovered in the Marib-Shabwa basin and oil seeps have been detected in the Tihama basin, both of which are associated with halokinesis in different geological times. The salt in the Marib-Shabwa basin is Jurassic (Tithonian age) and an initial phase of halokinesis began in very Late Jurassic time. Features associated with halokinesis were detected during seismic interpretation and include listric gaps, rollover structures, turtle backs and salt pillows. All these structural features are associated with listric faults, which played a positive role for migrating hydrocarbon from Lam and Meem source rocks to the Alif reservoir rocks.

The salt in the Tihama basin is Middle Miocene in age and an initial phase of halokinesis began in very Late Miocene time. Features associated with halokinesis were detected during seismic interpretation and include salt-pillows, stocks, detached stocks, tongues, canopies and salt cored anticlines. A clear understanding of the implication of salt tectonics in the Tihama basin will lead to oil and gas discoveries.

Abdul Sattar Othman Nani received his MSc and PhD degrees in Exploration from Baku University in 1978 and 1985, respectively. He completed his PhD Equivalency from the University of Karachi in 1986. He has worked for the Ministry of Oil and Mineral Resources, Yemen since 1978. Abdul Sattar has published a number of scientific articles.

VSPs and 3-D Seismic Pitfalls at Shaybah Field, Saudi Arabia

Edgardo L. Nebrija, Saudi Aramco and Bernard G. Frignet, Schlumberger

The 3-D seismic data at Shaybah field does not reveal a clear reflector at the top of the target ShuÕaiba reservoir. Furthermore, its synthetic seismic response varies areally while several intra-reservoir reflections observed on the 3-D data cannot be confirmed on the synthetics. Two causes have been suspected: (1) contamination of the 3-D data by residual multiple noise; and (2) editing/environmental effects on the Shaybah density/sonic logs. Hence, the reservoir structure map is based on picks made on a consistent reflector closest to the reservoir, the top of the Biyadh Formation at the base of the ShuÕaiba.

Since acquiring and processing the 3-D seismic data, sonic and density have been logged from total depth to surface and zero-offset VSPs shot in 13 vertical wells. The QC-VSP processing, based on semblance-weighted deconvolution, improves the originally low airgun source frequency and makes the processed VSPs exceed 3-D resolution. These VSPs consistently: (1) detect a powerful top Biyadh reflection which does not always tie the noise-contaminated 3-D seismic; (2) confirm the weak or absent top ShuÕaiba reflection; and (3) tie shallower strong reflectors, such as the Rus and Aruma.

Tracking the Biyadh reflector on the 3-D is not straightforward. The reflection pattern contains ambiguities which require interpretive separation between what is geologically reasonable from what is not. The VSPs and synthetics demonstrate the presence of several strong multiples in the 3-D seismic which cause these ambiguities. A non-conventional approach whereby multiples identified by the VSP are tracked away from the wellbore clarifies the geological section and leads to improved horizontal well planning in the area around the vertical well. Nevertheless, in some cases, even careful multiple tracking fails to locate disruptions of the primary reflection, leading to erroneous seismic picks.

Carefully edited and spliced sonic and density logs indicate that sonic velocity increases while density decreases from the overlying shale to the porous ShuÕaiba reservoir. The resulting low acoustic impedance contrast yields a very weak ShuÕaiba reflector on the synthetics. Lack of valid density data in the often washed-out shale has been responsible for the pseudo-ShuÕaiba reflector observed in previous Shaybah synthetics.

The ShuÕaiba reservoir is characterized by fairly uniform porosity. However, in some areas, nuclear and sonic logs show a low-porosity interval with corresponding high acoustic impedance. The VSPs identify this potential flow baffle whose lateral extent can be delineated with the 3-D seismic.

VSP surveys have also been deployed in a Òlook-aheadÒ mode whereby reflections from targets below the current total depth are detected. Extrapolation of the VSP first-arrival data is expected to yield more accurate depth estimates to these horizons than existing velocity surveys at wells several tens of kilometers away.

The VSPs at Shaybah have provided a very critical calibration for the 3-D seismic data, confirming what is signal, isolating noise events which pose interpretation pitfalls, and improving time-to-depth conversion. With the re-processing of the Shaybah 3-D seismic data now in progress, the VSPs acquired to date will continue to serve as a valuable reference on seismic bandwidth, phase, amplitude, signal-to-noise ratio, and velocity.

Edgardo L. Nebrija received a PhD in Geophysics from the University of Wisconsin at Madison. From 1979 to 1992, he worked for Shell Offshore, Inc. in New Orleans, Louisiana in various capacities as Marine Seismic Party Chief, Explorationist and Exploitation Geophysicist. Since 1992, Ed has been a staff member of the Northern Area Reservoir Geology Division of Saudi Aramco responsible for the seismic interpretation of the Shaybah 3-D seismic data in support of development drilling and reservoir characterization of the Shu’aiba reservoir. He has also worked in the Marjan field of offshore Arabian Gulf. Ed is a member of the SEG and EAGE.

Bernard G. Frignet is Interpretation-Development Geophysicist with Schlumberger-Middle East in Al-Khobar, Saudi Arabia. He graduated from Ecoles des Mines de Paris and in 1975 received a degree in Geophysics from Institut Français du Pétrole. He started his career with Bureau de Recherches Geologiques et Mineres in Orleans, France and joined Schlumberger in 1982. Bernard has held various Interpretation-Development assignments in the Africa-Mediterranean and the Far East regions before coming to the Middle East in 1990. His primary interest is the integration of seismic and wireline logs. He has contributed several publications in the field of VSP and sonic. Bernard is a member of the SPE and SEG.

Utilization of Special and Conventional Core Analyses in Characterizing a Central Arabian Sandstone

Taha M. Okasha, James J. Funk and Yaslam S. Balobaid Saudi Aramco

This paper describes the use of both special and conventional core analysis data in characterizing the Upper Permian Central Arabian Sandstone. The test results of various special core analysis tests conducted over the years indicate that core preservation and laboratory procedures play an important role in defining relative permeability, capillary pressure and wettability.

The results of conventional core analysis show high contrast in basic core properties (K and ̅). Large differences in relationships between porosity and permeability support the complexity of the Central Arabian Sandstone. Porosity and permeability variations from well to well, within the same area, and within the same formation, are significant. A new technique has been developed to identify intervals with different porosity/permeability relationships. This technique presents reservoir quality index (RQI) as a function of depth and assists in describing reservoir units which have similar properties.

Relative permeability results of several wells using composite cores at reservoir conditions indicated that oil recoveries ranged from 38% to 85% of original oil in place while residual oil saturations range from 16% to 27% of the pore space. The results of modified Amott wettability tests and United States Bureau Measurements wettability indices revealed intermediate to water-wet character of the Central Arabian sandstone reservoir with an increase in water-wet characteristics with depth. Mercury injection tests showed that this Upper Permian Sandstone reservoir can be classified as a trimodal pore system with different capillary character and median pore radii varying from 0.1 to 4 microns. In addition, the cross-plotting of Amott indices to water and Amott indices to oil in a ternary diagram was introduced as a quick quantifying technique for wettability characterization.

Taha M. Okasha is currently a Laboratory Scientist at Saudi Aramco R&D Center in Dhahran, Saudi Arabia. His major interests are reservoir characterization, formation evaluation and enhanced oil recovery. He holds BSc and MSc degrees in Engineering Geology from Suez Canal University, Egypt and King Fahd University of Petroleum and Minerals (KFUPM), Saudi Arabia. Taha received his PhD degree in Petroleum Engineering from KFUPM. He is a member of the SPE and ACS.

James J. Funk is currently a Senior Laboratory Scientist at Saudi Aramco R&D Center in Dhahran, Saudi Arabia. His major interests are in reservoir characterization, formation evaluation, NMR, and CT scanning applications. He holds a BA in Chemistry from the University of Houston and an MSc in Chemical Engineering from the University of Florida. James was previously an Advanced Research Engineer with Texaco Exploration and Technology Department in Houston, Texas. He has worked in several areas of reservoir engineering including formation evaluation and core analysis. He is a member of SPE, SPWLA and SCA.

Yaslam S. Balobaid is currently a Laboratory Scientist at Saudi Aramco R&D Center in Dhahran, Saudi Arabia. He holds a BSc in Chemistry and Geology degree from United Arab Emirates University. Yaslam’s areas of interest are core analysis and reservoir characterization. He is a member of the SPE.

New Stratigraphic Play Concepts in the Cretaceous, Eastern Offshore Qatar

Wendell G. Olivier, Christopher W. Hollister Chevron Overseas Petroleum (Qatar) Ltd. Laszlo Varkonyi MOL Hungarian Oil & Gas Company and Rashid A. Al-Sulaiti Qatar General Petroleum Corporation

Exploration activity in Qatar has traditionally focused on Jurassic Arab Formation reservoirs, but recently operators have been looking to the Cretaceous section as well for large untapped reserves. Recent production start-ups at Al-Shaheen field (Maersk-operated) and Al-Khalij field (Elf-operated) have indicated substantial potential for the Cretaceous reservoirs. These fields, and much of the perceived remaining exploration prospectivity, involve stratigraphic traps. These stratigraphic play types range from the familiar platform-margin and salt-flank plays, to more exotic paleo-karst/diagenetic and hydrodynamic plays.

New exploration technologies have helped to generate new play concepts for the area. The advent of 3-D seismic for the purposes of wildcat exploration has allowed these stratigraphic concepts to be refined to a level of detail not previously possible. Also, sequence stratigraphic analysis and detailed biostratigraphy have played critical roles in bringing these new prospects to maturity.

Wendell G. Olivier is a Senior Geologist with Chevron Overseas Petroleum (Qatar) Ltd. He received his BSc in Geology from Nicholls State University in 1977 and MSc in Geology from Idaho State University in 1979. Wendell has worked for Gulf/Chevron for 18 years in a variety of locations including the Gulf of Mexico, Rocky Mountains, West Coast of the US and Latin America. He is currently assigned to the Africa/Middle East Business Unit working on the Qatar project.

Christopher W. Hollister is a Staff Geophysicist with Chevron Overseas Petroleum (Qatar) Ltd. He received his BSc degree in Applied Geophysics from the University of California, Los Angeles in 1982, and his MSc degree in Geophysics from Stanford University in 1987. Christopher began his industry career with Gulf, and joined Chevron in 1987. During his career, he has worked seismic interpretation projects in a variety of US domestic and overseas exploration areas.

Laszlo Varkonyi is currently the Chief Geologist for the Middle East Region of the International Exploration and Production Division of MOL (Hungarian Oil and Gas Company). Laszlo received his MSc degree in Geology from the ELTE University, Budapest, Hungary in 1985. In the first part of his career he worked on a variety of projects in Hungary. Since the early 1990s, Laszlo has been working on foreign projects mainly in the Middle East, North Africa, and Southeast Asia.

Rashid Ahmed Al-Sulaiti is the

Exploration Manager for Qatar General Petroleum Company (QGPC). Rashid received a BSc degree in Petroleum Engineering from Cairo University in 1977. He has been working on a variety of assignments for QGPC for almost twenty years. In 1990, he assumed the position of Exploration Manager for QGPC.

Basin Mechanics and the Predictability of Fractured, Stylolitized and Vuggy Reservoir Location and Characteristics

Peter J. Ortoleva Indiana University

A three-dimensional model of basin stress and deformation history is used to predict the location and characteristics of reservoirs. The inputs to the model are the present-day stratigraphic, thermal, and overall tectonic data from well logs, cores, surface geology, and seismic and other remote techniques. The output is the evolution over the basin of the generation of natural fractures, gouge, compaction, stylolites and vug stability. These predictions give, thereby, the history of the creation of migration routes, seals and reservoirs over the history of the evolving basin.

The model is applied to several basins to illustrate its use in petroleum exploration and production. The cases explored are: (1) tight gas sand production from natural fractures (Piceance Basin, West Colorado, USA); (2) collapsed or fractured vuggy reservoirs in carbonates with fracture-enhanced production (Permian Basin, West Texas, USA); and (3) salt tectonic-associated reservoirs (the US offshore Gulf). These diverse examples can be analyzed with our fully three-dimensional finite element model due to the generality of our rock rheology. The latter integrates poroelasticity, nonlinear continuous deformation, fracturing and pressure solution with diageneis, multi-phase hydrology and temperature dynamics. The result is a unique model that yields important insights into the present-day and geological history of formations or whole basins of interest. Enhanced insights are gained because the interpretation of the usual data (seismic, well log, core analysis, etc.) are constrained by the laws of fluid flow, diagenetic reaction and rock mechanics.

Peter J. Ortoleva has been analyzing reaction-transport systems for the last 28 years. During this period, he and his students have developed over 20 numerical codes for simulating crystal growth, reaction-diffusion systems, mechano-chemistry, reactive flow in porous media, and stochastic phenomena in reaction-transport systems. The main emphasis of his work over the past 16 years has been on geochemical phenomena in general and in the genesis and dynamics of compartments and the development of geochemical exploration and engineering codes. He has written two monographs on geochemistry and chemical reaction theory, has edited an AAPG Memoir on compartments, and has recently completed a monograph on basin compartmentation.

A Comprehensive Palynozonation of the Devonian-Carboniferous of the Gulf Region, Middle East and North Africa

Bernard Owens and Janet Lines British Geological Survey/University of Sheffield

Accurate palynostratigraphic calibration of the Devonian-Carboniferous sequences in the Gulf Region and throughout the Middle East are frequently impeded by the absence of a regionally specific sequence of palynological biozones. Correlations are commonly achieved by dependence on long range comparisons with assemblages from the Euramerican Continent. High reliance is commonly placed on the presence of a small number of stratigraphically significant miospore taxa which are widely distributed throughout the Old Red Sandstone Continent and marine Devonian and the more varied facies regimes of the Carboniferous in northwest Europe without any attempt to recognize the value of the large number of indigenous taxa present in the northern margin of Gondwana. A major review of all published data available from Morocco to Iran has critically assessed all distribution data with particular emphasis on data sets from Saudi Arabia, Libya and Algeria. The large dataset generated permits the establishment of a comprehensive series of twenty seven biozones extending from the Pridolian to the Gzhelian. Independent biostratigraphical evidence to calibrate the zonal boundaries is sparse but all available evidence is integrated. Correlations are proposed with all previously established local basinal zonation schemes and local basinal lithostratigraphical units are assigned to the new zonal units.

Bernard Owens is an Upper Paleozoic Palynologist working at the British Geological Survey in Nottingham where he is also Manager of the Basin Analysis and Stratigraphy Group. During the past 18 years he has managed major research projects involving a team of leading European palynologists in Libya and the Arabian Peninsula. Bernard is a former President of the Commission Internationale de Microflore du Paleozoique and currently holds an academic chair in the University of Sheffield where he is Director of the Center for Palynological Studies.

Janet Lines is a Technical Assistant in the Basin Analysis and Stratigraphy Group of the British Geological Survey. In the last decade she has been a contributor to major review studies of the Carboniferous palynology of the Arctic to North Africa and the Devonian-Carboniferous palynology of North Africa, Middle East and Gulf Region.

Exploration in Compartmented Basins: Data Integration Through Diagenetic, Hydrologic, Mechanical Modeling

Anthony J. Park Indiana University

Many reservoirs world-wide have been found in association with compartments, i.e., in sediments enclosed in diagenetically enhanced permeability barriers. To further the effort of exploration of these and to aide in their characterization, we have developed a three-dimensional numerical simulator, CIRF.B, that effectively uses observed formation pressures, well logs, seismic data, and basin history and sediment composition data.

This program, CIRF.B, simulates diagenetic mineral reactions and associated chemical compaction to capture the development of seals and porosity and permeability modification. It simulates sediment deformation (including mechanical compaction) and stress evolution to predict the location and history of fracturing, along with fluid flow. Thus, the model simulates the formation of fractured and overpressured reservoirs, as well as the more classical structural and stratigraphic traps. The model generates petroleum using thermal decomposition kinetics.

