HYDROCARBONS IN THE MIDDLE MIOCENE JERIBE FORMATION,DYALA REGION,NE IRAQ

The Lower Miocene Jeribe Formation in northern and NE Iraq is composed principally of dolomitic limestones with typical porosity in the range of 10–24% and mean permeability of 30 mD. The formation serves as a reservoir for oil and gas at the East Baghdad field, gas at Mansuriya, Khashim Ahmar, Pulkhana and Chia Surkh fields, and oil at Injana, Gillabat, Qumar and Jambur. A regional seal is provided by the anhydrites of the Lower Fars (Fat'ha) Formation. For this study, oil samples from the Jeribe Formation at Jambur oilfield, Oligocene Baba Formation at Baba Dome (Kirkuk field) and Late Cretaceous Tanuma and Khasib Formations at East Baghdad field were analysed in order to investigate their genetic relationships. Graphical presentation of the analytical results (including plots of pristane/nC₁₇ versus phytane/nC_l8, triangular plots of steranes, tricyclic terpane scatter plots, and graphs of pristanelphytane versus carbon isotope ratio) indicated that the oils belong to a single oil family and are derived from kerogen Types II and III. The oils have undergone minor biodegradation and are of high maturity. They were derived from marine organic matter deposited with carbonate‐rich source rocks in suboxic‐anoxic settings. A range of biomarker ratios and parameters including a C₂₈/ C₂₉ sterane ratio of 0.9, an oleanane index of 0.2 and low tricyclic terpane values indicate a Late Jurassic or Early Cretaceous age for the source rocks, and this age is consistent with palynomorph analyses. Potential source rocks are present in the Upper Jurassic – Lower Cretaceous Chia Gara Formation and the Middle Jurassic Sargelu Formation at the Jambur, Pulkhana, Qumar and Mansuriya fields; minor source rock intervals occur in the Balambo and Sarmord Formations. Hydrocarbon generation and expulsion from the Chia Gara Formation was indicated by pyrolysate organic matter, palynofacies type (A), and the maturity of Gleichenidites spores. Oil migration from the Chia Gara Formation source rocks (and minor oil migration from the Sargelu Formation) into the Jeribe Formation reservoirs took place along steeply‐dipping faults which are observed on seismic sections and which cut through the Upper Jurassic Gotnia Anhydrite seal. Migration is confirmed by the presence of asphalt residues in the Upper Cretaceous Shiranish Formation and by a high migration index (Rock Eval SI / TOC) in the Chia Gara Formation. These processes and elements together form a Jurassic/Cretaceous – Tertiary petroleum system whose top‐seal is the Lower Fars (Fat'ha) Formation anhydrite.     

Thermal modeling and hydrocarbon generation of the Late Jurassic-Early Cretaceous Chia Gara Formation in Iraqi Kurdistan region,northern Zagros Fold Belt

The Late Jurassic-Early Cretaceous Chia Gara Formation is an important oil-source rock in Iraqi Kurdistan region. Chia Gara source rock is characterised by high organic matter and sulphur content with Type II_S kerogen. 1D basin models were integrated with geological information and geochemical data from Chia Gara Fm at four well locations in Kurdistan region, northern Iraq. The models of the burial/thermal history indicate that Chia Gara Fm is presently in the peak-oil generation window and some oil cracked to gas during Late Eocene to Late Miocene time. Onset of oil-generation began during the Middle Paleocene- Early Oligocene (60–30?Ma). Oil was generated during the Late Eocene to Late Miocene (48–9 Ma). The models also suggest that the oil was expelled from Chia Gara source rock during the Late Eocene to Late Miocene (37–9 Ma), with a transformation ratio more than 50%. The high transformation ratio of more than 80% in two wells suggests that the generated oil was cracked to gas during the end of Middle Miocene time and continued to present day. The basin modeling results further suggest that Chia Gara Formation acts as a prolific petroleum-source rock and significant of oil and limited of gas have been generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.     

