THE TARIM BASIN, NW CHINA: FORMATION AND ASPECTS OF PETROLEUM GEOLOGY

The formation and evolution since the Sinian of the Tirim Basin, NW China, are introduced in this paper. on the basis of a study of stratigraphical and sedimentaty facies. and an analysis of structura1, features. Mechanisms of basin formation have varied throughout this time, caused by frequent tectonic movements along the southern margin of the Eurasian Plate. As regards petroleum geology. six structural units have been classified from a consideration of the distribution of major source-rock sequences. An overall evaluation is made concerning hydrocarbon exploration in the individual structural units. Moreover, a general review is presented regarding source rocks, hydrocarbon reservoirs, trap structures, sealing layers and hydrocarbon generation, as well as possible recent exploration successes     

柴窝堡盆地的石油地质特征

柴窝堡盆地面积2880km²,是一个小型的山间构造盆地。它与准噶尔盆地之间隔有大断裂带和石炭系基岩凸起,其下可能存在前寒武基底硬块。中石炭世至二叠纪,柴窝堡地区为博格达裂谷和博格达残留海湖泊的一部分,侏罗纪末期因博格达山隆升而演变为山间盆地。柴窝堡盆地分为4个一级构造单元,其中达北凹陷面积1200km²,是石油勘探的远景区,其内的圈闭类型以背斜为主。盆地内发育两套生储盖组合,油、气资源量十分丰富。盆地内的局部构造被评价排队,分为4类,有3个可供优先勘探的有利构造。     

HYDROCARBON GENERATION POTENTIAL AND DEPOSITIONAL ENVIRONMENT OF SHALES IN THE CRETACEOUS NAPO FORMATION,EASTERN ORIENTE BASIN,ECUADOR

Marine shale samples from the Cretaceous (Albian‐Campanian) Napo Formation (n = 26) from six wells in the eastern Oriente Basin of Ecuador were analysed to evaluate their organic geochemical characteristics and petroleum generation potential. Geochemical analyses included measurements of total organic carbon (TOC) content, Rock‐Eval pyrolysis, pyrolysis — gas chromatography (Py—GC), gas chromatography — mass‐spectrometry (GC—MS), biomarker distributions and kerogen analysis by optical microscopy. Hydrocarbon accumulations in the eastern Oriente Basin are attributable to a single petroleum system, and oil and gas generated by Upper Cretaceous source rocks is trapped in reservoirs ranging in age from Early Cretaceous to Eocene. The shale samples analysed for this study came from the upper part of the Napo Formation T member (“Upper T”), the overlying B limestone, and the lower part of the U member (“Lower U”).The samples are rich in amorphous organic matter with TOC contents in the range 0.71–5.97 wt% and Rock‐Eval T_max values of 427–446°C. Kerogen in the B Limestone shales is oil‐prone Type II with δ¹³C of ?27.19 to ?27.45‰; whereas the Upper T and Lower U member samples contain Type II–III kerogen mixed with Type III (δ¹³C > ?26.30‰). The hydrocarbon yield (S₂) ranges from 0.68 to 40.92 mg HC/g rock (average: 12.61 mg HC/g rock). Hydrogen index (HI) values are 427–693 mg HC/g TOC for the B limestone samples, and 68–448 mg HC/g TOC for the Lower U and Upper T samples. The mean vitrinite reflectance is 0.56–0.79% R₀ for the B limestone samples and 0.40–0.60% R₀ for the Lower U and Upper T samples, indicating early to mid oil window maturity for the former and immature to early maturity for the latter. Microscopy shows that the shales studied contain abundant organic matter which is mainly amorphous or alginite of marine origin. Extracts of shale samples from the B limestone are characterized by low to medium molecular weight compounds (n‐C₁₄ to n‐C₂₀) and have a low Pr/Ph ratio (≈ 1.0), high phytane/n‐C₁₈ ratio (1.01–1.29), and dominant C₂₇ regular steranes. These biomarker parameters and the abundant amorphous organic matter indicate that the organic matter was derived from marine algal material and was deposited under anoxic conditions. By contrast, the extracts from the Lower U and Upper T shales contain medium to high molecular weight compounds (n‐C₂₅ to n‐C₃₁) and have a high Pr/ Ph ratio (>3.0), low phytane/n‐C₁₈ ratio (0.45–0.80) with dominant C₂₉ regular steranes, consistent with an origin from terrigenous higher plant material mixed with marine algae deposited under suboxic conditions. This is also indicated by the presence of mixed amorphous and structured organic matter. This new geochemical data suggests that the analysed shales from the Napo Formation, especially the shales from the B limestone which contain Type II kerogen, have significant hydrocarbon potential in the eastern part of the Oriente Basin. The data may help to explain the distribution of hydrocarbon reserves in the east of the Oriente Basin, and also assist with the prediction of non‐structural traps.     

