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.     

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.     

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.     

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.     

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.     

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.     

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 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.     

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.     

Investigating gas resource potentiality from Late Jurassic Madbi Formation in the NW –Say’Un-Masila Basin,Eastern Yemen

Late Jurassic Madbi shale samples from Al-Qarn-01 well in the NW Say’un-Masila Basin, Eastern Yemen are analyzed using conventional geochemical data such as total organic carbon (TOC) content and Rock-Eval pyrolysis. The results in this study are used to evaluate the gas resource potentiality in the basin. The analyzed shales have high TOC content between 1.00% and 3.12%, and their HIs range from 77 to 177?mg HC/g TOC. These values indicate that the investigated Madbi shale intervals contain Type III kerogen and are considered to be very good gas-source rocks. Furthermore, the relatively high Rock-Eval pyrolysis T_max (447–459?°C) and PI (0.09–0.44) values indicate mainly peak to late mature 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.     

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

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

HYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS,BORNU (CHAD) BASIN,NE NIGERIA

The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock-Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil- to gas-prone organic matter (Type II-III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r²= 0.86). Rock-Eval T_max calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post-mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons.     

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.     

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.     

SEPARATION OF MACERALS FROM SUBBITUMINOUS COALS AND THEIR RESPONSE TO LIQUEFACTION

ABSTRACT

Separation of macerals from three Alberta subbituminous coals was investigated using float-and-sink method with dense liquids followed by the density gradient technique proposed by Dyrkacz and co-workers at Argonne National Laboratory, U.S.A. Resolutions of 90 percent or greater purity were obtained in some fractions in quantities sufficient to study their response to liquefaction. The ease of liquefaction of macerals isolated from subbituminous coals was, in descending order, liptinite, vitrinite, inertinite. Liquefaction of inertinite occurred at somewhat higher temperatures compared to that of vitrinite macerals which initiated between 350^° and 400^°C.

Analysis of the chemical makeup of macerals from a subbituminous coal indicated that liptinite was relatively rich in hydrogen, whereas vitrinite and inertinite were relatively rich in oxygen and carbon respectively. The average densities were 1.285, 1.345 and 1.458 g/cc for liptinite, vitrinite, and inertinite respectively. X-ray diffraction and NMR spectra of the three macerals were also investigated which will be the subject of a future detailed report.     

RELATIONSHIPS BETWEEN HYDROCARBON GENERATION, COAL TYPE AND RANK FOR MIDDLE EOCENE COALS, BULLER COALFIELD, NEW ZEALAND

The Buller Coalfield in the northern portion of the Paparoa Trough (NW South Island, New Zealand) contains a middle Eocene bituminous coal-bearing succession that exhibits marked variations in both coal rank and type. The across-basin rank changes result from differential late Palaeogene subsidence of the Paparoa Trough and subsequent inversion. Superimposed upon coalification trends are down-seam variations in coal type, evidenced by isorank variation in conventional chemical parameters. These type variations are not a consequence of changes in maceral group proportions, which are dominated by vitrinite. Forty-eight coal samples from fifteen drillholes through the Brunner Coal Measures have been examined for vitrinite reflectance, proximate analysis, specific energy, and sulphur content. Total Organic Carbon (TOC), Rock-Eval properties and the bulk composition of the bitumen were also determined. All the coals analysed lie within the high volatile bituminous B to medium volatile bituminous coalification stages. Variation in analytical properties within this suite, and more specifically within serial samples, provides insights into the nature of the organic matter comprising the coals. While TOC varies systematically with ash content, reflecting proximity of the depositional mires to fluvial systems, values increase with rank (68–86% ash free). The Hydrogen Index (HI) decreases from 334 to 190 mg hydrocarbons/g TOC over a range of 429 to 470 d?C Tmax, analogous to the volatile matter content and vitrinite reflectance, respectively. The more perhydrous coal samples at a given rank are characterised by depressed Tmax/vitrinite reflectance and elevated Hi/volatile matter contents. Bitumen and sulphur contents are not the primary control onperhydrous characteristics. The bitumen content crudely corresponds to the S1 peak plus the initial portion of the S2 peak liberated under low temperatures during Rock-Eval pyrolysis; however, the bulk of the generative potential is associated with the residual kerogen fraction. Suggate (S) Rank and maximum palaeotemperature appear to be the best indicators of coal rank. A period of significant hydrocarbon generation and release begins at Tmax～440d?C for the Buller coals. The main oil “window” is defined by the interval 440–455d?C Tmax or 0.8–1.1% vitrinite reflectance (Ro_max), and by correlation to maximum palaeo-temperatures, 125–155d?C. This is further substantiated by mass balance considerations, which indicate that hydrocarbon generation (Petroleum Generation Index (PG1) > 0.1) was occurring in the coals at a maturity level of O. 7–0.9 % Ro_max (Tmax 440–444 d?C) with an increase in PGI between ～0.9 and 1.1% Ro_max (～Tmax 445–455 d?C). Between PGI 0.1 and 0.4, the expulsion efficiency rapidly increased, presumably due to generation and expulsion of the bulk of the oil.     