To illustrate the applicability of the model, examples will be shown from the Anadarko, Piceance, and West Texas Permian Basins of USA. These gas- and oil-rich basins provide a full suite of carbonate to siliciclastic reservoir lithologies where production is from matrix, vug, karst, or fractures. Of particular interest here is the Permian Basin, West Texas, which has many facets in common with the producing carbonate fields of the Middle East. Comparisons of predicted and observed compartments from this region will be presented.

Anthony J. Park completed the Bachelor of Science degree in Geology from the University of Washington, in 1985. Since then he has been associated with the Department of Geology at Indiana University, where he has completed the Master of Science and Doctor of Philosophy degrees in Theoretical Geochemistry. He is currently a Research Associate at the Laboratory for Computational Geodynamics. While working for the graduate degrees, Anthony has done extensive internship and contract work for Amoco and Mobil. For two years, from 1995 to 1996, he was a post-doctoral fellow at the Institut Français du Pétrole in Rueil-Malmaison, France.

The Seismic Sequence Stratigraphy of the Ghudun/Safiq (Ordovician and Silurian) of North Oman

Mark Partington, Tom Faulkner, Angus McCoss and Eilard H. Hoogerduijn Starting Petroleum Development Oman

The Ordovician and Silurian sediments of North Oman comprise a thick interval of proximal braid plain paralics (Ghudun Formation) overlain by a series of shallow marine mudstones and sandstones (Safiq Formation) probably deposited in a glacial/peri-glacial paleoenvironment. Over 33% of wells penetrating the interval have oil or gas shows. In order to understand the hydrocarbon trapping potential of the Ghudun/Safiq in North Oman, a predictive sequence stratigraphic framework was defined to constrain the lateral and vertical distribution of reservoir, source and seal in the area.

Based on detailed well log correlations and biostratigraphic analysis of over 110 exploration wells, the Ordovician to Silurian of North Oman is subdivided into five 2nd-order tectono-stratigraphic units, within which over 20 shorter term, higher frequency changes are superimposed. The depositional history of the Ghudun/Safiq was controlled by an interaction of eustatic sea-level variations, climate, sedimentation rates and local halokinetic subsidence, resulting in a number of fining and coarsening upwards, 3rd-order, cycles of varying duration. A wide variety of vertical and lateral facies changes are recognized within the Safiq Group of North Oman, from proximal braid plain sandstones and shelf sands, to deeper water mass flows.

The recognition and identification of regionally correlatable units within the Ordovician and Silurian sequences of North Oman has resulted in the identification of three major play opportunities with a wide variety of minor play opportunities.

The exploration well-based scheme was further integrated and tested with the observed seismic sequence stratigraphy to produce a predictive template which is currently being tested by a vigorous exploration campaign. One of these plays has already been positively tested and is currently under appraisal.

Mark Partington is currently a Senior Seismic Interpreter in Petroleum Development Oman (PDO). He has MSc and PhD degrees from University College, London and the University of Aberdeen. Mark has 17 years petroleum exploration experience. Before joining PDO he was employed as a Consultant Stratigrapher by Shell International in the Netherlands, prior to which he worked as an Exploration Geologist and Palynologist with BP and Robertson Research International, working mainly on the UK and Norwegian North Sea. Mark has published over 10 papers on exploration geology, stratigraphy and palaeontology.

Tom Faulkner (see abstract “The Athel Play in Oman: Controls on Reservoir Quality” on page 61 for biography and photograph)

Angus McCoss is New Opportunities Team Leader in the Exploration Department at Petroleum Development Oman (PDO). Angus has a PhD in Structural Geology from Queens University, Belfast. Before joining PDO, Angus worked for New Opportunities in Shell China and Shell Research in The Netherlands.

Eilard H. Hoogerduijn Starting received a PhD in Structural Geology from Utrecht University in 1991. He joined Shell in the same year and was posted to SIPM (later SIEP) in The Hague, Netherlands. There Eilard was involved in the development of prospect evaluation software. Subsequently he moved into a new venture exploration team, looking at opportunities in the Middle East. Following a year in a reorganization team, he got involved with fault-seal analysis research in Shell’s EP Research organization in Rijswijk, Netherlands. Eilard joined Petroleum Development Oman’s Frontier Exploration Team in mid-1997.

Resolving the Near-Surface Velocity-Depth Ambiguity

Peter I. Pecholcs, Son Nguyen Saudi Aramco and Dan Kosloff Paradigm Geophysical

In Central Saudi Arabia, seismic data is acquired along lines over near-surface conditions which include different combinations of sand lenses, buried channels, shallow leaching, subcropping formations, and in some areas the effects of a shallow unconfined aquifer. In addition, recent field work has shown the existence of significant post-Triassic surface folds which may have formed by anhydrite dissolution and collapse or basement reactivation. These variable near-surface conditions give rise to both lateral velocity and structural variations and thus to time anomalies with wavelengths as small as a common depth point interval and much greater than an effective spread length.

In the study area, the sparsely spaced and shallow uphole control points could not be used to generate a reliable 3-D average velocity-depth model. The base of weathering is well below the maximum uphole penetration depth. Fortunately, the spatially-varying unconsolidated sand are underlain by multiple refractors. The first breaks can be reliably picked and a delay time solution calculated. But without accurate velocity or depth of weathering control, a velocity-depth ambiguity problem exists and a unique refraction static solution cannot be obtained from accurate time delays. This ambiguity can be overcome only by drilling strategically placed upholes through the base of weathering or indirect velocity measurements from shallow reflectors. Otherwise, we rely on the creative interpretation skill of the interpreter and the near-surface modeler. The interpreted near-surface velocity-depth model is used to calculate datum statics and applied to the stacked time section which effectively downward continues the sources and receivers to a seismic reference datum (SRD). At this stage, the interpreter typically assumes the datum- corrected time section is free of most near-surface velocity anomalies.

Prospect generation begins by identifying time anomalies, interpreting time horizons and converting these time horizons to depth horizons. The process of converting a time section to depth section ultimately determines if these time anomalies have any commercial value. There are several top-down approaches available for converting a time section to a depth section and all depend on the initial near-surface velocity-depth model. If the top macro layer(s) are not accurately modeled and validated, these errors will propagate into the subsurface and introduce or remove structures.

A strike and dip line (over an existing low-relief field) were chosen which cover an area with nearly flat surface topography and formations dipping at angles of less than one degree. Independent near-surface velocity-depth models were constructed and compared from upholes, refraction delay time solutions and coherency inversion. Each of these independent shallow structures differently affect the conversion of time-to-depth. The shallow reflection data was carefully reprocessed, interpreted and integrated with constrained reflection/refraction tomography and pre-stack depth migration methods to improve the accuracy of the depth image. Final time-to-depth conversion velocities were calibrated with sonic logs and check shot surveys.

Peter I. Pecholcs is currently working with Saudi Aramco. He received a BSc degree from Suny StonyBrook in 1980 and a MSc degree from Columbia University in 1982. Prior to joining Saudi Aramco, Peter worked with Sohio Petroleum between 1983 and 1988, the University of Hawaii between 1988 and 1991 and United States Geological Survey from 1991 to 1992. He is interested in wave p propagation and inversion.

Son Nguyen is currently working with Saudi Aramco. Son received his BSc degree from MSU in 1980. He worked with Teknica Inc. between 1982 and 1988, Interseis Inc. between 1988 and 1989 and Geocenter Inc. between 1989 and 1990. Son is interested in seismic data processing and inversion.

Dan Kosloff holds a PhD degree from the California Institute of Technology in 1978. Since 1992 Dan has been working with Paradigm Geophysical. He is interested in seismic wave propagation and inversion.

Paleogeographic Evolution of the Northern Arabian Plate

Dogan Perincek King Fahd University of Petroleum & Minerals Orhan Duran, Nihat Bozdogan and Tanyol Coruh Turkish Petroleum Corporation

Southeast Turkey is located at the northern margin of the Arabian Plate. Sedimentary rocks were deposited in several basins from Precambrian to Recent. The autochthonous strata were effected by tectonic events which caused several sedimentological breaks and unconformities.

The oldest known lithostratigraphic unit is the Precambrian volcanoclastic, shale and sandstone. It is overlain unconformably by the Cambrian, which is characterized by continental to transitional type clastics at the bottom, shelf carbonates in the middle, and shallow marine shale and sandstone alternations at the top. This unit grades into coastal shallow marine deposits of the Ordovician sequence which is overlain by the Upper Devonian-Lower Carboniferous coastal to shallow marine deposits in the east. Above a regional unconformity, the Upper Silurian-Middle Devonian shallow marine rocks were deposited in the central part of Southeast Turkey. The Permian, composed mostly of carbonates and some clastics, is present only in the eastern part of the study area.

The Paleozoic and Mesozoic rocks seem to be comformable with minor breaks in sedimentation in the eastern part of Southeast Turkey. The Lower Triassic comprises two argillaceous carbonate units separated by a red bed sequence. The overlying Middle Triassic-Lower Cretaceous sequence is represented by a carbonate-evaporate sequence of restricted to open marine environments in the mid-southern parts. It grades laterally into shallow marine carbonates, both in the eastward and westward directions.

A regional unconformity is present at the base of the Aptian-Cenomanian Mardin Group which is the main oil-producing sequence in Southeast Turkey. This group is represented by various types of shallow marine carbonates and semi-restricted deep marine organic-rich carbonates. After a sedimentological break, transgressive shallow to deep marine deposits were developed during the Coniacian and Maastrichtian. The presence of the Upper Campanian-Lower Maastrichtian turbiditic clastics is an indicator of the intense tectonism in the northern part of Southeast Turkey. Following this tectonic phase, reefoidal and bank-type carbonates were deposited in relatively stable, marginal and platform-type marine environments in the north. However, the southern parts were the area of deep-marine deposition. These conditions prevailed at the end of the Paleocene. During the Early-Middle Eocene an extensional tectonic regime was effective in the north. The Early-Middle Eocene deposition was terminated by a regression in the Late Oligocene time.

After a regional hiatus, the sedimentation in a transgressive sea took place during the Early-Middle Miocene. Turbiditic clastics, bank-type carbonates and shallow marine to continental clastics and carbonates were deposited during this time. The deposition ended with the alluvial and fluvial deposits of the Late Miocene to Pliocene.

Dogan Perincek received his MSc in Geology and PhD in Petroleum Geology from the University of Istanbul in 1972 and 1978, respectively. He worked with the Turkish Petroleum Corporation as a Structural Geologist and Petroleum Explorationist between 1975 and 1989. Dogan also worked with King Fahd University of Petroleum and Minerals (KFUPM) as Research Scientist, as an Explorationist with Mobil Exploration and Huffco Turkey Incorporated, as Geophysicist with the Geological Survey of Victoria (1992), Geological Survey of Western Australia (1995) and World Geoscience Co. Ltd. (1997). Dogan rejoined KFUPM in late 1997. Dogan is a member of the AAPG, Australian Society of Exploration Geophysicists, Petroleum Exploration Society of Australia and Dhahran Geological Society.

Orhan Duran received his MSc degree from the University of Istanbul and joined Turkish Petroleum Corporation (TPAO) in 1974. He worked with the Arabian Gulf Oil Company in Benghazi, Libya between 1982 and 1986. He returned to TPAO as a Senior Geologist and then became a Deputy Group Manager of International Projects. He is currently Group Manager of the Research Center. Orhan published numerous papers and is a member of the AAPG, Chamber of Geological Engineers of Turkey, Association of Petroleum Geologists of Turkey and EAGE.

Nihat Bozdogan received a MSc degree in Geology from Hacettepe University in Ankara, Turkey. He joined the Research Center of the Turkish Petroleum Corporation as a Stratigrapher. Nihat is currently Manager of the Stratigraphy Department of the Research Center. His interests include palyno-stratigraphy, palinofacies, petroleum system and paleogeographic evaluation of Paleozoic sequence of southeastern Turkey and the Arabian Plate.

Tanyol Coruh received his MSc degree in Geology from Hacettepe University in Ankara, Turkey in 1973. He worked for the Mineral Research and Exploration Institute of Turkey as a Field Geologist for four years. In 1977 he joined the Research Center of the Turkish Petroleum Corporation as a Stratigrapher. His main interest is foraminifera biostratigraphy of southeastern Turkey.

Seismic Imaging of a Water Table and its Use as a 3-D Seismic Datum

William M. Petersen and Marty Rademakers Saudi Aramco

A distinctive shallow seismic event is noted on seismic records acquired in a portion of Central Arabia, east and south of Riyadh. This event is relatively flat, and is cut by reflections that abruptly change seismic character as they cross the event. Analysis of well-log data and synthetic seismograms indicate that the event is the seismic response to the local water table, which, in the area of this study, is at a depth of about 1,000 feet. The water-table seismic event is developed within the porous sands of the Biyadh Formation, but terminates to the west where the water table enters the Buwaib carbonates. To the east, north and south, the event extends beyond the study area.

The water-table seismic event proved to be of use in providing an acceptable datum-statics solution for the Nuayyim field 3-D seismic survey. The initial datum-statics model for the survey was derived from a grid of 143 upholes, drilled 200 to 600 feet deep. The 3-D seismic data processed using the uphole model exhibited false time structures of ±12 meters resulting from near-surface velocity variations. The very gentle real structure of Nuayyim field necessitated a better datum solution. A water-table datum was found to be considerably more effective than the uphole solution in removing near-surface velocity effects.

William M. Petersen (see abstract “Geochemical Evidence for Reservoir Compartmentalization in Central Arabian Paleozoic Reservoirs” on page 96 for biography and photograph)

Marty Rademakers (see abstract “Improved Characterization of the Unayzah Reservoir, Central Arabia, from 3-D Seismic with Stratigraphic Inversion and Statistical Pattern Recognition” on page 124 for biography and photograph)

Layered Acoustic Impedance Inversion and its Impact on Reservoir Characterization

Stephen J. Pharez, Andrew Strachan and Jo White Compagnie Générale de Géophysique

From reduction of exploration risk, through to optimizing field management, reservoir characterization is a common problem throughout the exploration and production cycle, and seismic data have a key role in the reservoir characterization process. Gluck et al. (1996) described a unique, layered approach to acoustic impedance inversion and here we demonstrate the use of the technique in identifying the spatial extent and quality of reservoir sands from two differing environments; the North Sea and offshore Nigeria.

The acoustic impedance inversion technique used, employs a model-based approach to produce a finely- stratified, broad-band impedance model. This model is iteratively updated with impedance and interface variations on a global basis. One of the benefits of this truly 3-D technique is that the starting macro-model requires only sparse a priori knowledge and does not require direct input of the well logs in any form. This means that all available wells can be used to validate the final layered impedance micro-model and thus enable lateral prediction of lithology, porosity and fluid content within a reservoir.

3-D time horizons located at the main impedance breaks define the initial macro model layers. From this, a series of finely-stratified layers, are produced by optimizing the match between the observed and modeled seismic data using a simulated annealing method. This may then be output as a conventional cube and examined using an interpretation workstation. However, as each layer has time, impedance and thickness attributes, a higher level of information content can be extracted by visualizing these layers in 3-D; not only to reveal the local variation of impedance within a layer, but also to examine the connectivity between reservoir segments.

During the inversion of a migrated volume from the North Sea, a number of significant features were identified. We will illustrate the presence of a low impedance structure with channel morphology which is not visible on the seismic amplitude data due to tuning effects. At the target level, a high impedance zone was also resolved between two wells. This indicated the possibility of a permeability barrier within the reservoir and the correlation with well data will be explored.

Our second study is a relatively simple Niger Delta rollover structure of alternating deltaic sand-shale sequence with dip closure. The principle reservoir sands are variable in quality but show a clear low impedance response, which is enhanced by the presence of oil. Calibration to well data shows there is excellent delineation of the producing reservoirs from the seismic impedance response. Inversion of the seismic data correlates with the known porosity information and delineates the extent of the reservoir; in particular, the shaling-out of the deeper sand downdip. The results also show the presence of a thin shale cap on the main reservoir sand which is not visible on the seismic but is highlighted by the inversion.