PETROLEUM GEOLOGY OF THE FULA SUB‐BASIN,MUGLAD BASIN,SUDAN

The Fula sub‐basin is a fault‐bounded depression located in the NE of the Muglad Basin, Sudan, and covers an area of about 3560 km². Eleven oilfields and oil‐bearing structures have been discovered in the sub‐basin. The Lower Cretaceous Abu Gabra shales (Barremian – Aptian), deposited in a deep‐water lacustrine environment, are major source rocks. Reservoir targets include interbedded sandstones within the Abu Gabra Formation and sandstones in the overlying Bentiu and Aradeiba Formations (Albian – Cenomanian and Turonian, respectively). Oil‐source correlation indicates that crude oils in the Aradeiba and Bentiu Formations are characterized by low APIs (<22°), low sulphur contents (<0.2%), high viscosity and high Total Acid Number (TAN: >6 mg KOH/g oil on average). By contrast, API, viscosity and TAN for oils in the Abu Gabra Formation vary widely. These differences indicate that oil migration and accumulation in the Fula sub‐basin is more complicated than in other parts of the Muglad Basin, probably as a result of regional transtension and inversion during the Late Cretaceous and Tertiary. The Aradeiba‐Bentiu and Abu Gabra Formations form separate exploration targets in the Fula sub‐basin. Four play fairways are identified: the central oblique anticline zone, boundary fault zone, fault terrance zone and sag zone. The most prospective locations are probably located in the central oblique anticline zone.     

PETROLEUM GEOLOGY OF THE WESTERN PART OF THE CENTRAL IRAN BASIN

Eocene extension and magmatism in Central Iran was followed by late Eocene – early Oligocene uplift, erosion, volcanism and the deposition of the continental and evaporitic sediments of the Lower Red Formation. During the late Oligocene – early Miocene, an extensional (or transtensional) phase occurred with the deposition of the limestones and marls of the Qom Formation, followed by the evaporitic deposits or mudstones of the basal part of the Upper Red Formation. Since the late Miocene, compression has resulted in regional shortening and uplift, with the deposition of the thick, clastic-dominated upper part of the Upper Red Formation and the overlying conglomeratic unit. Between 1951 and 2016, a total of 45 exploration, appraisal and development wells were drilled across the western part of the Central Iran Basin where the Alborz, Sarajeh and Aran fields are hydrocarbon discoveries. Traps at these fields are NW-SE oriented detachment folds formed during the late Miocene – Pliocene. Porous and fractured limestones in the Qom e-member are the principal reservoir units, and are capped by evaporites or mudstones in the basal part of the Upper Red Formation. Organic-rich mudstones in the Qom e- and c-members together with shales in the Jurassic Shemshak Formation are potential source rocks. An overview of 80 years of exploration efforts in the western part of the Central Iran Basin suggests that the main reasons for the general lack of success include drilling-associated problems, poor reservoir characteristics, lack of hydrocarbon charge, and underestimating the thickness of the overburden on top of the Qom reservoir.     

对焉耆盆地油气地质条件的认识

焉耆盆地位于南天山造山带东部,是在海西期褶皱基底上形成的中新生代沉积盆地,作为西北地区一个小型的侏罗纪含油气盆地,该盆地除与周缘的塔里木盆地、吐哈盆地有相似性外,还有自己独特的石油地质条件。指出中生代原型盆地具有张扭性断陷盆地的沉积演化特征,构造变形以“挤压、走滑和拆离滑脱”为主要特征,形成了3种独特的构造控油组合及成藏模式;三叠系、侏罗系含油气系统在南北凹陷形成了2个相对独立的油气运聚系统,其中北部凹陷存在着燕山中期和喜山晚期2次油气充注期,而南部凹陷仅发育燕山中期一次油气充注期。     

