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.     

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.     

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 POTENTIAL OF UPPER CRETACEOUS MARINE SOURCE ROCKS IN THE TERMIT BASIN,NIGER

Upper Cretaceous mudstones are the most important source rocks in the Termit Basin, SE Niger. For this study, 184 mudstone samples from the Santonian–Campanian Yogou Formation and the underlying Cenomanian–Coniacian Donga Formation from eight wells were analyzed on the basis of palaeontological, petrographical and geochemical data, the latter including the results of Rock‐Eval, biomarker and stable isotope analyses. Samples from the upper member of the Yogou Formation contain marine algae and ostracods together with freshwater algae (Pediastrum) and arenaceous foraminifera, indicating a shallow‐marine to paralic depositional environment with fresh‐ to brackish waters. Terrestrial pollen and spores are common and of high diversity, suggesting proximity to land. Samples from the lower member contain marine algae and ostracods and arenaceous foraminifera but without freshwater algae, indicating shallow‐marine and brackish‐water settings with less freshwater influence. The wide range of gammacerane index values, gammacerane/C₃₀ hopane (0.07–0.5) and Pr/Ph ratios (0.63–4.68) in samples from the upper member of the Yogou Formation suggest a low to moderately saline environment with oxic to anoxic conditions. In samples from the lower member, the narrower range of the gammacerane index (0.23～0.35) and Pr/Ph ratios (0.76–1.36) probably indicate a moderately saline environment with suboxic to relatively anoxic conditions. Petrographic analyses of the Yogou Formation samples show that organic matter is dominated by terrestrial higher plant material with vitrinite, inertinite and specific liptinites (sporinite, cutinite and resinite). Extracts are characterized by a dominance of C₂₉ steranes over C₂₇ and C₂₈ homologues. Results of pyrolysis and elemental analyses indicate that the organic matter is composed mainly of Type II kerogen grading to mixed Type II‐III and Type III material with poor to excellent petroleum potential. Mudstones from the upper member of the Yogou Formation have higher petroleum generation potential than those from the lower member. Mudstones in the Donga Formation are dominated by Type III organic matter with poor to fair petroleum generation potential. Geochemical parameters indicate that in terms of thermal maturity the Yogou Formations has reached or surpassed the early phase of oil generation. Samples have T_max values and 20S/(20S+20R) C₂₉ sterane ratios greater than 435°C and 0.35, respectively. 22S/(22S+22R) ratios of C₃₁ homohopanes range from 0.50 to 0.54. The results of this study will help to provide a better understanding of the hydrocarbon potential of Upper Cretaceous marine source rocks in the Termit Basin and also in coeval intracontinental rift basins such as the Tenere Basin (Niger), Bornu Basin (Nigeria) and Benue Trough (Nigeria).     

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.     

BIOMARKER GEOCHEMISTRY OF CRUDE OILS AND NEOGENE BITUMINOUS SHALES IN THE YENIKÖY AREA,EREĞLI‐ULUKIȘLA BASIN,CENTRAL ANATOLIA,TURKEY

In the Ere?li‐Uluk??la Basin, southern Turkey, crude oil shows have been observed in the subsurface in the shale‐dominated non‐marine Upper Miocene – Pliocene succession. Based on analyses of samples from four boreholes, the shales’ organic matter content, thermal maturity and depositional characteristics are discussed in this study. Geochemical correlations are established between shale extracts and a crude oil sampled from the shale succession. The shales have moderate to high hydrogen index (HI) and very low oxygen index (OI) values. Pyrolysis data show that the shales contain both Types I and II kerogen, and n‐alkane and biomarker distributions indicate that organic matter is dominated by algal material. Very high C₂₆/C₂₅ and C₂₄/C₂₃, and low C₂₂/C₂₁ tricyclic terpane ratios and C₃₁ R/C₃₀ hopane, C₂₉/(C₂₈+C₂₉) MA and DBT/P ratios in shale extracts indicate that deposition occurred in a lacustrine setting. High gammacerane and C₃₅ homohopane concentrations and low diasterane/sterane ratios with a very low Pr/Ph ratio suggest that both the shales and the source rocks for the oil were deposited in a highly anoxic environment in which the water column may have been thermally stratified. Although the shales analysed have very low T_max values, the production index is quite high which suggests that the shales are early‐mature to mature. Biomarker ratios including C₃₂ 22S/(22R+22S) homohopanes, C₂₉ 20S/(20R+20S) and ββ(ββ+αα) steranes, moretane/hopane, TA(I)/TA(I+II) and MPI‐3 all suggest that the shales are within the oil window. Heavy components of free hydrocarbons (S₁) within the shales may have been recorded as part of the Rock‐Eval S₂ peak resulting in the low T_max values. The oil and shale extracts analysed are similar according to their sterane and triterpane distributions, suggesting that the oil was generated by the shales. However burial depths of the Upper Miocene – Pliocene shale succession are not sufficient for thermal maturation to have occurred. It is inferred that intense volcanism during the Pliocene – Pleistocene may have played an important role in local maturation of the shale succession.     