The use of a unique, layered approach to acoustic impedance inversion, combined with visualization of the resultant layer attributes, provides a very powerful tool for reservoir characterization studies and the planning of horizontal well trajectories. The layer geometries, which are derived without interpretation, conform to known lithostratigraphic boundaries and greatly aid the identification of features not resolved on the original seismic data. Calibration of the impedance volume with petrophysical data permits delineation of the main reservoir sands, which coupled with volumetric visualization enables connectivity evaluation.

Stephen J. Pharez received a BSc degree (Honors) in Geophysical Sciences from Southampton University and has since spent 20 years within the industry in both service and oil company sectors. Most recently Stephen was with the BP/Statoil alliance before joining Compagnie Générale de Géophysique 2 years ago to head the Integrated Geoscience activity in London. Areas of interest include depth imaging, multiple suppression and the use of seismic attributes for reservoir characterization.

Andrew Strachan has more than three and a half years industry experience, three of which are with Compagnie Générale de Géophysique (CGG), after completing an MSc in Exploration Geophysics from Imperial College, London. Throughout his time at CGG he has been involved in a variety of projects ranging from depth imaging, acoustic impedance inversion studies and OBC multi-component processing.

Jo White joined Compagnie Générale de Géophysique’s Integrated Geoscience Services Department as a Geologist, having gained 3 years experience working in the UK for two US oil companies (Conoco and Brabant). His expertise is in 3-D seismic interpretation, depth mapping and well log analysis. He received his MSc degree in Petroleum Geology from Imperial College and MA in Geology from the University of Cambridge. Jo is a member of the AAPG and PESGB.

The Structural and Tectonic Evolution of East-Central Oman from the Cambrian to the Tertiary

Robin Pilcher, Amerada Hess Ltd., UK, Gerald P. Roberts and Neil A. Harbury Birkbeck College and University College London

The Huqf Uplift is a long-lived structural high situated in east-central Oman, on the southeast margin of the Arabian Plate. Structural mapping was carried out in this area between 1993 and 1996 to determine the geometries, kinematics and timing of deformation in the Huqf Uplift. The results of a detailed field based study in the region, presented here, are used to constrain the structural and tectonic evolution of east-central Oman. Evidence for two distinct structural deformation phases between the Precambrian-Cambrian and Tertiary is presented: a Precambrian-Cambrian phase of east-west extension and a late-Cretaceous phase of north-south left-lateral strike-slip. For each of these deformation phases structures, such as strike-slip faults, folds, thrusts, normal faults, joints, were recorded in the field and used to determine the geometry and kinematics of deformation. The timing of deformation is constrained using a combination of published stratigraphic schemes, primary field logging, sample collection and nannofossil dating.

In the Huqf Uplift, the Precambrian-Cambrian extensional event is characterised by north-south trending normal faults with erosionally truncated footwall topography, and fanning fluvial paleocurrent patterns. Published models for the tectonic driving forces responsible for this deformation do not satisfactorily explain the structures recorded during this study and a new model is proposed whereby the extensional basins in Oman formed in response to left-lateral motions on the Najd Fault Zone. The strike-slip deformation is characterised by major north-south, left-lateral transpressional strike-slip faults and associated folds and Riedel shear arrays. Outcrops of ophiolitic strata along the southeastern margin of Oman were also examined and found to contain similar left-lateral transpressive structures. A new tectonic model for the relationship between the plate-margin processes responsible for ophiolite obduction, and the strike-slip structures in eastern Oman, is proposed.

Robin Pilcher received his MSc in Applied Structural Geology and Rock Mechanics from the Royal School of Mines, Imperial College, London in 1993. He gained his PhD, a study of the structural and tectonic evolution of the Huqf uplift, Oman, from Birkbeck College, University of London in 1997. Robin currently works as an Exploration Geologist with Amerada Hess Ltd., UK.

Gerald P. Roberts achieved his BSc in Geology in 1987 from the University of Wales, his PhD in Structural Geology from the University of Durham in 1991, and then became a Natural Environment Research Council Research Fellow at the University of Manchester in 1990 to 1992. Gerald was appointed as a Lecturer in Structural Geology and Tectonics at the University of London in 1992.

Neil A. Harbury (see abstract “A Regional Sedimentological Study of the Lower Cretaceous Shu’aiba Formation in Oman” on page 53 for biography and photograph)

Latest Results of the Natih 9C3D Seismic Survey

Hans Potters and Vic Hitchings Petroleum Development Oman

In this paper we discuss the latest results of the Natih 9-component 3-dimensional (9C3D) seismic reservoir characterisation experiment carried out jointly by Petroleum Development Oman, the main oil producer in Oman, and Shell Research in the Netherlands. The survey was carried out in 1991-1992 and comprised the acquisition, processing and interpretation of a 28.4 square kilometer 3-D nine-component survey over the Natih field in Northern Oman. After an introduction to the geological, geophysical and reservoir engineering aspects we present maps of the polarization and time splitting between the fast and the slow shear wave over the Natih reservoir. The observed very large anisotropy, viz. in excess of 20 percent time splitting over a large part of the survey, suggests that the main objective of the experiment -fracture detection by a multi-component 3-D survey - has been met. An independent fault modelling exercise was undertaken on the Natih field based on the complete 3-D seismic survey results. Fault/fracture ‘domains’ were identified on the basis of fault frequency and orientation. Comparisons with the 9C3D results showed that the domains were present in the latter data set as areas of coherent splitting character. A review of the production data for the field indicated that the domains were consistent with well behavior reflecting the degree of fracturing.

In addition, we present evidence that shear waves are sensitive to fluid type in fractured media. Two observations are examined from the Natih 9C3D data where regions of gas are characterised by slow shear velocities. Firstly, the shear-wave splitting map of the Natih reservoir exhibits much larger splitting values over the gas cap on the reservoir. It is argued that this increase in splitting results from a decrease in the slow shear velocity which is a response to both fractures and the fracture filling fluid. Secondly, the thick Fiqa shale overburden exhibits a low shear-velocity anomaly that is accompanied by higher shear reflectivity and lower frequency content. No such effects are evident in the conventional P-wave data. This feature is interpreted as a response to a gas chimney above the reservoir, a conclusion supported by both effective-medium modelling, drilling data and geological knowledge.

The introduction of gas in fractured rock appears to decrease the shear velocity whilst leaving the compressional velocity largely unaffected. This conclusion has direct implications for seismic methods in exploration, appraisal and development of fractured reservoirs and suggests that S-wave data, rather than the conventional P-wave data, provide direct hydrocarbon indicators. These observations are supported with modelling results.

Hans Potters obtained a PhD in Physics at Utrecht University in 1984. He worked on velocity modeling, inversion, AVO, rock properties and shear seismic during research and section head assignments with Shell in the Netherlands and the USA. Hans became head of the Quantitative Interpretation and Geophysical Support group in Petroleum Development Oman in 1994.

Vic Hitchings obtained a PhD in Geology at University College, Swansea in 1982. He worked in core evaluation with Robertson Research for six years in the U.K. and Southeast Asia and joined Shell in 1986 as a Reservoir Geologist working in The Netherlands and Nigeria. In 1993 Vic joined Petroleum Development Oman and has worked as the Senior Production Geologist with Fahud/Natih/Lekhwair area developing static reservoir models of faulted and fractured reservoirs.

Fault and Flexure Analysis Using Formation Top Data

Hussam Qasem and Peter J. Ortoleva Indiana University

Data on formation tops is used to identify faults and flexure and characterize them quantitatively. A statistical analysis allows for the estimation of uncertainties inherent in the input data. The result of our data analysis package is a three-dimensional characterization of faults and flexure, a related discretization grid adapted to these features for reservoir simulation, and graphical tools for viewing these structures. Matrix yield criteria and vug and karst collapse criteria are included to estimate the stability of fracture and macroporosity and related producibility.

The analysis is applied to the Permian Basin, West Texas, U.S.A., which has carbonate reservoirs of varying depositional environments. Of interest for this presentation are the basin’s characteristics which are similar to those of the Middle East carbonate strata. Correlations of similarities between these two environments may demonstrate the usability of the proposed analysis for Middle East petroleum resources.

Hussam Qasem graduated from Shaikh Abdul-Aziz Secondary High School in Manama, Bahrain. He has attended Indiana University since January 1995 and is pursuing a degree in Computer Science. He was an Associate Instructor in the Computer Science Department at Indiana University from January 1996 until May 1997. In October 1996, Hussam joined a biochemistry group in the Chemistry Department of Indiana University as a Computer System Administrator and subsequently joined the Laboratory for Computational Geodynamics in March 1997 as a System Analyst. Currently, Hussam is developing techniques for visualizing and analyzing complex three-dimensional geological data. Hussam also has a special interest in graphics and operating systems.

Peter J. Ortoleva (see abstract “Basin Mechanics and the Predictability of Fractured, Stylolitized and Vuggy Reservoir Location and Characteristics” on page 138 for biography and photograph)

Cambrian Intra-Salt Carbonate Stringers of South Oman: Reviving a Complex Exploration Play

Joachim W. Reinhardt, Folco Hoogendijk, Ruwaina Al-Riyami, Joachim E. Amthor, Glen Williams and Neil L. Frewin Petroleum Development Oman

In the period 1978-1983 Petroleum Development Oman (PDO) drilled a number of oil and gas discoveries on carbonate stringer objectives in the Southern Oman Salt Basin. The stringer reservoirs consist of porous dolomites, often over-pressured and stratigraphically trapped in the Cambrian Ara Salt Formation. Although potentially rewarding, with well flow rates up to 1,400 m3 of oil per day, the play was found to be complex with respect to reservoir quality prediction, production behavior, hydrocarbon charge and seismic imaging. As a result, despite a large number of identified prospects, the play has received relatively little and only sporadic attention in the past years.

An integrated project team, established in late 1996 within the Exploration Unit of PDO, is aiming at fully assessing the remaining upside potential of the play by applying new seismic and geological concepts and drilling structures representative of the prospect portfolio. Increasingly available 3-D seismic data and its integration with sedimentological, geochemical and structural data, is essential for the improved understanding of the play.

A critical success factor for the play is the 3-D seismic imaging of the stringer prospects. Long-offset recording during the seismic acquisition stage has proven to be crucial. During data processing, the removal of seismic multiples, imaging of steeply dipping events such as the flanks of the salt and the carbonate stringers themselves, and careful velocity picking have significantly improved the 3-D seismic data quality. During the interpretation stage, seismic-to-well matching, seismic attribute mapping, careful selection of display parameters, and the application of an inverse “bottom-to-top” seismic stratigraphic correlation method are important.

As a first step of the project, a new intra-salt stratigraphic framework based on seismic stratigraphy, a reinterpretation of well log and core data using the concept of evaporite-carbonate sequences, and chemostratigraphy was established. This data, merged with regional 3-D seismic structural maps, aided in constructing a series of paleogeographic maps showing predicted reservoir trends in space and time. In addition, focused geochemical studies have addressed the issues of source rock distribution, maturity and richness.

The stringer prospects have now been grouped into risk classes using a seismic facies classification scheme, a reservoir facies prediction model, the hydrocarbon charge risk and finally operational requirements, i.e. type of rig based on the prospect depths and pressure regime.

Joachim W. Reinhardt is currently working as a Senior Seismic Interpreter in the South Oman Frontier Exploration Team of Petroleum Development Oman (PDO). He has been Project Coordinator of the Intra-salt Carbonate Stringer Theme since his arrival at PDO in late 1996. Joachim holds a MSc with Honors in Geology from Erlangen University in Germany. He joined Shell International in 1988 and has since worked for NAM in The Netherlands, Myanma Shell in Rangoon/Burma and Shell China in Beijing.

Folco Hoogendijk is a Seismic Interpreter working for Petroleum Development Oman (PDO) in the South Oman Frontier Exploration Team’s Intra-salt Carbonate Stringer project. He holds a MSc in Geology from Utrecht University in The Netherlands and joined Shell International in 1989. Folco joined PDO in 1996 after working for Shell Expro in London for 6 years.

Ruwaina Al-Riyami is currently working as a Seismic Interpreter in the South Oman Frontier Exploration Team of Petroleum Development Oman (PDO). She joined PDO in 1994 after obtaining an MSc in Geology from San Diego State University. Ruwaina has been involved in the Intra-salt Carbonate Stringer Theme project since late 1996.

Joachim E. Amthor (see abstract “Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation” on page 60 for biography and photograph)

Glen Williams is currently working as a Geophysicist in the Quantitative Seismic Inter-pretation Team in the Exploration Unit of Petroleum Development Oman (PDO). He joined PDO as a Contractor from the Geocon Group in early 1997, and has some twenty years of experience as an Exploration Geophysicist, mostly in the Western Canadian Basin. Prior to his assignment with PDO, he worked in Libya with Veba Oil. Glen holds a BSc with Honors in Physics from the University of Victoria, Canada.

Neil L. Frewin (see abstract “Oil Families of Oman” on page 55 for biography and photograph)

Integrated Haushi Hydrocarbon Habitat Study in North Oman

Pascal D. Richard, Peter J.R. Nederlof, Jos J.M. Terken and Nashwa Al-Ruwehy Petroleum Development Oman

In North Oman 20 fields, with a combined STOIIP of 500 million m3, have reserves booked in the Haushi (Gharif and Al Khlata) reservoirs. In addition, some 150 prospects are recognized with a combined UR expectation of 39 million m3. Following a successful exploration campaign, the success ratio decreased progressively. An integrated charge and retention study was therefore carried out to revitalize the play. The aim of the study was to establish a framework for predicting fluid content (gas, oil, water). Components of this were a charge study to explain the hydrocarbon distribution on a basin scale, and a retention study addressing top and fault seal quality.

The oil in the Haushi has been generated by three different source rocks: Q, Huqf (Shuram) and Safiq. However, oil typing shows that over 90% of the oil in place is derived from the ‘Q’ source rock. This seems to indicate a charge problem for prospects outside the ‘Q’ migration fairways. The ‘Q’ kitchen was defined with the help of chemical odometers, nitrogen compounds whose relative concentrations provide a measure of migration distance. Measurements on 18 ‘Q’ oils suggest a source area on the western margin of the Ghaba Salt basin, immediately to the east of Ramlat Rawl and Saih Rawl. Seismic lines across this area show salt filled rim synclines which possibly contain the ‘Q’ source beds.

The two main sealing lithologies are carbonate (Khuff and Haushi Limestone) and shale (intra Haushi shales), which can act as both top seal and/or fault seal. Based on log response, seal lithologies for gas-only, gas-and-oil and oil-only could not be discriminated. Recent mud logs over the Khuff Formation (top seal of the Gharif reservoirs) showed no evidence for a gas fraction, suggesting that the Khuff is an efficient gas seal. However, it has been observed that gas fields tends to have thicker Khuff seals and smaller fault throw than the oil fields. This trend is related to the regional westward tilting of the basin during Khuff deposition.

Fault seal has been analyzed on across-fault juxtaposition diagrams. Highly faulted prospects above salt domes are water bearing. However, apart from these extreme cases, seal breaching is not seen as a general problem. Sand-sand juxtaposition areas along faults were calculated in several Gharif accumulations. Although cross fault juxtaposition was identified as the critical factor determining the hydrocarbon contacts in some moderately faulted fields (e.g. Burhaan), there seems to be no general relation between fault throw and hydrocarbon retention.

Based on the long-distance migration of the Q oil proven by the chemical odometers, and the relation between hydrocarbon fill and Khuff thickness, an opportunity map has been generated for North Oman. A strategy of exploring for stratigraphic traps in the Q migration fairways is deemed to have the greatest chance of success.

Pascal D. Richard is a Structural Geologist with Shell Exploration since 1991. Pascal received his PhD from Rennes University, France, in 1989. He spent five years at the research lab KSEPL in the structural geology group where he was involved in hydrocarbon migration studies and was responsible for Structural Sandbox Modeling. Pascal is now the Structural Geology focal point in the Exploration Unit of Petroleum Development Oman. He is particularly interested in Strike-slip Tectonics, Sandbox Modeling and Prospect Evaluation.

