SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM

Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil‐prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock‐Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus‐morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436–572 mg HC/g TOC. From a pyrolysis S₂ versus TOC plot it is estimated that about 55% of the mudstones’TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318–409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial‐derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R₀. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10‐STB‐1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half‐grabens in the Song Hong Basin.     

煤系烃源岩油气生成、排出与滞留特征

针对煤系地层烃源岩的油气生成、排出与滞留能力的有效性问题,选取不同沉积环境、不同时代煤岩及其夹层中的碳质泥岩和泥岩,开展了在成岩作用下的高温高压半开放—半封闭体系模拟实验,建立了相应的演化模式.结果表明,不同沉积环境下,Ⅱ2型煤系烃源岩在生油窗内具有一定的排油能力,也具备较强的烃气生成能力,既可以作为油源岩,也是高效气...     

HYDROCARBON POTENTIAL OF JURASSIC SOURCE ROCKS IN THE JUNGGAR BASIN, NW CHINA

Jurassic source rocks in the Junggar Basin (NW China) include coal swamp and freshwater lacustrine deposits. Hydrocarbon-generating macerals in the coal swamp deposits are dominated by desmocollinite and exinite of higher-plant origin. In lacustrine facies, macerals consists of bacterially-altered amorphinite, algal- amorphinite, alginite, exinite and vitrinite. Coals and coaly mudstones in the Lower Jurassic Badaowan Formation generate oil at the Qigu oilfield on the southern margin of the basin. Lacustrine source rocks generate oil at the Cainan oilfield in the centre of the basin.
The vitrinite reflectance (Ro) of coal swamp deposits ranges from 0.5% to 0.9%, and that of lacustrine source rocks from 0.4% to 1.2%. Biomarker compositions likewise indicate that thermal maturities are variable. These variations cause those with lighter compositions to have matured earlier. Our data indicate that oil and gas generation has occurred at different stages of source-rock maturation, an "early" stage and a "mature" stage. Ro values are 0.4%–0.7% in the former and 0.8%–1.2% in the latter.     

PETROLEUM SEEPAGES AT ASUK, DISKO, WEST GREENLAND: IMPLICATIONS FOR REGIONAL PETROLEUM EXPLORATION

Organic geochemical screening and biological marker analysis was carried out on a total of 45 Albian-Cenomanian sandstone and mudstone samples collected from a landslide block on thenorth coast of Disko island, central West Greenland. The landslide block covers an area of severalsquare kilometres, and originated approximately 400 m up-section from where it moved to itspresent position after the last glaciation. The mudstones are generally rich in organic carbon butshow no potential for petroleum generation. However, biodegraded oil stains were found in thepoorly lithified sandstones. Staining by undegraded or only slightly degraded oil in volcanic rocks iscommon in this region, but the occurrence described here is the only known outcrop where staining occurs in siliciclastic sediments, and also the only one known in which the oil is severely biodegraded.
The oil stains appear to represent a biodegraded variety of the Cretaceous marine shale derived Itilli oil type which is known from many locations in the Disko-Nussusaq-Svartenhuk Halvø region. The oils entered the sandstones before the landslide event, probably during or beforethe extrusion of the volcanic succession in the Paleogene.
This is the first time that a petroleum seepage has been found to the east of the Kuugannguaq-Qunnillik fault zone, which is located approximately 30 km west of Asuk. The presence of stainingby marine oil at Asuk demonstrates that marine petroleum source rocks were deposited muchfurther eastwards than was previously thought, thus expanding the area of potential explorationsignificantly. The presence of marine source rocks to the east of the Kuugannguaq-Qunnillik faultzone may explain the frequent observation of Direct Hydrocarbon Indicators in seismic datacollected in the Vaigat Sound.     

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.     

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.     