Occurrence and Distribution of Carbazoles and Benzocarbazoles in Tertiary Niger Delta Source Rocks

The distributions of carbazoles and benzocarbazoles in source rocks from the Northern depobelt of the Tertiary Niger Delta, Nigeria, have been investigated by gas chromatography-mass spectrometry (GC-MS). Biomarker compositions of the source rocks indicate that the source rocks were formed from organic matter of mixed origin (terrestrial and marine) and are either immature or at early maturity stage. The carbazoles distributions in the source rocks are dominated by C₀-C₂-carbazoles and strong variation was observed in their distributions with increasing maturity. Among the C₁-carbazoles, 1-methylcarbazole shows a decrease trend at the immature stage and an increase trend at higher maturity levels. 2- and 3-methylcarbazoles display an increasing trend with increasing maturity while 4-methylcarbazole exhibits a decreasing pattern with increasing maturity. Within the C₂-carbazoles isomers, 1,8- and 2,7-dimethylcarbazoles, show an increasing trend with increasing maturity while the partially exposed isomers 1,3- and 1,6-dimethylcarbazoles decrease with increasing maturity. The ratio of benzo[a]carbazole/benzo[a]carbazole +benzo[c]carbazole varies significantly from 0.36 to 0.55 in the entire maturity range, indicating a strong maturity dependence. These results show that maturity will have great effect on the use of carbazoles and benzocarbazoles distributions as oil migration parameter in the Niger Delta.     

LOWER CARBONIFEROUS SHALES IN THE EASTERN TAURIDE BELT,SOUTHERN TURKEY: SOURCE ROCK CHARACTERISTICS

Lower Carboniferous (Tournaisian‐Visean) shales, sandstones and limestones are exposed at the surface in autochthonous units in the Eastern Taurides, southern Turkey. This study investigates the organic geochemical characteristics, thermal maturity and depositional environments of shale samples from two outcrop locations in this area (Belen and Naltas). The total organic carbon (TOC) contents range from 0.11 to 5.61 wt % for the Belen samples and 0.04 to 1.74 wt % for the Naltas samples. T_max values ranging from 432–467 °C indicate that the samples are in the oil generation window T_max and are thermally mature. Rock‐Eval pyrolysis data indicate that the organic matter in the shales is composed mainly of Type II and III kerogen. Solvent extract analyses of the samples show a unimodal n‐alkane distribution with a predominance of low carbon number (C₁₃‐C₂₀) n‐alkanes. Pr/Ph ratios and CPI values range from 1.57–1.66 and 1.08–1.11, respectively Pr/n‐C₁₇ and Ph/n‐C₁₈ ratios also indicate that the shales consist of mixed Type II/III organic matter. Sterane distributions are C₂₇>C₂₉>C₂₈ as determined by the sum of normal and isosteranes, suggesting marine depositional conditions 20S/(20S+20R) and ββ (ββ+αα) C₂₉ sterane ratios range from 0.51–0.54 and 0.53–0.57, respectively. These values are high and 20S/(20S+20R) sterane isomerisation has reached equilibrium values. Tricyclic terpanes are abundant on m/z 191 mass chromatograms and C₂₃ tricyclic terpanes are the dominant peak, which indicates a marine depositional setting. C₂₉ norhopane has a higher concentration than C₃₀ hopane, and C₃₀ diahopane and C₂₉Ts are present in all the samples. Ts and Tm were recorded in similar abundances. Moretane/hopane ratios are very low. 22S homohopanes are dominant over 22R homohopanes, and the C₃₂ 22S/(22R + 22S) C₃₂ homohopane ratios are between 0.58 and 0.59, indicating that homohopane isomerisation has reached equilibrium. C₃₁ homohopanes are dominant and the abundance of homohopanes decreases towards higher numbers. Although regional variations in the level of thermal maturity of Upper Palaeozoic sediments throughout the Taurus Belt region largely depend on burial depth, organic geochemical data indicate that the Lower Carboniferous shales in the eastern Taurus region (Naltas and Belen locations) have potential to generate hydrocarbons. These shales are thermally mature and have entered the oil generation window.     

