WORLD‐CLASS PALEOGENE OIL‐PRONE SOURCE ROCKS FROM A CORED LACUSTRINE SYN‐RIFT SUCCESSION,BACH LONG VI ISLAND,SONG HONG BASIN,OFFSHORE NORTHERN VIETNAM

Oil‐prone source rocks occurring in lacustrine syn‐rift successions have generated significant amounts of hydrocarbons in many Cenozoic basins in SE Asia. As most exploration wells are located on structural highs, the source rock successions are seldom drilled and their initial composition and generation potential are poorly known. The inverted Bach Long Vi Graben is located at the intersection of the NW–SE trending Song Hong Basin (Yinggehai Basin) and the NE–SW trending Beibuwan Basin in the Gulf of Tonkin, offshore northern Vietnam. The uppermost part of the inverted graben is exhumed and exposed on Bach Long Vi island. In order to investigate the amount and source rock quality of the syn‐rift mudstones, the ENRECA‐3 well was drilled on the island and cored some 500 m of the syn‐rift succession. The well provided excellent cores with a recovery of 99%, dominated by lacustrine mudstones interbedded with various gravity flow deposits. Organic petrography shows that the mudstones are thermally immature and contain sapropelic Type I and mixed Types I and III kerogen. Source rock screening data from more than 300 samples demonstrate that the lacustrine source rocks have an average TOC content of 2.88 wt% and an average Hydrogen Index of 566 mg HC/g TOC. The average Hydrogen Index of the reactive kerogen was determined to be 769 mg HC/g TOC. The Source Potential Index (SPI) is 9 tons HC/m² and the mudstones will, upon full maturation, generate black oil with a gas‐liquid ratio not exceeding ～1700 scf/stb. The mudstones are thus highly oil‐prone. In addition, several tens of metres of source rock within the overlying succession are exposed on Bach Long Vi island and in the surrounding seafloor, and the well did not reach the base of the source rock succession. Although the net‐source rock thickness of the ENRECA‐3 well is estimated to be 233 m, the net thickness of the entire source rock succession will be greater. The present study is the first organic geochemical assessment of a thick lacustrine source rock section in the petroliferous NE Song Hong Basin, and the promising results may be applied not only to other parts of the basin but also to other Cenozoic basins with syn‐rift successions containing significant source rock intervals.     

DISTRIBUTION OF SOURCE ROCKS AND MATURITY MODELLING IN THE NORTHERN CENOZOIC SONG HONG BASIN (GULF OF TONKIN), VIETNAM

The northern offshore part of the Cenozoic Song Hong Basin in the Gulf of Tonkin (East Vietnam Sea) is at an early stage of exploration with only a few wells drilled. Oil to source rock correlation indicates that coals are responsible for the sub‐commercial oil and gas accumulations in sandstones in two of the four wells which have been drilled on faulted anticlines and flower structures. The wells are located in a narrow, structurally inverted zone with a thick predominantly deltaic Miocene succession between the Song Chay and Vinh Ninh/Song Lo fault zones. These faults are splays belonging to the offshore extension of the Red River Fault Zone. Access to a database of 3,500 km of 2D seismic data has allowed a detailed and consistent break‐down of the geological record of the northern part of the basin into chronostratigraphic events which were used as inputs to model the hydrocarbon generation history. In addition, seismic facies mapping, using the internal reflection characteristics of selected seismic sequences, has been applied to predict the lateral distribution of source rock intervals. The results based on Yükler ID basin modelling are presented as profiles and maturity maps. The robustness of the results are analysed by testing different heat flow scenarios and by transfer of the model concept to IES Petromod software to obtain a more acceptable temperature history reconstruction using the Easy%R₀ algorithm. Miocene coals in the wells located in the inverted zone between the fault splays are present in separate intervals. Seismic facies analysis suggests that the upper interval is of limited areal extent. The lower interval, of more widespread occurrence, is presently in the oil and condensate generating zones in deep synclines between inversion ridges. The Yükler modelling indicates, however, that the coaly source rock interval entered the main window prior to formation of traps as a result of Late Miocene inversion. Lacustrine mudstones, similar to the highly oil‐prone Oligocene mudstones and coals which are exposed in the Dong Ho area at the northern margin of the Song Hong Basin and on Bach Long Vi Island in Gulf of Tonkin, are interpreted to be preserved in a system of undrilled NW–SE Paleogene half‐grabens NE of the Song Lo Fault Zone. This is based on the presence of intervals with distinct, continuous, high reflection seismic amplitudes. Considerable overlap exists between the shale‐prone seismic facies and the modelled extent of the present‐day oil and condensate generating zones, suggesting that active source kitchens also exist in this part of the basin. Recently reported oil in a well located onshore (BIO‐STB‐IX) at the margin of the basin, which is sourced mainly from “Dong Ho type” lacustrine mudstones supports the presence of an additional Paleogene sourced petroleum system.     

