GEOCHEMISTRY AND ORIGIN OF UPPER CRETACEOUS OILS FROM THE TERMIT BASIN,NIGER

Crude oil samples (n = 16) from Upper Cretaceous reservoir rocks together with cuttings samples of Upper Cretaceous and Paleogene mudstone source rocks (n = 12) from wells in the Termit Basin were characterized by a variety of biomarker parameters using GC and GC‐MS techniques. Organic geochemical analyses of source rock samples from the Upper Cretaceous Yogou Formation demonstrate poor to excellent hydrocarbon generation potential; the samples are characterized by Type II kerogen grading to mixed Types II–III and III kerogen. The oil samples have pristane/phytane (Pr/Ph) ratios ranging from 0.73 to 1.27, low C₂₂/C₂₁ and high C₂₄/C₂₃ tricyclic terpane ratios, and values of the gammacerane index (gammacerane/C₃₀hopane) of 0.29–0.49, suggesting derivation from carbonate‐poor source rocks deposited under suboxic to anoxic and moderate to high salinity conditions. Relatively high C₂₉ sterane concentrations with C₂₉/C₂₇ sterane ratios ranging from 2.18–3.93 and low values of the regular steranes/17α(H)‐hopanes ratio suggest that the oils were mainly derived from kerogen dominated by terrigenous higher plant material. Both aromatic maturity parameters (MPI‐1, MPI‐2 and R_c) and C₂₉ sterane parameters (20S/(20S+20R) and ββ/ (αα + ββ)) suggest that the oils are early‐mature to mature. Oil‐to‐oil correlations suggest that the Upper Cretaceous oils belongs to the same genetic family. Parameters including the Pr/Ph ratio, gammacerane index and C₂₆/C₂₅ tricyclic terpanes, and similar positions on a sterane ternary plot, suggest that the Upper Cretaceous oils originated from Upper Cretaceous source rocks rather than from Paleogene source rocks. The Yogou Formation can therefore be considered as an effective source rock.     

尼日尔Termit盆地Yogou组泥岩地球化学特征及沉积背景

Yogou组泥岩是Termit盆地主要的烃源岩之一。为了揭示Termit盆地Yogou组沉积时期物源属性、物源区的构造背景及其沉积环境,通过对4口井20块泥岩样品的主量元素、微量元素和稀土元素测试,对Yogou组泥岩的元素地球化学特征进行了综合分析。结果显示： Yogou组上部以被动大陆边缘物源为主,下部以长英质物源为主,物源区处于大陆岛弧的构造背景条件下。Yogou组中-上部沉积时期水体盐度相对较低,为海陆过渡相沉积;Yogou组下部沉积时期水体盐度较高,为海相沉积。CIA指数、Sr/Cu值等指标表明,Yogou组沉积时期研究区处于湿热的气候条件;V/（V+Ni）等指标说明,Yogou组沉积时期水体处于厌氧环境。     

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.     

PETROLEUM PROSPECTIVITY OF CRETACEOUS FORMATIONS IN THE GONGOLA BASIN,UPPER BENUE TROUGH,NIGERIA: AN ORGANIC GEOCHEMICAL PERSPECTIVE ON A MIGRATED OIL CONTROVERSY

Organic geochemical studies of Cretaceous formations in the Gongola Basin, northern Nigeria, show TOC values that are generally higher than the minimum (0.5 wt %) required for hydrocarbon generation. Data from Rock‐Eval pyrolysis and biomarker studies indicate the presence of both terrestrial and marine derived Types II and III organic matter, which is immature in the Gombe Formation and of marginal maturity in the Yolde Formation. Immature Type III to IV OM is present in the Pindiga Formation; and Type III OM, with a maturity that corresponds to the conventional onset (or perhaps peak) of oil generation occurs in the Bima Formation. However, Bima Formation samples from the 4710 – 4770 ft (1435.6 – 1453.9 m) depth interval within well Nasara‐1 indicate Type I OM of perhaps lacustrine origin (H31R/H30 ratio generally ≤0.25). Although the Nasara‐1 well was reported to be dry, geochemical parameters (high TOCs, S₁, S₂ and Hls, low Tmax compared to adjacent samples, a bimodal S₂ peak on the Rock‐Eval pyrogram, a dominance of fluorinite macerals), together with generally low H3IR/H30 biomarker ratios within the 4710–4770 ft (1435.6–1453.9 m) interval, suggest the presence of migrated oil, perhaps sourced by lacustrine shales in the Albian Bima Formation located at as‐yet unpenetrated depths. The presence of the migrated oil in the Bima Formation and its possible lacustrine origin suggest that the petroleum system in the Gongola Basin is similar to that of the Termit, Doba and Doseo Basins of the Chad Republic, where economic oil reserves have been encountered.     