Peter J.R. Nederlof (see abstract “Distribution and Formation of Pyrobitumen in Haima Reservoirs in North Oman” on pages 101-102 for biography and photograph)

Jos J.M. Terken (see abstract “Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation” on page 60 for biography and photograph)

Nashwa Al-Ruwehy (see abstract “Oil Families of Oman” on page 55 for biography and photograph)

Sequence Stratigraphy of the Post-Nappe Units of Oman (Maastrichtian to Miocene)

Jack Roger, Philippe Razin, Chantal Bourdillon and Robert Wyns Bureau de Recherches Géologiques et Minières

Detailed sedimentologic and biostratigraphic analysis of the Maastrichtian to Miocene post-nappe units of the Oman Mountains has made it possible to establish a more complete regional sequence stratigraphy chart. Maastrichtian to Miocene deformation of the Oman Mountains, in part inherited from Late Cretaceous Alpine structures, led to a new paleogeographic configuration with development of the Buraymi Basin in the northwest of the mountain belt and the Abat Basin in the southeast. These two areas show platform-basin transition with a more complete stratigraphic sequence than in the Arabian Platform.

Eleven, 2nd-order depositional sequences have been identified, corresponding to major transgressive-regressive cycles, and show a depositional partitioning between platform and basin that can be directly related to tectonic activity. The periods of tectonic relaxation, reflected by subsidence, are characterized by aggradation of the carbonate shelves onlapping the Arabian craton, i.e. Maastrichtian, Selandian-Thanetian, Ilerdian-Ypresian, Lutetian, Bartonian, Priabonian, Rupelian, Chattian-Aquitanian, Burdigalian-Langhian. The periods of extensional tectonism are marked by craton uplift and emergence, with slope and hemipelagic deposition being restricted to the reactivated basins and faulted margins of the former platforms, i.e. latest Maastrichtian-Danian, Cuisian, latest Bartonian-Early Priabonian, latest Rupelian. The Early Miocene compressional tectonism caused infilling of the last active troughs and uplift of the present Oman Mountain chain.

Jack Roger and Philippe Razin (see abstract “Sedimentology and Reservoir Geometry of the Late Permian Upper Gharif and Lower Khuff Formations in Interior Oman: Outcrop Study in the Haushi Area” on pages 82-83 for biographies and photographs)

Chantal Bourdillon has been with the Bureau de Recherches Géologiques et Minières since 1982. She received a PhD degree from the University of Marseille. She has been involved in biostrati-graphical studies of Oman, Saudi Arabia and Red Sea. Chantal is interested in Maastrichtian to Priabonian biological events. She is a member of the French Geological Society, of the European Paleontological Society, the French Paleontological Association and the Group of Paleogene Study.

Robert Wyns (see abstract “The Paleozoic Succession of the Tabuk Basin in Saudi Arabia: Lithostratigraphy, Sedimentology and Sequence Stratigraphy” on page 105 for biography and photograph)

Meteoric Diagenesis and Porosity Evolution Using Cathodoluminescence Petrography, Shu’aiba Formation (Lower Cretaceous), Abu Dhabi, United Arab Emirates and Jebel Akhdar, Oman

S. Duffy Russell Abu Dhabi Company for Onshore Oil Operations and Gordon M. Walkden University of Aberdeen

Previous workers have successfully determined porosity evolution using cathodoluminescence (CL) petrography on sediments of different ages and geographic locations, yet little CL data is available for the Shu’aiba Formation. The Shu’aiba provides one of the best examples of CL response in carbonate sediments from four subsurface and six outcrop study areas. Petrographic studies of porosity evolution through the application of CL analysis reveal a complex diagenetic history of exposure to mixed meteoric and marine pore fluids. Although there is no conclusive evidence of subaerial exposure (such as caliche, paleokarsts, vadose cements), there is direct evidence of significant exposure to meteoric pore fluids within a phreatic environment.

The diagenesis of the Shu’aiba involved early marine and meteoric cementation phases and late meteoric-marine mixed cementation. Early syntaxial cements reveal a sequence of four clear zonations - non-luminescent (NL), bright, dull, and bright/dull subzoned cements. Microprobe analyses reveal zonal concentrations of Mn and Fe consistent with early exposure to meteoric oxic fluids (NL cement -Mn 32-68 ppm, Fe 80-103 ppm) and evolution of the pore fluids through stagnation (bright cement) to two phases of mixed meteoric-marine burial (dull cement - Mn 320-630 ppm, Fe 1,570-3,620 ppm to bright cement - Mn 470-690 ppm, Fe 149-360 ppm). Multiple episodes of exposure to meteoric-phreatic pore fluids occurred, as evidenced by the successive dissolution of aragonitic inner shellwalls of rudists. Cement zonations are correlative over great distances within one stratigraphic subunit of the upper Shu’aiba, suggesting the uniformity of meteoric-phreatic diagenesis. An understanding of porosity evolution is the key to predicting reservoir quality in highly productive subunits of the upper Shu’aiba.

S. Duffy Russell is currently a Senior Review Geologist with the Abu Dhabi Company for Onshore Oil Operations (ADCO). After receiving his BSc degree in Geology from North Carolina State University and MSc in Geology from Duke University, he spent over 18 years as a Geologist in various Exploration and Producing assignments with Mobil Oil Corporation and as a Geophysicist at Amoco Production Company. His current studies in carbonate diagenesis and sedimentology are part of an ongoing PhD research project at the University of Aberdeen. He is a member of the AAPG, SEPM, SEE, and SPE.

Gordon M. Walkden is currently the Head of the Department of Geology and Petroleum Geology at the University of Aberdeen, Scotland. After receiving a degree from Quintin School in London, he obtained his PhD in Carbonate Sedimentology from Manchester University in 1970. Gordon was appointed Lecturer in the Department of Geology and Petroleum Geology and Senior Lecturer in 1988, and became Department Head in 1993. He has extensive field experience and supervision of research in Britain, Europe, North America and the Middle East.

Attribute-Driven Porosity Estimation by Neural Systems

Muhammad M. Saggaf and Husam Al-Mustafa Saudi Aramco

Neural networks are dynamic systems composed of a large number of interconnected cells, or neurons. In the brain an enormous amount of neurons are operating in parallel at any given instance. Artificial neural networks are based on models of the human brain and behavior. They have proven helpful in recognizing patterns that can be attained by learning through experience, and can be highly effective estimators of non-linear relations.

In this paper, porosity is estimated by applying neural networks to attributes derived from seismic data. A number of wells are employed with the purpose of predicting porosity in the inter-well area, thus producing a 3-D map of porosity from a 3-D seismic survey. After pre-processing, which includes depth-to-time conversion of porosity logs and calibration of synthetic seismograms to the seismic data to at each well location, relevant seismic attributes are extracted from the seismic data. The network is then trained by presenting it with both the derived attributes from the seismic traces at the wells and with the measured porosity there. Porosity is then estimated in the inter-well area by applying the trained network to the entire seismic survey.

Several network geometries and structures are investigated and evaluated, including feed-forward back-propagation and radial basis networks. Special smoothness constraints are imposed on the networks in order to reduce the effect of local minima and converge to a solution that represents the smoothest model that fits data. This also helps to avoid the over-fitting of the data.

The technique has been applied to seismic data in the Shedgum region of the Ghawar field in Saudi Arabia. The network performance is evaluated through systematic cross-validation tests, in which one well is removed from the training set, the network training is carried out, and then the estimated porosity at the hidden well is checked against the measured values there. The process is repeated for each well. These cross-validation tests indicate that neural networks, can be effective at predicting porosity from seismic data, as the agreement between predicted and measured porosity values is rather good. The method can be broadened further by utilizing global optimization techniques like genetic algorithms.

Muhammad M. Saggaf holds a BSc in Mathematics (1989) from King Fahd University of Petroleum and Minerals and a MSc in Geophysics (1996) from the Massachusetts Institute of Technology. His areas of interest include signal analysis, fractal models, wave propagation, inversion, neural networks, fuzzy logic, microprocessor architecture, and parallel computing. Muhammad is a member of the SEG.

Husam Al-Mustafa holds a BSc in Geophysics (1988) from King Fahd University of Petroleum and Minerals, and a MSc in Geophysics (1993) from Texas A&M University. His areas of interest include neural networks, rock properties, shear wave propagation, and fractured reservoirs.

Enhanced Deconvolution of Saudi Arabian Seismic Data

Muhammad M. Saggaf and Roma A. Hergott Saudi Aramco

That reflection coefficients follow the white noise model is one of the fundamental assumptions of conventional deconvolution schemes, especially those based on optimal Wiener filtering (the most widely used technique in the petroleum industry) such spiking and gap deconvolution methods. In other words, reflection coefficients are assumed to be uncorrelated random variables, with a flat power spectral density and an auto-correlation function that is a unit spike. However, analyses of well logs shows that in the majority of cases reflectivity tends to depart from the white noise model, and to have a power spectrum that has a richer content of higher frequencies - a spectral behavior that is often called “blueness”.

The assumption of white noise leads to a conventional deconvolution operator that can recover only the white component of reflectivity, thus yielding a distorted representation of the desired output. In this paper, a new stochastic model, fractionally integrated noise, is proposed for modeling reflectivity. It is a model that more closely approximates the spectral character of reflectivity, and it encompasses white noise as a special case. The conventional deconvolution method is generalized based on this model in order to handle reflectivity that is not white. The technique is implemented as a post-deconvolution spectral compensation filter that restores the non-white component of reflectivity that was removed by conventional deconvolution.

The conventional and generalized deconvolution filters are analyzed by applying them to synthetic traces derived from sonic and density logs of onshore and offshore wells in Saudi Arabia. Comparing the resulting output by the true reflectivity calculated from the logs shows that the generalized filter yields a significant improvement in the accuracy of deconvolution, as indicated by the residual wavelet and RMS errors between the recovered and actual reflection coefficients. The generalized technique is also applied to seismic data sections from north Saudi Arabia on data that is characterized by relatively weak resolution and encumbered by low frequency noise. Visual inspection of the output shows a notable improvement in the sections in terms of enhanced event continuity, wavelet compression, signal resolution, and suppression of low frequency noise.

Muhammad M. Saggaf (see abstract “Attribute-Driven Porosity Estimation by Neural Systems” on page this for biography and photograph)

Roma A. Hergott joined Saudi Aramco in 1980. Since 1992, she has held the position of Group Leader of 2-D Review Processing. She previously worked in seismic processing in Calgary, Canada with Digitech and Seiscan Delta. Roma received her BSc in Mathenatics from the University of Alberta in 1972.

Automatic Log Facies Analysis Based on Competitive Neural Networks

Muhammad M. Saggaf and Edgardo L. Nebrija Saudi Aramco

Manual interpretation of facies from well logs is a laborintensive process that involves the expenditure of a considerable amount of time by an experienced well log analyst, even with the aid of graphical techniques like cross-plotting. The problem becomes especially more difficult as the number of simultaneous logs to be analyzed is increased. Automatic methods that rely on multi-variate statistics are inflexible, require a large amount of statistical data, and often need complex dimension-reduction techniques like principal component and discriminant factor analyses to reduce the problem to a more manageable size. These dimension-reduction techniques, however, are themselves compute-intensive and inflict an unnecessary distortion of the input space.

In this paper we propose to approach the problem of identifying facies from well logs though the use of neural networks that perform vector quantization of input data by competitive learning. These are uncomplicated one-layer or two-layer networks that are small, compute-efficient, inherently well suited to classification and pattern identification, and avoid the difficulties associated with back-propagation feed-forward neural networks; namely that their convergence is often unreliable, they have a monotonous generalization behavior (overfitting, large networks often perform worse than smaller ones on test data), require a considerable amount tweaking for the network geometry and choice of activation functions, and lack biological plausibility.

Competitive networks can be used in either an unsupervised or supervised manner. Unsupervised learning looks for structure in the data without requiring a training dataset. This mode is often called feature-discovery or a “let-the-data-talk” scheme. It performs clustering, or quantization of the input space, but the resulting classes are unlabelled. Supervised learning imposes structure by calibrating the resulting categories by the training dataset and labeling the classes accordingly. It is often called guided or directed classification, as it quantizes the input space into predefined target classes.

Both types of networks are implemented and used for the automatic facies analysis of horizontal wells in Saudi Arabia. Unsupervised networks provide a quantization, or zonation of the penetrated lithologies from which a geologist can start interpretation of the facies encountered in the well. This is done by examining the properties of the resulting classes and labeling them with the appropriate facies names. Supervised networks are first trained on the logs of a vertical well and the facies description derived from its cores. They are then applied on the logs of uncored horizontal wells in the same sabkha for an automatic identification of their facies.

These networks are easy to build and use, and produce results equivalent to those of a human log analyst at a fraction of the time needed for manual analysis. They are also relatively insensitive to incomplete or noisy data and exhibit the usual neural network advantages of generalization, graceful degradation, and adaptability to parallel computing.

Muhammad M. Saggaf (see abstract “Attribute-Driven Porosity Estimation by Neural Systems” on page 149 for biography and photograph)

Edgardo L. Nebrija (see abstract “VSPs and 3-D Seismic Pitfalls at Shaybah Field, Saudi Arabia” on page 136 for biography and photograph)

Sequential Simulations of Porosity in a Carbonate Reservoir

Ali Sahin and Saleem G. Ghori King Fahd University of Petroleum & Minerals

Geostatistical simulation techniques such as Sequential Gaussian Simulation (SGS) and Sequential Indicator Simulation (SIS) were developed recently and have now become popular in simulation of both continuous and discrete variables. These techniques have several advantages including automatic handling of both isotropies and data conditioning, as well as fast computer implementation. SIS has an advantage over SGS in that it does not require any assumption about the distribution of data.

Both SIS and SGS techniques were applied to simulate the porosity distributions within a carbonate reservoir in Saudi Arabia. The results revealed that the realizations generated by SIS have a wider range of variability than those generated by SGS. The histograms and the variograms of the input data were reproduced more satisfactorily with the SGS technique. However, the SIS technique was employed since different correlation ranges existed for different porosity cutoff values. Also, the use of indicator classes in the SIS technique assists reservoir engineers to focus on the range of values which are critical in predicting reservoir performance. Therefore, the SIS technique appears to be more appropriate for the geostatistical simulation of porosity within the reservoir under consideration.

Ali Sahin is currently working as an Associate Professor at the Research Institute of King Fahd University of Petroleum and Minerals (KFUPM) in Dhahran, Saudi Arabia. He is involved in various research projects in the field of petroleum reservoir characterization and mineral deposit evaluation. Ali received his BSc (Honors) in Mining Geology and PhD in Applied Geostatistics from the University of Leeds. After his graduation in 1977, he joined the Mineral Exploration and Research Institute (Ankara, Turkey) as a Senior Geologist. During his stay in Ankara, he also served as a Faculty Member at the Department of Mining and Petroleum Engineering in the Middle East Technical University. Ali joined the Department of Earth Sciences at KFUPM in 1982, where he taught courses in Geostatistics, Economic Geology and Computer Applications in Geology, and participated in the supervision of 14 MSc students. He also served as a member of the Editorial Board of the Arabian Journal for Science and Engineering. Ali is a member of the Institution of Mining and Metallurgy, Turkish Geological Society and the Dhahran Geological Society.

Saleem G. Ghori received his BSc in Petroleum Engineering from the University of Engineering and Technology, Lahore, Pakistan. He received his MSc and PhD degrees from the New Mexico Institute of Mining, USA, both in Petroleum Engineering. After graduation in 1992, he worked as a Research Associate in the Petroleum Engineering Department of the University of Texas at Austin. Saleem joined the Research Institute at the King Fahd University of Petroleum and Minerals in November 1993. His research interests are geostatistics, reservoir flow simulation, tracer technology and parallel processing computers. He is a member of the SPE.

