OIL CHARGE HISTORY OF BITUMENS OF DIFFERING MATURITIES IN EXHUMED PALAEOZOIC RESERVOIR ROCKS AT TIANJINGSHAN,NW SICHUAN BASIN,SOUTHERN CHINA

Low‐maturity soft bitumen (or biodegraded heavy oil) and higher maturity solid bitumen are present in Palaeozoic siliciclastics at Tianjingshan in the NW Sichuan Basin, southern China. The origin of these bitumens of variable maturities was investigated. Samples of low‐maturity bitumen from Lower Devonian sandstones and high‐ and low‐maturity bitumen from Upper Cambrian siltstones were analysed to investigate their organic geochemistry and stable isotope compositions. Lower Cambrian and Upper Permian black shales were also investigated to assess their source rock potential, and the burial and maturation history of potential source rocks was modelled using PetroMod. Liquid and gaseous hydrocarbon fluid inclusions in the Devonian sandstones were analysed. Results suggest that both the soft and solid bitumens are derived from crude oil generated by Lower Cambrian organic‐rich black shales. Reservoir rocks at Tianjingshan have experienced two separate oil charge events – in the early‐middle Triassic and early‐middle Jurassic, respectively. The first oil charge was generated by Lower Cambrian black shales in a kitchen area located in the hanging wall of the Tianjingshan fault. The later oil charge was also derived from Lower Cambrian black shales, but the kitchen area was located in the footwall of the fault. Movement on the Tianjingshan fault resulted in progressive burial of the Lower Devonian sandstone reservoir rocks until the end of the middle Triassic, and the “early” charged oil was thermally degraded into high‐maturity solid bitumen. The later‐charged oil was altered into soft bitumen of lower maturiy by biodegradation during uplift of the reservoir after the Jurassic.     

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.     

HYDROCARBON POTENTIAL OF MIDDLE JURASSIC COALY AND LACUSTRINE AND UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SOURCE ROCKS IN THE SØGNE BASIN,NORTH SEA

The Søgne Basin in the Danish‐Norwegian Central Graben is unique in the North Sea because it has been proven to contain commercial volumes of hydrocarbons derived only from Middle Jurassic coaly source rocks. Exploration here relies on the identification of good quality, mature Middle Jurassic coaly and lacustrine source rocks and Upper Jurassic – lowermost Cretaceous marine source rocks. The present study examines source rock data from almost 900 Middle Jurassic and Upper Jurassic – lowermost Cretaceous samples from 21 wells together with 286 vitrinite reflectance data from 14 wells. The kerogen composition and kinetics for bulk petroleum formation of three Middle Jurassic lacustrine samples were also determined. Differences in kerogen composition between the coaly and marine source rocks result in two principal oil windows: (i) the effective oil window for Middle Jurassic coaly strata, located at ～3800 m and spanning at least ～650 m; and (ii) the oil window for Upper Jurassic – lowermost Cretaceous marine mudstones, located at ～3250 m and spanning ～650 m. A possible third oil window may relate to Middle Jurassic lacustrine deposits. Middle Jurassic coaly strata are thermally mature in the southern part of the Søgne Basin and probably also in the north, whereas they are largely immature in the central part of the basin. HI_max values of the Middle Jurassic coals range from ～150–280 mg HC/g TOC indicating that they are gas‐prone to gas/oil‐prone. The overall source rock quality of the Middle Jurassic coaly rocks is fair to good, although a relatively large number of the samples are of poor source rock quality. At the present day, Middle Jurassic oil‐prone or gas/oil‐prone rocks occur in the southern part of the basin and possibly in a narrow zone in the northern part. In the remainder of the basin, these deposits are considered to be gas‐prone or are absent. Wells in the northernmost part of the Søgne Basin / southernmost Steinbit Terrace encountered Middle Jurassic organic–rich lacustrine mudstones with sapropelic kerogen, high HI values reaching 770 mg HC/g TOC and E_a‐distributions characterised by a single dominant E_a‐peak. The presence of lacustrine mudstones is also suggested by a limited number of samples with HI values above 300 mg HC/g TOC in the southern part of the basin; in addition, palynofacies demonstrate a progressive increase in the abundance and areal extent of lacustrine and brackish open water conditions during Callovian times. A regional presence of oil‐prone Middle Jurassic lacustrine source rocks in the Søgne Basin, however, remains speculative. Middle Jurassic kitchen areas may be present in an elongated palaeo‐depression in the northern part of the Søgne Basin and in restricted areas in the south. Upper Jurassic – lowermost Cretaceous mudstones are thermally mature in the central, western and northern parts of the basin; they are immature in the eastern part towards the Coffee Soil Fault, and overmature in the southernmost part. Only a minor proportion of the mudstones have HI values >300 mg HC/g TOC, and the present‐day source rock quality is for the best samples fair to good. In the south and probably also in most of the northern part of the Søgne Basin, the mudstones are most likely gas‐prone, whereas they may be gas/oil‐prone in the central part of the basin. A narrow elongated zone in the northern part of the basin may be oil‐prone. The marine mudstones are, however, volumetrically more significant than the Middle Jurassic strata. Possible Upper Jurassic – lowermost Cretaceous kitchen areas are today restricted to the central Søgne Basin and the elongated palaeo‐depression in the north.     