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.     

尼日尔Moul凹陷白垩系Yogou组海陆过渡相沉积与成藏条件

Termit盆地是西非裂谷系中典型的海相沉积盆地,海陆过渡相沉积特征对于盆地烃源岩、储层、盖层及油气生成、聚集的影响巨大。Moul凹陷白垩系Yogou组是Termit盆地海相油气勘探的典型成功实例。受构造沉降与海平面变化控制,Moul凹陷白垩系Yogou组发育曲流河三角洲、辫状河三角洲、远岸水下扇、混积陆棚及滨浅海等5种沉积相类型;凹陷东部发育辫状河三角洲_远岸水下扇沉积体系,凹陷西部发育曲流河三角洲_混积陆棚沉积体系,凹陷中心则以浅海和远岸水下扇沉积体系为主;Yogou组沉积相序演化垂向呈“浅海_远岸水下扇_三角洲”进积序列叠加的特点,平面具有“盆缘三角洲_盆内重力流_混积陆棚”多相匹配的特征,使烃源岩与储层呈“纵向叠置相邻、平面广泛分布”的分布格局,形成了多套“三明治”式优质生储盖组合,为油气成藏奠定坚实的基础;Yogou斜坡、Koulele帚状带及Trakes斜坡油气运聚条件优越,保存条件良好,是勘探重点区带;YSQ1、YSQ2高位域及YSQ3低位域生储盖组合条件好,是主要目的层段。在地质认识基础上,优化井位部署,多口井获工业油流,有力推动了盆地油气勘探的进程。     

CRUDE OIL GEOCHEMISTRY AND SOURCE ROCK POTENTIAL OF THE UPPER CRETACEOUS – EOCENE SUCCESSION IN THE BELAYIM OILFIELDS,CENTRAL GULF OF SUEZ,EGYPT

This study evaluates the petroleum potential of source rocks in the pre‐rift Upper Cretaceous – Eocene succession at the Belayim oilfields in the central Gulf of Suez Basin. Organic geochemical and palynofacies investigations were carried out on 65 cuttings samples collected from the Thebes, Brown Limestone and Matulla Formations. Analytical methods included Rock‐Eval pyrolysis, Liquid Chromatography, Gas Chromatography and Gas Chromatography – Mass Spectrometry. Four crude oil samples from producing wells were characterised using C₇ light hydrocarbons, stable carbon isotopes and biomarker characteristics. The results showed that the studied source rocks are composed of marine carbonates with organic matter dominated by algae and bacteria with minimal terrigenous input, deposited under reducing conditions. This conclusion was supported by n‐alkane distributions, pristane/ phytane ratios, homohopane and gammacerane indices, high concentrations of cholestane, the presence of C₃₀ n‐propylcholestanes, and low diasterane ratios. The source rocks ranged from immature to marginally mature based on the Rock‐Eval T_max together with biomarker maturity parameters. The analysed crude oil samples are interpreted to have been derived from source rock intervals within the Eocene Thebes Formation and the Upper Cretaceous Brown Limestone. The similarity in the geochemical characteristics of the crude oils suggests that there was little variation in the organofacies of the source rocks from which they were derived.     

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.     