ORGANIC FACIES VARIATIONS AND HYDROCARBON GENERATION POTENTIAL OF PERMIAN GONDWANA GROUP COALS AND ASSOCIATED SEDIMENTS,BARAPUKURIA AND DIGHIPARA BASINS,NW BANGLADESH

In the Barapukuria and Dighipara coal basins, NW Bangladesh, the Basement Complex is overlain by the coal‐bearing Permian Gondwana Group. In the present study, 36 core samples collected from five boreholes in these two basins were analysed using organic geochemical and organic petrological methods. Based on the results of biomarker analyses (TIC, m/z 191 and m/z 217 fragmentograms) and maceral composition (proportions of vitrinite, liptinite, inertinite), three organic facies were identified: coals, carbargillites and mudstones. Together with other evidence, cross‐plots of HI versus T_max and Pr/nC₁₇ versus Ph/nC₁₈ indicate that the coals, as expected, were dominated by terrestrial organic matter (OM). The carbargillites contained a mixture of terrestrial and probable Type II aquatic OM, and the mudstones contained mostly terrestrial OM. Accordingly the coals, carbargillites and mudstones are interpreted to have been deposited in swamp‐dominated environments in a delta‐plain setting which was subject, in the case of carbargillites, to periodic flooding. Suboxic conditions were indicated by very high Pr/Ph ratios and a high content of inertinite macerals. All the samples analysed were immature or early mature for hydrocarbon generation, as indicated by mean vitrinite reflectance (%R_o) of 0.60–0.81%, Rock‐Eval T_max of 430–439°C, and biomarker ratios (hopane C₃₂ 22S/(22S+22R)) of 0.57–0.60. Carbargillites showed potential for both liquid and gaseous hydrocarbon generation; coals were mainly gas‐prone with minor liquid hydrocarbon potential; and mudstones were dominantly gas‐prone. The oil‐prone nature of the samples was attributed to the presence of resinite, cutinite, bituminite and fluorescent vitrinite. The presence of exsudatinite within crack networks, solid bitumen and oil droplets as well as bituminite at early oil‐window maturities suggests that the organic matter may have expelled some hydrocarbons.     

塔里木盆地沙雅隆起星火1井寒武系烃源岩特征

在对塔里木盆地北部星火1井寒武系玉尔吐斯组灰黑、黑色碳质泥岩进行一系列有机地球化学特征测试分析的基础上,从有机碳、氯仿沥青"A"、生烃潜量、热解峰温、海相镜状体反射率、烃源岩可溶抽提物和饱和烃色质特征等方面着手,对该烃源岩的有机质丰度、成熟度及类型进行分析。结合前人研究成果,讨论了这套烃源岩与以往报道的寒武系烃源岩的异同,并开展了与塔河原油的油—岩对比分析。结果表明,该套烃源岩有机质丰度高,而且已达高成熟热演化阶段,与柯坪露头肖尔布拉克剖面下寒武统玉尔吐斯组烃源岩特征类似;星火1井下寒武统黑色碳质页岩有机质地化特征与塔河油田原油具亲源性。     

OIL-PRONE LOWER CARBONIFEROUS COALS IN THE NORWEGIAN BARENTS SEA: IMPLICATIONS FOR A PALAEOZOIC PETROLEUM SYSTEM

In this study, we assess the oil generation potential of Lower Carboniferous, liptinite-rich coals in the Tettegras Formation on the Finnmark Platform, southern Norwegian Barents Sea. Oil from these coals has been expelled into intercalated sandstones. The coals may have contributed to petroleum recorded in well 7128/4–1 on the Finnmark Platform and may constitute a new Palaeozoic source rock in the Barents Sea. The Tettegras Formation coals contain up to 80 vol.% liptinite (mineral matter free base) and have low oxygen indices. Hydrogen indices up to 367 mg HC/g TOC indicate liquid hydrocarbon potential. In wells 7128/4–1 and 7128/6–1, the coals have vitrinite reflectance R_o= 0.75–0.85 %. Compared to shale and carbonate source rocks, expulsion from coal in general begins at higher maturities (R_o= 0.8–0.9% and T_max= 444–453°C). Thus, the coals in the wells are mostly immature with regard to oil expulsion. The oil in well 7128/4–1 most likely originates from a more mature part of the Tettegras Formation in the deeper northern part of the Finnmark Platform. Wide variations in biomarker facies parameters and δ¹³C isotope values indicate a heterogeneous paralic depositional setting. The preferential retention by coal strata of naphthenes (e.g. terpanes and steranes) and aromatic compounds, compared to n-alkanes and acyclic isoprenoids, results in a terrigenous and waxy oil. This oil however contains marine biomarkers derived from the intercalated shales and siltstones. It is therefore important to consider the entire coal-bearing sequence, including the intercalated shales, in terms of source rock potential. Coals of similar age occur on Svalbard and Bjørnøya. The results of this study therefore suggest that a Lower Carboniferous coaly source rock may extend over large areas of the Norwegian Barents Sea. This source rock is mature in areas where the otherwise prolific Upper Jurassic marine shales are either immature or missing and may constitute a new Palaeozoic coal-sourced petroleum system in the Barents Sea.     