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.     

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.     

DEPOSITIONAL ENVIRONMENTS, ORGANIC MATURITY AND PETROLEUM POTENTIAL OF THE CRETACEOUS COAL-BEARING ATANE FORMATION AT QULLISSAT, NUUSSUAQ BASIN, WEST GREENLAND

Coals and coaly mudstones of the Cretaceous Atane Formation are exposed along the north coast of the island of Disko and the south coast of Nuussuaq peninsula, West Greenland. Numerous oil seepages have been found in the region, but the so‐called Kuugannguaq oil type only occurs at the north coast of Disko. The oil is presumed to have been generated from coaly (Type III) source rocks in the Vaigat strait where the Atane Formation is thermally mature due to deep burial. The exposed coals and coaly mudstones may thus be thermally immature equivalents of the active source rocks. The exposed section at Qullissat on the island of Disko is composed of four sedimentary facies associations: delta plain, distributary channel, delta front, and transgressive sand sheet. Samples of coals and coaly mudstones from the delta plain association were analysed for their total organic carbon (wt % TOC) and total sulphur (wt % TS) contents, and their source rock potential was determined by Rock‐Eval pyrolysis. The organic matter composition was analysed by reflected light microscopy and the thermal maturity was established by vitrinite reflectance measurements. The Qullissat samples were supplemented with source rock screening data from coals and coaly mudstones from the Atane Formation at Paatuut on the south coast of Nuussuaq. The coals and coaly mudstones from Qullissat are dominated by huminite, but several samples have a considerable content of inertinite. The mineral content is high in some samples. Inundations of the peat‐mires may have been quite frequent resulting in the formation of the coaly mudstones. TS contents (0.13–8.97 wt %) and the presence of framboidal pyrite suggest that the precursor peats were influenced by seawater, and that peat formation probably occurred during rises in relative sea‐level. The organic matter is thermally immature, and a constructed vitrinite reflectance gradient for the region suggests that the Qullissat section prior to exhumation was buried to 1,500–1,600 m depth. Hydrogen Index (HI) values from both Qullissat and Paatuut are generally low; estimated maximum HI values for three Qullissat coals yield values of 140–190 mg HC/g TOC. The coals are gas‐prone and only marginally oil‐prone, and may in addition possess a limited oil expulsion efficiency. The effective oil window extends from approximately 1.0–1.6%Ro and the start of the effective oil window is located at about 3,000 m depth. Very thick sedimentary successions in the Vaigat strait indicate that such burial depths have been reached for the Atane Formation offshore, and up‐dip migration of hydrocarbons from these source rocks may have generated the Kuugannguaq oil seepage.     

