SEDIMENTOLOGY,GEOCHEMISTRY AND RESERVOIR POTENTIAL OF SANDSTONES IN THE SILURIAN AKKAS FORMATION,WESTERN IRAQ

The source rock potential of “hot shales” in the Silurian Akkas Formation in Iraq has been investigated by numerous studies, but the reservoir potential of sandstone intervals in the formation has received less attention. This study investigates the sedimentology and geochemistry of sandstones from the Akkas Formation in the Akkas‐1, Akkas‐3 and KH5/6 wells in western Iraq. The composition of sandstone samples from the Akkas wells is similar; in general they are classified as sub‐litharenites, quartz‐arenites and sub‐arkoses. Scanning electron microscopic analysis identified extensive microporosity and good pore connectivity, suggesting that these sandstones have the potential to form hydrocarbon reservoirs. The sandstones from the KH5/6 well are more lithic‐rich than those from the Akkas wells and are classified as sub‐litharenites. They have larger, more connected pores and better reservoir potential. Low permeability shale intervals within the Akkas Formation and the conformably‐underlying Ordovician Khabour Formation form barriers to hydrocarbon migration into the Akkas and Khabour sandstones. Hydrocarbon migration from the Akkas “hot shales” in the Akkas field is therefore controlled by faulting and fracturing. Petrographic and whole rock geochemical analyses showed that the composition of sandstones in the Akkas Formation is different from that of sandstones in the Khabour Formation. The chemical alteration index ranges from 77.39 to 87.06%, indicating intense weathering of the provenance area before sandstone deposition. The studied samples are texturally mature which indicates good potential for fluid storage capacity. A decrease in feldspar content in the Akkas Formation is attributed to possible recycling of sediments from the Khabour Formation into the Akkas Formation following the Hirnantian glaciation, or to longer distance transportation from the source area.     

TEMPORAL AND SPATIAL DISTRIBUTION OF ORIGINAL SOURCE ROCK POTENTIAL IN UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SHALES,DANISH CENTRAL GRABEN,NORTH SEA

The Danish Central Graben, North Sea, is a mature oil‐ and gas‐producing basin in which the principal source rocks are the Upper Jurassic – lowermost Cretaceous marine shales of the Farsund Formation (Kimmeridge Clay Formation equivalent), with possible additional potential in the directly underlying Lola Formation. This study investigates the initial source rock potential of the basin by evaluating the original (back‐calculated) source rock properties (TOCo, S2o, HIo) of the shales in the Farsund and Lola Formations within a temporal and spatial framework. About 4800 samples from 81 wells regionally distributed in the Danish Central Graben were included in the study. Samples for source rock analysis were in general collected with varying sampling density from the entire shale section. The shale section has been divided into seven units (referred to as pre‐FSU1 to FSU6; FSU: Farsund Seismic Unit) which are delineated by mappable, regional‐scale seismic markers. For the pre‐FSU1 and FSU2–FSU6 units, the number of available samples ranged from 608 to 1145, while 433 samples were available for FSU1. Good source rock quality varies through space and time and reflects both the structural development of the basin and the effects of the Late Jurassic transgression, with primary kitchen areas developing in the Tail End Graben, Feda Graben, Gertrud Graben and the Rosa Basin. The source rock quality of the shales increases gradually through time and reaches a maximum in FSU6 which includes the “hot shales” of the Bo Member. The maximum source rock quality appears to correspond to an original Hydrogen Index (HIo) of approximately 675 mg HC/g TOC. The proportion of oil‐prone samples per unit (with HIo >350 mg HC/g TOC) ranges from 7 to 11% in the pre‐FSU1 to FSU2 units (Lower Kimmeridgian – Lower Volgian), increasing to 18 – 22% in FSU3 and FSU4/FSU5 (Lower Volgian – Middle Volgian), and reaching a maximum of 53% in FSU6 (Upper Volgian – Ryazanian). FSU6 is the most prolific oil‐prone source rock interval, but the presence of oil‐prone intervals in older and deeper parts of the shale succession is important for assessing the generation potential of the Upper Jurassic petroleum system. The breakdown of the Upper Jurassic – lowermost Cretaceous shale section into mappable seismic units with assigned original source rock properties will contribute to a considerably improved understanding of the temporal and spatial distributions of source rock quality in the Danish Central Graben.     