SOURCE ROCK POTENTIAL OF THE BLUE NILE (ABAY) BASIN, ETHIOPIA

The Blue Nile Basin, a Late Palaeozoic ‐ Mesozoic NW‐SE trending rift basin in central Ethiopia, is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones) and continental siliciclastics. Within this fill, perhaps the most significant source rock potential is associated with the Oxfordian‐Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation which has a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formation have HI and S₂ values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen‐Gohatsion area in the centre of the basin, these black shales and mudstones are immature for the generation of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, the formation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentary rocks and Tertiary volcanics. Production index, T_max, hydrogen index and vitrinite reflectance measurements for shale and mudstone samples from this areas indicate that they are mature for oil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons have been generated in this area from 10Ma to the present day. The presence of an oil seepage at Were Ilu points to the presence of an active petroleum system. Seepage oil samples were analysed using gas chromatography and results indicate that source rock OM was dominated by marine material with some land‐derived organic matter. The Pr/Ph ratio of the seepage oil is less than 1, suggesting a marine depositional environment. n‐alkanes are absent but steranes and triterpanes are present; pentacyclic triterpanes are more abundant than steranes. The black shales and mudstones of the Upper Hamanlei Limestone Formation are inferred to be the source of the seepage oil. Of other formations whose source rock potential was investigated, a sample of the Permian Karroo Group shale was found to be overmature for oil generation; whereas algal‐laminated gypsum samples from the Middle Hamanlei Limestone Formation were organic lean and had little source potential     

柴达木地区上古生界石炭系烃源岩评价

通过柴达木盆地周缘地区上古生界暗色泥岩、碳酸盐岩、煤及碳质泥岩的有机地球化学的测试分析,研究结果表明,石炭系烃源岩主要以暗色泥岩为主,炭质泥岩和煤可能具有生烃能力。下石炭统暗色泥岩有机碳含量一般达到了差到中等,而上石炭统暗色泥岩有机碳含量达到好或者很好;上、下石炭统的暗色灰岩有机碳含量均比较低,一般仅为非到差等烃源岩。有机碳评价较好的泥岩主要发育在潮坪、泻湖、沼泽相沉积相类型中;剖面上评价较好的层位为怀头他拉组的中部和克鲁克组及其扎布萨尕秀组的下段,评价结果已经达到好到很好等级。样品中的有机质类型均以Ⅲ型和Ⅱ₂型为主。除都兰、格尔木地区有机质成熟度过高、处于过成熟的生干气阶段外,其他地区有机质成熟度中等,正处于生烃、排烃高峰期,具有良好的油气勘探前景。     

准噶尔盆地陆东—五彩湾地区石炭系烃源岩

陆东—五彩湾地区天然气具有典型的源控成藏特征,将露头资料、钻井资料和地震资料相结合,对陆东—五彩湾地区石炭系烃源岩的丰度、类型、成熟度特征进行了系统研究和评价。研究区石炭系烃源岩以深灰色泥岩和灰色泥岩为主,其次为凝灰岩、炭质泥岩、粉砂质泥岩和煤;上石炭统巴塔玛依内山组(C2b)烃源岩丰度高于下石炭统滴水泉组(C1d),下石炭统烃源岩的类型好于上石炭统;石炭系烃源岩成熟度高值区分布在滴南凸起西段—五彩湾凹陷一带,向南、北方向石炭系烃源岩的成熟度降低;石炭系烃源岩与火山岩的分布具有互补性,烃源岩呈东西向带状分布,烃源岩最发育区位于滴南凸起西段及其南部。图8表2参15     