SOURCE ROCK EVALUATION OF COALS FROM THE LOWER MAASTRICHTIAN MAMU FORMATION, SE NIGERIA

The Lower Maastrichtian Mamu Formation in the Anambra Basin (SE Nigeria) consists of a cyclic succession of coals, carbonaceous shales, silty shales and siltstones interpreted as deltaic deposits. Sub‐bituminous coals within this formation are distributed in a north‐south trending belt from Enugu‐Onyeama to Okaba in the north of the basin. Maceral analyses showed that the coals are dominated by huminite with lesser amounts of liptinite and inertinite. Despite high liptinite contents in parts of the coals, an HI versus T_max diagram and atomic H/C ratios of 0.80‐0.90 and O/C ratios of 0.11‐0.17 classify the organic matter in the coals as Type III kerogen. Vitrinite reflectance values (%R_r) of 0.44 to 0.6 and T_max values between 417 and 429°C indicate that the coals are thermally immature to marginally mature with respect to petroleum generation. Hydrogen Index (HI) values for the studied samples range from 203 to 266 mg HC/g TOC and S₁+S₂ yields range from 141.12 to 199.28 mg HC/ g rock, suggesting that the coals have gas and oil‐generating potential. Ruthenium tetroxide catalyzed oxidation (RTCO) of two coal samples confirms the oil‐generating potential as the coal matrix contains a considerable proportion of long‐chain aliphatics in the range C_19‐35. Stepwise artificial maturation by hydrous pyrolysis from 270°C to 345°C of two coal samples (from Onyeama, HI=247 mg HC/g TOC; and Owukpa, HI=206 mg HC/g TOC) indicate a significant increase in the S₁ yields and Production Index with a corresponding decrease in HI during maturation. The Bitumen Index (BI) also increases, but for the Owukpa coal it appears to stabilize at a T_max of 452‐454°C, while for the Onyeama coal it decreases at a T_max of 453°C. The decrease in BI suggests efficient oil expulsion at an approximate vitrinite reflectance of ～I%R_r. The stabilization/decrease in BI is contemporaneous with a significant change in the composition of the asphaltene‐free coal extracts, which pass from a dominance of polar compounds (～77‐84%) to an increasing proportion of saturated hydrocarbons, which at >330°C constitute around 30% of the extract composition. Also, the n‐alkanes change from a bimodal to light‐end skewed distribution corresponding to early mature to mature terrestrially sourced oil. Based on the obtained results, it is concluded that the coals in the Mamu Formation have the capability to generate and expel liquid hydrocarbons given sufficient maturity, and may have generated a currently unknown volume of liquid hydrocarbons and gases as part of an active Cretaceous petroleum system.     

COMPOSITION AND PETROLEUM POTENTIAL OF LAKE FACIES IN THE FA-MS-48-73 WELL, MAE SOON STRUCTURE, FANG OILFIELD, NORTHERN THAILAND

The Fang Basin is one of a series of Cenozoic rift‐related structures in northern Thailand. The Fang oilfield includes a number of structures including the Mae Soon anticline on which well FA‐MS‐48‐73 was drilled, encountering oil‐filled sandstone reservoirs at several levels. Cuttings samples were collected from the well between depths of 532 and 1146 m and were analysed for their content of total organic carbon (TOC, wt%), total carbon (TC, wt%) and total sulphur (TS, wt%); the petroleum generation potential was determined by Rock‐Eval pyrolysis. Organic petrography was performed in order to determine qualitatively the organic composition of selected samples, and the thermal maturity of the rocks was established by vitrinite reflectance (VR) measurements in oil immersion. The TOC content ranges from 0.75 to 2.22 wt% with an average of 1.43 wt%. The TS content is variable with values ranging from 0.12 to 0.63 wt%. Rock‐Eval derived S₁ and S₂ yields range from 0.01–0.20 mg HC/g rock and 1.41–9.51 mg HC/g rock, respectively. The HI values range from 140 to 428 mg HC/g TOC, but the majority of the samples have HI values >200 mg HC/g TOC and about one‐third of the samples have HI values above 300 mg HC/g TOC. The drilled section thus possesses a fair to good potential for mixed oil/gas and oil generation. On an HI/T_max diagram, the organic matter is classified as Type II and III kerogen. The organic matter consists mainly of telalginite (Botryococcus‐type), lamalginite, fluorescing amorphous organic matter (AOM) and liptodetrinite which combined with various TS‐plots suggest deposition in a freshwater lacustrine environment with mild oxidising conditions. T_max values range from 419 to 436°C, averaging 429°C, and VR values range from ～0.38 to 0.66% R₀, indicating that the drilled source rocks are thermally immature with respect to petroleum generation. The encountered oils were thus generated by more deeply buried source rocks.     

DEPOSITIONAL ENVIRONMENT AND SOURCE‐ROCK CHARACTERISATION OF ORGANIC‐MATTER RICH UPPER SANTONIAN – UPPER CAMPANIAN CARBONATES,NORTHERN LEBANON

