The Upper Jurassic Arab C Reservoir in the Dukhan Field is the product of a stable epicontinental shelf subjected to continuous relative sea-level variations, with the preserved sediments representing a complex of syndepositional carbonate lithologies and textures deposited in subtidal, intertidal and sabkha environments. Though the depositional units are spatially correlated within a sequence-stratigraphic context, petrophysical observations do not conform to the primary depositional fabric, and a cross-cutting relationship is observed.

Petrographic analysis highlights sporadic occlusion of primary inter-particle porosity by overgrowth burial-diagenetic calcite cements. Though this form of cementation is observed throughout the reservoir, the prevalence is observed to increase significantly below an inferred free-water level (paleo-FWL), associated with a concomitant reduction in porosity relative to a preserved higher porosity above the contact. By inference, a continuum of diagenetic overprinting has occurred during burial. It is directly related to the temporal variation in hydrocarbon charge displacing water within the trap, which regulates both the abundance and aqueous-phase transport potential for calcium and carbonate ions. Stylolitic dissolution seams are abundant and may be an important source of calcite dissolution by-products.

The reservoir has a high spatial sampling density of core and petrophysical logs (800 m average well spacing). Detailed analysis of the porosity distribution and trends has facilitated the interpretation of structural closure development during burial, hydrocarbon charge and structural tilting. These processes have interacted to produce the current petrophysical spatial configuration. Doming related to the formation of the Qatar Arch has instigated the recent uplift in the southern part of the Dukhan Field, with the tilt levering diagenetically cemented facies from below the paleo-FWL to a new position above the re-equilibrated current FWL. The paleo-FWL encloses the preserved high-porosity interval, and is spatially coincident with a ring of bitumen occurrences. At ground level, the Neogene Hofuf fluvial deposits are uplifted and tilted, and constrain the maximum age for the uplift event.

By virtue of the analysis, process and the recognition of inter-linked structural and diagenetic processes, a unified porosity-trend model has been formulated. It captures the sum of the individual components from a common generic standpoint, and has helped to increase the predictability of the simulated inter-well porosity variations.

3-D carbonate seismic stratigraphy of the Berriasian–Valanginian Minagish Field region, Kuwait

Maha Al-Baghli (Kuwait Oil Company <mbaghli@kockw.com>) and John D. Pigott (University of Oklahoma, USA)

Much previous exploration in the Minagish Field of Kuwait has concentrated upon prospectivity of the principle structures facilitated by 3-D seismic with much less attention directed toward stratigraphic studies. Therefore, questions concerning the seismic imagery of carbonate reservoir quality and seal potential owing to facies changes accompanying allocyclic (global tectono-eustatic) and autocyclic (depositional) processes with a paragenetic overprint (diagenetic-fracture history) have been only modestly studied. The focus of this investigation is upon the carbonate seismic facies placed within a sequence-stratigraphic framework.

In order to characterize the geophysical aspects (facies) of the operational seismic sequences and subdivided parasequences, we employed seismic attributes constrained with the lithostratigraphic information furnished by the boreholes. Those practical seismic attributes, which were especially well-suited to the facies analysis of these carbonates, are shown in Figure 1.

An integrated procedure that combines “Galloway borehole motif” and “Vail seismic sequence” indicates eight distinct operational seismic sequences (parasequence sets). These sequences reveal the dynamic interplay between local autocyclic processes (the advance and foundering of carbonate shoaling platforms) versus regionally correlative allocyclic processes (marl flooding accompanying sea-level rise and apparent non-depositonal-discontinuity surfaces with sea-level stillstands). For this gently subsiding platform edge of the intra-shelf Gotnia Basin during the Berriasian–Valanginian, eight parasequence sets are readily observed. These cycles observed in the third-order borehole Galloway motifs are consistent with the Vail seismic interpretations and their vertical accommodation space-fill dynamics. Although these cycles do not exactly coincide with the formal stratigraphic nomenclature of the area (e.g. the Middle Minagish), they are easily identified on seismic, correspond to Galloway motifs, and are numbered, from bottom to top, in Table 1.