PETROLEUM GEOLOGY IN THE PALEOZOIC CLASTICS OF THE MIDDLE AMAZON BASIN, BRAZIL

Paleoenvironmental maps of all the stratigraphic units of the Middle Amazon Basin from Ordovician to Early Carboniferous are analysed in terms of their source-rock and reservoir potentials. These maps were obtained by applying the following techniqes; detailed petrography of diamictites, sandstones and siltstones including measurements of index of clasticity; analysis of early and late diagenetic cementation processes; environmental interpretation of sedimentary structures; geochemistry of trace elements and lateral variations of clay mineral assemblages based on X-ray diffraction data. Five distinct sedimentary models were recognized. Fluvio-deltaic model consisting of fluvial, deltaic, distal deltaic and offshore subenvironments. Tidal flat model consisting of marshes, intertidal flat, shoreface and offshore subenvironments. Beach model consisting of dunes (inferred), beach, shoreforce and offshore subenvironments. Glacial model (Nhamundá time, Early Silurian), consisting of glacial (tillites), fluvial, beach, shoreface and offshore subenvironments. Glacial model (Curiri time, Late Devonian) consisting of glacial (tillites with subglacial sandstone channels and interglacial braided streams), shoreface and offshore subenvironments. From the association of these depositional models, the direction and intensity of the supply of coarse clastics was determined in a semi-quantitative manner for each stratigraphic unit. The time andspace distribution of the detritalsupplies and of the areas of coarse clastic sedimentation indicates a continuous synsedimentary tectonic control of the depocenters by the differential subsidence of the underlying Precambrian basement in the shape of large blocks limited by a system of NW-SE and NE-SW lineaments. By using an index of synsedimentary tectonic activity it is possible to define three major episodes of coarse clastic sedimentation which have the best reservoir potential: Early Silurian fluvio-glacial systems, Early Devonian progmding deltas and Late Devonian fluvio-glacial systems. The tmps for hydrocarbons are mainly stmtigmphic but enhanced by the weak structures of the basin and result from the relationship between the coarse clastics and two intervening sequences of mature black shales.     

STRATIGRAPHY AND PETROLEUM GEOLOGY OF THE CROATIAN PART OF THE ADRIATIC BASIN

Coastal parts of Croatia are dominated by the SW‐verging Dinaric foldbelt, to the west and SW of which is the Adriatic Basin (the stable foreland). In both areas, the stratigraphic column is dominated by a thick carbonate succession ranging from Carboniferous to Miocene. Four megasequences have been identified: (i) a pre‐platform succession ranging in age from Late Carboniferous (Middle Pennsylvanian: Moscovian) to Early Jurassic (Early Toarcian; Bru?ane and Ba?ke Ostarije Formations); (ii) an Early Jurassic to Late Cretaceous platform megasequence (Mali Alan Formation); (iii) a Paleogene to Neogene post‐platform megasequence (Ra?a Formation); and (iv) a Neogene to Quaternary (Pliocene to Holocene) megasequence (Istra and Ivana Formations). A number of organic‐rich intervals with source rock potential have been identified on‐ and offshore Croatia: Middle and Upper Carboniferous, Upper Permian, Lower and Middle Triassic, Lower and Upper Jurassic, Lower and Upper Cretaceous, Eocene, and Pliocene – Pleistocene. Traps and potential plays have been identified from seismic data in the Dinaric belt and adjacent foreland. Evaporites of Permian, Triassic and Neogene (Messinian) ages form potential regional seals, and carbonates with secondary porosity form potential reservoirs. Oil and gas shows in wells in the Croatian part of the Adriatic Basin have been recorded but no oil accumulations of commercial value have yet been discovered. In the northern Adriatic offshore Croatia, Pliocene hemi‐pelagic marlstones and shales include source rocks which produce commercial volumes of biogenic gas. The gas is reservoired in unconsolidated sands of the Pleistocene Ivana Formation.     

伦坡拉第三纪盆地的形成机理和石油地质特征

位于班-怒大断裂中的赞-兹断层右行走滑拉分,是伦坡拉盆地形成的动力学机制.盆地的石油地质特征表现为：①现今构造格局具南北分带、东西分块的特点;②牛堡组不仅厚度大,而且分布广,自下而上三段的粒度和颜色还具粗-细-粗和红-黑-红的特点,而丁青湖组不仅粒度细,而且颜色深,厚度小,分布局限;③源岩颜色深、粒度细、厚度大、分布广、有机质类型好、成熟度中等、转化率高;④储集砂体厚度大、分布广,且孔、渗条件好;⑤油气显示类型多、分布广,原油密度较大,粘度较低,高蜡低硫,后生变化强烈     