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.     

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.     

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.     

BURIAL AND THERMAL HISTORY MODELLING OF THE MURZUQ AND GHADAMES BASINS (LIBYA) USING THE GALO COMPUTER PROGRAMME

The GALO computer programme was used to model the thermal and burial histories of the Murzuq and Ghadames Basins, Libya. The model was based on recent drilling and seismic data from the basins, and used published deep temperature and vitrinite reflectance measurements. The model provides more accurate results than previous studies which were based on constant geothermal gradients during the basins' histories, and variations in heat flux at the base of the sedimentary cover were chosen so that calculated values of vitrinite reflectance coincide with those observed. The Murzuq Basin and Libyan part of the Ghadames Basin contain similar source rock units but have different burial histories. In the Murzuq Basin, maximum present‐day burial depths of Cambrian sediments range from 2200 to 2800 m and only locally reach 3000 – 3600 m; in the Ghadames Basin, however, burial depths can exceed 4–5 km. The burial history of the Murzuq Basin includes several periods of intense erosion and lithospheric heating which produced significant lateral variations in thermal maturity, leading in places to unexpected results. For example, relatively shallow‐buried Lower Silurian source rocks in the A‐76 area on the flank of the Murzuq Basin have a thermal maturity of R_o = 1.24% which is higher than the maturity of the same interval in more deeply buried areas (wells D1‐NC‐58 or J1‐NC101). In the central part of the Ghadames Basin, the modelling suggests a higher level of thermal maturity for organic matter in Silurian strata (R_o 0.8 to 1.3%), confirming the generation potential of Lower Silurian “hot shales”. Significant hydrocarbon generation began here in the Late Carboniferous and continues at the present day. Modelling of the Late Devonian (Frasnian) Aouinat Ouinine Formation “hot shales” suggests limited hydrocarbon generation depending strongly on burial depth, with the main phase of hydrocarbon generation taking place during the final episode of thermal activation in the Cenozoic. In the wells studied in the Ghadames Basin, the “oil window” extends over a considerable part of the present‐day sedimentary column.     

ORGANIC-RICH SHALES IN THE UPPER TRIASSIC ZANGXIAHE FORMATION,NORTHERN QIANGTANG DEPRESSION,NORTHERN TIBET: DEPOSITIONAL ENVIRONMENT AND HYDROCARBON GENERATION POTENTIAL

This study reports on the organic geochemical characteristics of high-TOC shales in the Upper Triassic Zangxiahe Formation from a study area in the north of the Northern Qiangtang Depression, northern Tibet. A total of fifty outcrop samples from the Duoseliangzi, Zangxiahe South and Zangxiahe East locations were studied to evaluate the organic matter content of the shales and their thermal maturity and depositional environment, and to assess their hydrocarbon generation potential. Zangxiahe Formation shales from the Duoseliangzi profile have moderate to good source rock potential with TOC contents of up to 3.4 wt.% (average 1.2 wt.%) and potential yield (S₁+S₂) of up to 1.11 mg HC/g rock. Vitrinite reflectance (R_o) and T_max values show that the organic matter is highly mature, corresponding to the condensate/wet gas generation stage. The shales contain mostly Types II and I kerogen mixed with minor Type III, and have relatively high S/C ratios, high contents of amorphous sapropelinite, low Pr/Ph ratios, high values of the C₃₅ homohopane index (up to 3.58%), abundant gammacerane content, and a predominance of C₂₇ steranes. These parameters indicate a saline, shallow-marine depositional setting with an anoxic, stratified water column. The source of organic matter was mainly aquatic OM (algal/bacterial) with subordinate terrigenous OM. Zangxiahe Formation shale samples from the Zangxiahe East and Zangxiahe South locations have relatively low TOC contents (0.2 to 0.8 wt.%) with Type II kerogen, suggesting poor to medium hydrocarbon generation potential. R_o and T_max values indicate that organic matter from these locations is overmature. The discovery of organic-rich Upper Triassic shales with source rock potential in the north of the Northern Qiangtang Depression will be of significance for oil and gas exploration elsewhere in the Qiangtang Basin. Future exploration should focus on locations such as Bandaohu to the SE of the study area where the organic-rich shales are well developed, and where structural traps have been recorded together with potential reservoir rocks and thick mudstones which could act as seals.     