Overall, the four rythmic couplets in Figure 3 demonstrate the dynamic interplay between allocyclic and autocyclic carbonate depositional processes of a subsiding carbonate basin margin with changes in relatively high-energy grainstone-packstone progradation units capped by lower-energy wackestone-mudstone flooding units. It is the underlying high-energy couplets, which exhibit the greater reservoir quality in this field. Within the parasequence sets, the incorporation of the seismic attributes into facies maps, and constrained with the borehole information, reveals episodes of carbonate ooid bank development and abandonment, which corresponds to spatial differences in reservoir quality.

Further seismic facies work integrated with borehole petrophysics and petrography may provide important insight into the petroleum system evolution of the Minagish Field as well as identify reservoir sweet spots.

Sequence stratigraphy and sedimentology of the Upper Jurassic Arab and Hith formations, Abu Dhabi, United Arab Emirates

Abdulla Al-Mansoori (ADCO <amansoori@adco.ae>) and Christian J. Strohmenger (ExxonMobil <christian.j.strohmenger@exxonmobil.com>)

The Kimmeridgian–Tithonian Arab and Hith formations are part of the highstand sequence set of a second-order supersequence, built by five third-order composite sequences: (1) J70 Sequence, Jubaila/Arab D; (2) J80 Sequence, Arab C; (3) J90 Sequence, Arab B; (4) J100 Sequence, Arab A/Lower Asab Oolite; and (5) J105 Sequence, Upper Asab Oolite/Hith), bounded on top by sequence boundary J110 SB. The J70 to J105 sequences belong to the highstand sequence set of the Upper Jurassic second-order supersequence and show progradation of the facies belts towards the east. Through time, the lagoon behind the barrier-bar complex became increasingly evaporitic being dominated by salina-type deposits during Hith deposition (J105 Sequence).

The overall depositional environment envisaged for the Arab Formation is that of a barrier-shoal complex with open-marine, offshore sedimentation to the east and a protected, evaporitic, platform interior (lagoon) to the west. A barrier-shoal complex was developed along the platform margin and deposition was dominated by oolitic grainstones. Concomitant deposition of sabkha, tidal-flat, salina, and lagoonal sediments occurred westwards, and open-marine mudstones and wackestones were deposited eastwards of the barrier-shoal complex.

Reservoir quality is strongly controlled by the depositional environment and the lithofacies types. The best reservoir is present within grain-dominated lithofacies types of the barrier-shoal complex. Relatively poor reservoir quality is characteristic of mud-dominated lithofacies types that occur in open-marine environments. In the platform interior, the dominantly dolomitized lithofacies types show quite good reservoir qualities within thin intercalated packstone to grainstone layers, interpreted as tidal-channel or washover deposits. During Hith time, the restriction of the platform interior increased, and predominantly salina-type, anhydrite-after-gypsum was deposited.

The focus of this study is on the depositional environment of the anhydrite sediments, as it is important to distinguish between salina-type (saltern) and sabkha-type evaporites. In contrast to sabkha-type deposits, where evaporites form within the host rock (sediment-dominated: late highstand and lowstand systems tracts), salina-type deposits represent subaqueous evaporite precipitations (evaporite-dominated: late lowstand and transgressive systems tracts deposits). Distinguishing between the different anhydrite depositional environments is crucial for the correct sequence-stratigraphic interpretation of the Arab and Hith carbonate-evaporite successions.

Distribution of the reservoir properties in the Minagish and Ratawi formations (Kuwait): A complex interplay of sedimentation, depositional architecture and diagenesis

Haifa R. Al-Muraikhi (Kuwait Oil Company <hmuraikh@kockw.com>), Dipankar Dutta (Kuwait Oil Company), Sawsan N. Al-Anezi (Kuwait Oil Company), Benoit Vincent (Cambridge Carbonates), Joanna Garland (Cambridge Carbonates) and Peter Gutteridge (Cambridge Carbonates)

The Middle Minagish (Tithonian-Berriasian) and Ratawi (Valanginian) formations are oil-bearing carbonate reservoirs in the Umm Gudair Field of Kuwait. Reservoir properties vary widely between these two, due to significant variation in the interplay of sedimentation, depositional architecture, and diagenesis. In order to constrain reservoir properties and predict their distribution, this study integrates sedimentological, sequence-stratigraphic and high-resolution petrographic data from three cored wells (900 ft of core) in the Minagish Formation, and two cored wells (350 ft of core) from the Ratawi Formation.