ORGANIC GEOCHEMISTRY OF BARENTS SEA PETROLEUM: THERMAL MATURITY AND ALTERATION AND MIXING PROCESSES IN OILS AND CONDENSATES

The petroleum system in the Barents Sea is complex with numerous source rocks and multiple uplift events resulting in the remigration and mixing of petroleum. In order to investigate the degree of mixing, 50 oil and condensate samples from 30 wells in the SW Barents Sea were geochemically analysed by GC‐FID and GC‐MS to evaluate their thermal maturity and secondary alteration signatures. Saturated and aromatic compounds from C₁₄–C₁₈ and biomarker range (C₂₀₊) hydrocarbons were compared with light (C₄‐C₈) hydrocarbon alteration and maturity signatures from a previous study. The geochemical data demonstrate that petroleum generation occurred from the early‐ to late‐oil/condensate window, correlating to calculated vitrinite reflection values of between 0.7%R_c and 1.9%R_c. Two maturation traits are in general present in the oil samples analysed and indicate mixing of petroleum phases: a C₂₀₊ fraction which represents a possible “black‐oil ‐related” signature; and a C_20‐ fraction, which is probably a more recent oil charge. However, maturity variations are less pronounced in condensates, which in general exhibit higher generation temperatures than oils but are influenced by severe phase fractionation effects. The samples are characterised by diverse biodegradation signatures including depletion of C_15‐ saturated compounds, almost complete removal of n‐alkanes, elevated Pr/n‐C₁₇ values, high 17α(H), 25‐norhopane content, and a reverse trend in methylated naphthalene distribution. However, the presence of the more recent, unaltered light hydrocarbon charge together with the oil with a palaeo‐biodegraded signature is clear evidence that mixing has occurred. A cross‐plot of C₂₄‐tetracyclic terpane/C₃₀αβ‐hopane versus C₂₃‐C₂₉‐tricyclic terpane/C₃₀αβ‐hopane can be used to discriminate between Palaeozoic/Triassic and Jurassic‐generated petroleums in the Barents Sea region, since it appears to be maturity independent.     

MIGRATED PETROLEUM IN OUTCROPPING MESOZOIC SEDIMENTARY ROCKS IN SPITSBERGEN: ORGANIC GEOCHEMICAL CHARACTERIZATION AND IMPLICATIONS FOR REGIONAL EXPLORATION