不同类型煤系烃源岩对油气藏形成的作用

以冀中坳陷东北部石炭-二叠系和柴达木盆地北缘侏罗系主体煤系烃源岩为实例，运用油气地球化学新技术、新方法，在系统分析和总结大量烃源岩及油气样品（6629块／次）分析数据的基础上，根据油气源对比、不同类型烃源岩的综合评价和生烃量计算结果，确认冀中苏桥油气田的凝析油或轻质油主要是C2b-P1s含壳质组煤和炭质泥岩二次生排的油气；而柴北缘冷湖油田的原油主要来自J1浅湖一半深湖相泥岩，生排油气量也以湖相泥岩所生油气为主。煤系中的暗色泥岩、炭质泥岩和煤的有机质类型及显徽组分随沉积相或亚相的变化而不同，生烃能力差别很大，滨海（湖）沼泽煤及炭质泥岩生烃能力多好于泥岩，而较深水浅水湖（或海）沼泽泥岩生烃能力多优于煤。图5表7参16     

黔东南麻江—凯里地区烃源岩的有机岩石学特征

应用全岩有机岩石学分析方法,研究了黔东南麻江-凯里地区烃源岩的显微组分组成、生烃组分及有机质热演化.该区烃源岩主要有含沥青碳酸盐岩、泥岩和煤3类,其显微组分含量因样品不同而异,显示非均质性.含沥青碳酸盐岩样品的显微组分总含量(TMC)值为0.8%～13.6%,泥岩样的TMC值为1.4%～9.4%,煤样的TMC值超过70%.该区烃源岩的富氢显微组分主要由壳质组、沥青组、次生有机质和矿物沥青基质构成,其中孢子体、壳屑体、沥青及矿物沥青基质是其主要的生烃组分.该区烃源岩有机质热演化程度处于成熟-过成熟阶段,其等效镜质组反射率R_o为0.674%～2.659%.      

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.     

ORGANIC PETROLOGY OF POTENTIAL SOURCE ROCKS IN THE TARIM BASIN, NW CHINA

Potential source rocks in the Tarim Basin (NW China) include Cambrian-Lower Ordovician lagoonal carbonates and mudstones; Middle-Upper Ordovician platform carbonates; Carboniferous-Permian shallow-marine carbonates and mudstones; and Triassic-Jurassic continental deposits including coals and lacustrine mudstones. Our petrological observations show that the organic components in Cambrian-Ordovician deposits are mainly alginites andamorphinites with minor vitrinite-like macerals, zooclasts and solid bitumen (Type I organic matter). The organic carbon content of these rocks is 0.1–2% TOC (averaging 0.9%TOC in deeper-water fades) and they are mature to overmature in terms of oil generation.
Organic macerals in Permian-Carboniferous source rocks are dominated by alginite with minor quantities of zooclasts andexinite derived from terrestrial higher plants (mainly Type II OM with minor Types I and III). TOC contents are 0.1–1%. These rocks are mature to highly-mature in terms of oil generation.
Macerals in Jurassic-Triassic source rocks are dominated by vitrinite and inertinite, with V+I > 50% and alginite + amorphinite < 40%; exinite averages 2–5%. This organic matter type is Type III, and the sediments are immature to just mature.
We have calculated the original organic matter richness of Ordovician deposits at selected locations. The original OM content appears to have been particularly high around Lunnan (in the North Tarim Uplift), in the Central Tarim Uplift and around Tadong (in the SE Uplift). These areas are therefore suggested to have particularly high exploration potential.     

ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION,NIMA BASIN,CENTRAL TIBET