The Minagish Formation was deposited in an overall eastward-prograding carbonate ramp. Seven facies associations have been identified in it, ranging from outer ramp, through mid-inner ramp with small rudist-corals buildups, to inner-ramp protected muddy lagoonal settings. The sequence-stratigraphic scheme shows the lateral continuity of the sedimentary architectures, however, the Middle/Upper Minagish boundary is diachronous, being older in the western part of the field where the clastic source of the Upper Minagish delta progradation is located. Five reservoir rock types have been identified in the Minagish Formation. Interparticle porosity and microporosity are the key pore-type. Cementation has only a minor direct effect on reservoir quality, but locally prevents subsequent chemical compaction.

The regional setting for the Ratawi Limestone around Umm Gudair Field was an intra-shelf depression with the dominance of lagoonal allochems. The Ratawi Limestone has a distinctive cyclicity, which represents frequent shifting of depositional environments due to fluctuation of relative sea level. Cycles typically shallow upward from mid/outer-ramp argillaceous facies associations to inner-ramp bioturbated wackestone-grainstone.

The cyclic nature of sedimentation in the Ratawi Limestone favoured chemical compaction in the argillaceous units at the base of each sedimentary cycle. Redistribution of dissolved carbonates in the stylolites/seam-rich levels cemented the lithofacies in nearby horizons. The circulation of acidic fluids, preceding oil emplacement, generated an enlargement of preserved microporosity in the non-cemented middle part of the sedimentary cycles, and around burrows within the tight zones. The latter zones are almost exclusively oil-stained, whereas the cemented zones may represent barriers to flow. Three rock types have been established in the Ratawi Formation and the dominant pore types are typically micropores and moulds.

Upper Arab Reservoir correlation in a giant gas field in the United Arab Emirates: Integration of core, log, borehole image and pressure data

Fatima Al Darmaki (Al Hosn Gas <Fatima.AlDarmaki@alhosngas.com>), David A. Lawrence (Al Hosn Gas), Richard P. Singleton (Al Hosn Gas), Noel Lucas (Al Hosn Gas) and Ewan Swindells (Baker Hughes)

The upper interval of the Arab Formation is a secondary reservoir objective in a major gas field currently under development in onshore Abu Dhabi, United Arab Emirates (UAE). This presentation will illustrate the impact of integrating core sedimentological descriptions, log response, borehole image and pressure data to develop a sequence-stratigraphic correlation of thin reservoir targets in the upper interval of the Arab Formation.

Historically the upper interval of the Arab Formation is defined as two reservoir-bearing units (the Arab A and B members) overlain by the regionally extensive anhydrite top seal of the Hith Formation. These subdivisions were based on lithostratigraphic correlations driven largely by porosity log trends. The Hith - Arab A/B comprises predominantly non-reservoir lime mudstones and anhydrites with thin inter-beds of reservoir quality limestone and dolomites. The Hith - Arab A/B interval undergoes rapid areal thickness variations as observed in central Abu Dhabi where it thins towards its easterly depositional limit.

The contact between the Arab A and B is gradational and clearly diachronous, becoming stratigraphically younger to the northeast. The basal Arab B generally comprises slightly thicker carbonate reservoir units. Pressure data has indicated that these limestones are most likely in pressure communication with the underlying lower Arab sequence. The Arab A carbonate units are more vertically discrete carbonate layers and tend to be more dolomitic. Well correlations and pressure data indicate that these carbonates are laterally extensive, encased within anhydrites. The upper layers of the Arab A show different pressure and fluid compositional regime. It is likely that they experienced different gas charge and fill histories.

A sequence stratigraphic-based correlation framework has been developed, with at least 13 high-frequency sequences recognized. These are typically characterized by a transgressive phase (limestone/dolomite) capped by a regressive phase (anhydrite). Early cementation and dolomitization can modify primary depositional surfaces. Despite this, minor discordances have been recognized by subtle dip changes from borehole image data and their significance for correlation is being evaluated.