The presence of migrated petroleum in outcropping rocks on Spitsbergen (Svalbard archipelago) has been known for several decades but the petroleum has not been evaluated by modern geochemical methods. This paper presents detailed organic geochemical observations on bitumen in outcrop samples from central and eastern Spitsbergen. The samples comprise sandstones from the Lower Cretaceous Carolinefjellet Formation, the Upper Triassic – Middle Jurassic Wilhelmøya Subgroup and the Upper Triassic De Geerdalen Formation; a limestone from the De Geerdalen Formation; and carbonates from the Middle Jurassic – Lower Cretaceous Agardhfjellet Formation. In addition a palaeo‐seepage oil was sampled from a vug in the Middle Triassic Botneheia Formation. This data is integrated with the results of analyses of C₁–C₄ hydrocarbon fluid inclusions trapped in quartz and calcite cements in these samples. Organic geochemical data suggest that the petroleum present in the samples analysed can be divided into two compositional groups (Group I and Group II). Group I petroleums have distinctive biomarker characteristics including Pr/Ph ratios of about 1.3–1.5, high tricyclic terpanes relative to pentacyclic terpanes, and relatively high methyl‐dibenzothiophenes compared to methyl‐phenanthrenes. By contrast Group II petroleums have low tricyclic terpanes relative to pentacyclic terpanes and low methyl‐dibenzothiophenes compared to methyl‐phenanthrenes, and most Pr/Ph ratios range from 1.90 to 2.57. The petroleum in both groups was derived from marine shale source rocks deposited in proximal to open marine settings. Group I petroleums, present in the sandstones of the Wilhelmøya Subgroup and the De Geerdalen Formation and as a palaeo‐seepage oil in the vug in the Botneheia Formation, are likely to have been sourced from the Middle Triassic Botneheia Formation. Group II petroleums, found in the sandstone of the Carolinefjellet Formation, the limestone from the De Geerdalen Formation and in carbonates of the Agardhfjellet Formation, are inferred to have been generated from the Jurassic‐Cretaceous Agardhfjellet Formation. The analysis of biomarker and aromatic hydrocarbons in the petroleums indicate three relative maturation levels, equivalent to expulsion at vitrinite reflectances of about 0.7–0.8%R_c, 0.8–0.9%R_c and 1.0–1.6%R_c. On average, Triassic host rocks contain petroleum of higher maturity compared to the Jurassic and Cretaceous host rocks. The fluid inclusion data suggest that gaseous hydrocarbons from the sandstones of the Wilhelmøya Subgroup are thermogenic, and are of similar maturity to the petroleum in extracts from these sandstones, suggesting that the gas was generated together with oil in the oil window. By contrast the inclusion gases from carbonate rocks analysed have a mixed (thermogenic / biogenic) origin. The outcropping rocks in which these oils occur are analogous to offshore reservoirs on the Norwegian Continental Shelf. The study may therefore improve our understanding of the subsurface offshore petroleum systems in the Barents Sea and possibly also in other circum‐Arctic basins.     

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS,ONSHORE NILE DELTA,EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C₂₉/C₂₇ sterane, diasterane/sterane, hopane/sterane and oleanane/C₃₀ hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C₃₂ homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta. A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ¹³ methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.     

VERTICAL VARIATIONS IN RESERVOIR GEOCHEMISTRY IN A PALAEOZOIC TRAP,EMBLA FIELD,OFFSHORE NORWAY

The Embla field, located in the Greater Ekofisk area (Norwegian North Sea), produces oil from Palaeozoic reservoir rocks comprising moderately to well sorted micaceous sandstones and silty mudstones. The reservoir is divided into “upper” and “lower” sandstones by a mudstone/siltstone succession, and is overlain by the Jurassic Tyne Group. Below are Palaeozoic mudstones and fractured rhyolites. Bitumen coatings on sand grains and in the fractured rhyolites have been recorded at Embla, and the bitumen may modify the dynamic response of the reservoir during production. In this paper, the organic geochemistry of core extracts and DST oil from well 2–7/26S were analysed by Iatroscan TLC‐FID, GC‐FID and GC‐MS in order to investigate heterogeneities in petroleum composition, thermal maturity and biodegradation between the lower and upper sandstones and the fractured rhyolites, and to investigate the trap filling history. The geochemical data suggest that the reservoir at Embla has received two pulses of oil. The first oil pulse represents a palaeo‐filling event which is interpreted to have charged the reservoir around the end of the Triassic. This oil was biodegraded in the reservoir which must therefore have been uplifted to depths of less than ca. 2km (equivalent to ca. 70°C). Because of later burial, the reservoir is at a depth of more than 4km at the present day. This palaeo‐oil is compositionally different to most North Sea oils, and may be derived from a source rock containing Type II kerogen. The second more recent oil pulse, comprising “Ekofisk” type oil, started to refill the Embla structure when the Kimmeridge‐equivalent Mandal Formation became thermally mature around the end of the Cretaceous. This second oil migrated along the Skrubbe Fault. Extracts from the upper and lower sandstones are medium to highly mature and show different biomarker and aromatic maturity signatures. The bitumen from the lower sandstone is more mature as indicated by ratios of diasteranes/(diasteranes + regular steranes), 20S/(20S + 20R) steranes, and calculated vitrinite reflectances. Bitumen from rhyolite samples shows the lowest maturity. This suggests that the oil trapped in the fractured rhyolites represents the early oil pulse which did not undergo in‐reservoir cracking or biodegradation after its emplacement.     