Statistical Distributions and Correlation of Petrophysical Parameters in a Carbonate Reservoir

Ali Sahin, Salih Saner and Hany F. El-Sahn King Fahd University of Petroleum & Minerals

Statistical analysis of petrophysical parameters and correlation between these parameters are extremely important in characterization of carbonate reservoirs. This study demonstrates how these tools can be used effectively to characterize the Arab-D reservoir in the Abqaiq field located in the Eastern Province of Saudi Arabia. Extensive data sets consisting of well-log porosity, core porosity and core permeability values from the productive zones (Zone 1, Zone 2, and Zone 3) of reservoir and lithology indicators from Zone 1 provided the basic data for the study.

Statistical analysis revealed that the well-log porosity and the core porosity distributions of respective zones are almost identical with core porosity distributions having slightly higher mean values. This can be explained by possible bias in core selection and differences in the conditions of measurements. The porosity distribution for Zone 1 is approximately normal reflecting a mixed lithologic framework within this zone. However, due to grain-dominated sediments associated with mainly high porosity values, the porosity distribution for Zone 2 displays asymmetry with a negative skewness. On the other hand, due to mud dominated sediments exhibiting low porosity in Zone 3, the porosity distribution is asymmetric with a positive skewness.

The general pattern of permeability distribution for each zone on the logarithmic scale is similar to that of the corresponding porosity distribution reflecting some degree of correlation between porosity and permeability. The corresponding distributions of vertical and horizontal core permeability values are similar, but their averages are different. The average horizontal permeability values within both Zone 1 and Zone 2 are considerably higher than the corresponding averages for the vertical permeability. However, the reverse is true in Zone 3 with the average vertical permeability being slightly higher than the average horizontal permeability.

The correlation plots between the core porosity and core permeability on semi-log paper and regression analysis revealed relatively poor correlation between these variables with the correlation coefficient being less than 0.7 for all zones. The correlation diagrams for the core porosity and the core permeability within each lithology in Zone 1 indicate that the lithologic control on porosity is not very significant in this zone.

Ali Sahin (see abstract “Sequential Simulations of Porosity in a Carbonate Reservoir” on page 151 for biography and photograph)

Salih Saner is an Associate Professor at the Research Institute of the King Fahd University of Petroleum and Minerals (KFUPM) since 1981. He has 21 years of experience in the petroleum industry and research with specialization in petroleum geology and formation evaluation. Salih received his PhD in Geology from the University of Istanbul in 1977. He worked as an exploration geologist with Turkish Petroleum Corporation for six years before joining KFUPM. Currently, Salih is associated with the Petroleum and Gas Technology Division at the Research Institute as the leader of the Geology and Well Logging Group. Geological basin analysis, reservoir modeling, well logging, rock and pore characterization, and petrophysical studies are the fields of his interest. He has about 30 publications in these fields. Salih is a member of the AAPG, SPE, SPWA, Society of Core Analysts, Association of Turkish Petroleum Geologists, and the Chamber of Turkish Geological Engineers.

Hany F. El-Sahn is currently working as a Scientist at the Research Institute of King Fahd University of Petroleum and Minerals (KFUPM). He received his MSc degree in Earth Sciences from KFUPM in 1992, and his BSc degree in Geology from Cairo University in 1984. Since joining the Research Institute in 1992, Hany has participated in several geological and petroleum engineering projects. His areas of interest include regional geology, carbonate facies analysis, micropaleontology, and computer aided modeling. Hany is the co-author of several publications in the fields of geology, geostatistics and computer programming.

Structural Evolution by Mega-Regional Seismic in the Northwest Triassic Basin (Block 409)

Cherifa Sakher and Farida Benatmane Sonatrach Exploration

The Triassic reservoirs constitute the main plays with the development of the trias argilo-greseux that produce in Hassi R’mel giant gas field. From the tectonic viewpoint this area has a structural style associated with major faults trending northeast-southwest or north-south.

The main phases that have affected this area are the Hercynian and Autrichian orogenies. The effects of the Hercynian orogeny are characterized by significant erosion in Paleozoic time. In the Early Mesozoic, the area was affected by broad subsidence resulting in the formation of a broad basin.

In order to develop a structural and tectonic appraisal of the Talemzane block two directions (northeast-southwest and northwest-southeast) of the megaregional cross- section and geological cross-section were used. Also a satellite image study of the Talemzane block and depth map was used to determine the structure and deformation along the study area and extrapolate the information southward into the Hassi R’mel block and eastward into the Mehaiguene block.

This approach improved our understanding of the basin architecture and the planning of future seismic and exploration activities.

Cherifa Sakher graduated from the University of Algeria in Geophysics in 1992 after which she studied petroleum exploration at the Institut Algerieu du Pétrole for a year. Cherifa joined Turkish Petroleum Corporation in 1996 for six months and was involved in hydrocarbon exploration and assessment of some blocks in Algeria. She is presently Geophysicist Engineer with Sonatrach Exploration on a variety of exploration projects, one of which was the interpretation of the giant Algerian gas field Hassi R’mel. Her research interests include the processing and the seismic interpretation on Workstation “Charisma”.

Farida Benatmane graduated in Geology from the University of Algeria in 1991. She also studied Petroleum Geology at the Institut Algerien du Pétrole. Farida worked with Sonatrach Division Exploration in 1994 on various interpretational geological projects and is currently Geologist Engineer with the company. She is interested in sedimentology research.

AGU Spring Meeting

26-29 May, 1998

For more information please contact:

AGU Meetings Department

2000 Florida Avenue, NW

Washington, DC 20009, USA

Tel: (202) 462-6900; Fax: (202) 328-0566

Facies and Diagenesis as Controlling Factors on Reservoir Quality of the Proterozoic-Cambrian Ara Group Carbonates (South Oman Salt Basin)

Stefan Schröder, Albert Matter, Karl Ramseyer University of Bern and Joachim E. Amthor Petroleum Development Oman

The Ara Group of the South Oman Salt Basin attracts renewed interest by exploration because of its hydrocarbon potential. It comprises a cyclic sequence of dolomite reservoirs, prolific source rocks, and evaporite seals. Due to deep erosional truncation in post-Ara times no surface exposures are available. Subcrops of the Ara Group are confined to the interior of Oman where it was deposited in several evaporitic basins, one of them being the South Oman Salt Basin. The study focuses on (1) the facies evolution through time as a basis for a sequence stratigraphic analysis, and (2) the degree to which the diagenetic evolution controls reservoir quality, with the aim to predict reservoir quality distribution.

The Ara Group (Late Proterozoic to Early Cambrian) consists of a thick (3 to 4 kilometers) sequence of evaporites (sulfates, halite and potash salts) deposited during more restricted phases, and dolomites that represent more open marine conditions. In a typical succession, basal dolomites are followed by thin anhydrite and thick halite, again overlain by anhydrite. The cyclic repetition of this succession reflects recurrent changes in salinity and sea level.

The almost complete dolomitization of the rocks has obliterated much of the depositional fabric. However, some remaining features allow reconstruction of the general depositional environment. Microbialites are most conspicuous, and their presence indicates a deposition in a peritidal setting. Due to the lack of grazing organisms, the microbes could have colonized even the deeper subtidal areas. Observations on slabbed cores suggest a gradual transition from more or less stratiform mats, often associated with sabkha-anhydrite, that are typical of inter- and supratidal areas, and dome-shaped small biohermal constructions forming subtidal shoals. Their internal fabric can be highly variable and they show only minor occurrences of evaporites.

Isotope data suggest that dolomitization as the main diagenetic process occurred during and/or shortly after deposition. The microfabric of Ara carbonates comprises mostly fine-crystalline dolomite with intercrystalline porosity developed during the transformation of micritic calcite to dolomite. Anhedral crystals are associated with the microbial mats. Coarse- to medium-crystalline dolospar occurs either as primary pore-filling or as replacement of pore-filling calcite. In general, dolomitization enhanced the porosity of the carbonates.

During successive diagenetic stages several processes affected the dolomites. The diagenetic sequence can be subdivided into an early dolomitization with positive effects on porosity, and a late succession of both porosity creating and destroying processes. Leaching and formation of fractures were porosity creating processes. Porosity destroying processes include cementation by evaporites (halite, anhydrite) and bitumen, as well as partial de-dolomitization and silica replacement of anhydrite. Destructive processes dominated during late diagenesis. Initial porosity was controlled by facies distribution and most probably increased from supratidal sabkhas to subtidal shoals. During diagenesis lithologies with high initial porosity (e.g. bioherms) were cemented preferentially, whereas lithologies with moderate initial porosity (e.g. in inter- to subtidal microbialites) remained unaffected.

Stefan Schröder received his MSc in Geology from Würzburg University, Germany in 1997. He worked on Pliocene clastic sediments and neotectonics in Italy before joining Bern University. Stefan is currently working on his PhD on sedimentology and diagenesis of subsurface Proterozoic/Cambrian carbonates and evaporites from Oman.

Albert Matter and Karl Ramseyer (see abstract “The Athel Play in Oman: Controls on Reservoir Quality” on page 62 for biography and photograph)

Joachim E. Amthor (see abstract “Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation” on page 60 for biography and photograph)

Late Triassic Evaporite and Pre-Triassic Strata: Potentials for Future Hydrocarbon Prospects in Lebanon

Mars E. Semaan Lebanese American University

Indications of the presence of Triassic evaporites beneath Lebanon, in the eastern side of the Levant in the Mediterranean is documented. In 1993, a marine seismic survey in northern Lebanon, and covering the widest part of the continental shelf, showed deeper structural horizons with a high velocity below the Jurassic, which with further analysis may confirm the presence of deeper evaporites. These Jurassic successions contain intervals of carbonates and evaporites, henceforth showing potential existence for non-flushed biodegraded accumulations under anhydrite seals. These horizons were correlated with the salt deposits in the Kura-Chine basin of the Palmyrides.

The Triassic successions are believed to be a continuation of the west-southwest trend of the adjacent Palmyride Basin of Syria. This trend also suggests that the basin axis is west-southwest and continues toward Egypt, with its thickest section present in northern maritime Lebanon. The Palmyride Basin is well-known from subsurface exploration and drilling, where a number of Triassic oil and gas discoveries were made.

Regional considerations with regard to distribution and trend of the Kura-Chine salt basin, may be correlated with the westward extension across the Levant Transform fault under north Lebanon. These deposits are then expected to be present under the northern part of Lebanon. Thus a sealing, potentially prospective pre-Jurassic subsurface successions seems to be firmly established for Lebanon.

This paper will attempt to shed some light on these probable Triassic evaporites which may hold the future of oil and gas prospects in Lebanon. The fractured and eroded younger rocks of Lebanon suffered fresh water flushing which has removed any hydrocarbons present. However, the Upper Triassic evaporites and the pre-Triassic strata still hold unflushed oil reservoirs. This is the proposed theory. Additional geophysical data and reprocessing of the 1993 marine data from offshore Lebanon may be necessary to prove this theory.

Mars E. Semaan received his MSc degree in 1978 and PhD degree in Physics in 1982 from Texas Christian University. Mars is currently an Assistant Professor of Physics at the Lebanese American University in Byblos. He also worked with PT Caltex Pacific Indonesia between 1991 and 1996 and as Geophysicist with Texaco’s Exploration and Production Division between 1982 and 1991. His interests are related to hydrocarbon prospects in Lebanon. Mars is a member of the API, AAPG, IPA and SEG.

GSA Annual Meeting

26-29 October, 1998

For more information please contact:

GSA Meetings Department

Tel: (303) 447-2020; Fax: (303) 447-1133

A High Resolution Sequence Stratigraphic Study of the Callovian-Early Kimmeridgian Shuqra Formation in the Aden-Ahwar Area of Coastal South Yemen

John D. Smewing Earth Resources Ltd., UK Abdul R. Saeed and Abdul M. Ahmed Ministry of Oil and Mineral Resources, Yemen

The Shuqra Formation forms part of a widespread transgressive carbonate succession overlying the Kohlan sandstone and basement in south Yemen. In order to better understand the distribution, development and geometric relationship of its constituent lithofacies, an outcrop-based, high-resolution sequence stratigraphic study has been carried out on the Shuqra Formation in the Aden-Ahwar area of coastal south Yemen.

This has involved the correlation of twelve measured stratigraphic sections along a regional east-west dip line. The results of this analysis have shown that the Shuqra was deposited on a southeast-facing, clastic-influenced homoclinal carbonate ramp and that it contains five lithofacies representing delta plain to mid-outer ramp environments. The distribution of lithofacies on this ramp was controlled by long-term variations in relative sea level and not by short-lived localized tectonics. Based on the correlatable vertical stacking pattern of these lithofacies and the identification of key surfaces, the Shuqra can be divided into three unconformity-bound third order depositional sequences. The Kohlan sandstone is found in the lowest part of the lowermost sequence. The base Madbi comprises the lower part of an overlying fourth sequence.

Potential for source rock development exists in the transgressive portions of the Shuqra sequences. Porosity in the Shuqra at outcrop is minimal. However, grainy inner ramp carbonates were developed in the highstand systems tracts and these may be expected to have intergranular porosity in the subsurface. The sequence boundary at the top of the Shuqra was subaerially exposed and secondary porosity can be anticipated in the underlying limestones. The Kohlan sandstone is clean and generally only poorly to moderately cemented.

John D. Smewing is currently Director of Earth Resources Ltd., UK. He received his BSc degree in Earth Sciences and Chemistry with Honors from Leeds University in 1971, and PhD in Earth Sciences from the Open University in 1975. Following an early career in ophiolite studies, John established the Earth Resources Institute in 1980 and now directs a number of international outcrop-based projects for the oil industry.

Abdul R. Saeed graduated in Geology from Qatar University in 1985 and has since been working as a Geologist with the Ministry of Oil and Mineral Resources in Sana’a, Republic of Yemen. His work has involved secondment to a number of operating companies in Yemen where his duties have included field and well site geology, gravity and seismic surveying and seismic interpretation. He has been a member of the Reevaluation Data Committee in PEPB and Chairman of Al-Bakri Oil Company.

Abdul M. Ahmed completed his MSc in Geology at Baku, Azerbaijan in 1981. He has been working with the Ministry of Oil and Mineral Resources in Sana’a, Republic of Yemen since 1982. His work has involved secondment to a number of operating companies in Yemen where his duties have included field and well site geology, stratigraphic correlation and seismic interpretation. He has acted as Ministry Geologist Representative for Hunt Oil Company.

Limits and Possibilities Determining Rt with Array Resistivity Logging Tools

Kurt M. Strack, Michael A. Frenkel and Alberto G. Mezzatesta Western Atlas Logging Services

In locating hydrocarbon-bearing formations in a borehole, electrical logging techniques play a key role by distinguishing between oil and water saturated rocks. Among the electrical techniques both classes, induction and current injection (galvanic) tools, are of significant importance in determining movable and residual hydrocarbons. Over the years, substantial effort has been put into the tool design to obtain the best possible apparent readings representing the formation resistivities. Unfortunately, with more complex environments such as dipping beds, deep invasion and thin beds, significant interpretation must be done to avoid false analysis. The most objective way is the use of geophysical inversion which gives good reliable formation parameter estimates.

Usually, level-by-level interpretation schemes are used in log analysis. Electrical measurements at each logging depth level are used to interpret multiple formation parameters including the depth of the invasion zone and the resistivities of the invaded and uncontaminated formation. Only the combination of multiple measurements will yield reliable estimates for these parameters. Additionally, when combining galvanic and induction measurements, one can also use the inherent bias of each measurement to compensate for the weakness of the other and obtain a unified significantly less biased and thus more realistic interpretation. Although this process is very beneficial in delivering a less biased interpretation it further increases computational requirements.