The revised correlation framework has significant impact on mapping areal trends in reservoir facies, understanding reservoir connectivity and fluid property variations. Well design and depletion strategies are being modified to ensure optimal drainage of layers with different fluid and pressure regimes.

From geochemistry to stratigraphy: Unraveling the history of three oil machines in Kuwait

Rita Andriany (Kuwait Oil Company <RAndriany@kockw.com>), Awatif Al-Khamiss (Kuwait Oil Company) and Ghaida Al-Sahlan (Kuwait Oil Company)

The application of biological markers (biomarkers) as geochemical fossils for exploration, development, and production purposes is growing rapidly. Their ability to retain the chemical structures during geological processes has been utilized to differentiate among three main source-rock intervals from Late Jurassic to Early Cretaceous. Two source-rock intervals, the Oxfordian Najmah and Berriasian Makhul formations, have been recognized as two giant oil machines. The presence of a fine-grained interval in the Hith Formation opens a new target for exploration.

A number of selected compounds of biomarkers and carbon-isotope ratios can separate these three source rocks (fine-grained intervals) into their genetic relationship: Makhul (cluster-1), Najmah (cluster-3), Gotnia and Hith (cluster-4). The evidence of similarity (genetic relationship) between oil stains and core within the Hith Formation is the crucial clue for exploration. It indicates that the fine-grained interval within the Hith Formation is a new potential charge. However, due to the limited evidence that is based on just one sample, more data should be examined to improve the reliability of the interpretation.

Oxygen levels change with sea-level fluctuations and glaciations, and an increase of the oxygen intensity in the water column will decrease the amount of preserved organic matter. The history of oxidation and reduction during sedimentation processes can be determined by comparing the pristane/phytane (Pr/Ph) ratios over selected parameters including the pristane/n-C17, phytane/n-18, gammacerane index, and canonical variable. A general decrease in Pr/n-C17, and the absence of gammacerane accompanied by high Ph/n-C18 (> 0.3), porphyrin and sulfur content, within the Najmah source rock, indicates the deposition of carbonates in an anoxic marine environment. The Najmah source rock contains more total organic matter (TOC weight %) than the Makhul source rock. In summary, geochemical fossils in fine-grained intervals are not only capable of unraveling genetic relationships (oil-oil to source correlation), but also can be utilized as stratigraphic markers because they retain chemical structures during geological processes.

Geochemical characterization and volumetric assessment of the prolific Mesozoic source rocks of the northeastern Arabian Plate

Adrian A.M. Aqrawi (Statoil <aamaq@statoil.com>) and Balazs Badics (Statoil <balb@statoil.com>)

The Middle-Upper Jurassic and Lower Cretaceous strata of the NE Arabian Plate contain several prolific world-class source rocks for some of the largest petroleum systems globally. They are located within the Zagros and Mesopotamian foreland basins covering the northern, central and southeastern parts of Iraq, together with western and southwestern parts of Iran, particularly the Lurestan and Khuzestan provinces. These source rocks principally include the Bajocian-Bathonian Sargelu, the Callovian-Early Kimmeridgian Naokelekan and the Late Tithonian-Early Berriasian Chia Gara and Sulaiy formations of Iraq and their chronostratigraphic equivalents in Iran. They have charged the main Cretaceous and Tertiary reservoirs throughout Iraq and Iran (in various trap types and sizes) with more than 250 billion barrels of proven recoverable hydrocarbons.

Stratigraphically, these formations represent transgressive system tracts (TST) sequences deposited within the deep basinal settings of anoxic environments. Lithologically, they are dominated by black shales and bituminous marly limestones with high total organic carbon (TOC) contents (ranging from 1–18 wt% TOC) and by Type II kerogen. Their Rock Eval S2 yields may reach up to 60 mg HC/g Rock, particularly along the depocenter of the Mesopotamian Foreland Basin. The immature Hydrogen Index (HI) values might have been up to 700 mg HC/g TOC; the present-day observed values vary depending on the location within the basin and the present-day maturity. The Source-Potential Index (SPI) [i.e. mass of hydrocarbons in tons, which could be generated from an area of 1.0 sq m in case of 100% Transformation Ratio] ranges from 1–4 in the paleo shallow-water areas reaching 10–12 in the basin centre, with maximum values of 16–18 in the paleo-depocentres.