Samples of Turonian – upper Campanian fine‐grained carbonates (marls, mud‐ to wackestones; n = 212) from four boreholes near Chekka, northern Lebanon, were analysed to assess their organic matter quantity and quality, and to interpret their depositional environment. Total organic carbon (TOC), total inorganic carbon and total sulphur contents were measured in all samples. A selection of samples were then analysed in more detail using Rock‐Eval pyrolysis, maceral analyses, gas chromatography – flame ionization detection (GC‐FID), and gas chromatography – mass spectrometry (GC‐MS) on aliphatic hydrocarbon extracts. TOC measurements and Rock‐Eval pyrolysis indicated the very good source rock potential of a ca. 150 m thick interval within the upper Santonian – upper Campanian succession intercepted by the investigated boreholes, in which samples had average TOC values of 2 wt % and Hydrogen Index values of 510 mgHC/gTOC. The dominance of alginite macerals relative to terrestrial macerals, the composition of C₂₇–C₂₉ regular steranes, the elevated C₃₁ 22R homohopane / C₃₀ hopane ratio (> 0.25), the low terrigenous / aquatic ratio of n‐alkanes, as well as δ¹³C_org values between ?29‰ and ?27‰ together suggest a marine depositional environment and a mainly algal / phytoplanktonic source of organic matter. Redox sensitive geochemical parameters indicate mainly dysoxic depositional conditions. The samples have high Hydrogen Index values (413–610 mg/g TOC) which indicate oil‐prone Type II kerogen. T_max values (414 – 432°C) are consistent with other maturity parameters such as vitrinite reflectance (0.25–0.4% VRr) as well as sterane and hopane isomerisation ratios, and indicate that the organic matter is thermally immature and has not reached the oil window. This study contributes to the relatively scarce geochemical information for the eastern margin of the Levant Basin, but extrapolation of the data to offshore areas remains uncertain.     

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.     

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

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

HYDROCARBON SOURCE ROCK POTENTIAL OF LATEST ORDOVICIAN – EARLIEST SILURIAN TANEZZUFT FORMATION SHALES FROM THE EASTERN KUFRA BASIN,SE LIBYA

This paper summarizes the results of Rock‐Eval pyrolysis data of 43 shale samples collected from the latest Ordovician – earliest Silurian (Tanezzuft Formation) interval in the CASP JA‐2 well at Jebel Asba on the eastern margin of the Kufra Basin, SE Libya. The results are supported by analysis of cuttings samples from an earlier well of uncertain origin nearby, referred to here as the UN‐REMSA well. The Tanezzuft Formation succession encountered in the JA‐2 well can be divided into three intervals based on Rock‐Eval pyrolysis data. Shales in the shallowest interval (20 – 46.5 m depth) are altered probably by weathering and lack significant amounts of organic matter. Total organic carbon (TOC) contents of shales from the intermediate interval (46.5 – 68.5 m depth) vary between 0.19 and 0.75 wt%. Most samples in this interval have very limited source rock potential although a few have Hydrogen Index (HI) values up to 378 mg S₂/g TOC. T_max values of 422 – 426°C indicate the organic matter is immature. Shales from the deepest interval (68.5 – 73.9 m depth) are diagenetically altered, perhaps by fluids flowing along a nearby fault or along the contact between the Tanezzuft Formation and the underlying Mamuniyat Formation and apparently lack any organic matter. Cuttings samples from the UN‐REMSA well have TOC contents of 0.48–0.87 wt%, HI values of 242–252 mg S₂/g TOC, and T_max values of 421–425°C. These results offer little support for the presence of the basal Silurian (Tanezzuft Formation) source rock which is prolific elsewhere in SW Libya and eastern Algeria and, together with the overall immaturity of the equivalent section, reduces the probability of finding major oil reserves in the eastern part of the Kufra Basin.     

Source rock potential of the Sayındere formation in the Şambayat oil field,SE Turkey

Upper Campanian–Maastrichtian Say?ndere Formation, located in southeastern Turkey, composed of pelagic limestone which was deposited relatively deep marine. In this study, well samples of the Say?ndere Formation were analyzed by Rock-Eval pyrolysis and the oil sample from this unit were analyzed by GC, and GC-MS to assess source rock characteristics and hydrocarbon potential. The TOC values of the Say?ndere Formation samples range from 0.34 to 4.65?wt.% with an average of 1.14?wt.% and organic matter have good TOC value. Hydrogen Index (HI) values range from 407?mg HC/g TOC to 603?mg HC/g TOC and indicates Type II kerogen. T_max values are in the range of 434 - 442?°C and indicate early-mid mature stage. The Say?ndere samples have fair to good hydrocarbon potential based on TOC contents, S2, and PY values. According to the HI versus TOC plot, most of the samples have good oil source. The oil sample contains predominant short-chain n-alkanes and plots in marine algal Type II field on a Pr/n-C17 versus Ph/n-C18 cross-plot indicating anoxic environment. Biomarker analysis shows that the deposition of oil source rock is carbonate-rich sediments.     