塔北英买力低凸起奥陶系油藏充注历史的流体包裹体证据

通过流体包裹体偏光-荧光镜下观察、均一温度测试、红外光谱等分析手段,结合埋藏热演化史分析,确定了塔北隆起西部英买力低凸起奥陶系油藏充注期次。奥陶系储层共发育4类烃类包裹体,根据荧光颜色对液烃包裹体进一步划分为重质油包裹体和中-轻质油包裹体;根据包裹体岩相学特征将烃类包裹体分为早、晚两期,均一温度峰值分别为66.7~72.5℃和86.4~95.3℃,表明主要发生过两期原油运移、充注过程。石油包裹体红外光谱特征及参数计算结果表明,早期充注原油成熟度较低,烃类包裹体主要发褐色、黄褐色荧光;晚期充注原油成熟度相对较高,烃类包裹体显示黄白-蓝绿色荧光。包裹体均一温度结合埋藏热演化史确定早、晚两期原油充注过程分别对应于晚加里东期和晚海西期。根据油藏沥青特征和现今油藏原油密度等综合因素分析认为,油藏降解过程主要发生在早海西期,而晚海西期是主成藏期。     

准噶尔盆地莫索湾凸起古油藏的流体证据

对准噶尔盆地腹部地区古油藏分布及次生油气藏调整规律认识的局限性制约了该地区的勘探与开发。莫索湾凸起侏罗系三工河组在白垩纪位于古背斜的高部位,是油气的集散地,研究该区古油藏形成及演化过程对指导次生油气藏的发现至关重要。对莫索湾凸起三工河组进行流体包裹体分析和系列定量荧光分析,并结合构造演化史、生烃史和区域埋藏史-热史为古油藏的存在提供了流体证据,分析了其油气充注历史,并预测了次生油气藏的调整方向。研究结果显示:(1)莫索湾凸起三工河组在早白垩世早期开始接受油气充注形成古油藏,表现在储集层QGF指数大于4,GOI指数大于5%,古油藏充注时,油气被矿物捕获形成烃类包裹体,被捕获的两类包裹体荧光颜色和傅里叶红外光谱参数值说明随着烃源岩成熟度逐渐变大,油质也逐渐变轻。(2)新近纪地层掀斜时,古油藏被破坏,油气发生调整,表现在部分层段QGF指数较高,但是QGF-E强度较低。(3)莫索湾凸起三工河组经历了不只一期油气充注,推断其混入了侏罗系烃源岩生成的成熟度较低的油气,因为部分层段显示较低的QGF指数和较高的QGF-E强度,且TSF的R1分布范围很大。(4)构造显示莫索湾古油藏平面范围达700km2,古油藏被破坏后沿着各低凸带向北线状运移。     

THE PALEOCENE SANDY SIRI FAIRWAY: AN EFFICIENT “PIPELINE” DRAINING THE PROLIFIC CENTRAL GRABEN?