Assuming a mean gross formation thickness of 178 m (and net source rock thickness of 110 m having >1% TOC), a mature area of 327,000 sq km, with a 3.71 wt% of mean immature TOC and HI of 600 mg HC/g TOC, the Sargelu Formation could have generated up to 9,200 billion barrel of oil and 1,800 billion barrel of oil-equivalent gas within the Mesopotamian foreland and Zagros basins. The Naokelekan Formation is a very thin condensed section, so a net source-rock thickness of 15 m (having > 1% TOC), in a mature area of 205,000 sq km, with a 5.0 wt% mean immature TOC and HI of 650 mg HC/g TOC, this formation could have generated up to 1,237 billion barrel of oil and 250 billion barrel of oil-equivalent gas in the same basins. Finally, the Chia Gara Formation with a net source rock thickness of 55 m (having > 1% TOC), in a mature area of 166,000 sq km with a 3.70 wt% mean immature TOC and HI of 550 mg HC/g TOC could have generated up to 1,900 billion barrel of oil and 391 billion barrel of oil-equivalent gas in the Mesopotamian foreland and Zagros basins of NE Arabian Plate.

Hydrocarbon prospectivity of the Late Jurassic–Early Cretaceous Makhul Formation in north and northwestern Kuwait

Raju T. Arasu (Kuwait Oil Company <rarasu@kockw.com>), Sunil K. Singh (Kuwait Oil Company), Talal F. Al-Adwani (Kuwait Oil Company), Badruzzaman Z. Khan (Kuwait Oil Company), Jose Macadan (Kuwait Oil Company) and Ali F.N. Abu-Ghaneej (Kuwait Oil Company)

The Late Tithonian–Early Berriasian Makhul Formation is the lowermost sedimentary sequence of the Thamama Group in Kuwait. It is underlain by the anhydrite deposits of the Hith Formation, and conformably overlain by the Minagish carbonates. The Makhul carbonates are about 900 feet thick and buried at depths of 11,000 to 14,000 ft in Kuwait.

The depositional environment of the Makhul is interpreted as inner neritic, in a northeast dipping ramp setting. Two highstand system tracts have been identified within the formation. In terms of lithofacies it is divided into upper, middle and lower zones. The upper zone is an argillaceous lime mudstones/wackestone, interbedded with slightly dolomitic limestone. The middle zone is dominated by grey mudstone to wackestone with rare packstone. Occasional thin laminae showing faint fluorescence are present within this interval. The lower Makhul zone consists of kerogen-rich layers with alternating laminae of mudstone and wackestone. It has potential to act as source rock. The porosity of the formation is 3–4%.

In the northern parts of Kuwait the Makhul section is imaged by 2-D and 3-D seismic reflections as a northeastward prograding package, downlaping onto the top of the Hith Formation. The acoustic impedance of the lower Makhul is very low, comparable to the impedance of shale and grading to relatively higher impedance towards the top.

That the tight reservoirs of the Makhul Formation have hydrocarbon potential is proven. A few wells in the south and a recently drilled well in north Kuwait have produced oil in the initial testing. Furthermore, some of the deep wells have recorded very high formation gas while drilling.

Fractures are present in the Makhul rocks as seen in the well data. They may play a vital role for the sustainable production from these unconventional reservoirs. A 3-D seismic-based discontinuity attribute has brought out evenly spaced sub-vertical discontinuities. Interestingly, the wells which have intersected discontinuities gave high gas readings in the mudlog. Anomalous frequency absorption seen at places could be an indicator of hydrocarbon/fractures.

Understanding the trapping mechanism and geomechanical properties of the formation can lead to ‘sweet spots’ for commercial success in future.

Field-scale heterogeneity of carbonate reservoirs from the Arab Formation: Lessons learned from seven case studies

Bruno Caline (Total <bruno.caline@total.com>), Mathieu Rousseau (Total), Carine Maza (Total), Alain Roumagnac (Total), Solange Cantaloube (Total) and Eric Zuckmeyer (Total)

Preparation of robust reservoir model for the Arab Formation relies on a thorough characterization of the different carbonate facies from core and thin-section examination. However, the key step remains to properly extrapolate the detailed facies recognition in cored wells to uncored wells. The objective of this presentation is to illustrate how electrofacies have been successfully first calibrated on a few cored wells and then extrapolated to all uncored wells in five hydrocarbon fields in the United Arab Emirates (UAE) and two in Qatar.