PETROLEUM GEOLOGY OF THE TARIM BASIN, NW CHINA: RECENT ADVANCES

The Tarim Basin is located in the Xijiang Uygur Autonomous Region of NW China, and covers an area of about 560,000 sq. km. At dawn on September 22nd, 1984, Well Shashen-2 (drilled by a team from the Ministry of Geology and Mineral Resources) blew-out spectacularly when it penetrated Ordovician dolomites at a depth of 5,392m. The blow-out marked the discovery of a highly-productive oil- and gasfield, from which daily output has reached 1,000 m³ oil and 2 MM (million) m³ gas.
Over the last decade or so, 560,000 km of gravimetric surveys (scale l.10⁶) and 338,000 km of airborne magnetic surveys (1:200,000) have been completed. Some 200,000 line-km of 2-D seismic profiles and 10,000 km of 3-D surveys have also been carried out, and more than 200 wells have been drilled. Twenty-two oilfields producing from ten stratigraphic intervals, four of which have reserves of more than 100 million tons, have been discovered or explored, indicating that the future prospects for petroleum exploration in the basin are very favourable (Kang and Huang, 1992; Jia, 1991a; 1991b). Annual production in the Tarim Basin reached 2,300,000 t in 1995 (Kang et al, 1996).     

FACIES DISTRIBUTION AND PETROLEUM GEOLOGY OF THE BOMBAY OFFSHORE BASIN, INDIA

In view of the recent oil and gas dicoveries in the Bombay Offshore basin, its detailed geology has been worked out in terms of its source rock and reservoir potential. An agewise, layer-cake lithofacies analysis and five depositional model maps from Paleocene to Middle Miocene age, together with a number of paleotectonic sections has led to the reconstruction of a xeneralized depositional model of the basin as a whole. This proposed depositional model envisages the Bombay Offshore basin as a shelf-to-basin carbonate model. During Paleogene and Early Neogene time the clastic supply by the proto-Narmada river from the NE resulted in delta progradation up to the Dahanu depression, which was a region of pro-deltas and lagoons with a considerable thickness of finer clastics. Beyond the Dahanu depression, the Bombay High and Bassein-Alibag-Ratnagiri shelf remained open carbonate platforms, while the DCS area was the locale of shelf-edge carbonate build-up.
The potential targets for exploration are the deltaic sandstone to the north in the Tapti area—particularly where the sandy facies interfingers with the shales and the porous limestone horizons in the Bombay Platform, Bassein-Alibag-Ratnagiri shelf and the DCS trend. The Dahanu depression is thought to be the main source rock area.     

海拉尔盆地石油地质特征及勘探前景

海拉尔盆地是在古生代褶皱基底上形成的中新生代断陷盆地,国内面积为40550km²。盆内上侏罗统厚达5300m,其扎赉诺尔群的深浅湖相、沼泽相沉积最厚达4400m,是盆地主要生油层,有机质丰度中等,干酪根属Ⅱ、Ⅲ类,已成熟。盆内呈北东向长条状凹凸相间的构造格局,各凹陷都具有多物源的沉积特征,砂体发育,各类圈闭众多。地面及钻孔中已见多处油气显示,并在海参4井中发现了工业油流,说明盆地勘探前景良好。     

PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE ADRIATIC BASIN,OFFSHORE CROATIA

Offshore Croatia is a relatively underexplored area with no oilfields currently on production. Exploration commenced in 1970 and several biogenic gas fields were subsequently discovered producing from shallow Plio‐Pleistocene reservoir rocks in the northern Adriatic area; however, exploration wells drilled for oil in Mesozoic carbonates have failed, although several wells encountered oil shows. Using data from the Croatian and Italian Adriatic, we provide in this paper some new insights into the Mesozoic palaeogeography and hydrocarbon plays of offshore Croatia. Offshore Croatia has been divided into three areas – north, central and south – with distinctive geological characteristics and hydrocarbon systems. The effects and importance of halokinesis in the eastern Adriatic is described and its influence on the petroleum systems is discussed. The evaluation of a modern, regional, high‐resolution dataset has enhanced our understanding of the Adriatic Basin and supports the presence of petroleum systems with potential mature source rocks in shales from the Triassic succession, supplying reservoir rocks in Jurassic and Cretaceous carbonate platform margins/slope talus plays, and Cenozoic siliciclastic plays.     