SOURCE ROCK POTENTIAL OF THE UPPER JURASSIC – LOWER CRETACEOUS SUCCESSION IN THE SOUTHERN MESOPOTAMIAN BASIN,SOUTHERN IRAQ

This paper reports on the hydrocarbon potential of subsurface samples from the Upper Jurassic Lower Cretaceous succession at the Rumaila (North and South), Zubair, Subba and West Qurna oilfields in southern Iraq. A total of 37 fine‐grained core samples of the Sulaiy, Yamama, Ratawi and Zubair Formations from ten wells were analyzed. Contents of organic carbon and sulphur were measured; other analyses included Rock‐Eval pyrolysis, optical microscopy in incident light, solvent extraction and gas chromatography of non‐aromatic hydrocarbons. The results indicated that the samples from the Cretaceous succession (Yamama, Zubair and Ratawi Formations) are at moderate levels of thermal maturity, whereas samples from the Upper Jurassic – Lower Cretaceous Sulaiy Formation are at a stage of thermal maturity beyond peak oil generation. According to the results of this study, the Sulaiy Formation is an excellent highly‐mature source rock and it is probably responsible for the generation of large quantities of oil in the study area. The samples differ with respect to their organic fades and biomarker distribution, indicating that palaeo depositional conditions varied significantly.     

A PRELIMINARY EVALUATION OF JURASSIC SOURCE ROCK POTENTIAL IN KUWAIT

Jurassic sedimentary rocks in Kuwait are generally assigned to the Marrat, Dhruma, Sargelu and Najmah Formations (mainly limestones and calcareous shales) and the overlying Hith and Gotnia Formations which are composed of anhydrites and evaporites. This paper reports the results of organic-geochemical analyses of Jurassic carbonate and shale samples recovered from ten wells in Kuwait. Analytical techniques included TOC analysis, elemental analyses of kerogen, density separation and petrographic analyses. The thermal history of Kuwait was modelled and calibrated with maturity indicators from the studied wells.
The analytical results point to the presence of marine kerogen between Types II and III. Generally, the formations show amorphous rich sapropelic organic matter with high H/C ratios and low densities. Biodegradation of some samples resulted in elevated O/C ratios. The results of maturity studies indicate that most of the Jurassic Succession is mature, maturity differences being due to depth variations. Oil generation began in Late Cretaceous to Eocene time when structural traps had already been formed. Jurassic source rocks may therefore have supplied reservoir units in Kuwait. In particular, the Najmah Formation includes well-preserved amorphous marine algal type organic matter. The high TOC values and thermal maturity of this formation make it one of the most important potential sources of oil in Kuwait.     

伊拉克中部白垩系油藏油源及运移特征

针对伊拉克中部Ahdeb油田白垩系油藏油源不清、油藏特征不明问题,以原油地化分析数据、三维地震解释、包裹体地化分析等作为研究对象,对其油源及运移特征进行分析。研究表明Ahdeb油田白垩系油藏烃类流体均形成于还原-强还原、相对闭塞海相有机质沉积,生物标志物特征对比表明,各油藏油源一致。结合伊拉克地区源岩地化特征对比分析,源岩应为上侏罗统Chia Gara组。运移以垂向为主,通道为受基底Najiad断裂控制形成的南西-北东向开启性走滑断裂,主要向断裂终点上白垩统Khasib组发生垂向运移,运移中遇横向发育高孔渗储层发生侧向运移,为次运移方向。Chia Gara源岩自白垩纪晚期开始排烃,整体可划分为2期运移:第一期发生于晚白垩世-新近纪,流体为低熟源岩排出的重质油,此时圈闭未形成,原油进入Khasib层后沿高孔渗地层向盆缘做大规模运移;第二期为新近纪后扎格罗斯造山运动使地层埋深迅速增加,源岩进入高成熟期排出的相对高成熟原油,随圈闭形成而聚集成藏。     