BURIAL HISTORY AND THERMAL MATURITY EVOLUTION OF THE TERMIT BASIN,NIGER

Reconstruction of the burial history and thermal evolution of the Cretaceous – Tertiary Termit Basin, a sub‐basin within the larger Eastern Niger Basin of Niger, indicates spatially and temporally variable conditions for organic matter maturation during the basin's multi‐phased evolution. Three episodes of tectonic subsidence which correspond to the observed fault mechanical stratigraphy within the Termit Basin are identified: Late Cretaceous, Maastrichtian to early Paleocene, and Oligocene. These episodes fall within the regional tectonic phases of the West African Rift System delineated by previous studies. The basin exhibits substantial heterogeneity in the magnitude of the tectonic episodes and in consequent thermal maturities. For this paper, 1D burial and thermal histories of eight widely dispersed wells in the Agadem permit area in the SW of the Termit Graben were modelled to investigate the maturation of organic matter in source rocks ranging from Santonian to Oligocene in age. The kinetic modelled maturities match with maturities based on Rock‐Eval T_max values for four wells if present‐day heat flows are elevated. Future exploration strategies in the Termit Basin should take into consideration these heterogeneities in thermal histories and tectonic pulses, which may lead to the development of hydrocarbon accumulations with different oil‐gas compositions in different reservoir compartments.     

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.     

SOURCE ROCK POTENTIAL AND ORGANIC GEOCHEMISTRY OF CENOMANIAN-TURONIAN BLACK SHALES,WESTERN TAURUS,SW TURKEY

The depositional environment and hydrocarbon source rock potential of Cenomanian-Turonian black shales of the Dereköy and Ballik Formations in SW Turkey were investigated by organic geochemical methods. In detail, 33 samples from three section of the Dereköy Formation, and 15 samples from one section of the Ballik Formation were analysed for elemental (TOC, Rock -Eval pyrolysis), C₁₅₊-lipid and biomarker compositions. Based on maximum pyrolysis degradation temperatures of not more than 420°C, all the shale samples are classified as immature, corresponding to a vitrinite reflectance of less than 0.45% R_r and a lignite to sub-bituminous coal stage. This is confirmed by relatively high isoprenoid to n-alkane ratios as well as by high biomarker contents. According to this maturity stage, and both total organic carbon contents of 6–41% and hydrogen indices of 255–708 mg HC/g TOC, the Cenomanian-Turonian black shales exhibit fair to excellent source rock potential with mixed Type II and Type I kerogen. Relatively high isoprenoid to n-alkane ratios may indicate at least partial (bio-) degradation/evaporation/waterwashing and selective modification of the lipid composition due to the nature of the outcrop. However, very similar unimodal n-alkane distributions in the gas chromatograms of four selected shale samples, with a predominance in the C₁₆ to C₁₇ region, clearly point to a significant contribution of algal and/or bacterial type organic matter with low terrigenous organic input. C₂₇, C₂₈ and C₂₉ steranes in shales from both formations have similar distributions (C₂₉>C₂₇>C₂₈). High C₃₁ R homohopane / C₃₀ hopane ratios indicate a marine depositional environment. This is confirmed by the presence of gammacerane in all the black shales investigated which in general indicates salinity. Pregnanes in one sample (BA-6) may point to hypersaline conditions.     

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.     

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.     

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.     

Biomarkers and isotopic characteristics of crude oils from a central Niger delta depobelt field,Nigeria

Twelve crude oils samples from a field in the central depobelt in the Niger delta, Nigeria were analyzed for their biomarkers and isotopic composition by Gas chromatography–Mass spectrometry and Isotope mass spectrometry. The percentage C_27, C₂₈ and C₂₉ steranes in the oils ranged from 35.80 to 39.9, 28.1 to 30.8 and 29.9 to 35.0, respectively. The distribution of molecular biomarkers and isotopic composition in the oils indicated that they were formed from source rocks of a mixed source (marine and terrestrial kerogen) but with greater input from marine organic matter. The Pr/Ph ratios of the oil samples ranged from 1.2 to 2.3 and this indicated organic matter deposited under suboxic conditions. The vitrinite reflectance (%VRc) values calculated from methylphenanthrene index-1 (MPI-1) parameter ranged from 0.89 to 1.07 indicating oils generated at the peak of oil window.     