PETROLEUM GEOLOGY AND HYDROCARBON POTENTIAL OF THE GUBAN BASIN,NORTHERN SOMALILAND

The Guban Basin is a NW‐SE trending Mesozoic‐Tertiary rift basin located in northern Somaliland (NW Somalia) at the southern coast of the Gulf of Aden. Only seven exploration wells have been drilled in the basin, making it one of the least explored basins in the Horn of Africa – southern Arabia region. Most of these wells encountered source, reservoir and seal rocks. However, the wells were based on poorly understood subsurface geology and were located in complex structural areas. The Guban Basin is composed of a series of on‐ and offshore sub‐basins which cover areas of 100s to 1000s of sq. km and which contain more than 3000 m of sedimentary section. Seismic, gravity, well, outcrop and geochemical data are used in this study to investigate the petroleum systems in the basin. The basin contains mature source rocks with adequate levels of organic carbon together with a variety of reservoir rocks. The principal exploration play is the Mesozoic petroleum system with mature source rocks (Upper Jurassic Gahodleh and Daghani shales) and reservoirs of Upper Jurassic to Miocene age. Maturity data suggest that maximum maturity was achieved prior to Oligocene rift‐associated uplift and unroofing. Renewed charge may have commenced during post‐ Oligocene‐Miocene rifting as a result of the increased heat flows and the increased depth of burial of the Upper Jurassic source rocks in localised depocentres. The syn‐rift Oligocene‐Miocene acts as a secondary objective owing to its low maturity except possibly in localised offshore sub‐basins. Seals include various shale intervals some of which are also source rocks, and the Lower Eocene evaporites of the Taleh Anhydrite constitute an effective regional seal. Traps are provided by drag and rollover anticlines associated with tilted fault blocks. However, basaltic volcanism and trap breaching as a consequence of the Afar plume and Oligocene‐Miocene rifting of the Gulf of Aden cause considerable exploration risk in the Guban Basin.     

南海万安盆地油气地质特征

在充分了解万安盆地基底地质结构和地层发育特征的基础上,揭示了盆地的成因机制和地质构造演化史,探讨了盆地的油气地质特征及其在不同地区的差异,并初步确定了盆地的含油气远景。     

伊宁盆地类型及其石油地质意义

伊宁复合盆地成生发展可划分为石炭纪一早二叠世、晚二叠世和新生代3个构造发展阶段,相应地先后形成了孤内盆地、孤内残余盆地和远源碰撞山间盆地3种性质各异的原型盆地。弧内盆地属典型拉张型盆地,弧内残余盆地属地幔冷却收缩沉降盆地,生油岩系均较发育;远源碰撞山间盆地属压性盆地,生油岩系不发育。前两类盆地油气前景较好。     

RESERVOIR SANDSTONES OF THE CRETACEOUS NAPO FORMATION U AND T MEMBERS IN THE ORIENTE BASIN,ECUADOR: LINKS BETWEEN DIAGENESIS AND SEQUENCE STRATIGRAPHY

This paper investigates whether diagenetic alterations in sandstones and resulting changes in reservoir quality are influenced by depositional environments and sequence stratigraphy. The study focusses on the Cretaceous U and T sandstone members of the Napo Formation in the Oriente Basin of Ecuador. The sandstones were deposited in fluvial, transitional and marine environments, and comprise Lowstand (LST), Transgressive (TST) and Highstand Systems Tract (HST) deposits. The data were obtained by detailed petrographic observations supported by microprobe, stable isotope, and fluid inclusion analyses. The sandstones consist of fine- to medium-grained quartzarenites and subarkoses. Diagenetic events include cementation by chlorite, early and late kaolinite/dickite, early and late carbonates (siderite, Fe-dolomite/ankerite), and quartz. Early (eogenetic) processes included formation of chlorite grain coatings, kaolinite pore filling, and siderite (SI) cementation. Chlorite is absent in TST sandstones but was found frequently in LST-HST sandstones. Early kaolinite is not present in LST sandstones but occurred frequently in LST-HST sandstones. The distribution of mesogenetic cements relative to sequence stratigraphy is different in the U and T units. In the U sandstones, calcite is frequent in LST deposits and absent in the LST-HST. Fe-dolomite/ankerite is abundant only in the TST. S2 siderite is present in the TST and LST, but absent in the LST-HST. Quartz cement and kaolinite/dickite are equally distributed in all systems tracts. In the T sandstones Fe-dolomite/ankerite is only abundant in the TST, whilst calcite, quartz and dickite have similar distributions in all the systems tracts. The distribution of kaolinite cement is interpreted to be the result of relatively more intense meteoric-water flux occurring during sea-level fall, whereas chlorite cement may have formed through burial diagenetic transformation of precursor clays e.g. berthierine which was precipitated in mixed marine-meteoric waters in tidal channel and estuarine environments. Chlorite cement in the T and U sandstones appears to have retarded development of quartz overgrowths, and 12–13% primary porosity is retained. The T sandstones (LST-HST) contain up to 4% chlorite cement. Little evidence for chemical compaction was found with the exception of occasional concave-convex grain contacts. Eogenetic siderite appears to have helped to preserve reservoir quality through supporting the sandstone framework against further compaction, but mesogenetic calcite has considerably reduced primary porosity. Eogenetic siderite (SI) was partly replaced by later carbonate cements such as late siderite (S2) and Fe-dolomite. Although there appears to be a relationship in the Napo Formation between the occurrence of siderite SI and sequence stratigraphy, the relationship may change when original volumes of siderite are considered. There is likewise partial replacement of early kaolinite and recrystalization to dickite which masks the amount of original early kaolinite. Since the amount of early kaolinite could not be confirmed, the relationship to sequence stratigraphy is tentative. Only chlorite seems to have a clear relationship to sequence stratigraphic framework in the Napo Formation. The high intergranular volume (IGV) of the sandstones indicates that cementation played a more important role than mechanical and chemical compaction in both Napo Formation sandstone members. Later dissolution of feldspar grains and siderite cements was the main process of secondary porosity development (up to 11% in the U sandstones).     