VARIATIONS IN COMPOSITION, PETROLEUM POTENTIAL AND KINETICS OF ORDOVICIAN – MIOCENE TYPE I AND TYPE I-II SOURCE ROCKS (OIL SHALES): IMPLICATIONS FOR HYDROCARBON GENERATION CHARACTERISTICS

Lacustrine and marine oil shales with Type I and Type I-II kerogen constitute significant petroleum source rocks around the world. Contrary to common belief, such rocks show considerable compositional variability which influences their hydrocarbon generation characteristics. A global set of 23 Ordovician – Miocene freshwater and brackish water lacustrine and marine oil shales has been studied with regard to their organic composition, petroleum potential and generation kinetics. In addition their petroleum generation characteristics have been modelled. The oil shales can be classified as lacosite, torbanite, tasmanite and kukersite. They are thermally immature. Most of the shales contain >10 wt% TOC and the highest sulphur contents are recorded in the brackish water and marine oil shales. The kerogen is sapropelic and is principally composed of a complex of algal-derived organic matter in the form of: (i) telalginite (Botryococcus-, Prasinophyte- (Tasmanites?) or Gloeocapsomorpha-type); (ii) lamalginite (laminated, filamentous or network structure derived from Pediastrum- or Tetraedron-type algae, from dinoflagellate/acritarch cysts or from thin-walled Prasinophyte-type algae); (iii) fluorescing amorphous organic matter (AOM) and (iv) liptodetrinite. High atomic H/C ratios reflect the hydrogen-rich Type I and Type I-II kerogen, and Hydrogen Index values generally >300 mg HC/g TOC and reaching nearly 800 mg HC/g TOC emphasise the oil-prone nature of the oil shales. The kerogen type and source rock quality appear not to be related to age, depositional environment or oil shale type. Therefore, a unique, global activation energy (E_a) distribution and frequency factor (A) for these source rocks cannot be expected. The differences in kerogen composition result in considerable variations in E_a-distributions and A-factors. Generation modelling using custom kinetics and the known subsidence history of the Malay-Cho Thu Basin (Gulf of Thailand/South China Sea), combined with established and hypothetical temperature histories, show that the oil shales decompose at different rates during maturation. At a maximum temperature of ∼120°C reached during burial, only limited kerogen conversion has taken place. However, oil shales characterised by broader E_a-distributions with low E_a-values (and a single approximated A-factor) show increased decomposition rates. Where more deeply buried (maximum temperature ∼150°C), some of the brackish water and marine oil shales have realised the major part of their generation potential, whereas the freshwater oil shales and other brackish water oil shales are only ∼30–40% converted. At still higher temperatures between ∼165°C and 180°C all oil shales reach 90% conversion. Most hydrocarbons from these source rocks will be generated within narrow oil windows (∼20–80% kerogen conversion). Although the brackish water and marine oil shales appear to decompose faster than the freshwater oil shales, this suggests that with increasing heatflow the influence of kerogen heterogeneity on modelling of hydrocarbon generation declines. It may thus be critical to understand the organic facies of Type I and Type I-II source rocks, particularly in basins with moderate heatflows and restricted burial depths. Measurement of custom kinetics is recommended, if possible, to increase the accuracy of any computed hydrocarbon generation models.     

GEOCHEMICAL CHARACTERIZATION OF CENOMANIAN/TURONIAN BLACK SHALES FROM THE TARFAYA BASIN (SW MOROCCO)