Organic Geochemical Evaluations of Bituminous Rock and Coals in Miocene Himmetoglu Basin (Bolu,Turkey)

Abstract

The studied area is a lake basin located in Bolu basin in Turkey. In the basin, from Upper Cretaceous to Upper Miocene 3,000-m thickness sediments were deposited. Upper Miocene Himmetoglu formation consisted of sandstone, claystone, and marl. To the middle level of the formation are located coal, bituminous limestone, and bituminous shales. In the basin, there are two coal beds whose thicknesses range from 1 to 13 m. The coals are easily breakable and black in color. In the coal beds exists some bituminous limestone and bituminous shales, and their thicknesses are between 5 and 45 cm. The amount of organic matter of the bituminous rocks from the Upper Miocene Himmetoglu formation are between 6.83 and 56.34 wt%, and the amount of organic matter of the bituminous limestone from the formation are between 13.58 and 57.16 wt%. These values indicate that these rocks have very good source potential. According to hydrogen index (HI), S ₂/S ₃, HI-T _max, and HI-OI (oxygen index) parameters, kerogen types of the bituminous rocks and coals belonging to Upper Miocene Himmetoglu formation are Type I, Type II, and Type III. In accordance with HI, S ₂/S ₃, HI-T _max, and HI-OI parameters, the bituminous rocks and coals from the Upper Miocene Himmetoglu formation are mostly immature.     

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.     

NASARA-I WELL, GONGOLA BASIN (UPPER BENUE TROUGH, NIGERIA): SOURCE-ROCK EVALUATION

Well Nasara‐I, one of three exploration wells recently drilled in the Gongola Basin in the Upper Benue Trough (onshore Nigeria), was tested and found to be dry. The well penetrated an entirely Cretaceous succession comprising the Pindiga, Yolde and? Bima Formations, and standard organic geochemical analyses were carried out to assess the source‐rock potential of selected samples. Total organic carbon (TOC) contents were found generally to be very low, with no values exceeding 1.0wt%, and about one‐half of them ranging between 0.50 and 0.87wt%. Hydrogen indices (Hls) correlated against Tmax indicate some gas‐generative potential. However, in the depth interval between 4,710ft and 4,770ft, TOC values of between 52.1 and 55.2 wt% were recorded; these are characteristic of coals. This is the first report of a coal within the Pindiga, Yolde or Bima Formations. Hls were between 564 and 589 mgHC/gTOC and Tmax was 423–428°C. Although hydrogen indices can be misleading in assessing the oil‐generative potential of a coal, values as high as those recorded in Nasara‐I permit oil‐generative capabilities to be inferred. Total ion chromatograms of the saturated hydrocarbon fractions of the coaly samples show some ramping of unresolved complex mixtures attributable to biodegradation. Further biomarker data indicate a dominance of low molecular weight n‐alkanes (C₁₅–C₂₅), pristane/phytane ratios of 0.8 to 1.3, and very high contents of C₂₈ regular steranes. These attributes, together with the very high Hls, indicate that some oils generated from a probably deeper‐seated or laterally‐located (and yet to be identified) lacustrine source rock must have migrated and been adsorbed into the coaly facies, which were later intermittently subjected to anoxic to suboxic biodegradation processes.