广西百色盆地石油地质概述

百色盆地地处广西西部,东起思林,西至百色,长109公里,宽2—9公里,面积830平方公里。盆地的石油地质工作已有几十年的历史,在七十年代进行了大规模的综合勘探,结果在田东凹陷的北部找到了油气富集区,为建设广西第一个石油基地创造了条件。     

西北地区石油地质特征及油气前景

西北地区(贺兰山——六盘山以西、昆仑山——秦岭以北)主要受南北挤压力和南北对扭力作用,产生了以北西向的西域系和东西向的纬向系为主干的多构造体系的复合.形成了与我国东部截然不同的区域构造特征.1.地壳结构:莫霍面一般为36—60公里;地幔上隆部位常常是中新生代厚度变化的斜坡带上.2.区域构造格架:(1)西域系:由阿尔泰构造带、博罗霍洛——祁连构造带及巴楚——奇曼塔克构造带等为骨干和相应的沉降带所组成.发生于早古生代,晚古生代活动最强烈,中新生代仍有活动.     

THE PETROLEUM GEOLOGY OF THE EARLY EOCENE EL GARIA FORMATION, HASDRUBAL FIELD, OFFSHORE TUNISIA

The Hasdrubal field (offshore Tunisia) comprises an Early Eocene shallow‐marine nummulitic limestone reservoir (the El Garia Formation) sourced by deep‐marine mudstones and limestones of the generally age‐equivalent Bou Dabbous Formation. The field is located on a NNW‐SSE trending horst between a series of en‐echelon normal to oblique faults, and is dip‐closed except to the north where a stratigraphic pinch‐out into the Bou Dabbous Formation is inferred. Middle Eocene shales and dense limestones of the Cherahil Formation form the main seal. The El Garia Formation reservoirs significant volumes of hydrocarbons in Tunisia and Libya. A detailed micropalaeontological and nannofossil study has been undertaken of the El Garia Formation and the immediately over‐ and underlying formations which together form the Metlaoui Group, using subsurface data from the Hasdrubal field. This has permitted a detailed chronostratigraphic and sequence stratigraphic framework to be developed, including the recognition of three flooding events, which can partly be calibrated with second‐order sequences, thus permitting the correlation of discrete reservoir units across the field. A further six microfaunal events are recognized between the Chouabine Formation and the “Compact Micrite Member” within the Metlaoui Group. Previous depositional models for the El Garia Formation are discussed and a new model is proposed. The model partly explains why a number of wells drilled along the El Garia nummulite “bank” trend have failed to encounter the nummulite reservoir fades, and why, even where this fades was encountered, the limestones were frequently tight and/or contained limited hydrocarbons. It is also suggested that proximity to source is a critical factor, with the development of dissolution porosity by acidic pore waters migrating in advance of hydrocarbons. This is critical for enhancing reservoir quality and thus promoting the capacity to reservoir hydrocarbons, as indicated by the location of existing discoveries.