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.     

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.     

POST-DRILLING ANALYSIS OF THE NORTH FALKLAND BASIN— PART 1: TECTONO-STRATIGRAPHIC FRAMEWORK

Six wells were drilled in the extensional North Falkland Basin in 1998. The wells encountered a Devonian to Cenozoic stratigraphy dominated by thick Mesozoic syn‐ and post‐rift successions. Although most previously published models predicted that the succession would most likely be of marine origin, it is in fact predominantly terrestrial; marine conditions did not become established in the basin until the Late Cretaceous. The oldest rocks recorded are Devonian and these were penetrated in only one well. The overlying succession comprises: a fluvio‐lacustrine, early syn‐rft interval of ?mid‐Jurassic to Tithonian age; a late syn‐rift fluvio‐lacustrine interval of Tithonian to Berriasian age; a rift‐sag transitional unit of Berriasian to Valanginian age; an early post‐rift lacustrine unit of Valanginian to early Aptian age; a middle post‐rift, transgressive unit of Aptian to Albian age; a late post‐rift, terrestrial to marine unit of Albian to early Palaeocene age; and a post‐up lift thermal subsidence unit of Palaeocene to Recent age. Much of the sediment appears to have been derived from volcanic and/or metamorphic terranes, probably located to the north or NW of the basin. As well as the volcanic material which occurs in the ground mass and as lithoclasts in many of the units, some volcaniclastic rocks and minor amounts of ashfall tufls are observed, particularly within the late syn‐rift succession.     

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.     

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.     

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.     

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.     

HYDROCARBON POTENTIAL AND PALAEO‐DEPOSITIONAL ENVIRONMENT OF LACUSTRINE SOURCE ROCKS: MIDDLE JURASSIC SHIMENGOU FORMATION,NORTHERN QAIDAM BASIN,NW CHINA

The Middle Jurassic Shimengou Formation in the Qaidam Basin, NW China, includes coals and lacustrine source rocks which locally reach oil shale quality (i.e. yielding >3.5 % oil on low‐temperature distillation). In the present study, the palaeo‐depositional environment and hydrocarbon potential of the 84.5 m thick Shale Member of the Shimengou Formation are investigated based on bulk geochemical parameters, organic petrographic data, biomarker analysis, and stable isotope geochemistry of 88 core samples. The Shale Member was deposited in an anoxic freshwater lake which formed following the drowning of a precursor low‐lying mire. Variations in bulk geochemical parameters allow four informal units to be identified, referred to (from the base up) as Units 1 to 4. These contain intervals of oil shale of varying thicknesses. In Unit 1, mudstones in the interval referred to as oil shale Layer 1 (true thickness [TD]: 2.06 m) are OM‐rich as a result of algal blooms and photic zone anoxia, and correspond to an initial flooding event. Subsequently, productivity of aquatic organisms decreased, resulting in the deposition of organic‐lean mudstones in Unit 2. Oil shale Layers 2 (TD: 2.03 m) and 3 (TD: 8.03 m) near the base of Unit 3 were deposited during maximum water depths. As with Layer 1, high productivity by algal blooms resulted in photic zone anoxia in a stratified water column. The shales in the upper part of Unit 3 are characterized by high TOC contents and a gradual increased input of terrigenous OM, and were deposited in a stable semi‐deep lake. Finally, organic‐lean mudstones in Unit 4 were deposited in shallow lacustrine conditions. The reconstruction of depositional environments in thick, non‐marine shale‐rich successions by mineralogical, petrographic and inorganic geochemical methods may be challenging as a result of the homogenous composition of component mudstones. The results of this study indicate, however, that sub‐division and basin‐wide correlation of such intervals can be achieved by organic geochemical analyses. Oil shales and organic‐rich mudstones in Units 1 and 3 of the Shimengou Formation Shale Member are excellent oil‐prone source‐rocks with a Source Potential Index of 3.2 t HC/m². Considering the large area covered by the Shimengou Formation in the northern Qaidam Basin (～34,000 km²), the results of this study highlight the regional significance for future petroleum exploration. They indicate that variations in organic productivity and dilution by minerals are key factors controlling the abundance and type of organic matter in the formation. An understanding of these factors will assist with the identification of exploration targets.     

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.     

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.     