PETROLEUM GEOLOGY OF THE NOGAL BASIN AND SURROUNDING AREA,NORTHERN SOMALIA,PART 2: HYDROCARBON POTENTIAL

Seismic reflection profiles and well data show that the Nogal Basin, northern Somalia, has a structure and stratigraphy suitable for the generation and trapping of hydrocarbons. However, the data suggest that the Upper Jurassic Bihendula Group, which is the main source rock elsewhere in northern Somalia, is largely absent from the basin or is present only in the western part. The high geothermal gradient (～35–49 °C/km) and rapid increase of vitrinite reflectance with depth in the Upper Cretaceous succession indicate that the Gumburo Formation shales may locally have reached oil window maturity close to plutonic bodies. The Gumburo and Jesomma Formations include high quality reservoir sandstones and are sealed by transgressive mudstones and carbonates. ID petroleum systems modelling was performed at wells Nogal‐1 and Kalis‐1, with 2D modelling along seismic lines CS‐155 and CS‐229 which pass through the wells. Two source rock models (Bihendula and lower Gumburo) were considered at the Nogal‐1 well because the well did not penetrate the sequences below the Gumburo Formation. The two models generated significant hydrocarbon accumulations in tilted fault blocks within the Adigrat and Gumburo Formations. However, the model along the Kalis‐1 well generated only negligible volumes of hydrocarbons, implying that the hydrocarbon potential is higher in the western part of the Nogal Basin than in the east. Potential traps in the basin are rotated fault blocks and roll‐over anticlines which were mainly developed during Oligocene–Miocene rifting. The main exploration risks in the basin are the lack of the Upper Jurassic source and reservoirs rocks, and the uncertain maturity of the Upper Cretaceous Gumburo and Jesomma shales. In addition, Oligocene‐Miocene rift‐related deformation has resulted in trap breaching and the reactivation of Late Cretaceous faults.     

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.     

HYDROCARBON ACCUMULATION PROCESSES IN THE YANGTAKE FOLDBELT,KUQA FORELAND BASIN,NW CHINA: INSIGHTS FROM INTEGRATED BASIN MODELLING AND FLUID INCLUSION ANALYSES

Abundant gas and condensate resources are present in the Kuqa foreland basin in the northern Tarim Basin, NW China. Most of the hydrocarbons so far discovered are located in foldbelts in the north and centre of the foreland basin, and the Southern Slope region has therefore been less studied. This paper focusses on the Yangtake area in the west of the Southern Slope. Basin modelling was integrated with fluid inclusion analyses to investigate the oil and gas charge history of the area. ID modelling at two widely spaced wells (DB‐1 and YN‐2) assessed the burial, thermal and hydrocarbon generation histories of Jurassic source rocks in the foreland basin. Results show that the source rocks began to generate hydrocarbons (R_o >0.5%) during the Miocene. In both wells, the source rocks became mature to highly mature between 12 and 1.8 Ma, and most oil and gas was generated at 5.3–1.8 Ma with peak generation at about 3 Ma. Two types of petroleum fluid inclusions were observed in Cretaceous and lower Paleocene sandstone reservoir rocks at wells YTK‐5 and YTK‐1 in the Yangtake area. The inclusions in general occur along healed microfractures in quartz grains, and have either yellowish or blueish fluorescence colours. Aqueous inclusions coexisting with both types of oil inclusions in Cretaceous sandstones in well YTK‐5 had homogenization temperatures of 96–128 °C and 115–135 °C, respectively. The integrated results of this study suggest that oil generated by the Middle Jurassic Qiakemake Formation source rocks initially charged sandstone reservoirs in the Yangtake area at about 4 Ma, forming the yellowish‐fluorescing oil inclusions. Gas, which was mainly sourced from Lower Jurassic Yangxia and Middle Jurassic Kezilenuer coaly and mudstone source rocks, initially migrated into the same reservoirs in the Yangtake area at about 3.5 Ma and interacted with the early‐formed oils forming blueish‐fluorescing oil inclusions. The migration of gas also resulted in formation of the condensate accumulations which are present at the YTK‐1 and YTK‐2 fields in the Yangtake area.     