The Tertiary Nima Basin in central Tibet covers an area of some 3000 km² and is closely similar to the nearby Lunpola Basin from which commercial volumes of oil have been produced. In this paper, we report on the source rock potential of the Oligocene Dingqinghu Formation from measured outcrop sections on the southern and northern margins of the Nima Basin. In the south of the Nima Basin, potential source rocks in the Dingqinghu Formation comprise dark‐coloured marls with total organic carbon (TOC) contents of up to 4.3 wt % and Hydrogen Index values (HI) up to 849 mg HC/g TOC. The organic matter is mainly composed of amorphous sapropelinite corresponding to Type I kerogen. Rock‐Eval T_max (430–451°C) and vitrinite reflectance (R_r) (average R_r= 0.50%) show that the organic matter is marginally mature. The potential yield (up to 36.95 mg HC/g rock) and a plot of S2 versus TOC suggest that the marls have moderate to good source rock potential. They are interpreted to have been deposited in a stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the organic matter was dominated by algae as indicated by biomarker analyses. Potential source rocks from the north of the basin comprise dark shales and marls with a TOC content averaging 9.7 wt % and HI values up to 389 mg HC/g TOC. Organic matter consists mainly of amorphous sapropelinite and vitrinite with minor sporinite, corresponding to Type II‐III kerogen. This is consistent with the kerogen type suggested by cross‐plots of HI versus T_max and H/C versus O/C. The T_max and R_r results indicate that the samples are immature to marginally mature. These source rocks, interpreted to have been deposited under oxic conditions with a dominant input of terrigenous organic matter, have moderate petroleum potential. The Dingqinghu Formation in the Nima Basin therefore has some promise in terms of future exploration potential.     

番禺低隆起PY30-1构造热流体活动证据及油气成藏

PY30-1构造是珠江口盆地番禺低隆起一个发育底辟体的重要含油气构造,为揭示其油气成藏规律,在确定该构造存在热流体活动的基础上,研究其油气来源和超压演化,并进一步分析油气成藏过程。镜质体反射率（Ro）、蒙脱石—伊利石矿物不正常转换和流体包裹体均一温度均指示PY30-1构造存在多期热流体活动,热流体活动的同时伴随烃类的运移。油源分析结果表明PY30-1构造中的油气主要来自白云凹陷恩平组煤系烃源岩,文昌组泥岩为次要烃源岩。地层压力演化史模拟结果表明：由于受珠琼运动二幕、南海运动和东沙运动的影响,白云凹陷存在3期压力释放过程,分别是在距今37～40 Ma、31～33 Ma和0～16 Ma,最后一期压力释放与油气充注期具有很好的一致性。研究认为PY30-1构造中的油气是东沙运动引起白云凹陷压力释放,使得烃类从烃源岩中排出沿底辟构造中的断裂垂向运移的结果。图7参23     

PETROLEUM POTENTIAL, THERMAL MATURITY AND THE OIL WINDOW OF OIL SHALES AND COALS IN CENOZOIC RIFT BASINS, CENTRAL AND NORTHERN THAILAND

Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock‐Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil‐producing basins and VR gradients were constructed. Rock‐Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal‐derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus‐type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%R_o show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%R_o. The oil shales have H/C ratios >1.43, and Hydrogen Index (HI) values are generally >400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HI_max of the coals, which represent the true source rock potential, range from ～160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil‐producing basins reflect high geothermal gradients of ～62°C/km and ～92°C/km. The depth to the top oil window for the oil shales at a VR of ～0.70%R_o is determined to be between ～1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ～300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ～0.82 to 0.98%R_o and burial depths of ～1300 to 1400 m (～92°C/km) and ～2100 to 2300 m (～62°C/km) are necessary for efficient oil expulsion to occur.     

柴达木盆地北缘东段大煤沟组一段优质烃源岩

柴达木盆地北缘地区的中 下侏罗统是主要的油气源岩,而其中的大煤沟组七段是优质油气源岩。为了进一步评价柴达木盆地北缘东段侏罗系生烃能力,系统采集了大煤沟剖面中 下侏罗统大煤沟组的泥岩、油页岩、碳质泥岩、煤岩等样品,并进行了系统的常规的有机地球化学分析（有机碳,S₁+S₂,I _H,沥青A,总烃,H/C与O/C值,干酪根,碳同位素组成δ¹³C,生物标志化合物规则甾烷的组成等）。结果表明,大煤沟组一段与七段一样,是优质油气源岩,这是柴达木盆地北缘地区的新发现。大煤沟组孢粉的显微沉积有机质组成及有机质类型的研究也证实了上述结论。在对盆地中-下侏罗统进行油气资源评价及勘探部署时,对大煤沟组一段的优质油气源岩应给予足够的重视。