ORGANIC GEOCHEMISTRY OF CRUDE OILS AND UPPER CRETACEOUS SOURCE ROCKS FROM CONCESSION 11, WEST SIRTE BASIN,LIBYA

This paper reports the results of Rock‐Eval pyrolysis and total organic carbon analysis of 46 core and cuttings samples from Upper Cretaceous potential source rocks from wells in the West Sirte Basin (Libya), together with stable carbon isotope (δ¹³C) and biomarker analyses of eight oil samples from the Paleocene – Eocene Farrud/Facha Members and of 14 source rock extracts. Oil samples were analysed for bulk (°API gravity and δ¹³C) properties and elemental (sulphur, nickel and vanadium) contents. Molecular compositions were analysed using liquid and gas chromatography, and quantitative biological marker investigations using gas chromatography – mass spectrometry for saturated hydrocarbon fractions, in order to classify the samples and to establish oil‐source correlations. Core and cuttings samples from the Upper Cretaceous Etel, Rachmat, Sirte and Kalash Formations have variable organic content and hydrocarbon generation potential. Based on organofacies variations, samples from the Sirte and Kalash Formations have the potential to generate oil and gas from Type II/III kerogen, whereas samples from the Etel and Rachmat Formations, and some of the Sirte Formation samples, have the potential to generate gas from the abundant Type III kerogen. Carbon isotope compositions for these samples suggest mixed marine and terrigenous organic matter in varying proportions. Consistent with this, the distribution of n‐alkanes, terpanes and steranes indicates source rock organofacies variations from Type II/III to III kerogen. The petroleum generation potential of these source rocks was controlled by variations in redox conditions during deposition together with variations in terrigenous organic matter input. Geochemical analyses suggest that all of the oil samples are of the same genetic type and originated from the same or similar source rock(s). Based on their bulk geochemical characteristics and biomarker compositions, the oil samples are interpreted to be derived from mixed aquatic algal/microbial and terrigenous organic matter. Weak salinity stratification and suboxic bottom‐water conditions which favoured the preservation of organic matter in the sediments are indicated by low sulphur contents and by low V/Ni and Pr/Ph ratios. The characteristics of the oils, including low Pr/Ph ratio, CPI ～l, similar ratios of C₂₇:C₂₈:C₂₉ ααα‐steranes, medium to high proportions of rearranged steranes, C₂₉ <C₃₀‐hopane, low Ts/Tm hopanes, low sulphur content and low V/Ni ratio, suggest a reducing depositional environment for the source rock, which was likely a marine shale. All of the oil samples show thermal maturity in the early phase of oil generation. Based on hierarchical cluster analysis of 16 source‐related biomarker and isotope ratios, four genetic groups of extracts and oils were defined. The relative concentrations of marine algal/microbial input and reducing conditions decrease in the order Group 4 > Group 3 > Group 2 > Group1. Oil – source rock correlation studies show that some of the Sirte and Kalash Formations extracts correlate with oils based on specific parameters such as DBT/P versus Pr/Ph, δ¹³C_saturates versus δ¹³C_aromatics, and gammacerane/hopane versus sterane/hopane.     

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.     

POTENTIAL PETROLEUM SOURCE ROCKS IN THE TERMIT BASIN,NIGER

Potential source rocks from wells in the Termit Basin, eastern Republic of Niger, have been analysed using standard organic geochemical techniques. Samples included organic‐rich shales of Oligocene, Eocene, Paleocene, Maastrichtian, Campanian and Santonian ages. TOC contents of up to 20.26%, Rock Eval S₂ values of up to 55.35 mg HC/g rock and HI values of up to 562 mg HC/g TOC suggest that most of the samples analysed have significant oil‐generating potential. Kerogen is predominantly Types II, III and II–III. Biomarker distributions were determined for selected samples. Gas chromatograms are characterized by a predominance of C₁₇– C₂₁ and C₂₇– C₂₉ n‐alkanes. Hopane distributions are characterized by 22S/(22S+22R) ratios for C₃₂ homohopanes ranging from 0.31 to 0.59. Gammacerane was present in Maastrichtian‐Campanian and Santonian samples. Sterane distributions are dominated by C₂₉ steranes which are higher than C₂₇ and C₂₈ homologues. Biomarker characteristics were combined with other geochemical parameters to interpret the oil‐generating potential of the samples, their probable depositional environments and their thermal maturity. Results indicate that the samples were in general deposited in marine to lacustrine environments and contain varying amounts of higher plant or bacterial organic matter. Thermal maturity varies from immature to the main oil generation phase. The results of this study will contribute to an improved understanding of the origin of the hydrocarbons which have been discovered in Niger, Chad and other rift basins in the Central African Rift System.     