One way of addressing the computational constraints is by using massive parallel supercomputers which even in one processor mode reduces the computational time by one decade leaving enough room for speed improvements through code parallelization and special algorithms. Another way of addressing the heavy computational requirements is to replace the conventional two-dimensional inversion with a special rapid computational scheme where the two-dimensional calculations are broken into a sequence of one-dimensional ones. This process converges to the real two-dimensional solution approximately tens to hundreds times (model complexity dependent) faster than the conventional two-dimensional schemes. Yet another decade of speed improvements of the rapid two-dimensional inversion is being achieved by using neural net type techniques.

The two-dimensional inversion delivers not only the two-dimensional distribution of the formation parameters but also statistics which are essential for estimating the reliability of the results. Errors give an idea about the fit between the interpretation and the real data. Error bounds can give the possible range of the interpreted parameters and can be translated directly into maximum and minimum pay. The importance of each parameter can tell whether or not the data is sensitive to any changes in this parameter and thus false interpretations can be avoided.

Case histories for different tools and applications clearly show the benefits of the new concept of integrating multiple resistivity logs.

Kurt M. Strack received a MSc from the Colorado School of Mines and a PhD from University of Cologne, Germany. He is presently Chief Scientist at Western Atlas Logging Services (WALS) after being Manager of the Advanced Scientific Research and the Resistivity Product Line where he developed several of WALS’ new technologies. Prior to WALS Kurt worked as Geophysical Consultant, as university researcher and teacher (9 years in Cologne), as R&D Manager in the geothermal and logging industry. Kurt has published over 100 publications, one textbook and several patents. He also received a Fulbright scholarship and numerous international grant/awards throughout his career. His main interest is integrated geophysics, inversion, and technology transfer and project development. He is a member of the SPWLA, AAPG, ASEG, DGG, BDG, SPE, SEG and EAGE.

Michael A. Frenkel received a MSc degree in Applied Mathematics in 1978 from the Moscow Institute of the Oil and Gas Industry and a PhD in Physics and Mathematics in 1984 from the USSR Academy of Sciences, Moscow. He worked for 20 years in geophysics as a Scientist on the development of numerical methods and software for processing, modelling, inversion of electromagnetic and potential fields, well logging tool design and data interpretation. In 1992, Michael joined Western Atlas Logging Services where he is presently working as Senior Scientist on the development of fast inversion methods and software for well logging data interpretation. Michael has published over 30 scientific papers and twobooks. He is an active member of the SEG, SPWLA and AGU.

Alberto G. Mezzatesta received a PhD from the University of Houston and a diploma in Petroleum Engineering from the University of Cuyo, Argentina. Alberto joined Western Atlas in 1984 where he is presently Manager of Research Support with the responsibility of supporting the development of new technologies with modeling and inversion capabilities. Prior to this, he was a Project Leader for the development of the integrated interpretation of resistivity measurements using inversion methods, and was heavily involved in the development and deployment of the new resistivity technology. Prior to joining Atlas, Alberto was Head of the Reservoir Simulation Group in the National Oil Company, Argentina, where he worked in the areas of reservoir engineering, reservoir simulation, petrophysics and well log interpretation. Alberto’s areas of expertise are log interpretation development software, petrophysics, borehole geophysics, reservoir engineering, and reservoir simulation. He is an active member of the SPE, SPWLA, and SEG and has authored several publications and presentations at international symposia.

An Integrated Approach to Najmah-Sargelu Formation Fractured Carbonate Reservoir Prediction (Upper to Middle Jurassic) in the Gotnia Basin of Kuwait

Christian J. Strohmenger, Steven R. Webb Exxon Exploration Kuwait Inc. Jassim M. Al-Kandari, Kuwait Oil Company Jonathan Kaufman and James M. DeGraff Exxon Production Research Company

The information presented in this paper is based on the results to date of a joint technical study between Kuwait Oil Company and Exxon Exploration Company. A multidisciplinary approach was used to analyze and predict reservoir quality distribution in Mid to Upper Jurassic carbonates of the Najmah and Sargelu formations in the Gotnia Basin of southwestern Kuwait. The carbonate strata were deposited in low to moderate energy, inner to outer ramp/basinal environments, and are overlain and underlain by excellent regional seals. Fractures critical to reservoir performance were created in part by multiple tectonic events related to convergence and collision between the Arabian and Asian Plates, followed by periods of plate relaxation. In addition, maturation of excellent source rock in the upper Najmah Formation has generated near-lithostatic overpressures that probably contributed to fracturing. The economic viability of the reservoir depends on the distribution of matrix porosity in addition to the fracture networks. Disciplines used in the study include sequence stratigraphy, 2-D and 3-D seismic interpretation, petrophysics, petrography, fracture description and analysis, basin history modeling, geochemistry, and reservoir modeling.

The sequence stratigraphic framework developed in this study divides the section into two second-order sequences. In the lower sequence, a transgressive systems tract (TST) overlies the top-of-Marrat sequence boundary (SB), and in turn is overlain by a highstand systems tract (HST) on top of an intra-Dhruma maximum flooding surface (MFS). A second sequence boundary is placed near the top of the Sargelu Formation. In the upper sequence, a second MFS separates the TST and HST within the Najmah Formation. The HST displays a sequence boundary at the top of the clean Najmah limestone and is overlain by transgressive “Upper Najmah Shale” (condensed section). Detailed core to well-log ties allow further subdivision of the systems tracts into Sargelu early highstand systems tract, Sargelu late highstand systems tract, Najmah early transgressive systems tract, Najmah late transgressive systems tract, Najmah early highstand systems tract, and Najmah late highstand systems tract. The best matrix reservoir quality exists within the Najmah highstand systems tract and the Sargelu late highstand systems tract.

Fracture analysis based on core observations indicates that nearly all effective fractures are vertical and partly filled with calcite and sometimes bitumen. The open apertures of some fractures exceed one centimeter and are likely held open in the subsurface by the near-lithostatic pressures and irregular distribution of cements that act as natural propants. The highest fracture densities are in relatively clay-free, low total organic carbon content, low porosity packstones and wackestones near source rock intervals in the Najmah and extending downwards into the upper Sargelu. Fractures in these lithologies generally terminate abruptly against argillaceous or organic-rich strata. Based on fracture orientations determined from paleomagnetically oriented core, image logs, production data, and seismic interpretation, we conclude that the fractures formed as a combined product of overpressure generation and tectonism related to movement of the Arabian Plate.

Christian J. Strohmenger received a Diploma in Geology from the University of Giessen and a PhD in Mineralogy/Sedimentology from the University of Heidelberg, Germany. From 1989 to 1990 he worked as a Research Assistant in carbonate sedimentology and sequence stratigraphy at the University of Geneva, Switzerland. Christian joined BEB Erdgas und Erdoel GmbH, Hannover, Germany in 1990, working as a Carbonate Sedimentologist until 1994, and as a Seismic Interpreter until 1996. In 1996 he accepted a foreign assignment as an Exploration Geologist with Exxon Exploration Company in Houston, Texas, where he is currently working on carbonate reservoirs of Kuwait. Christian has published papers on a variety of topics, including carbonate sedimentology, sequence stratigraphy, and reservoir quality prediction.

Steven R. Webb received his BSc degree in Geology in 1973, and MSc degree in Geology in 1975, both from Texas Tech University in Lubbock, Texas. Since that time he has worked as an Exxon Geoscientist in a wide variety of exploration and production projects in numerous carbonate provinces around the world. From 1994 to present, Steven has been working the Middle East with more recent focus on Kuwait. He is currently a member of the Kuwait team working the Kra Al-Maru Joint Technical Study in Western Kuwait.

Jassim M. Al-Kandari received a BSc in Geology from Kuwait University in 1995 and joined Kuwait Oil Company (KOC) the same year. Jassim is presently a Geologist with KOC working in the Exploration and Development Group. He worked six months on a loan assignment with Exxon Exploration Company in Houston, Texas.

Jonathan Kaufman has over 16 years experience in carbonate reservoir characterization, with 9 of those years being at Exxon Production Research Company in Houston Texas. Jonathan has been involved in sequence/seismic stratigraphy, facies analysis, and reservoir quality studies of carbonate reservoirs from the USA, Canada, Russia, China, Mexico, West Africa, Indonesia, and the Middle East. He is presently a Senior Geologist in the field studies group at Sonat Exploration Company in Houston, Texas.

James M. DeGraff received a BSc in Geology (1975) and an MSc in Geophysics (1976) from Michigan Technological University, and a PhD in Structural Geology from Purdue University (1987). After joining Exxon Production Research Company in 1988, he worked on the prediction of fractured reservoir quality in a variety of reservoir types and structural settings around the world. His current assignment involves predicting fractured reservoir quality in Jurassic carbonate reservoirs of Kuwait. James has published numerous papers and abstracts on a variety of topics including fracture formation in fold-thrust belts and volcanic rocks, mechanical modeling of folds and faults, and fractured reservoir quality in carbonates, basement rocks, and tight sandstones.

GEO’98: Short Course

Fractured Reservoir Characterization and Modeling

18-19 April, 1998

For more information please contact:

Mr. Eric Gross, IFP Arabian Gulf,

P.O.Box 3282, Manama, Bahrain

Tel: (973) 214-778; Fax: (973) 217-908

e-mail: egifpbf@batelco.com.bh

State-of-the-Art 3-D DMO

Eric Suaudeau, Philippe Herrmann and Bernard David Compagnie Générale de Géophysique

Amplitude and phase preservation are nowadays becoming standard requirements for DMO processing of 3-D seismic surveys. In this respect, the inherent wide distribution of offsets and azimuths associated with land and OBC surveys, and also wide-tow marine surveys represent a challenge to conventional DMO algorithms. Several prerequisites are necessary in order to fulfil these preservation requirements, such as proper weighting of the DMO operator and frequency filtering of the same operator to remove aliasing noise. It has been shown that a key factor in the preservation of signal phase and amplitude is the application of a weighting that compensates for the field geometry. A large variety of weighting techniques have been proposed that significantly reduce acquisition footprints. Nevertheless practice shows that, even after proper weighting, artifacts still remain, which compromise the quality of the result and reduce the reliability of the data for further AVO studies.

These artifacts are related to the crude binning procedure applied to the DMO-generated traces in conventional algorithms. The Kirchhoff algorithm is generally applied for a constant-velocity model. Under such an assumption, the DMO operator is a 2-D operator which generates traces that are regularly sampled along the source-receiver segment. Traditionally DMO traces falling inside a bin are moved to the center of the bin, irrespective of their true position. This corresponds to a nearest-neighbor interpolation scheme, which, by smearing the DMO operator in the transverse direction, has the effect of aliasing the data and decreasing the spatial resolution.

In order to reduce the aliasing noise thus induced, traces have to be properly interpolated to the neighboring bin centers. This is achieved by convolving each of the DMO-generated traces with a band-limited interpolation filter along the line and CDP directions. The benefits of 2-D band limited spatial interpolation are manifold: (1) increase in spatial resolution, (2) better preservation of signal phase and amplitude, and (3) greater signal-to-noise ratio.

We illustrate the improvements brought about by this method on both synthetic and field data (notably from the Middle East). We show that footprint artifacts observed after DMO are mostly a spurious effect of the spatial interpolation scheme conventionally used. These artifacts can be removed at a reasonable computation cost. Furthermore this procedure can be applied to any acquisition geometry. It is model-independent and fully compatible with any DMO weighting scheme.

Eric Suaudeau is currently R&D Geophysicist with Compagnie Générale de Géophysique. He also worked with Informatique Pétrolière Scientifique from 1990 to 1992. Eric received his MSc in Physics in 1983, and PhD also in Physics in 1987 from Orsay University. He also holds a Post-Doctorate degree from the University of Florida. His professional interests are seismic processing and software engineering.

Philippe Herrmann has been with Compagnie Générale de Géophysique since 1992 and is currently R&D Geophysicist. He received his PhD in Geophysics from Delft University in 1991. Philippe is a member of the SEG and EAGE. His professional interest is seismic processing.

Bernard David is a Geophysicist and has been working with Compagnie Générale de Géophysique since 1981. He received his MSc in Earth Science from Paris VII University in 1976. Bernard’s professional interest is seismic processing.

Development of a Complex Sand-Shale Reservoir: A Case Study of the Wara Formation in the Minagish Field, West Kuwait

Dogan Sungur, Kuwait Oil Company, O.E. Ibe, BP Kuwait, Abdullah Bouhamad, Kuwait Oil Company and Arshad Waheed, Halliburton Services, Kuwait

The Wara Formation in the Minagish field of west Kuwait is of Upper Cretaceous, Cenomanian age. The formation consists of a series of alternating fine-grained marine sand and gray shales cut by younger channel deposits. Detailed stratigraphic interpretations and channel sand correlations provide strong evidence that flooding events and channel sand development can be combined into four distinctive and vertically stacked stratigraphic sequences. The channel sandstone exhibits good reservoir quality while the marine sands essentially possess non-commercial characteristics. Preparing a geological map, charting the course of the pay horizon and defining commercial reserves of the Wara reservoir in the Minagish area has been a challenge primarily due to uncertainties in reservoir continuity.

In addition to the geological challenges, sustaining stable production from this horizon has been difficult in the past. Measured oil gravity average 19 degrees API while average reservoir pressure is 2,500 psi. Production tests from seven completions showed unstable rates between 85-350 bopd at low wellhead pressures. It is suspected that the high viscosity oil and low formation pressures were the primary impediments to sustained productivity.

The challenge to develop this reservoir led to the implementation of two pilot programs to evaluate alternative completion and stimulation techniques for sustaining productivity in the Wara channel sands. A horizontal well was drilled and completed in Channel 1 while a propped fracture stimulation was performed across Channels 1-3 in an existing well. Both pilots aimed to increase the flow potential of the wells by enhancing the permeability thickness and conductivity respectively.

Preliminary results obtained from the pilots showed sustained rates of 1,750 and 2,750 bopd respectively from the horizontal and fracture stimulated wells compared to a maximum of 350 bopd tested in an offset well. Although extensive tests will be required to confirm initial results, plans are underway to drill a 7-well program to develop the reservoir. This paper details the methods applied to resolve geologic and engineering questions regarding successful development of a complex sand-shale reservoir.

Dogan Sungur is a Senior Geologist at Kuwait Oil Company (KOC). He has over 20 years of petroleum experience including 4 years with KOC, 7 years at AGOCO, Libya, 5 years in Norcen Oil, Calgary, Canada, 2 years at Husky Oil Operation Ltd. Calgary, Canada and 5 years with Turkish Petroleum Corporation, Ankara, Turkey. Dogan holds BSc and MSc degrees in Geology from Hacettepe University of Ankara, Turkey.

O.E. Ibe is a Petroleum Engineering Consultant with British Petroleum Exploration on secondment to Kuwait Oil Company. He has 20 years of reservoir and production engineering experience. Ibe previously worked for Mobil Oil E&P in California and Gulf Coast regions before joining British Petroleum in 1989. He holds BSc and MSc degrees in Natural Gas Engineering from Texas A&I University and a DEng in Petroleum Engineering from the University of Southern California.

Abdulla Bouhamad received his BSc in Petroleum Engineering from West Virginia University in 1980. Abdulla has 12 years experience in petroleum engineering and 3 years in reservoir engineering. He is currently the Superintendent of Field Development with Kuwait Oil Company.

Arshad Waheed is a Technical Advisor with Halliburton Ltd., Kuwait. He has been with Halliburton for 13 years working in stimulation, cementing, tools and testing services at various locations over this period. Arshad holds a BSc degree in Petroleum Engineering from Texas A&M University.

The Power of 3-D Seismic During Exploration: Successful Drilling of Seismic Anomalies Rosetta Concession, Nile Delta, Egypt

John L. Swallow, Steven J. Maddox and Sinead Lynch BG plc

The Rosetta Concession was officially granted to a British Gas International Exploration and Production led consortium on 29th May, 1995. Previous licencees had left BG a legacy of two non-commercial wells, Rosetta Northwest-1 and Rosetta-2, and a pre-1980 grid of poor quality 2-D seismic augmented by a few more modern (1986 to 1993) 2-D seismic lines. Based on these data a block wide review identified several play types within the Pliocene and Miocene and also generated a significant number of leads.