东海陆架盆地中新生代构造演化对烃源岩分布的控制作用

东海陆架盆地为发育于克拉通基底之上的中、新生代叠合盆地,该盆地经历了晚三叠世(?)—中侏罗世克拉通边缘坳陷盆地、白垩纪弧前盆地和晚白垩世末—新生代弧后裂陷盆地等3个构造演化阶段。侏罗纪盆地和白垩纪盆地主要残留在中央隆起带;新生代盆地演化在平面上表现出裂陷由西向东迁移的特征。不同时代盆地构造类型和大地构造位置控制了盆地烃源岩发育层位及平面分布:西部坳陷带以古新统月桂峰组湖相泥岩和灵峰组、明月峰组滨海相煤系地层为主要烃源岩;中央隆起带以上三叠统—中侏罗统福州组为主要烃源岩;东部坳陷带以始新统平湖组煤系地层为主要烃源岩,渐新统和中新统煤系地层为次要烃源岩。西湖凹陷天台斜坡带为中、新生代有利烃源岩的叠合区,具有“中生中储”和“新生中储”的优势,是东海陆架盆地天然气勘探的有利地区。     

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.     

蒙南盆地群石油地质条件评价

蒙南盆地群位于内蒙古中西部,由大小不等的10多个盆地组成。与油气有关的沉积地层主要是侏罗系和白垩系。经野外露头剖面和钻井岩性分析,下、中侏罗统五当沟组、厂汉沟组和下白垩统固阳组发育深湖半深湖相泥(页)岩、碳质泥岩和泥灰岩,是区内主要的烃源岩。烃源岩已进入成熟阶段,处于生油高峰期。侏罗系白垩系发育多套扇三角洲、分流河道以及三角洲前缘砂体,是较好的储集砂体。其中,侏罗系储集砂体的孔渗条件较差,白垩系砂体的孔渗条件较好。从整体上看,侏罗白垩系不仅具有下生、中储、上盖的组合型式,而且各层序亦具有自生、自储、自盖的组合型式。综合分析后,认为武川、桑根达来盆地为勘探最有利地区,三道沟、旗下营、乌兰花、固阳等盆地居次。     

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.     

SOURCE ROCK POTENTIAL OF EOCENE, PALEOCENE AND JURASSIC DEPOSITS IN THE SUBSURFACE OF THE POTWAR BASIN, NORTHERN PAKISTAN

The hydrocarbon source rock potential of five formations in the Potwar Basin of northern Pakistan – the Sakesar Formation (Eocene); the Patala, Lockhart and Dhak-Pass Formations (Paleocene); and the Datta Formation (Jurassic) – was investigated using Rock-Eval pyrolysis and total organic carbon (TOC) measurement. Samples were obtained from three producing wells referred to as A, B and C. In well A, the upper ca. 100 m of the Eocene Sakesar Formation contained abundant Type III gas-prone organic matter (OM) and the interval appeared to be within the hydrocarbon generation window. The underlying part of the Sakesar Formation contained mostly weathered and immature OM with little hydrocarbon potential. The Sakesar Formation passes down into the Paleocene Patala Formation. T_max was variable because of facies variations which were also reflected in variations in hydrogen index (HI), TOC and S2/S3 values. In well A, the middle portion of the Patala Formation had sufficient maturity (T_max 430 to 444°C) and organic richness to act as a minor source for gas. The underlying Lockhart Formation in general contained little OM, although basal sediments showed a major contribution of Type II/III OM and were sufficiently mature for hydrocarbon generation. In Well B, rocks in the upper 120 m of the Paleocene Patala Formation contained little OM. However, some Type II/III OM was present at the base of the formation, although these sediments were not sufficiently mature for oil generation. The Dhak Pass Formation was in general thermally immature and contained minor amounts of gas-prone OM. In Well C, the Jurassic Datta Formation contained oil-prone OM. T_max data indicated that the formation was marginally mature despite sample depths of > 5000 m. The lack of increase in T_max with depth was attributed to low heat flows during burial. However, burial to depths of more than 5000 m resulted in the generation of moderate quantities of oil from this formation.     

