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.     

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.     

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.     

THE OLIGOCENE–MIOCENE MENILITE FORMATION IN THE UKRAINIAN CARPATHIANS: A WORLD‐CLASS SOURCE ROCK

This study investigates the hydrocarbon potential of Oligocene–Miocene shales in the Menilite Formation, the main source rock in the Ukrainian Carpathians. The study is based on the analysis of 233 samples collected from outcrops along the Chechva River in western Ukraine in order to analyse bulk parameters (TOC, Rock‐Eval), biomarkers and maceral composition. In Ukraine, the Menilite Formation is conventionally divided into Lower (Lower Oligocene), Middle (Upper Oligocene) and Upper (Lower Miocene) Members. The Early Oligocene and Early Miocene ages of the lower and upper members are confirmed by new nannoplankton data. The Lower Menilite Member is approximately 330 m thick in the study area and contains numerous chert beds and turbidite sandstones in its lower part together with organic‐rich black shales. The shales have a high content of silica which was probably derived from siliceous micro‐organisms. The TOC content of the shales frequently exceeds 20 wt.% and averages 9.76 wt.%. HI values range between 600 and 300 mgHC/gTOC (max. 800 mgHC/gTOC). The Middle Member contains thin black shale intervals but was not studied in detail. The Upper Member is about 1300 m thick in the study area and is composed mainly of organic‐rich shales. Chert layers are present near the base of the Member, and a prominent tuff horizon in the upper part represents a volcanic phase during shale deposition. The member grades into overlying molasse sediments. The average TOC content of the Upper Menilite succession is 5.17 wt.% but exceeds 20 wt.% near its base. Low T_max and vitrinite reflectance measurements for the Lower (419°C and 0.24–0.34 %R_r, respectively) and Upper (425°C and 0.26–0.32 %R_r, respectively) Menilite Member successions indicate thermal immaturity. Biomarker and maceral data suggest a dominantly marine (Type II) organic matter input mixed with varying amounts of land‐plant derived material, and indicate varying redox and salinity conditions during deposition. Determination of the Source Potential Index (SPI) shows that the Menilite Formation in the study area has the potential to generate up to 74.5 tons of hydrocarbons per m². The Chechva River outcrops therefore appear to have a significantly higher generation potential than other source rocks in the Paratethys realm. These very high SPI values for the Menilite Formation may explain why a relatively small area in Ukraine hosts about 70% of the known hydrocarbon reserves in the northern and eastern Carpathian fold‐thrust belt.     

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.     

STRATIGRAPHIC CORRELATION AND SOURCE ROCK CHARACTERISTICS OF THE BALUTI FORMATION FROM SELECTED WELLS IN THE ZAGROS FOLD BELT,KURDISTAN REGION,NORTHERN IRAQ

The Upper Triassic Baluti Formation has been identified and mapped based on its log response in selected wells from the Zagros foldbelt in the Kurdistan Region of northern Iraq. A preliminary evaluation of the formation's source rock potential was made by Rock-Eval screening analysis in four wells along a NW-SE profile (Atrush-1, Shaikan-5B, Taq Taq-22 and Miran-2) with maturity determined from reflectance measurements in samples from well Taq Taq-22. The Baluti Formation consists of thinly interbedded shales, carbonates and anhydrite ranging in thickness from 48 m in well Atrush-1 to 118 m in well Miran-2. The Rock-Eval screening was conducted primarily on bulk cuttings samples plus selected picked cuttings. The TOC content is low to moderate (0.23 to 1.14 wt%). However, the shale content in many of the analysed bulk samples was relatively low, making assessment of the source potential problematic. The highest TOCs are recorded from the thickest analysed sections from wells Miran-2 and Taq Taq-22, where high-gamma bituminous shales are present. Rock-Eval T_max values ranging from 295 to 438°C are not consistent with estimates of pre-Zagros burial to depths of between 4600 m (Atrush-1) and 6900 m (Miran-2). The relatively low T_max values suggest that the S2 response does not reflect kerogen pyrolysis in these samples and may be due to the presence of solid bitumen, which is observed in the Baluti Formation in at least three of the study wells (Taq Taq-22, Miran-2 and Shaikan-5B). Little pyrolysable organic matter remains in the formation due to the interpreted deep pre-Zagros burial and the consequent high maturity in Taq Taq-22 (VR = 1.51%R_o) and Miran-2 (estimated VR >2%R_o), and the poor source character in Atrush-1 and Shaikan-5B. Organic petrography suggests the presence of vestiges of Types I and II kerogen in Taq Taq-22, with bitumen observed as stains in the matrix of the shales and also in the pores and fractures of interbedded dolostones. However, bitumen reflectance determinations for Taq Taq-22 indicate an equivalent vitrinite reflectance maturity of no more than 0.93%R_o, which is significantly less than that of the indigenous vitrinite, implying the solid bitumen in this well is derived primarily from migrated hydrocarbons. Further detailed analysis is required, but the results suggest that the Baluti Formation may have sourced hydrocarbons in its depocentre which is identified in this study as covering a NW-SE trending area between Bekhme and Sangaw.     

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 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.     

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

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