UPPER TRIASSIC-MIDDLE JURASSIC STRATIGRAPHY AND SEDIMENTOLOGY IN THE NE QAIDAM BASIN, NW CHINA: PETROLEUM GEOLOGICAL SIGNIFICANCE OF NEW OUTCROP AND SUBSURFACE DATA

Although Mesozoic source and reservoir rocks are known to occur at oilfields in the northern Qaidam Basin (NW China), the precise identification and distribution of Mesozoic rocks in the subsurface are outstanding problems. The Dameigou locality has in the past been considered as the type section for Lower-Middle Jurassic strata in northern Qaidam. Previous studies have concluded that the onset of non-marine sedimentation here took place in the Early Jurassic; and that Mesozoic strata penetrated by wells in the Lenghu structural zone are Middle Jurassic.
In this paper, we present new data from the Lengke-1 well, drilled in the Lenghu structural zone in 1997. This data indicates the existence of a more extensive pre-Middle Jurassic stratigraphy than has previously been recognized. Biostratigraphic data together with regional seismic mapping suggest that the pre-Middle Jurassic succession at Lengke-1 includes both Late Triassic and Early Jurassic deposits. The Late Triassic sedimentary rocks appear to have been deposited in local half graben, some of which were later inverted during Jurassic, Cretaceous and Cenozoic tectonism.
Lower and Middle Jurassic strata (lacustrine and fluvial deposits) are present in the SW and NE parts of the Lenghu structural zone, respectively. Extensive organic-rich intervals are present in both successions. Lower Jurassic lacustrine mudstones may represent a previously under-appreciated, and potentially large, source rock sequence.     

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.     

PETROLEUM SYSTEMS OF THE BONGOR BASIN AND THE GREAT BAOBAB OILFIELD,SOUTHERN CHAD

The Bongor Basin in southern Chad is an inverted rift basin located on Precambrian crystalline basement which is linked regionally to the Mesozoic – Cenozoic Western and Central African Rift System. Pay zones present in nearby rift basins (e.g. Upper Cretaceous and Paleogene reservoirs overlying Lower Cretaceous source rocks) are absent from the Bongor Basin, having been removed during latest Cretaceous – Paleogene inversion-related uplift and erosion. This study characterizes the petroleum system of the Bongor Basin through systematic analyses of source rocks, reservoirs and cap rocks. Geochemical analyses of core plug samples of dark mudstones indicate that source rock intervals are present in Lower Cretaceous lacustrine shales of the Mimosa and upper Prosopis Formations. In addition, these mudstones are confirmed as a regional seal. Reservoir units include both Lower Cretaceous sandstones and Precambrian basement rocks, and mature source rocks may also act as a potential reservoir for shale oil. Dominant structural styles are large-scale inversion anticlines in the Lower Cretaceous succession whilst underlying “buried hill” -type basement plays may also be important. Accumulations of heavy to light oils and gas have been discovered in Lower Cretaceous sandstones and basement reservoirs. The Great Baobab field, the largest discovery in the Bongor Basin with about 1.5 billion barrels of oil in-place, is located in the Northern Slope, a structural unit near the northern margin of the basin. Reservoirs are Lower Cretaceous syn-rift sandstones and weathered and fractured zones in the crystalline basement. The field currently produces about 32,000 barrels of oil per day.     

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.     

北部湾盆地流二段3类烃源岩的生烃成藏特征

传统研究认为北部湾盆地主力烃源岩为整个流二段湖相烃源岩。应用大量原油和岩石的地球化学分析资料,结合沉积和地质资料,重新对北部湾盆地流二段烃源岩进行了生烃和油气成藏研究。研究结果表明,古近纪沉积的流二段不同层段烃源岩的质量差异较大,明显存在着优质（油页岩）、好和一般3种不同类型的烃源岩。3类烃源岩的生烃和成藏研究表明,3类烃源岩对油藏的贡献各不相同,其中优质烃源岩[丰度高、类型好（Ⅰ型）、产油率达500mg/g_TOC]贡献最大,它对涠西南凹陷和乌石凹陷原油产量的贡献高达80%;好烃源岩[丰度中等、类型较好（Ⅱ₁型）、产油率为300mg/g_TOC]次之,对原油产量的贡献仅为20%;而一般烃源岩[丰度较低、类型较差（Ⅱ₂）、产油率仅为200mg/g_TOC]对凹陷原油的贡献极少。由此表明,厚度不大（厚约为50～100m）、质量极好的流二段底部优质湖相烃源岩才是北部湾盆地真正的主力烃源岩。优质烃源岩生成的原油主要成藏于流二段、流三段、长流组和角尾组,而好烃源岩生成的原油则主要成藏于流一段和涠洲组。3类烃源岩丰度、类型、生烃能力及成藏方面的差异,决定了北部湾盆地的油气勘探必须寻找到优质烃源岩才能提高勘探的成功率。     