LOWER SILURIAN "HOT SHALES" IN JORDAN: A NEW DEPOSITIONAL MODEL

Data are presented from the Batra Formation (also known as the Mudawwara Shale Formation) of a core from well BG‐14 in the Batna el Ghoul area, southern Jordan, which enable a new depositional model to be proposed for the middle Rhuddanian (lower Llandovery, Silurian) “hot shale” which may be applicable to other Arabian and North African “hot shales” of similar stratigraphical age. This “hot shale” probably results from rapid early burial of organic carbon associated with a minor regression during which anoxic bottom conditions were maintained for most, but not all, of the time. Evidence for regression comes from (1) increased sediment grain size within the “hot shale” by comparison with underlying shales; (2) palynological changes including a decrease in acritarch species diversity; an increase in the relative abundance of sphaeromorphs, veryhachiids with three processes and acritarchs with short, simple processes; and a decrease in the relative abundance of acanthomorphs; (3) a positive δ¹³C_org excursion (other Late Ordovician and Silurian positive δ¹³C_org excursions occur during regressions); and (4) very brief intervals of oxygenation (associated with sediment influx) reflected in the preservation of graptolites as three‐dimensional pyrite internal moulds, rather than as flattened periderm. The minor regression reflects a eustatic sea‐level fall, evidence for which has recently been presented from several regions, including Arctic Canada, Bohemia and Scotland. The BG‐14 “hot shale” is shown to be thicker than estimated in previous studies. Previous TOC measurements from the upper part of the “hot shale” were affected by the weathering of overlying strata in the BG‐14 core. ICP‐MS measurements show that uranium content is high in these weathered levels, extending the stratigraphical extent of the “hot shale” interval into the middle Rhuddanian. Depositional models such as that presented here rely on a robust biostratigraphical framework; in the Ordovician and Silurian of Arabia and North Africa, this can be provided by graptolites and chitinozoans.     

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.     

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.     

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

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

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.     

SOURCE ROCK POTENTIAL OF THE BLUE NILE (ABAY) BASIN, ETHIOPIA

The Blue Nile Basin, a Late Palaeozoic ‐ Mesozoic NW‐SE trending rift basin in central Ethiopia, is filled by up to 3000 m of marine deposits (carbonates, evaporites, black shales and mudstones) and continental siliciclastics. Within this fill, perhaps the most significant source rock potential is associated with the Oxfordian‐Kimmeridgian Upper Hamanlei (Antalo) Limestone Formation which has a TOC of up to 7%. Pyrolysis data indicate that black shales and mudstones in this formation have HI and S₂ values up to 613 mgHC/gCorg and 37.4 gHC/kg, respectively. In the Dejen‐Gohatsion area in the centre of the basin, these black shales and mudstones are immature for the generation of oil due to insufficient burial. However, in the Were Ilu area in the NE of the basin, the formation is locally buried to depths of more than 1,500 m beneath Cretaceous sedimentary rocks and Tertiary volcanics. Production index, T_max, hydrogen index and vitrinite reflectance measurements for shale and mudstone samples from this areas indicate that they are mature for oil generation. Burial history reconstruction and Lopatin modelling indicate that hydrocarbons have been generated in this area from 10Ma to the present day. The presence of an oil seepage at Were Ilu points to the presence of an active petroleum system. Seepage oil samples were analysed using gas chromatography and results indicate that source rock OM was dominated by marine material with some land‐derived organic matter. The Pr/Ph ratio of the seepage oil is less than 1, suggesting a marine depositional environment. n‐alkanes are absent but steranes and triterpanes are present; pentacyclic triterpanes are more abundant than steranes. The black shales and mudstones of the Upper Hamanlei Limestone Formation are inferred to be the source of the seepage oil. Of other formations whose source rock potential was investigated, a sample of the Permian Karroo Group shale was found to be overmature for oil generation; whereas algal‐laminated gypsum samples from the Middle Hamanlei Limestone Formation were organic lean and had little source potential     