A new petroleum charge model is presented for the sand‐dominated Paleocene channel system known as the Siri Fairway in the Central Graben of the North Sea. The Siri Fairway is located in the platform area along the Danish ‐ Norwegian border and extends from the Norwegian palaeo shelf into the Tail‐End Graben and Søgne Basin. The nearest known expelling source rocks are located in the Central Graben. The discovery of the Siri oilfield and later the Cecilie and the Nini fields proves that petroleum has migrated through these Paleocene sandstones for up to 70 km, which is a considerable distance in the North Sea. If the Siri Fairway has acted as a “pipeline” for petroleum migrating from the Graben to the platform area, the chemical composition of the hydrocarbons discovered in the Graben and within the Fairway itself should be similar in terms of maturity and organic facies signature. This study shows this not to be the case. The Graben oils have a mature signature, whereas the oils from the Siri field have an early mature signature and are mixed with biogenic gas generated in situ. The biogenic gas “signature”, which was inherited from gas which accumulated in the trap before the arrival of the oil charge, should have disappeared if petroleum had continuously been introduced to the Fairway. It therefore appears that hydrocarbon charging to the Fairway ceased for some reason before the source rocks in the Graben entered the main oil window; the Siri Fairway therefore represents an aborted migration route, and limited charging of the Paleocene sandstone deposits in the platform has occurred. The chemical composition of the oils from the Siri field indicates that the Fairway was charged from two different basins with different subsidence histories. The Siri‐2 trap is thus interpreted to have been filled with the same oil as that found in Siri‐1 and Siri‐3, but this oil was later partly displaced by oil generated in a shallower sub‐basin. The sandstones in the Siri Fairway were deposited as turbidites and/or gravity slides in the Late Paleocene, and consist of stacked interfingering sandstone lobes which are encased to varying degrees in fine‐grained sediments. Although long distance migration through the sandstones has been proved to occur, connectivity between individual sandlobes may be problematic. The number of dry wells drilled in the Fairway and the early‐mature character of the analysed oils, together with the general absence of more mature later petroleum, indicate that migration routes in this region are limited and difficult to predict.     

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.     

准噶尔盆地中部侏罗系三工河组储层沥青地球化学特征及其对油气成藏过程的指示

准噶尔盆地中部地区侏罗系三工河组储层中广泛发育固体沥青,记录了重要的油气成藏信息。基于岩相学、反射率、激光拉曼光谱和生物标志化合物等多方面的综合分析,结合构造和成藏演化史,探讨了沥青的成因、来源及其对油气成藏的指示意义。研究区三工河组储层沥青主要赋存在构造缝中,裂缝面存在弯曲变形,矿物显微构造变形明显,指示沥青形成与构造活动破坏古油藏有关。沥青的生物标志化合物特征与油源对比结果指示沥青主要来源于二叠系风城组和下乌尔禾组的烃源岩,具有混源成藏特征。沥青成熟度较低（等效镜质体反射率为0.62%～0.79%）,且具强烈生物降解特征,说明为生物降解成因沥青,同时生物标志物指示沥青受到晚期原油充注的影响。古油藏成藏时间在中侏罗世车—莫古隆起形成初期,晚侏罗世—早白垩世古隆起抬升遭受强烈剥蚀,古油藏遭受破坏进而引发轻烃组分散逸,并伴随生物降解作用演化形成沥青。早白垩世,下乌尔禾组烃源岩晚期油气开始充注后,三工河组储层没有再发生强烈构造活动,随储层再次埋深和油气充注,最终形成现今油气藏。虽然研究区三工河组储层曾经历构造活动调整,但油气的再次充注使其仍成为有利的勘探对象。      

COAL-GENERATED OIL: SOURCE ROCK EVALUATION AND PETROLEUM GEOCHEMISTRY OF THE LULITA OILFIELD, DANISH NORTH SEA

Controversy still exists as to whether coals can source commercial accumulations of oil. The Harald and Lulita fields, Danish North Sea, are excellent examples of coal‐sourced petroleum accumulations, the coals being assigned to the Middle Jurassic Bryne Formation. Although the same source rock is present at both fields, Lulita primarily contains waxy crude oil in contrast to Harald which contains large quantities of gas together with secondary oil/condensate. A compositional study of the coal seams at well Lulita‐IXc (Lulita field) was therefore undertaken in order to investigate the generation there of liquid petroleum. Lulita‐IXc encountered six coal seams (0.15–0.25 m thick) which are associated with reservoir sandstones. The coals have a complex petrography dominated by vitrinite, with prominent proportions of inertinite and only small amounts of liptinite. Peat formation occurred in coastal‐plain mires; the coal seams at Lulita‐IXc represent the waterlogged, oxygen‐deficient and occasionally marine‐influenced coastal reaches of these mires. Vitrinite reflectance values (mostly 0.82–0.84%Ro) indicate that the coals are thermally mature. Most of the coal samples have Rock‐Eval Hydrogen Index values above 220 mg HC/g TOC, although the HI values may be increased due to the presence of extractable organic matter. Oil‐source rock correlations indicate that there are similarities between crude oil samples (and an oil‐stained sandstone extract) from the Lulita field, and extracts from the Bryne Formation coals immediately associated with the reservoir sandstones; from this, we infer that the coals have generated the crude oil at Lulita. The presence in the coals of oil‐droplets, exsudatinite and micrinite is further evidence that they have generated liquid petroleum. The generation of aliphatic‐rich crude oil by the coals in the Lulita field area, and the coals' high expulsion efficiency, may have been facilitated by a combination of the coals'favourable petrographic composition and their capability to generate long‐chain n‐alkanes (C₂₂₊). Moreover_; all the Lulita coal seams are relatively thin and this may have facilitated oil saturation to the expulsion threshold. We suggest that during further maturation of the coals, 19–22% of the organic carbon will potentially participate in petroleum‐generation, of which about 42–53% will be in the gas‐range and 47–58% in the oil‐range.     