The sedimentary interpretation of the Arab reservoirs from the different studied fields is primarily based on the integration of: (1) high-resolution stratigraphic architecture of the carbonate-evaporite series allowing subdivision of the reservoir interval into meter-scale stratigraphic units; and (2) recognition of depositional and diagenetic trends within each stratigraphic unit in order to constrain the distribution of the main facies.

Special attention was paid to properly define a number of pre-rock types along selected cored wells, each of them being characterised by a specific log signature and porosity/permeability relationship. Once this calibration exercise was carried out, the pre-rock types were propagated to uncored wells. The robustness of the propagation needs to be validated by few blind tests on cored wells that were not used in the calibration step. This method proved to be successful in recognizing the main reservoir facies including grain-supported facies affected by tar mat deposition.

Maps for each stratigraphic unit were prepared to display the thickness and proportion of electrofacies on a well-by-well basis. These maps were used to constrain the field-scale distribution of reservoir facies taking into account the depositional and diagenetic trends provided by regional paleogeographical reconstructions. Results from the seven field case studies will be highlighted during the presentation.

Termination of the Gotnia Salt and its effects on the petroleum system of the Partitioned Zone, Saudi Arabia and Kuwait

Robert Corley (Saudi Arabian Chevron <corlera@chevron.com>), Mike Ye (Chevron Wafra Joint Operations) and Sukhdarshan Kumar (Kuwait Gulf Oil Company)

The Partitioned Zone is an area located along the southern border of the State of Kuwait and the northeastern portion of the Kingdom of Saudi Arabia. The Gotnia Formation of Late Kimmeridgian to Early Tithonian age lies unconformable below Sulaiy/Makhul formations and conformable above the Jubaila Formation, within the Partitioned Zone. Gotnia age-equivalent formations, on the Arabian Platform, include the Arab-Hith formations of Saudi Arabia, Qatar and United Arab Emirates. The Gotnia Formation extends from southern Iraq through Kuwait reaching a maximum thickness of approximately 1,500 feet in southern Kuwait. The termination of the Gotnia Formation is approximately 50 km south of its recorded maximum thickness. Terminus of the Gotnia Formation is mappable and extends in an east-west direction through the Partitioned Zone. Extensive 3-D and 2-D seismic coverage allows detailed identification of the southern pinch-out of the Gotnia Formation. Subsurface control is also aided by several deep wells on either side of the Gotnia pinch-out. This effort will demonstrate and define the structural and stratigraphic nature of the Gotnia Formation’s southern terminus and its effect on the petroleum system within the Partitioned Zone.

Sequence stratigraphy and depositional systems in the Late Jurassic to Early Cretaceous (Oxfordian to Valanginian) of the Arabian Plate: Implications for regional exploration and reservoir description

Roger B. Davies (Neftex Petroleum Consultants <roger.davies@neftex.com>) and Michael D. Simmons (Neftex Petroleum Consultants)

The Oxfordian to Valanginian succession on the Arabian Plate is dominated by extensive carbonate shelves and intra-shelf basin deposits that were the sites of rich source-rock accumulation. The largest of the intra-shelf basins is variably called the Mesopotamian/Gotnia/Garau Basin and persisted throughout this period whereas other intra-shelf basins were most strongly developed in the Oxfordian and show evidence of progressive infill by shelf-margin sediments. Evaporites are a major component of Kimmeridgian to Tithonian deposition in both shelf and basinal locations, but less significant in other parts of the stratigraphy. Siliciclastics are generally less important, though increasing clastic deposition in the Early Cretaceous, particularly in the northern half of the plate, heralded the major Zubair/Biyadh delta system that dominated the succeeding Hauterivian to Barremian stratigraphy in the western half of the Arabian Plate (Saudi Arabia, Kuwait and southern Iraq).