Organic geochemical and petrological investigations were carried out on Cenomanian/Turonian black shales from three sample sites in the Tarfaya Basin (SW Morocco) to characterize the sedimentary organic matter. These black shales have a variable bulk and molecular geochemical composition reflecting changes in the quantity and quality of the organic matter. High TOC contents (up to 18wt%) and hydrogen indices between 400 and 800 (mgHC/gTOC) indicate hydrogen‐rich organic matter (Type I‐II kerogen) which qualifies these laminated black shale sequences as excellent oil‐prone source rocks. Low T_max values obtained from Rock‐Eval pyrolysis (404–425 MC) confirm an immature to early mature level of thermal maturation. Organic petrological studies indicate that the kerogen is almost entirely composed of bituminite particles. These unstructured organic aggregates were most probably formed by intensive restructuring of labile biopolymers (lipids and/or carbohydrates), with the incorporation of sulphur into the kerogen during early diagenesis. Total lipid analyses performed after desulphurization of the total extract shows that the biomarkers mostly comprise short‐chain n‐alkanes (C16–C22) and long‐chain (C25–C35) n‐alkanes with no obvious odd‐over‐even predominance, together with steranes, hopanoids and acyclic isoprenoids. The presence of isorenieratane derivatives originating from green sulphur bacteria indicates that dissolved sulphide had reached the photic zone at shallow water depths (～100m) during times of deposition. These conditions probably favoured intensive sulphurization of the organic matter. Flash pyrolysis GC‐MS analysis of the kerogen indicates the aliphatic nature of the bulk organic carbon. The vast majority of pyrolysis products are sulphur‐containing components such as alkylthiophenes, alkenylthiophenes and alkybenzothiophenes. Abundant sulphurization of the Tarfaya Basin kerogen resulted from excess sulphide and metabolizable organic matter combined with a limited availability of iron during early diagenesis. The observed variability in the intensity of OM sulphurization may be attributed to sea level‐driven fluctuations in the palaeoenvironment during sedimentation.     

中国近海海陆过渡相烃源岩二元分布模式——以珠江口盆地白云凹陷为例

珠江口盆地白云凹陷是中国近海盆地已证实的富气凹陷,对烃源岩的研究是该凹陷关键的地质问题之一。通过地震、钻井、地球化学和古生物资料综合分析认为恩平组沉积时期,白云凹陷北坡发育海陆过渡相三角洲,凹陷深部为浅海相沉积。受控于沉积相带的分布,烃源岩呈二元分布特征,分三角洲煤系烃源岩和浅海相泥岩。三角洲煤系分布在凹陷的缓坡区,烃源岩包括煤层、炭质泥岩和暗色泥岩,沉积有机质来自陆源,这类烃源岩地球化学指标以高双杜松烷、低奥利烷和高Pr/Ph值为特征。浅海相泥岩烃源岩分布于深凹陷部位,有机质可细分为2类：一类为陆源海相有机质,地球化学指标以低双杜松烷、高奥利烷和中等Pr/Ph值为特征;另一类为海生藻类,地球化学指标以不含双杜松烷及奥利烷、低Pr/Ph值为特征|这2种类型的烃源岩形成了2种不同类型的气藏。海陆过渡相烃源岩在中国近海外带多个凹陷中都发育,其生烃能力与热演化程度有关。成熟和过成熟时,生成大量天然气;成熟和低成熟时生成一定量的石油。烃源岩分布位置的差异导致天然气富集区主要在热成熟度足够高的煤系三角洲区,生烃灶处在“缓坡区”;另外成熟度足够高的浅海相泥岩区,也是天然气的富集区域,生烃灶处在“深凹区”。     

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     

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.     

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.     

HIGH‐RESOLUTION STRATIGRAPHY,PALYNOFACIES AND SOURCE ROCK POTENTIAL OF THE ÁGUA DE MADEIROS FORMATION (LOWER JURASSIC), LUSITANIAN BASIN,PORTUGAL

In the Lusitanian Basin (central‐western Portugal), the Lower Jurassic carbonate‐dominated succession is thought to have significant source rock potential. One of the most important units is the Água de Madeiros Formation (Upper Sinemurian – lowermost Pliensbachian) which is composed of alternating organic‐rich marls and limestones including black shale horizons. This paper is based on a study of this formation at its type locality at S. Pedro de Moel in western Portugal. Data includes Total Organic Carbon (TOC) measurements, palynofacies analyses and results of Rock‐Eval pyrolysis presented within a high‐resolution lithostratigraphic framework. TOC contents were measured in some 200 samples from the Água de Madeiros Formation covering a stratigraphic interval of 58 m, and vary widely up to a maximum of about 22 wt %. Kerogen assemblages are dominated by marine amorphous organic matter with varying contributions by phytoclasts and palynomorphs. A majority of the 85 samples analyzed by Rock‐Eval pyrolysis have S₂ values above 10 mg HC/g rock, reaching a maximum of 78 mg HC/g rock. These high S₂ values are correlative with maximum values of the Hydrogen Index which averages 355 mg HC/g TOC (maximum of 637 mg HC/g TOC). However in spite of these indicators of source‐rock potential, the Água de Madeiros Formation in the study area is thermally immature or very early mature, as indicated by T_max values below 437 °C and average vitrinite reflectance values of 0.43 % R_o.