Geochemical characteristic and origin of solid bitumen in the Jurassic and Triassic sandstone reservoir of Santai Area,Junggar Basin,NW China

Solid bitumen was identified in the pore spaces of the Jurassic and Triassic sandstone reservoir in the Santai Area, Junggar Basin, NW China, which limits economic petroleum production, even influencing hydrocarbon accumulation. Organic geochemical techniques were figured out the origin of bitumen and its formation mechanisms. Carbon isotope characteristics of the crude oil and bitumen-reservoir extracts suggests the bitumen mainly derived from sapropelic-type source rock of Pingdiquan Formation, which was deposited in the semideep and deep lacustrine environment. Biomarker date indicates bitumen was formed from petroleum in low thermally mature stage and biodegradation was responsible for formation of the bitumen.     

塔里木盆地孔雀河地区侏罗系油气成藏期次研究

根据储层的成岩次序、油气包裹体特征及含烃盐水包裹体均一温度,结合伊利石测年及烃源岩的演化史,对塔里木盆地孔雀河地区成藏期次进行综合研究,认为孔雀河地区下侏罗统阿合组含油气储层有三期油气充注成藏过程:第一期为燕山中、晚期,以油为主,成熟度中等偏低,油质较重,系下古生界古油藏破坏后的二次充注;第二期为喜山早期,约50-40 Ma,以油为主含气,成熟度较高,为轻质油类型,油源仍来自深部;第三期为喜山中、晚期(20 Ma以来),以气为主含油,有来自下部地层中干酪根和原油的高温裂解气,也有来自侏罗系地层自身生成的石油(局部地区)和天然气     

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.     

IN‐RESERVOIR FRACTIONATION AND THE ACCUMULATION OF OIL AND CONDENSATES IN THE SURMA BASIN,NE BANGLADESH

Petroleum in the Surma basin, NE Bangladesh (part of the Bengal Basin) ranges from waxy crude oils to condensates. The origin and source rocks of these hydrocarbons were investigated based on the distributions of saturated and aromatic hydrocarbons in 20 oil samples from seven oil and gas fields. The relative compositions of pristane, phytane and adjacent n‐alkanes suggest that the source rock was deposited in a non‐marine setting. The abundance and similar distribution of biphenyls, cadalene and bicadinanes in most of the crude oils and condensates indicates a significant supply of higher‐plant derived organic matter to the source rocks. Maturity levels of the crude oils and condensates from the Surma basin correspond to calculated vitrinite reflectance (R_c) values of 1.0–1.3%, indicating hydrocarbon expulsion from the source rock at a comparatively high maturity level. The R_c values of oils from the Titas field in the southern margin of the Surma basin are relatively low (0.8–1.0%). Some oils were severely biodegraded. The similar distribution of diamondoid hydrocarbons in both biodegraded and non‐biodegraded oils indicated similar types of source rocks and similar maturity levels to those of oils from the Surma basin. The Oligocene Jenam Shale and/or underlying non‐marine deposits located at greater depths may be potential source rocks. The diversity of the petroleum in the Surma basin was likely due to evaporative fractionation, resulting in residual waxy oils and lighter condensates which subsequently underwent tertiary migration and re‐accumulation. Evaporative fractionation due to modification of the reservoir structure occurred during and after the Pliocene, when large‐scale tectonic deformation occurred in and around the Bengal Basin.     