ORGANIC GEOCHEMICAL CHARACTERIZATION AND SHALE GAS POTENTIAL OF THE PERMIAN BARREN MEASURES FORMATION,WEST BOKARO SUB‐BASIN,EASTERN INDIA

This study investigates the shale gas characteristics of the Permian Barren Measures Formation (Gondwana Supergroup) in the West Bokaro sub‐basin of the Damodar Valley Basin, eastern India. A total of 23 core shale samples collected from a borehole located in the western part of the sub‐basin were analysed using organic geochemical techniques and scanning electron microscopy. The samples are black carbonaceous shales composed chiefly of quartz, mica and clay minerals. Rock‐Eval pyrolysis data show that the analysed samples contain a mixture of Type II and Type III kerogen with TOC values of 2.7 to 6.2%. Rock‐Eval T_max values ranging from 443 to 452 °C correspond to calculated vitrinite reflectance of approximately 0.8–0.9%. A cross‐plot of hydrogen index versus T_max indicates that the samples have reached peak oil to wet gas maturities. A pristane/n‐C₁₇ versus phytane/n‐C₁₈ cross‐plot, together with biomarker parameters such as the dominance of C₂₉ over C₂₇ and C₂₈ steranes and high moretane/hopane ratios (0.22–0.51), demonstrate that the shale samples contain terrigenous organic matter deposited in a suboxic environment. Scanning electron microscopy images of shale samples show the presence of a complex, mostly intergranular pore network. Both micropores (>0.75μm) and nanopores (<0.75μm) were observed. Some pores are elongated and are associated with layer‐spaces in sheet silicate minerals; others are non‐elongated and irregular in shape. The organic geochemical parameters and the observed pore attributes suggest that the Barren Measures Formation has good shale gas potential.     

GEOCHEMISTRY OF SEEP AND PRODUCED OIL SAMPLES FROM SOUTHERN CAMEROON

Crude oil samples from surface seeps in the Douala Basin (southern Cameroon) and from producing fields in the nearby Rio del Rey and Kribi‐Campo sub‐basins were analysed for bulk and molecular geochemical parameters by inductively coupled plasma – mass spectrometry (ICP‐MS), gas chromatography – mass spectrometry (GC‐MS) and isotope ratio mass spectrometry (IRMS). The aims of the study were to assess the composition of the oils, to evaluate the relationship between the seep oils and the oils from producing fields, and to highlight the significance of the data for oil exploration in the region. Chromatograms of the saturate fractions of the oils exhibit biodegradation ranging from very light (PM1 on the scale of Peters and Moldowan, 1993) in oil from the offshore Lokele field in the Rio del Rey sub‐basin, to severe (PM 6+) for seep oils from the Douala Basin. A plot of Pr/n‐C₁₇ (1.3– 5.0) versus Ph/n‐C₁₈ (0.8–2.6) for the samples further supports mild biodegradation in some samples (Lokele, Kole, Ebome), and demonstrates that the oils from the Lokele and Kole fields (Rio Del Rey sub‐basin) and from Ebome field (Kribi‐Campo sub‐basin) originated from mixed organic matter with a dominant marine contribution. The Pr/Ph ratio (1.8–2.3) for the Lokele, Kole and Ebome oil samples, and the V/(V+Ni) ratios (< 0.5) for the seep oils (Douala Basin) and the oils from the Lokele, Kole and Ebome fields, indicate derivation from source rocks deposited in oxic – dysoxic environments. The CPI (1.0–1.1) demonstrates that the Lokele and Ebome oils originated from mature source rocks, with the ratios of C₃₁ 22S/(S+R) (0.57 to 0.63) and C₃₀‐βαH/C₃₀‐αβH (0.18–0.23) for the Lokele, Kole and Moudi samples indicating early oil window maturity. Both V/(V+Ni) ratios (0.06–0.22) and δ¹³C (‐26.96 to ‐24.89 ‰) were used for correlation of the oils, with the seep oils from the Douala Basin showing the closest relationship to the oil from the Lokele field. The presence of mature Type II / III source rocks in different basins in southern Cameroon suggests significant potential for oil exploration in the region.