GEOCHEMICAL EVALUATION OF CRUDE OILS FROM THE CARACARA AND TIPLE AREAS,EASTERN LLANOS BASIN,COLOMBIA: PALAEO BIODEGRADATION AND OIL MIXING

This study presents an organic geochemical characterization of heavy and liquid oils from Cretaceous and Cenozoic reservoir rocks in the Tiple and Caracara blocks in the eastern Llanos Basin, Colombia. Samples of heavy oil were recovered from the Upper Eocene Mirador Formation and the C7 interval of the Oligocene – Miocene Carbonera Formation; the liquid oils came from these intervals and from the Cretaceous Guadalupe, Une and Gachetá Formations. The heavy oil and most of the liquid oils probably originated from multiple source rocks or source facies, and showed evidence of biodegradation as suggested by the coexistence of n‐alkanes and 25‐norhopanes. The results indicate a close genetic relationship between the samples in the Carbonera (C7 interval), Mirador and Guadalupe Formation reservoirs. These petroleums are interpreted to result from at least two separate oil charges. An early charge (Oligocene to Early Miocene) was derived from marine carbonate and transitional siliciclastic Cretaceous source rocks as indicated by biomarker analysis using GC/MS. This initial oil charge was biodegraded in the reservoir, and was mixed with a later charge (or charges) of fresh oil during the Late Miocene to Pliocene. A relatively high proportion of the unaltered oil charge was recorded for heavy oil samples from the Melero‐1 well in the Tiple block, and is inferred to originate from Cenozoic carbonaceous shale or coaly source rocks. Geochemical parameters suggest that oils from the Gachetá and Une Formations are similar and that they originated from a source different to that of the other oil samples. These two oils do not correlate well with extracts from transitional siliciclastic source rock from the Upper Cretaceous Gachetá Formation in the Ramiriqui‐1 well, located in the LLA 22 block to the north. By contrast, one or more organofacies of the Gachetá Formation may have generated the heavy oil and most of the liquid oil samples. The results suggest that the heavy oils may have formed as a result of biodegradation at the palaeo oil‐water contact, although deasphalting cannot entirely be dismissed.     

TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES,DANISH CENTRAL GRABEN,NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.     