The Oxfordian to Valanginian contains several important petroleum systems reflecting the presence of numerous source rock, reservoir and seal combinations (Figure 1). Arguably it contains the most important petroleum system on Earth, namely the Late Jurassic of Saudi Arabia, Qatar and the United Arab Emirates (UAE). The system consists of the world-class Oxfordian source rocks of the Hanifa and Diyab formations, which fed the overlying stacked Kimmeridgian Arab Formation reservoirs. The reservoirs are sealed by regional intra-formational evaporites of the Arab Formation, with the ultimate topseal comprising the widespread Hith Formation anhydrites. There are additional major petroleum systems in other parts of the Arabian Plate, particularly Kuwait, southern Iraq and the Khuzestan region of Iran. Smaller but significant petroleum systems are present within the rift basins of Yemen. There are also examples of breached oil fields in the Zagros (Goff, 2005).

As noted above source rock deposition covered a large proportion of the Arabian Plate particularly during the Oxfordian and Late Tithonian to Early Berriasian. In addition to the Hanifa and Diyab formations, Oxfordian source rocks include the very rich Naokelekan Formation of Iraq and the Najmah Formation of Kuwait. We suspect that parts of the source-prone Sargelu Formation in Iran (Bordenave and Hegré, 2010) and Iraq are also of Oxfordian age, though detailed biostratigraphic data is not available. Late Tithonian to Berriasian source rocks include the Makhul Formation of Kuwait, the Sulaiy Formation of southern Iraq and the Garau Formation of southwestern Iran. The distribution of these source rocks is directly related to the stratigraphic history of the various intra-shelf basins. The Late Jurassic rifts of Yemen contain important Kimmeridgian-Tithonian source rocks in the Madbi and Sabatayn formations (Sachsenhofer et al., 2012) and there are other potential source rocks of Berriasian age (Alaug et al., 2011).

In addition to the Arab Formation, major reservoirs include the Hanifa and Hadriya in Saudi Arabia and the UAE, the Ratawi Oolite of the Partitioned Neutral Zone (PNZ), the Najmah, Minagish and Ratawi Limestone formations of Kuwait, the Najmah and Yamama formations of Iraq, and the Fahliyan Formation of Iran. There are more minor reservoirs in the Late Jurassic of the Yemen rift basins.

Major seals are formed by Late Jurassic evaporites, Berriasian marls and Early Valanginian shales. Widespread evaporite deposits were deposited in both platformal and basinal environments, particularly in the Kimmeridgian to Tithonian stages, notably forming the Hith and Gotnia formations of southern Iraq, Kuwait, Saudi Arabia, Qatar and the UAE. Evaporites of the Sabatayn Group are important seals in the Yemen rift basins.

Marls and shales that form important seals in the Early Cretaceous of northern Saudi Arabia, the PNZ, Kuwait and southern Iraq reflect increasing westerly-derived siliciclastic supply. Earlier siliciclastic input is recorded in other parts of the Arabian Plate, notably the Tithonian Makhul Formation and Tithonian–Berriasian Karimia Mudstone Formation in central Iraq (van Bellen et al., 1959-2005), and the Oxfordian to Tithonian Alif and Lam formations present in the rifts of Yemen (Ellis et al., 1996).

Local stratigraphy is well understood, particularly where there are major petroleum systems. For example, one of the first applications of sequence stratigraphy to reservoir description in the Middle East was for the Hanifa and Hadriya Member reservoirs of the Berri Field in Saudi Arabia where clear platform to basin transitions are proved by multiple well penetrations (McGuire et al., 1993). Nevertheless there are considerable stratigraphic and depositional variations across the Arabian Plate and correlations between more distant areas are not well-documented. As in other parts of Middle Eastern stratigraphy there is a dearth of well-documented and well-illustrated biostratigraphic data to constrain ages and hence correlations. Also very little age control is available currently from strontium-isotope dating of carbonates and anhydrites. Nevertheless careful sequence-stratigraphic analysis means that many of the correlations can be established across the Arabian Plate with reasonable confidence, and that a plate-wide sequence-stratigraphic framework can be applied. This analysis necessarily has considered sequence-stratigraphic models for mixed carbonate-evaporite and mixed carbonate-siliciclastic depositional systems in both platform and basinal settings. It has also taken into account available biostratigraphic and strontium-isotope ages.