With no firm prospects generated by autumn 1995, the decision was taken to shoot the largest single 3-D seismic survey then undertaken in Egypt (1,500 square kilometers) to explore the most prospective parts of the block. The 3-D survey was shot in January 1996 and processing was completed in September 1996.

Pliocene anomalies were tentatively identified during processing and worked into prospects by placing the anomalies into a coherent geological framework and quantifying their seismic response. This included the use of amplitude extractions, AVO analyses and modeling, and the description of flat spots and other attributes.

Within two months of receiving the 3-D volume, the consortium was able to agree to drill one of the anomalies. Rosetta-3 was drilled in March 1997 and encountered the three main gas-bearing sands as prognosed, with three DST’s flowing a cumulative rate of 60 mmscfg/d.

The story did not finish there. With high quality 3-D data already available it was possible to switch directly from exploration into the development phase of the project. Additional mapping based on the results of Rosetta-3 has further refined our understanding of the subsurface. At the time of writing Rosetta-3 lies within a development lease and a three well back to back drilling program is underway.

John L. Swallow and Steven J. Maddox (see abstract “Plio-Pleistocene Clastic Reservoirs of the Offshore Nile Delta, Arab Republic of Egypt” on page xxx for biographies and photographs)

Sinead Lynch has spent four years working in the oil and gas industry with British Gas E&P. Sinead has primarily worked in the Geophysical Operations and Special Projects Group which specializes in risk reduction using seismic attributes. Her areas of expertise include seismic modeling, AVO and inversion and she has applied these technologies on British Gas assets in North Africa, Southeast Asia and the UKCS.

The Natih Petroleum System of North Oman

Jos M.J. Terken Petroleum Development Oman

The Natih petroleum system is one of the smaller petroleum systems in Oman, measuring only some 20,000 square kilometers in areal extent. Resource volumes, however, are significant and amount to some 1.3 billion m3 of STOIIP. Most of the recoverable oil is concentrated in two giant fields, Fahud and Natih, which hold 145 and 100 million m3 respectively of 32° API oil.

The Natih Formation consists of a 400-meter thick carbonate succession of latest Albian to Early Turonian age. Reservoirs are comprised of heavily fractured, tight, chalky limestone that produce mainly via the fracture network. Shaly limestone intervals in the Natih Formation contain Type II organic matter. These source rocks are restricted to western North Oman and are mature only in the Late Cretaceous/Tertiary foreland basin. Burial histories and thermal modeling indicate that generation started during Late Cretaceous time and continues today.

Natih oils have a distinct biomarker and carbon isotope signature, which can be used to map their geographical distribution, and identifies other contributing oil types in mixtures. The Natih petroleum system is limited to central North Oman, its maximum extent being structurally bounded, in the south by the peripheral bulge of the Late Cretaceous/Tertiary foreland basin and in the east by the salt-structured core of the Ghaba Salt Basin. The presence of a massive top seal and rather modest deformation in the fold and thrustbelt of the Oman Mountains forces Natih oil to migrate laterally.

The volume of hydrocarbons generated by Natih source rocks was calculated and compared to the estimated in-place oil to determine the trapping efficiency of the petroleum system. Some 100 billion m3 of source rocks is currently mature and generating oil and has produced a cumulative volume of 14 billion m3 (100 billion bbls) oil. Natih oil-in-place amounts to 1.3 billion m3 (9 billion bbls), indicating that 9% of all generated hydrocarbons has actually been discovered. Currently 0.25 billion m3 (1.8 billion bbls) are booked as recoverable reserves, equivalent to 1.8% of the total generated volume. Both percentages classify the Natih petroleum system as the most efficient system in Oman. The outstanding efficiency is due to the presence of an excellent top seal and intra-formational source rocks, that have generated hydrocarbons since the Late Cretaceous.

Remaining potential has been recognized in truncation traps on the northern flank of the foreland bulge and in possible turbidites in the foreland basin.

Jos M.J. Terken (see abstract “Sedimentology, Diagenesis and Charge History of the Haima Deep Gas Reservoirs in North Oman: An Integrated Approach to Play Evaluation” on page 60 for biography and photograph)

Makarem: The Giant Awakes - Progressively Deeper Exploration Reveals New Huqf Gas Play in Oman

Graham J. Tiley, Joachim E. Amthor, and Pascal D. Richard Petroleum Development Oman

The gas business in Oman is relatively young, but has made rapid advances through a successful creaming of the Haima (deep clastics) play in the Ghaba Salt Basin. Since the first well drilled on the ‘Government Gas Sequence’ in 1985 some 19.5 trillion cubic feet (TCF) (550 billion cubic meters (BCM)) have been booked culminating in the signing of the Liquified Natural Gas agreement in 1996. To continue to meet growth targets of 1.0 to 1.5 TCF (28-42 BCM) of gas booking per year required the identification of a new play. This challenge has been partly met with the drilling of Makarem-1 which reached its total depth of 5,079 meters in August 1994. The well discovered gas in fractured Buah dolomites of the Precambrian Huqf Group, in a large tilted fault block with a closure of approximately 700 square kilometers. The critical factor in the identification of the Makarem prospect was improvements in seismic data quality, in particular long-cable 2-D seismic surveys.

The reservoir flowed 600,000 m3/d of dry, sour gas on test, but despite the encouraging flow rates considerable uncertainty remained over the long-term producibility of the reservoir and the degree of lateral connectivity. This issue was addressed through the development of a geological model based on identification of analogues and through the prediction of fracture density from the fault system as defined on 3-D seismic. The resulting reserves booking of 0.6 TCF (18 BCM) encompassed a 77 square kilometers area of the structure.

Initially two appraisal wells are planned, the first of which spudded in September 1997, to pursue the remaining scope of 2.6 TCF (76 BCM). The Makarem appraisal campaign offers considerable challenges both in terms of the High T drilling, logging and testing, as well as in maximizing reserves bookings from widely spaced penetrations in a complex reservoir. A program of multi-disciplinary work is underway to improve the reservoir model, pulling together a wide body of work on Precambrian carbonates and addressing specific issues such as reservoir continuity and the nature of the fault/fracture system.

Graham J. Tiley received a PhD in Geological Sciences from the University of Birmingham in 1988. He joined Shell in 1988 and was posted to Shell Research in The Netherlands where he worked on seismic interpretation software development. Graham was posted to Shell in Nigeria in 1992 where he worked in both lateral prediction and seismic interpretation. In 1996 he was posted to Petroleum Development Oman where he has been working on exploration and appraisal aspects of the Huqf play in North Oman.

Joachim E. Amthor (see Abstract “The Athel Play in Oman: Controls on Reservoir Quality” on page 60 for biography and photograph)

Pascal D. Richard (see abstract “Integrated Haushi Hydrocarbon Habitat Study in North Oman” on page 147 for biography and photograph)

Fluid Communication Across a Major Fault Transecting the ‘Uthmaniyah Khuff Reservoir

Mark H. Tobey, William J. Carrigan, Peter J. Jones, Henry I. Halpern, Jaffar M. Al-Dubaisi, Mohammed A. Al-Amoudi and Hani O. Al-Ohaily Saudi Aramco

Examination of ‘Uthmaniyah Khuff-C gas/condensate compositional signatures indicates that: (a) over geological time, there has been slow fluid migration across a north-south trending fault which transects the ‘Uthmaniyah Khuff into two reservoir compartments; and (b) since production began, this fluid migration has accelerated in the vicinity of a well adjacent to the fault, presumably as a result of pressure draw-down at that well.

Prior to gas production at ‘Uthmaniyah, the north-south trending fault acted as an effective barrier to fluid migration. There is an abrupt change in the chemical composition of fluids across the fault, most notably in H2S concentration. However, very slow fluid migration across the fault was established over a geological time-scale, resulting in a gradient in the chemical and isotopic compositions of fluids west of the fault. The highest H2S concentrations of the original well-stream compositions west of the fault occur adjacent to the fault (5.0 to 5.5%) and decrease to 3.0% 10 kilometers west of the fault. The H2S content at a well less than 2 kilometers east of the fault is 9.3%.

However, a recent sample collected from a well one kilometer west of the fault shows a 1.4% increase in H2S compared to the original 1983 well-stream composition. Two other nearby Khuff-C wells show no increase in H2S concentration over the production history of the field. The increasing H2S concentration at this one well attests to a relatively recent, localized, one-way fluid communication across the fault in that vicinity, over the well’s production history. Small, yet reproducible, differences in the condensate chromatographic signatures support that conclusion.

Thus, over the production history of the field (approximately 13 years), we observe an enormous acceleration in one-way communication across the fault between two reservoir compartments. This one-way communication has been going on over geological time, but at a much slower rate. The accelerated communication is most likely due to the production-induced pressure draw-down west of the fault.

Mark H. Tobey, William J. Carrigan, Peter J. Jones and Henry I. Halpern (see abstract “Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates” on pages 79-80 for biography and photograph)

Jaffar M. Al-Dubaisi has been with Saudi Aramco since 1984. He is a Research Scientist with the Lab R&D Center of Saudi Aramco. He received a BSc degree in Chemistry from the University of Tulsa in 1991. His research interests include reservoir geochemistry.

Mohammed A. Al-Amoudi and Hani O. Al-Ohaily (see abstract “Geochemical Evidence for Reservoir Compartmentalization in Central Arabian Paleozoic Reservoirs” on pages 96-97 for biographies and photographs)

The Athel Play in Oman: Al Noor and Al Shomou Field Development

Robert Turner, Michael O’Dell, Wouter Smits, Marcus Antonini, Elaine Leith, Sau-Wai Wong, Jean-Louis Alixant and Luc A.J. Vermin Petroleum Development Oman

The Al Noor field (discovered in 1989) and Al Shomou field (discovered in 1995) are located in the South Oman Salt Basin, some 50 kilometers west of Nimr field. Light, volatile oil (48° API) with associated hydrocarbon gas containing 1.5 mol% H2S and 3 mol% CO2 are present in the Athel Formation, a 400 meter-thick, silicilyte reservoir at a depth of approximately 4 kilometers. The infracambrian Athel silicilyte consists mainly of micro-crystalline silica with porosity ranging from 15 to 25% and associated low matrix permeability of 0.02 microDarcy or less. The Athel silicilyte is unique in that it is both a reservoir and a world-class source rock, with Total Organic Content (TOC) upto 6 weight% and hydrogen indices in excess of 400 milligram HC/g TOC. The reservoirs are stratigraphically encased within salt and shale and are geopressured with a gradient of 19.8 kilo Pascal/meter. To date six wells have been drilled in the Al Noor structure and four wells and side-tracks in the Al Shomou structure.

Given this unique setting, and the nature of the fluid, major multi-disciplinary challenges have to be met to optimize the economic oil recovery from the Athel silicilyte. A multi-disciplinary team (Exploration, Production and Surface engineering) was formed in Petroleum Development Oman to address these challenges and to define a Phase One field development plan as a precursor to a full development of the Al Noor field. Major challenges to be addressed are: (1) seismic imaging and reservoir characterization of salt-encased reservoirs based on Pre-Stack Depth Migrated 3-D seismic; (2) prediction of lateral reservoir connectivities in the absence of reservoir analogues and in the presence of an extensive cemented fracture system; (3) significant problems calibrating wireline log response due to large amounts of organic material in the small pores; (4) design of deep, high pressure corrosion resistant well completions; and (5) design of surface facilities to treat the sour gas production and to stabilize the volatile crude in an environmentally acceptable way.

In addition to the above, unstimulated production rates from the Al Noor field range between 40 and 110 m3/day. In order to make the project commercial, higher well initials resulting in higher recoverable volumes are required. To achieve this, different well designs such as massive hydraulic fractures, multi-laterals or multi-fracced multi-lateral wells, are considered. The first development wells will be hydraulically fractured. Extensive production tests before (barefoot) and after fraccing are planned to accurately assess the productivity improvement factor of the fracture stimulation. Initially, 2 large (280 tones proppant) fractures are planned per well. However, a further improvement to one “mega” frac is considered if this stimulation technique is proven to be successful.

Given the combination of high pressure, high gas/oil ratio, high CO2 and H2S content a unique combination of corrosion resistant sub-surface and surface material (e.g. Hastalloy, HPGRE and Alloy 28) is required to process the sour Athel crude in the facilities. A high- level integration between the surface engineers and the sub-surface team has proven to be a key success factor in optimizing the design envelope of the surface facilities and, as such, has contributed to significant cost reductions. First oil production through the surface facilities is planned by mid-2000.

The Phase One development of the Al Noor field, together with a planned reserves booking in 1997 of the Al Shomou field, will provide essential analogues for the maturing of future exploration discoveries in this unique silicilyte rock in Oman.

Robert (Bob) Turner graduated with a Chemical and Process Engineering degree from Herriot Watt University in 1974. He worked with Exxon, Amoco and Arabian Gulf Exploration before joining Shell in 1980. Bob has worked in Australia, Libya, UK, Gabon, Holland and Venezuela in a variety of jobs mainly in Production Engineering and Well Operations. Bob has played a key coordination role in development teams for Rabi, Sole Pit and Urdaneta West fields. He is currently the Asset Manager for the Athel development with a team comprising exploration, development and surface engineering staff.

Michael (Mike) O’Dell has over 27 years reservoir engineering, supervisory, research and technical training experience with a U.S. major and a Middle Eastern national oil company. He has worked in reserve estimation, development planning, reservoir simulation, production and injection surveillance, and pressure analysis in both U.S. and international operations, onshore and offshore. Mike is presently Senior Reservoir Engineer in the Athel Team in Petroleum Development Oman.

Wouter Smits graduated with a MSc degree in Structural and Economic Geology from Utrecht University, The Netherlands in 1985. After joining Shell at the end of 1995 he worked in the UK (well site and operations geology), Holland (integrated reservoir studies for Nigeria) and Brunei (Senior Reservoir Development Geologist in an integrated exploration and development team). Wouter is currently Senior Reservoir Development Geologist for the Athel Development in Petroleum Development Oman in an integrated team comprising exploration, development and surface engineering.

Marcus Antonini is currently Senior Seismic Interpreter in Petroleum Development Oman’s (PDO) Athel Development Team working on reservoir characterization in Al Shomou and developing the Athel exploration portfolio. Marcus worked as a Seismologist from 1986 to 1989 and joined BEB Oil & Gas Co. in Germany in 1989 as an Exploration Geophysicist. In 1995 he was transferred to PDO’s Exploration Unit working in the Ghaba Salt Basin, North Oman. Since 1996 Marcus has been working in frontier Athel exploration, South Oman dedicated to the acceleration of reserves additions in an integrated EP environment. Marcus has a Diploma degree in Geophysics from the University of Munich.

Elaine Leith graduated with a BSc degree from the University of Newcastle upon Tyne and a PhD from the University of Sheffield. She joined Shell in 1985 and worked as a Materials and Corrosion Engineer in the UK, Netherlands and Oman. In 1995 Elaine took up her current position as a Production Engineer for Petroleum Development Oman’s deep high pressure Athel play.

Sau-Wai Wong joined the Athel Team as the Senior Production Engineer in July 1997. Before coming to Oman, he worked for 3 years as a Petroleum Engineer in Sabah Shell Petroleum Company, Malaysia. Prior to that (1989-1994) Sau-Wai was with Shell Research in The Netherlands, where he conducted research in rock mechanics. He holds a BSc (Honors) degree in Civil Engineering and a PhD degree in Geomechanics, both from the University of Manchester, UK.

Jean-Louis Alixant (see abstract “The Athel Play in Oman: Controls on Reservoir Quality” on page 62 for biography and photograph)

Luc A.J. Vermin holds an ME in Mechanical Engineering from the Technical University of Eindhoven. He joined Shell International in 1989. Luc worked as Process Engineer in NAM, Netherlands for 4 years. After moving to Petroleum Development Oman as a Conceptual Engineer, Luc is currently Project Leader of the Athel Surface Facilities.