ORGANIC GEOCHEMISTRY,BURIAL HISTORY AND HYDROCARBON GENERATION MODELLING OF THE UPPER JURASSIC MADBI FORMATION,MASILA BASIN,YEMEN

The Masila Basin is an important hydrocarbon province in Yemen but the origin of its hydrocarbons is not fully understood. In this study, we evaluate Upper Jurassic source rocks in the Madbi Formation and assess the results of basin modelling in order to improve our understanding of burial history and hydrocarbon generation. This source rock has generated commercial volumes of hydrocarbons which migrated into Jurassic and Lower Cretaceous reservoir rocks. Cuttings samples of shales from the Upper Jurassic Madbi Formation from boreholes in the centre-west of the Masila Basin were analysed using organic geochemistry (Rock-Eval pyrolysis, extract analysis) and organic petrology. The shales generally contain more than 2.0 wt % TOC and have very good to excellent hydrocarbon potential. Kerogen is predominantly algal Type II with minor Type I. Thermal maturity of the organic matter is R_r 0.69–0.91%. Thermal and burial history models indicate that the Madbi Formation source rock entered the early-mature to mature stage in the Late Cretaceous to Early Tertiary. Hydrocarbon generation began in the Late Cretaceous, reaching maximum rates during the Early Tertiary. Cretaceous subsidence had only a minor influence on source rock maturation and OM transformation.     

3D BASIN MODELLING IN THE CENTRAL PERSIAN GULF,OFFSHORE IRAN

In the Central Persian Gulf, super‐giant natural gas accumulations in Permo‐Triassic reservoirs are assumed to be derived from “hot shale” source rocks in the lower Llandoverian (base‐Silurian) Sarchahan Formation, whereas oil in Mesozoic reservoirs is derived from Mesozoic source rocks. A 3D basin model has been established for a study area located in the Iranian part of the Central Persian Gulf in order to help understand the petroleum systems there. Sensitivity analyses considered different heat flow scenarios, and differences in the timing of Cenozoic uplift and erosion. For the Palaeozoic petroleum system, different thicknesses and distributions of the Silurian source rocks were considered. From current temperature profiles measured in five wells, present‐day heat flow was found to be in the order of 65 mW/m², while palaeo heat flow was probably between 60 and 68 mW/m² during Cenozoic maximum burial. For Llandoverian source rocks, oil and gas generation commenced during Jurassic and Late Cretaceous time respectively, and gas generation continued until the Neogene. Sensitivity analyses show that different assumptions on the timing of Cenozoic erosion do not have significant effects on the calculated timing of hydrocarbon generation or on the volume of generated hydrocarbons. As expected however, different heat flow scenarios (e.g. time‐constant heat flow of 65 mW/m² in the entire study area) had a significant influence. With an assumed 50 m thick Sarchahan “hot shale” succession developed uniformly in the study area (8 % TOC; 470 mg HC / g TOC HI), the model calculated gas accumulations which are of the same order of magnitude as those which have been discovered in this region (e.g. South Pars, Golshan and Balal fields). By contrast, scenarios with thinner “hot shales” and models without the Sarchahan Formation along the Qatar‐South Fars Arch do not predict the known accumulations. These scenarios suggest that prolific Silurian source rocks must be present on both sides of the South Pars / North Dome field, or that lateral gas migration from the south may have supplied the Permo‐Triassic reservoirs. This study shows that the Jurassic (mainly Hanifa / Tuwaiq Mountain Formation) and Cretaceous (Shilaif Formation) source units are not sufficiently mature in the study area to have generated significant volumes of oil. This result supports previous suggestions which envisaged lateral migration from the south of the oil present in Mesozoic reservoirs in the study area.     

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.     