AN OVERVIEW OF THE PETROLEUM SYSTEMS IN THE IONIAN ZONE,ONSHORE NW GREECE AND ALBANIA

The Ionian and Gavrovo Zones in the external Hellenide fold‐and‐thrust belt of western Greece are a southern extension of the proven Albanian oil and gas province. Two petroleum systems have been identified here: a Mesozoic mainly oil‐prone system, and a Cenozoic system with gas potential. Potential Mesozoic source rocks include organic‐rich shales within Triassic evaporites and dissolution‐collapse breccias; marls at the base of the Early Jurassic (lower Toarcian) Ammonitico Rosso; the Lower and Upper Posidonia beds (Toarcian–Aalenian and Callovian–Tithonian respectively); and the Late Cretaceous (Cenomanian–Turonian) Vigla Shales, part of the Vigla Limestone Formation. These potential source rocks contain Types I‐II kerogen and are mature for oil generation if sufficiently deeply buried. The Vigla Shales have TOC up to 2.5% and good to excellent hydrocarbon generation potential with kerogen Type II. Potential Cenozoic gas‐prone source rocks with Type III kerogen comprise organic‐rich intervals in Eocene–Oligocene and Aquitanian–Burdigalian submarine fan deposits, which may generate biogenic gas. The complex regional deformation history of the external Hellenide foldbelt, with periods of both crustal extension and shortening, has resulted in the development of structural traps. Mesozoic extensional structures have been overprinted by later Hellenide thrusts, and favourable trap locations may occur along thrust back‐limbs and in the crests of anticlines. Trapping geometries may also be provided by lateral discontinuities in the basal detachment in the thin‐skinned fold‐and‐thrust belt, or associated with strike‐slip fault zones. Regional‐scale seals are provided by Triassic evaporites, and Eocene‐Oligocene and Neogene shales. Onshore oil‐ and gasfields in Albania are located in the Peri‐Adriatic Depression and Ionian Zone. Numerous oil seeps have been recorded in the Kruja Zone but no commercial hydrocarbon accumulations. Source rocks in the Ionian Zone comprise Upper Triassic – Lower Jurassic carbonates and shales of Middle Jurassic, Late Jurassic and Early Cretaceous ages. Reservoir rocks in both oil‐ and gas‐fields in general consist of silicilastics in the Peri‐Adriatic Depression succession and the underlying Cretaceous–Eocene carbonates with minimal primary porosity improved by fracturing in the Albanian Ionian Zone. Oil accumulations in thrust‐related structures are sealed by the overlying Oligocene flysch whereas seals for gas accumulations are provided by Upper Miocene–Pliocene shales. Thin‐kinned thrusting along flysch décollements, resulting in stacked carbonate sequences, has clearly been demonstrated on seismic profiles and in well data, possibly enhanced by evaporitic horizons. Offshore Albania in the South Adriatic basin, exploration targets in the SW include possible compressional structures and topographic highs proximal to the relatively unstructured boundary of the Apulian platform. Further to the north, there is potential for oil accumulations both in the overpressured siliciclastic section and in the underlying deeply buried platform carbonates. Biogenic gas potential is related to structures in the overpressured Neogene (Miocene–Pliocene) succession.     

阆中地区须家河组烃源岩动态演化模拟

随着川北元坝地区须家河组天然气勘探取得重大突破,相邻的阆中地区须家河组的油气资源潜力开始受到重视。由于前期针对研究区须家河组烃源岩生、排烃演化以及生、排烃量等方面的研究较少,制约了须家河组油气资源潜力评价。文章从研究区的基础地质特征入手,运用三维盆地模拟技术开展烃源岩生、排烃演化史研究,并最终落实资源潜力。研究表明:须家河组烃源岩具有分布广泛、厚度大、处于生烃中心、有机质丰度高、热演化程度高等特点;该组烃源岩从中侏罗世晚期开始大量生烃,到早白垩世末期生烃结束,生、排烃期与构造形成期之间匹配关系良好,有利于油气的近源成藏;该组烃源岩生、排烃能力强,单位面积累计生、排烃量分别达94.25×108m3/km2和90.18×108m3/km2,资源潜力大,须三、须四段油气勘探前景良好。     

准噶尔盆地东部石炭系烃源岩演化模拟

利用TSM盆地模拟软件,对准噶尔盆地东部石炭系烃源岩的埋藏史、热演化史和生烃史进行分析。结果表明,研究区的沉降中心从侏罗纪到新生代存在由南向北迁移,而后又南移的跷跷板过程。南部的吉木萨尔凹陷内巴塔玛依内山组烃源岩有2个关键的生烃期:侏罗纪末,该烃源岩的镜质体反射率(R_o)分布在0.6%～1.3%之间,新生代中晚期之后,R_o分布在1%～2%之间;北部五彩湾凹陷内滴水泉组烃源岩的关键生烃期为白垩纪末期,R_o大部分在0.7%～1.5%之间,处于生烃高峰期;北部石钱滩凹陷石钱滩组烃源岩白垩纪末则刚进入生烃门限,演化程度低。另外,生烃强度从层位上看,滴水泉组和巴山组相对较大,可达200 mg/g,而石钱滩组较小,最高只有40 mg/g。     