流体包裹体在含油气系统成藏研究中的应用

含油气系统研究的核心是揭示烃类流体从源岩到圈闭的地质过程和历史 ,研究油气藏的形成时期和成藏模式 ,储层流体包裹体分析技术为这项研究开辟了新方法和新思路。通过流体包裹体类型、均一温度、激光拉曼及荧光光谱特征的研究 ,并结合精细时—温埋藏史恢复的盆地模拟技术 ,可有效地确定油气成藏期和时间以及油气运移的相态和方式 ,从而建立烃类的成藏模式     

库车坳陷北部单斜带油气充注史及成藏潜力分析

北部单斜带是库车坳陷油气成藏研究程度最低的构造带。基于流体包裹体、定量颗粒荧光和激光拉曼等分析技术对北部单斜带的油气充注史进行详细的研究,并结合生储盖和圈闭条件对其成藏潜力进行了评价。根据其常规孔隙型储层和裂缝储层的岩心样品对比分析表明,孔隙型储层中流体包裹体主要为单相黄色荧光油包裹体,储层QGF指数都大于6,QGF-E强度都大于20pc,油气充注显示出明显的继承性特点;裂缝型储层中包裹体主要为蓝白色荧光固液气三相包裹体和气液两相包裹体,储层QGF指数、QGF-E强度和R₁都显示出异常值,与孔隙型储层原油物性具有较大差异,认为储层早期(65Ma左右)经历一期油充注,晚期喜马拉雅造山运动使地层强烈褶皱产生大量裂缝,沟通了其他储层或源岩,使得晚期(10Ma左右)生成的轻质油沿裂缝网络发生一期充注,之后又经历一期(3Ma左右)气洗。研究区生储盖条件匹配良好。烃源岩演化达到主要生油阶段,部分地区的三叠系甚至达到生气阶段。储层物性致密,裂缝控制“甜点”发育,致密油气的勘探具有广阔的潜力。     

SOURCE‐ROCK MATURITY,HYDROCARBON POTENTIAL AND OIL – SOURCE‐ROCK CORRELATION IN WELL SHORISH‐1, ERBIL PROVINCE,KURDISTAN REGION,IRAQ

The Shorish‐1 exploration well is located in Erbil Province in the Kurdistan region of Iraq, on the outskirts of Erbil City near the dividing line between the Low Folded and High Folded Zones of the Zagros foldbelt. The well penetrated rocks which are between Miocene and Late Triassic in age. The depositional environment, source potential and maturity of organic‐rich intervals within the well succession were investigated using 38 cuttings samples. All samples were analysed for bulk geochemical parameters (i.e. total organic carbon, total carbon, sulphur, Rock‐Eval). A subset of 13 samples was selected for biomarker analysis, pyrolysis – gas chromatography and isotope investigations. In addition non‐commercial oil and oil impregnations were investigated for oil‐source correlations. Source rocks occur in the Jurassic Sargelu and Naokelekan Formations and the lowermost Cretaceous Chia Gara Formation. Analytical results suggest that these source rocks were deposited in a carbonate‐rich, anoxic environment in an intrashelf basin setting with free H₂S in the water column. Oxygen‐depleted conditions were favoured by salinity stratification. The average preserved TOC contents of the 100 m thick Sargelu Formation and the 25 m thick Naokelekan Formation are 2.2% and 4.6%, respectively. The TOC content of the Chia Gara Formation decreases upwards and averages 3.2% within its lower 40 m. Very high sulphur contents suggest the presence of kerogen Type II‐S, and that all the formations have generated sulphur‐rich hydrocarbons at relatively low maturities. In contrast to the oil impregnations within Jurassic strata, the oil and the oil impregnations within Cretaceous rocks are heavily biodegraded. Oil biomarker and isotope data indicate generation from the above‐mentioned Jurassic and Cretaceous source rock formations. As a result, generation from Triassic and Paleogene rocks can be excluded or is of negligible significance. Numerical models show that hydrocarbon generation rates from the Sargelu, Naokelekan and Chia Gara Formations peaked firstly at about 55 Ma (Paleocene/Eocene) and then again at 5 Ma before present (late Miocene/Pliocene). The first peak resulted from increased Paleocene subsidence, and the second peak was related to deep late Miocene/Pliocene burial. Hydrocarbon generation ceased during Recent uplift, during which ～2000 m of the Late Neogene succession was eroded.