BIOMARKER CHARACTERISTICS OF POTENTIAL SOURCE ROCKS IN THE JABAL NAFUSAH AREA,NW LIBYA: PETROLEUM SYSTEMS SIGNIFICANCE

The Jifarah Arch of NW Libya is a structurally prominent feature at the eastern end of the regional Talemzane Arch, separating the Ghadamis hydrocarbon province to the south from the offshore Pelagian province to the north. The Arch has experienced a complex structural history with repeated episodes of uplift, exhumation and burial. This paper provides a provisional assessment of its hydrocarbon habitat based on detailed geochemical analyses of potential Triassic, Silurian and Ordovician source rocks encountered by wells drilled in the area. Twenty‐seven core and cuttings samples of marine shales were collected from eight widely‐ dispersed wells and analyzed using standard Rock‐Eval pyrolysis techniques. Kerogen types II‐III were identified in the majority of Triassic samples analysed, indicating a low hydrocarbon generation potential, but oil‐prone Type II kerogen was found in the basal Silurian Tanezzuft Formation and Ordovician Memouniat Formation. The presence of steranes and acyclic isoprenoids suggested variable inputs of algal, bacterial and terrestrial organic matter, while biomarkers including C₃₀‐gammacerane and β–carotene and selected biomarker ratios (Pr/Ph ratio and homohopane index) were used to assess their depositional environment. Results indicate that extended zones with periodic (if not continuous) oxygen‐deficient conditions existed throughout the basin during Late Ordovician and Early Silurian time, favouring the preservation of organic matter. The thermal maturity of the samples was assessed by Rock‐Eval pyrolysis, zooclast reflectance, molecular ratios including C_32‐22S/(22S+22R)‐homohopanes, Ts/(Ts+Tm), C₂₉‐steranes and parameters based on the relative abundance of methylphenanthrene, methyldibenzothiophene and methylnaphthalene isomers. The results indicate significant variability in thermal maturity, with Ordovician and Silurian source rocks ranging from 0.6% to 0.7% VR_o equivalent increasing to 1.0% locally. These values represent palaeo‐maturities achieved at different times in the past and are considered too low to have generated significant volumes of hydrocarbons directly. However the downdip equivalents of these source rocks in the adjacent Ghadamis Basin contributed to prolific petroleum systems. The absence of large petroleum accumulations on the Jifarah Arch contrasts with the western part of the geologically similar Talemzane Arch, which harbours several giant and supergiant oil and gas fields. This difference is attributed both to the complex structural history of the Jifarah Arch, which permitted post‐charge leakage of palaeo‐accumulations, and stratigraphic migration barriers which restricted migration between Tanezzuft source rocks and Ordovician and Triassic reservoirs.     

GENETIC CLASSIFICATION OF OIL FAMILIES IN THE CENTRAL AND SOUTHERN SECTORS OF THE GULF OF SUEZ,EGYPT

The results of geochemical analyses were used to classify ten oil samples from six fields in the central and southern sectors of the Gulf of Suez, Egypt. The samples were collected from sandstone pay‐zones ranging in age from Early Palaeozoic (Nubia‐C) to Miocene (Kareem Formation) at various present‐day depths. Molecular and stable isotope analyses indicate the presence of two genetic oil families (Families I and II) and suggest their probable source rocks. The biomarker characteristics of Family 1 oils include low Pr/Ph ratio, CPI < 1.0, depleted rearranged steranes, very low diahopane concentrations, high sulphur content, high metal content and V/Ni ratio, low oleanane index, abundance of gammacerane and C₂₇ steranes, and high relative abundance of homohopanes and C₃₀ 24‐n‐propylcholestanes. Source rock deposition took place under anoxic marine‐carbonate and hypersaline conditions. The NCR and NDR 24‐norcholestane ratios together with the presence of highly‐branched isoprenoids in this oil family are consistent with Upper Cretaceous – Lower Paleogene source rocks. These characteristics suggest that the Upper Cretaceous Duwi Formation/Brown Limestone or Lower Eocene Thebes Formation are the source rocks for the oils in this family, which occur in the central sector of the Gulf of Suez. Family II oils have geochemical characteristics that point to a mature source rock deposited in a weakly reducing or suboxic setting under normal salinity conditions. Abundant oleananes, high 24‐ to 27‐norcholestane ratios and abundant C₂₅ highly‐branched isoprenoids suggest a Paleogene source rock. The Lower Miocene Rudeis Formation is the best candidate to have generated these oils which occur in the southern sector of the Gulf of Suez.     