UPPER TRIASSIC POTENTIAL SOURCE ROCKS IN THE QIANGTANG BASIN,TIBET: ORGANIC GEOCHEMICAL CHARACTERISTICS

Upper Triassic coal‐bearing strata in the Qiangtang Basin (Tibet) are known to have source rock potential. For this study, the organic geochemical characteristics of mudstones and calcareous shales in the Upper Triassic Tumengela and Zangxiahe Formations were investigated to reconstruct depositional settings and to assess hydrocarbon potential. Outcrop samples of the Tumengela and Zangxiahe Formations from four locations in the Qiangtang Basin were analysed. The locations were Xiaochaka in the southern Qiangtang depression, and Woruo Mountain, Quemo Co and Zangxiahe in the northern Qiangtang depression. At Quemo Co in the NE of the basin, calcareous shale samples from the Tumengela Formation have total organic carbon (TOC) contents of up to 1.66 wt.%, chloroform bitumen A contents of up to 734 ppm, and a hydrocarbon generation capacity (Rock‐Eval S₁+ S₂) of up to 1.94 mg/g. The shales have moderate to good source rock potential. Vitrinite reflectance (R_r) values of 1.30% to 1.46%, and Rock‐Eval T_max values of 464 to 475 °C indicate that the organic matter is at a highly mature stage corresponding to condensate / wet gas generation. The shales contain Type II kerogen, and have low carbon number molecular compositions with relatively high C_21?/C₂₁₊ (2.15–2.93), Pr/Ph ratios of 1.40–1.72, high S/C ratios (>0.04) in some samples, abundant gammacerane (GI of 0.50–2.04) and a predominance of C₂₇ steranes, indicating shallow‐marine sub‐anoxic and hypersaline depositional conditions with some input of terrestrial organic matter. Tumengela and Zangxiahe Formation mudstone samples from Xiaochaka in the southern Qiangtang depression, and from Woruo Mountain and Zangxiahe in the northern depression, have low contents of marine organic matter (Type II kerogen), indicating relatively poor hydrocarbon generation potential. R_r values and T_max data indicate that the organic matter is overmature corresponding to dry gas generation.     

四川盆地陆相页岩油成藏地质特征与重大发现

四川盆地下侏罗统发育陆相湖盆页岩,烃源岩品质好、有机质丰度高、页岩油资源丰富,以往研究主要关注自流井组大安寨段,其他层位研究较少。通过分析侏罗系页岩沉积环境、有机质丰度、类型、成熟度等地球化学特征,以及页岩储集性能、储集空间类型等地质条件,明确了下侏罗统湖相页岩油的地质特征及资源潜力。结果表明：四川盆地发育自流井组东岳庙段、大安寨段和凉高山组3套湖相页岩,页岩TOC含量一般大于1.0%;有机质类型为Ⅱ₁—Ⅱ₂型,3套页岩均具有较好的生烃潜力;R_o值为1.00%～1.82%,热演化程度为中等偏高。页岩厚度大、分布面积广,页岩平均孔隙度为4%～9%,页理缝发育。东岳庙段为平缓的广盆静水沉积环境;大安寨段为侏罗系最大湖泛期沉积,表现为深盆深水环境;凉高山组为广盆浅水环境。页岩发育纯页岩型、页岩-碳酸盐岩互层型、页岩-砂岩互层型3种组合样式。通过对页岩油富集层段进行评价,明确纵向上划分5个甜点段,平面上划分稀油区、轻质油区和凝析油气区3个区带。特别是平安1井等的重大发现,证实了四川盆地侏罗系具备良好的页岩油勘探开发潜力。     

Source and Reservoir Rock Potential of Tertiary Units in the Kozaklı Basin,Central Anatolia,Turkey

The authors present the hydrocarbon source rock potential and reservoir properties of the Eocene Formations in the Central Anatolian Kozakl? Basin. Potential source and reservoir rocks in the Kozakl? basin include transgressive-regressive bank carbonates, fore-bank, deep-marine shales and sandstones, and coal and bituminous facies. The organic geochemical data of the Middle Eocene shales (Sar?lar Formation) show that inadequate to marginal source rock qualities, and marginally mature to overmature characteristics, resulting from heat flow regime of the studied area. Alemli Member of the ?ncik Formation is good to excellent according to TOC wt% and immature to mature source rock from T_max values. Sedimentological features and age data indicate that the Uzunlu Formation was deposited under the control of antecedent topography. Reservoir properties of the Uzunlu Formation and Keklicek member indicate that the carbonate unit is not adequate for reservoir rock. However, siliciclastics of the Sar?lar Formation could be reservoir potential due to its high porosity and permeability values.