Development of the ‘Slip-Sweep’ Seismic Acquisition Technique

Jan Wams and Erik Kleiss Petroleum Development Oman

The idea behind slip-sweep recording is unnervingly simple: a vibrator group starts sweeping without waiting for the other group’s sweep to be completed. After correlation, a long composed record will result, which can be cut at the appropriate time-zeroes to extract the individual correlated records.

If this technique can be put into production, the benefits are a significant increase in seismic recording production rates (up to 400% increase), which would allow significant cost savings or gains in data quality. A potential problem is an enhanced noise level on the seismic records.

The slip-sweep method has been tested four times in several prospects in Oman. The initial test data sets were recorded during a production survey, with all parameters identical to the production survey (15 second sweep; 6 second listening time); this highlights any differences in the seismic data quality. As current acquisition instruments cannot yet accommodate the slip-sweep method to its full extent, a modified version was employed with the slip-sweep simulated in the processing centre.

These tests have indicated that there are small differences on loop-scale, with slip-sweep data being marginally nosier, leading to the tentative conclusion that the slip-sweep method does not lead to significant deterioration of data-quality, nor does it lead to a different structural interpretation.

Following these encouraging results, recently a part of a 3-D production survey was recorded in slip-sweep mode employing two recording instruments by continuous recording of a limited number of (up to 12) overlapping sweeps. The results of this test will be presented and the quality compared with the remainder of the survey.

Jan Wams graduated in 1975 from the University of Delft in Medical Acoustics. He was drafted into the Dutch Army in early 1976 where he researched laser- and night-vision equipment. Jan joined Shell in 1978 and shortly after was transferred to the UK to take up a position in seismic data processing, followed by postings in Thailand and Brunei as a Seismic Interpreter. Jan was transferred back to Holland in 1988 to head the Land Acquisition group, followed by a posting to Yemen as Chief Geophysicist. After a further year in Holland as an advisor on acquisition matters, he joined PDO in 1993 to head the geophysical operations department.

Erik Kleiss (see abstract “From Noise Attenuation Towards Signal Preservation” on page 128 for biography and photograph)

Pre-Khuff (Permian) Hydrocarbon Geology of the Ghawar Area, Eastern Saudi Arabia

Lawrence E. Wender, Jeffrey W. Bryant, Martin F. Dickens, Allen S. Neville, and Abdulrahman M. Al-Moqbel Saudi Aramco

Saudi Aramco is conducting an exploration program to discover additional non-associated gas reserves in the Ghawar area. The program has successfully discovered significant sweet gas and condensate reserves in the pre-Khuff siliciclastics and has further increased our understanding of the Paleozoic petroleum system.

The Permian Unayzah Formation is the principal pre-Khuff hydrocarbon reservoir in the southern Ghawar area, where it contains both oil and gas. The Unayzah consists of fluvial to marginal marine sands. The Devonian Jauf Formation is the principal pre-Khuff reservoir in the northern Ghawar area, where it hosts the recently discovered giant Hawiyah gas-condensate field. The Jauf consists of shallow marine sands which exhibit unusually high porosities considering the burial depths.

Pre-Khuff hydrocarbon traps are found in simple four-way closures as well as more complex structural-stratigraphic traps on the flanks of Hercynian structures. Trap formation and modification occurred in four main phases: the Carboniferous (Hercynian Orogeny); Early Triassic (Zagros Rifting); Late Cretaceous (First Alpine Orogeny); and Tertiary (Second Alpine Orogeny). Structures in the Ghawar area show differences in growth histories, which have impacted the amount and type of hydrocarbons contained.

The primary source rock for pre-Khuff hydrocarbons are the basal “hot shales” of the Lower Silurian Qalibah Formation. Maturation modeling of these shales indicates hydrocarbon generation began in the Middle Triassic (oil) and continues to the present (dry gas).

Lawrence E. Wender (see abstract “Geochemistry of Eastern Saudi Arabian Paleozoic Gas/Condensates” on page 80 for biography and photograph)

Jeffrey W. Bryant joined Saudi Aramco in 1990 as a Geologist working frontier exploration of the northwestern region of Saudi Arabia. Since 1993 he has been exploring for Paleozoic deep gas reserves in the Eastern Province of the Kingdom. Jeffrey has nearly 20 years of oil industry experience, including Alaska exploration and US Gulf Coast development with Exxon, and Gulf Coast of Mexico exploration with Agip. Jeffrey holds a MSc in Geology from the University of Arizona.

Martin F. Dickens is a Geophysical Specialist with Saudi Aramco. He has 20 years of international experience. Since 1993 he has been exploring for hydrocarbons in the Eastern province of Saudi Arabia. Martin holds a BSc in Geophysics from the University of Southampton.

AAPG Annual Meeting

17-20 May, 1998

For more information please contact:

AAPG Conventions Department

Tel: (918) 560-2679; Fax: (918) 560-2684

Allen S. Neville is a Geophysical Specialist with Saudi Aramco. He was previously with Gulf Oil Corporation and has over 20 years of oil industry experience. Since joining Saudi Aramco in 1987, he has been involved in the study and exploration of the Paleozoic in Saudi Arabia. Allen holds a MSc in Geology from Wright State University.

Abdulrahman M. Al-Moqbel is a Geophysicist with Saudi Aramco. He graduated in 1995 from the University of Pacific (California) with a BSc in Geophysics. He has worked in the Geophysical Data Processing Division and the Area Exploration Division. Abdulrahman has been involved in the study and exploration of the Paleozoic hydrocarbons in the Eastern Province of Saudi Arabia. He is a member of the AAPG.

Improvement on a Multi-Stage, Multi-Disk Type Borehole Seismic Source

Toshiyuki Yokota, Shigeharu Mizohata, Nobusuke Shimada, Yasutaka Shoji and Yoshiro Ishii Japan National Oil Corporation

In 1991, OYO Corporation developed the first model of a borehole seismic source (OWS: OYO Wappa Source) with a spring accelerated, mass impact, single stage, fluid filled, multi-disk design. Testing showed that this type of source has several advantages such as good repeatability, easy operation and low electric power requirements.

Japan National Oil Corporation and OYO Corporation have made recent design modifications to their borehole source that will help assure its practicality for future oil field geophysical surveys. Our tests show that a multi-stage, multi-disk design effectively increases the source energy output. The latest source now has six stages and ten disks in each stage. Our design also includes a unique method of transmitting the energy from hammer to anvil, simultaneously impacting all six stages.

We performed a crosswell survey field test using our latest borehole source in a west Texas carbonate-reservoir oil field in 1996. The distance between the two wells was about 1,200 feet. Our tests showed that the source could generate sharp P-wave first breaks which is preferable for accurate tomography results.

We believe that the fundamental development of our borehole source is almost complete. Future studies will evaluate source characteristics such as radiation pattern, energy conversion efficiency, and its practicability.

Toshiyuki Yokota received BSc and MSc degrees in Mineral Science and Technology from Kyoto University in 1989 and 1991, respectively. He joined the Geological Survey of Japan in 1991 and was involved with geothermal energy development. Toshiyuki joined Japan National Oil Corporation in 1997. His current interest is borehole seismology, especially cross-well tomography and seismic-while-drilling.

Shigeharu Mizohata received his BSc and MSc degrees in Geophysics from Kobe University. He worked with Japex Geoscience Institute Inc. in 1992, where he specialized in survey to detect active faults. He also worked with VSP on crosswell project on geothermal area, which aimed to detect geothermal reservoir zone. Shigerharu joined Japan National Oil Corporation in 1997 and is currently working for development of borehole seismic source.

Nobusuke Shimada holds BSc and MSc degrees in Geophysics from Tohoku University. He joined Japan National Oil Corporation (JNOC) in 1985 and has been working on project evaluation and geophysical survey planning in Japan and overseas. Nobusuke is currently Assistant Director of Geophysics Laboratory in Technical Research Center at JNOC. His current interests are reservoir geophysics and reservoir characterization by integration of multi-disciplinary data.

Yasunori Shoji is currently an Engineer in the R&D Department of OYO Corporation Instruments Division. He received his BSc and MSc degrees in Mining from Tohoku University. Yasunori joined OYO Corporation in 1984 and has been working in developing instruments for both geophysical and geotechnical surveys.

Yoshiro Ishii is currently the Assistant General Manager of Japan National Oil Corporation (JNOC), Middle East Representative Office in Abu Dhabi. He received his BSc from Tokai University. He joined JNOC in 1981 and has been working in new project evaluation and implementation of geophysical surveys around the world, including Oman, Jordan and Myanmar. Yoshiro was Head of Reservoir Geophysics Group at the Technological Research Center of JNOC.

Biosteering Horizontal Wells in Homogeneous Carbonates Using Advanced High Resolution Nannofossil Biostratigraphy

Charles R. Young Phillips Petroleum Company

Advanced High Resolution Nannoplankton Biostratigraphy techniques were used on archived (stored) North Sea well cores to subdivide both the Tertiary and Cretaceous chalk reservoir intervals. The High Resolution Zones obtained were capable of resolving multiple sequences within the reservoir units. They were successfully used, on wellsite-real time mode, to steer horizontally drilled wells within restricted target zones (e.g., upper third of reservoir interval). Each of the selected archived wells was the nearest cored well to a horizontal well’s projected total depth.

The techniques provided high resolution nannoplankton zones with resolution finer than the conventional NN/NP, CN/CP, and KPN/Sissingh zones. The stratigraphic resolution achieved is a fraction of a seismic wavelet. These techniques were used to subdivide: (1) the major Tertiary reservoir unit (reworked Cretaceous Zone, Field Layer ED) of the Ekofisk field into three (four?) units; and (2) the Cretaceous reservoir (Tor Formation). The advanced techniques include: (1) population dynamics; (2) polar ordination; (3) morphometric analyses; and (4) synchronous variation of nannofossil assemblages and petrophysical parameters.

The use of archived cores and advanced nannofossil analytic techniques to furnish a viable intra-reservoir level zonal scheme, as proven by the successful current horizontal well drilling program, provided Phillips Petroleum with savings of up to a million dollars per well. This was achieved by eliminating the need to core pilot hole, and run detailed biostratigraphy on that core to obtain a viable zonal scheme for biosteering control of the horizontal part of the well. This resulted in both reduced rig time and consultant time on well site.

These, and techniques currently being investigated, provide the tools and methods for onsite biosteering of horizontal wells in homogeneous carbonates throughout the world.

Charles R. (Bob) Young received BSc and MSc degrees in Geology from Wichita State University. He worked as a Geologist and Biostratigrapher with Texaco from 1969 to 1973, and as a Biostratigrapher/Senior Biostratigrapher with Atlantic Richfield Co. (ARCO) from 1973 to 1980. Bob is currently Senior Biostratigrapher with Phillips Petroleum Company. He is also a charter member of the International Nannoplankton Association.

The Stratigraphic Creation of Intrashelf Basins: Examples from the Cenomanian/Turonian (Natih Formation) in North Oman

Frans S.P. van Buchem, Institut Français du Pétrole Philippe Razin, University of Bordeaux, Alain Y. Huc, Institut Français du Pétrole, Bernard Pradier, Peter W. Homewood, Elf and Heiko W. Oterdoom Petroleum Development Oman

Intra-shelf shallow basins are an essential part of carbonate petroleum systems. The source rocks generally accumulate in the intra-shelf depression, while the reservoirs are formed during the time-equivalent aggradation and the subsequent progradation of the carbonate platform. The Cenomanian/Turonian carbonate system in Northern Oman shows twice this typical stratigraphic pattern (Natih E and Natih B members).

This paper documents in detail the initiation and evolution of the Natih B intra-shelf depression, based on 16 detailed field sections and 10 wells covering an area of 120 by 60 kilometers (Jebel Akhdar, Adam Foothills, Natih field). A high resolution cyclo-stratigraphic framework has been constructed based on the bed-by-bed sedimentological description in outcrop and in core, the specific gamma-ray signature (wireline logs and outcrop natural gamma-ray curves), and the measurements of carbonate and organic matter distribution. The system evolves in the studied transect from an initially flat topography with little lateral facies variations, into a platform to shallow basin topography during a 3rd-order transgressive phase. Facies consist initially of couplets of organic-rich/organic-poor limestone beds, with a high abundance of oysters. Topography is created when carbonate productivity, and thus bed thickness, increases in the proximal position. The organic matter distribution varies considerably, but in a predictable pattern, in a vertical and lateral sense (0.03 to 14% Total Organic Carbon Content (TOC), while its quality does not show any changes. In a cross-plot, carbonate and TOC show a perfect inverse linear relationship. This suggests a simple dilution relationship between the variable carbonate supply, and the stable background sedimentation of marine organic matter and clay.

The geometrical evolution and sediment flux pattern of this intra-shelf basin are defined within the context of a highresolution time framework. This provides a predictive model for the source rock distribution, and its geometrical and stratigraphic relationship to adjacent carbonate reservoir facies.

Frans S.P. van Buchem see abstract “Geochemical Simulation of Dolomitization in Platform Carbonate Reservoirs” on page 81 for biography and photograph)

Philippe Razin (see abstract “Sedimentology and Reservoir Geometry of the Upper Permian Upper Gharif and Lower Khuff Formations in Interior Oman: Outcrop Study in the Haushi Area” on page 82 for biography and photograph)

Alain Y. Huc (see abstract “Distribution and Formation of Pyrobitumen in Haima Reservoirs in North Oman” on page 101 for biography and photograph)

Bernard Pradier is Organic Geochemist, and currently in charge of the Organic Petrology Laboratory of Elf Exploration Production. He has a background in Uranium Geochemistry (thesis, 1983), Organic Petrology and Geochemistry (doctorate, 1988), and published about thirty scientific papers. After four years of fundamental research at CNRS, Bernard joined Elf in 1992. He manages research projects concerned with hydrocarbon migration and organic sedimentology, and is responsible for operational studies in petroleum system evaluation.

Peter W. Homewood is Senior Scientific Adviser of Elf Aquitaine Production. He has 23 years of professional experience, of which 14 years were spent at the Universities of Zürich and Fribourg in Switzerland, and 9 years in the petroleum industry. His main fields of interest are sedimentology, sedimentation and tectonics and alpine geology. He has been the Editor of Sedimentology (1986-1990). Peter has a PhD from the University of Lausanne.

Heiko W. Oterdoom (see abstract “The Karim Oilplay: Cambrian Alluvial-Lacustrine Deposits in South-Central Oman” on page 97 for biography and photograph)

Geochemical Evaluation of the Djofra Saddle Area

Linda M. Zeroual Sonatrach

For more than forty years, the Djofra Basin, which includes exploration blocks 314 and 315, has not been extensively explored. The two Djofra exploration permits comprise an area of 15,263 square kilometers. The lack of exploration activity can be assessed by the fact that only eight exploration wells were drilled between 1956 and 1978, all based on structural criteria.

The primary target in this basin is a Lower Devonian sandstone reservoir with fair to good porosity, ranging from 8% to 30%. The reservoir permeability is poor, however, ranging from 0.1 to 0.7 mD, due probably to the presence of very fine-grained matrix and the abundance of carbonate and shaly cements. To date oil shows have been encountered in two wells: HMK-1 in block 314 and BEL-1 in block 350.

Despite the risk associated with this basin, exploration has resumed in these two blocks for several reasons: (1) the target reservoir is not very deep; (2) an excellent source rock consisting of the Silurian radioactive shale; and (3) the detection of seismic amplitude anomalies which are interpreted as Lower Devonian sand bars with stratigraphic trap potential.

The negative exploration results to date are interpreted to be the result of mis-timing between hydrocarbon generation and migration, on the one hand, and the structural trap development. A comprehensive geochemical study, based on core cuttings and well data, is used to develop a model for the hydrocarbon habitat of the Djofra Basin.

Linda M. Zeroual graduated as Geophysicist Engineer from the University of Algiers. She started working with Sonatrach in 1991. She then took up Geosciences studies at the French Petroleum Institute between 1992 and 1993. Linda rejoined Sonatrach and has been working with the company since 1993.