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.     

Biomarkers Assessment of Crude Oils and Extracts from Jurassic-Cretaceous Rocks,North Qattara Depression,North Western Desert,Egypt

Abstract

Crude oils together with extracts from the Middle Jurassic (Khatatba Formation), Barremian-Early Aptian Alam El Bueib Formation, and Early Albian Kharita Formation were collected from five wells (Ras Qattara-Zarif-5, Ras Qattara-Zarif-3, and Zarif-1, Zarif-2, SW Zarif-1) in the North Qattara Depression. Biomarkers (pristane/phytane, isoprenoids/n-alkanes, steranes, triterpanes, C₂₉ steranes 20S/20S + 20R, C₂₃ tricyclic/C₃₀ hopane, Ts/Tm, C₃₀ moretane/C₃₀ hopane ratios, homohopane and gammacerane indices) of the saturated hydrocarbon fraction were analyzed in order to assess the source and maturity of the crude oils and the extracts. The results suggested that the oils from Khatatba and Alam El Bueib formations are mature, derived from source rocks containing marine and terrestrial organic matter, respectively. The source environments and maturity of the oil from the Khatatba Formation is similar to that of the Khatatba source rock extract. The oil from the Alam El Bueib formation differs from the extracts of the Alam El Bueib and Kharita formations. The Khatatba formation seems to be an effective source rock in the North Qattara Depression.     

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

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

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.     

LATE TO MIDDLE JURASSIC SOURCE FACIES AND QUALITY VARIATIONS, SOUTH VIKING GRABEN, NORTH SEA

Source facies and quality of the Late to Middle Jurassic source rock system in the South Viking Graben between 58°N and 60°15'N are highly variable both regionally and stratigraphically. In order to assess the degree of variability and to create a model of source rock quality and potential, isochore maps of the syn‐ and post‐rift sections of the Upper Jurassic Draupne Formation and underlying Heather Formation were generated from seismic and well data, and maturity‐corrected Rock‐Eval data were used to generate quantitative maps of oil and gas potential. The thin post‐rift section at the top of the Draupne Formation is a rich oil‐prone source, while the up to 1,600 m thick syn‐rift section contains a mixture of Type III and Type II material with substantial amounts of gas‐prone and inert organic matter. The Heather Formation, which reaches modelled thicknesses of up to 930 m, is a lean source and is generally gas‐prone. Detailed analyses and interpretations of biomarker and isotopic characteristics support this upward increase in oil‐prone Type II material. The analytical parameters include increasing relative amounts of C₂₇ regular steranes; decreasing ratios of C₃₀ moretane relative to C₃₀ hopane; and an increasing predominance of short chain n‐alkanes and progressively lighter isotopic values for saturate and aromatic fractions of source rock extracts. In addition, increasing amounts of 17α(H),21β(H)‐28,30‐bisnorhopane and decreasing amounts of C₃₄ homohopanes relative to C³⁵ homohopanes, as well as decreasing Pr/Ph ratios, suggest a general decrease in oxygenation upwards. Maps of average Pr/Ph ratios for the syn‐ and post‐rift Draupne Formation and for the Heather Formation are consistent with permanent water column stratification and gradual ascent of the O₂:H₂S interface from the Callovian to the Ryazanian. Interpretation of oil and gas potential maps, molecular parameters and estimates of sediment accumulation rates in combination suggest that the source facies of the upper, post‐rift Draupne Formation is controlled by widespread anoxia, reduced siliciclastic dilution and reduced input of gas‐prone organic and inert material; by contrast, the potential of the lower, syn‐rift Draupne Formation is strongly controlled by dilution by gas‐prone and inert organic matter resulting from mass flows and also by varying degrees of oxygenation. The oil and gas potential of the Heather Formation is mainly controlled by the degree of oxygenation and siliciclastic dilution.     

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.