Sharland et al (2001; updated in Sharland et al., 2004; Simmons et al., 2007) identified ten plate-wide maximum flooding surfaces in the Oxfordian to Valanginian succession (Figure 1). Further work continues to validate these surfaces, not just on the Arabian Plate but worldwide, and hence they still offer the most effective method for plate-wide correlation. We use them to discuss the sequence stratigraphy of the Oxfordian to Valanginian across the entire Arabian Plate and its importance in future exploration and detailed reservoir description.

The base of the Oxfordian Stage corresponds to a subaerial exposure surface in platform areas (J50 SB) but lies within an interval of continuous deposition within the source-rich intra-shelf basins. (Sharland et al., 2001, 2004). These intra-shelf basins either progressively filled with prograding shelf margin carbonates or evolved from source-prone to dominantly evaporitic basins that persisted into the Tithonian. Two Oxfordian maximum flooding surfaces (J50, J60) are associated with the richest source rock horizons.

The Kimmeridgian and Early Tithonian was a period of shelf-margin progradation into the intra-shelf basins allied to increasing isolation and associated evaporite deposition. Shallow-water sediments gradually infilled the Hanifa and Diyab intra-shelf basins, leading to widespread deposition of the Arab Formation and Asab Oolite shelf-margin grainstones. These grainstones were “trailed” by micrite-dominated, platform interior facies capped by evaporites deposited in widespread salterns. Strong cyclicity of the J70 to J100 MFS matches the Arab reservoir units. Deposition in these platform areas differed markedly from that in the longer-lived Gotnia intra-shelf basin where sequence-stratigraphic analysis identifies the same number of depositional cycles. Thick subaqueous halites and anhydrite dominated deposition but there is unequivocal evidence of at least one episode when at least parts of the Gotnia Basin completely dried out, probably due to complete isolation from more marine waters.

There is marked regional stratigraphic variation across the Jurassic/Cretaceous boundary. In some areas, particularly in the Mesopotamian/Gotnia/Garau Basin, we interpret continuous deposition across the Jurassic/Cretaceous boundary, whereas there is considerable missing (probably uplifted and eroded) Late Jurassic section in Syria (Krasheninnov et al., 2005; Caron and Mouty, 2007), the eastern UAE (Vahrenkamp et al., 2012), Oman (Rousseau et al., 2005, 2006) and Iran (Setudehnia, 1978; Gollestaneh, 1974).

Very extensive regional deposition was re-established during the Late Tithonian and Early Berriasian, except in Syria where Tithonian to Valanginian rocks are poorly represented. Important source rock deposition is associated with the J110 and K10 MFS. Carbonate ramps dominated by Bacinella-Lithocodium packstones and grainstones are widespread (Sadooni, 1993; Davies et al., 2000). These ramps prograded into the inherited and under-filled Late Jurassic Gotnia intra-shelf basin in the northern half of the Arabian Plate, and towards major marine embayments in Iran (Gollestaneh, 1974), eastern UAE (Aziz and El Sattar, 1997) and Oman (Droste and Van Steenwinkel, 2004). Siliciclastic deposition, (including sandstones and shales) was initially localised in central Iraq (Jassim and Goff 2006) and within the Yemen rifts (Ellis et al., 1996; Brannan et al., 1999). Marls of the Upper Minagish Member of the Minagish Formation in Kuwait are present in the K20 HST and form the diachronous topseal to the Minagish Oolite reservoirs (Davies et al., 2000; Banerjee and Haider, 2009). The overlying Ratawi Limestone reservoir contains the K30 MFS while the succeeding Ratawi Shale dominates the K30 HST (Sharland et al., 2001).

Within the Late Valanginian there is a tectonically enhanced, platform-wide unconformity (K40 SB of Sharland et al. 2001, 2004) that corresponds to a worldwide lowstand of sea level. The uppermost part of the Valanginian represents part of the transgressive systems tract to that unconformity. Recent work has identified significant relief on the K40 SB particularly in Kuwait where Late Valanginian sandstones of the lowermost Zubair Formation partially infill this relief and contain additional stratigraphically trapped reserves (Tanoli et al., 2011).