SOURCE ROCK POTENTIAL OF ORGANIC‐RICH SHALES IN THE TERTIARY BHUBAN AND BOKA BIL FORMATIONS,BENGAL BASIN,BANGLADESH

Sandstones in the Miocene Bhuban and Lower Pliocene Boka Bil Formations contain all of the hydrocarbons so far discovered in the Bengal Basin, Bangladesh. Organic‐rich shale intervals in these formations have source rock potential and are the focus of the present study which is based on an analysis of 36 core samples from wells in eight gasfields in the eastern Bengal Basin. Kerogen facies and thermal maturity of these shales were studied using standard organic geochemical and organic petrographic techniques. Organic matter is dominated by Type III kerogen with lesser amounts of Type II. TOC is 0.16–0.90 wt % (Bhuban Formation) and 0.15–0.55 wt % (Boka Bil Formation) and extractable organic matter (EOM) is 132–2814 ppm and 235–1458 ppm, respectively. The hydrogen index is 20–181 mg HC/g TOC in the Bhuban shales and 35–282 mg HC/ g TOC in the Boka Bil shales. Vitrinite was the dominant maceral group observed followed by liptinite and inertinite. Gas chromatographic parameters including the C/S ratio, n‐alkane CPI, Pr/Ph ratio, hopane Ts/Tm ratio and sterane distribution suggest that the organic matter in both formations is mainly derived from terrestrial sources deposited in conditions which alternated between oxic and sub‐oxic. The geochemical and petrographic results suggest that the shales analysed can be ranked as poor to fair gas‐prone source rocks. The maturity of the samples varies, and vitrinite reflectance ranges from 0.48 to 0.76 %VR_r. Geochemical parameters support a maturity range from just pre‐ oil window to mid‐ oil window.     

3D BASIN MODELLING IN THE CENTRAL PERSIAN GULF,OFFSHORE IRAN

In the Central Persian Gulf, super‐giant natural gas accumulations in Permo‐Triassic reservoirs are assumed to be derived from “hot shale” source rocks in the lower Llandoverian (base‐Silurian) Sarchahan Formation, whereas oil in Mesozoic reservoirs is derived from Mesozoic source rocks. A 3D basin model has been established for a study area located in the Iranian part of the Central Persian Gulf in order to help understand the petroleum systems there. Sensitivity analyses considered different heat flow scenarios, and differences in the timing of Cenozoic uplift and erosion. For the Palaeozoic petroleum system, different thicknesses and distributions of the Silurian source rocks were considered. From current temperature profiles measured in five wells, present‐day heat flow was found to be in the order of 65 mW/m², while palaeo heat flow was probably between 60 and 68 mW/m² during Cenozoic maximum burial. For Llandoverian source rocks, oil and gas generation commenced during Jurassic and Late Cretaceous time respectively, and gas generation continued until the Neogene. Sensitivity analyses show that different assumptions on the timing of Cenozoic erosion do not have significant effects on the calculated timing of hydrocarbon generation or on the volume of generated hydrocarbons. As expected however, different heat flow scenarios (e.g. time‐constant heat flow of 65 mW/m² in the entire study area) had a significant influence. With an assumed 50 m thick Sarchahan “hot shale” succession developed uniformly in the study area (8 % TOC; 470 mg HC / g TOC HI), the model calculated gas accumulations which are of the same order of magnitude as those which have been discovered in this region (e.g. South Pars, Golshan and Balal fields). By contrast, scenarios with thinner “hot shales” and models without the Sarchahan Formation along the Qatar‐South Fars Arch do not predict the known accumulations. These scenarios suggest that prolific Silurian source rocks must be present on both sides of the South Pars / North Dome field, or that lateral gas migration from the south may have supplied the Permo‐Triassic reservoirs. This study shows that the Jurassic (mainly Hanifa / Tuwaiq Mountain Formation) and Cretaceous (Shilaif Formation) source units are not sufficiently mature in the study area to have generated significant volumes of oil. This result supports previous suggestions which envisaged lateral migration from the south of the oil present in Mesozoic reservoirs in the study area.