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     

HYDROCARBON POTENTIAL OF THE UPPER CRETACEOUS SUCCESSION AT WELL 16/U‐1, ONSHORE QAMAR BASIN,EASTERN YEMEN

An Upper Cretaceous succession has been penetrated at onshore well 16/U‐1 in the Qamar Basin, eastern Republic of Yemen. The succession comprises the Mukalla and Dabut Formations which are composed of argillaceous carbonates and sandstones with coal layers, and TOC contents range up to 80%. The average TOC of the Mukalla Formation (24%) is higher than that of the Dabut Formation (1%). The Mukalla Formation has a Rock‐Eval T_max of 439–454 °C and an HI of up to 374 mgHC/gTOC, pointing to kerogen Types II and III. The Dabut Formation mainly contains kerogen Type III with a T_max of 427–456°C and HI of up to 152 mgHC/gTOC. Vitrinite reflectance values ranging between 0.3 and 1.0% and thermal alteration index values between 3 and 6 indicate thermal maturities sufficient for hydrocarbon generation. Three palynofacies types were identified representing marine, fluvial‐deltaic and marginal‐marine environments during the deposition of the Mukalla and Dabut Formations in the late Santonian — early Maastrichtian.     

MESOZOIC SOURCE ROCKS AND HYDROCARBON POTENTIAL OF THE SEYCHELLES OFFSHORE

Three wells in the Seychelles offshore indicate the existence of four potential source-rock intervals within the Mesozoic succession. Two of these originated during the rift phase that eventually cleaved Gondwana into Eastern and Western blocks — namely, Middle Triassic lacustrine mudstones, and Early/Middle Jurassic deltaic-lagoonal mudstones. The other two source-rock intervals were deposited on passive marine shelves during continental drift phases — namely, Late Jurassic to Early Cretaceous mudstones and siltstones during the East-West Gondwana drift, and Maastrichtian to Paleocene mudstones during the later Seychelles-India drift.
These source rocks are dominated by terrestrial organic matter. Although TOCs are generally good (greater than 1.0%) and range to excellent (7.82%), potential hydrocarbon yields are generally only poor to fair (less than 6 kg HC/tonne of rock). One good potential yield of 10 kg/tonne has been measured. Maturity data (R₀ and T_max) indicate that, in the wells, the youngest source rock is immature, while the oldest lies in the gas "window". The Jurassic/Cretaceous source rocks, on the other hand, lie within the oil "window".
Analyses of numerous beach-stranded tarballs that are believed to be of indigenous origin reveal, in addition to a source dominated by terrestrial organic matter, the presence of a source rock dominated by marine algal organic matter. Such a source rock may have developed during a Middle Jurassic phase of shallow-marine carbonate deposition, which shows some affinity to source-rock quality, and is characterized by an oolitic marker limestone in each well. This oolitic limestone is also a component fades of the carbonate succession that contains the prolific oil-prone source-rock fades of the Middle East.     

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.     

POST-DRILLING ANALYSIS OF THE NORTH FALKLAND BASIN—PART 2: PETROLEUM SYSTEM AND FUTURE PROSPECTS

Six wells were drilled in the North Falkland Basin in 1998. Five of these wells recorded oil shows, and up to 32% gas was also recorded in mud returns to the rig floor. However, none of the wells encountered commercially viable petroleum accumulations.
The syn-rift and early post-rift intervals contain thick, lacustrine claystones with oil source potential as indicated by TOC values up to 7.5% and Rock-Eva1 S₂ values of up to 102 kg HC per tonne of rock. These source rocks were immature or only marginally mature in five of the wells but had attained maturity in one of them. Modelling suggests that the main source interval may well be within the peak oil generation window in deeper, undrilled parts of the basin. Calculations of the amount of oil expelled range up to 60 billion barrels.
Most of the wells tested a closely-related set of plays in large structures asSociated with a sandstone interval near the top of the late syn-rifi to early post-rij? source-rock succession. Post-drilling geological modelling of the basin suggests that oil is unlikely to have migrated into this sandstone play at the localities tested, and that the wells consequently failed largely due to a lack of charge. Howevel_; the play maintains exploration potential elsewhere. Other plays, particularly those stratigraphically asSociated with the base rather than the top of the source rock, may have a higher chance of exploration success.