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.     

ORGANIC GEOCHEMISTRY OF OIL AND NATURAL GAS IN THE WEST DIKIRNIS AND EL‐TAMAD FIELDS,ONSHORE NILE DELTA,EGYPT: INTERPRETATION OF POTENTIAL SOURCE ROCKS

Crude oil in the West Dikirnis field in the northern onshore Nile Delta, Egypt, occurs in the poorly‐sorted Miocene sandstones of the Qawasim Formation. The geochemical composition and source of this oil is investigated in this paper. The reservoir sandstones are overlain by mudstones in the upper part of the Qawasim Formation and in the overlying Pliocene Kafr El‐Sheikh Formation. However TOC and Rock‐Eval analyses of these mudstones indicate that they have little potential to generate hydrocarbons, and mudstone extracts show little similarity in terms of biomarker compositions to the reservoired oils. The oils at West Dikirnis are interpreted to have been derived from an Upper Cretaceous – Lower Tertiary terrigenous, clay‐rich source rock, and to have migrated up along steeply‐dipping faults to the Qawasim sandstones reservoir. This interpretation is supported by the high C₂₉/C₂₇ sterane, diasterane/sterane, hopane/sterane and oleanane/C₃₀ hopane ratios in the oils. Biomarker‐based maturity indicators (Ts/Tm, moretanes/hopanes and C₃₂ homohopanes S/S+R) suggest that oil expulsion occurred before the source rock reached peak maturity. Previous studies have shown that the Upper Cretaceous – Lower Tertiary source rock is widely distributed throughout the on‐ and offshore Nile Delta. A wet gas sample from the Messinian sandstones at El‐Tamad field, located near to West Dikirnis, was analysed to determine its molecular and isotopic composition. The presence of isotopically heavy δ¹³ methane, ethane and propane indicates a thermogenic origin for the gas which was cracked directly from a humic kerogen. A preliminary burial and thermal history model suggests that wet gas window maturities in the study area occur within the Jurassic succession, and the gas at El‐Tamad may therefore be derived from a source rock of Jurassic age.     

WORLD‐CLASS PALEOGENE OIL‐PRONE SOURCE ROCKS FROM A CORED LACUSTRINE SYN‐RIFT SUCCESSION,BACH LONG VI ISLAND,SONG HONG BASIN,OFFSHORE NORTHERN VIETNAM

Oil‐prone source rocks occurring in lacustrine syn‐rift successions have generated significant amounts of hydrocarbons in many Cenozoic basins in SE Asia. As most exploration wells are located on structural highs, the source rock successions are seldom drilled and their initial composition and generation potential are poorly known. The inverted Bach Long Vi Graben is located at the intersection of the NW–SE trending Song Hong Basin (Yinggehai Basin) and the NE–SW trending Beibuwan Basin in the Gulf of Tonkin, offshore northern Vietnam. The uppermost part of the inverted graben is exhumed and exposed on Bach Long Vi island. In order to investigate the amount and source rock quality of the syn‐rift mudstones, the ENRECA‐3 well was drilled on the island and cored some 500 m of the syn‐rift succession. The well provided excellent cores with a recovery of 99%, dominated by lacustrine mudstones interbedded with various gravity flow deposits. Organic petrography shows that the mudstones are thermally immature and contain sapropelic Type I and mixed Types I and III kerogen. Source rock screening data from more than 300 samples demonstrate that the lacustrine source rocks have an average TOC content of 2.88 wt% and an average Hydrogen Index of 566 mg HC/g TOC. The average Hydrogen Index of the reactive kerogen was determined to be 769 mg HC/g TOC. The Source Potential Index (SPI) is 9 tons HC/m² and the mudstones will, upon full maturation, generate black oil with a gas‐liquid ratio not exceeding ～1700 scf/stb. The mudstones are thus highly oil‐prone. In addition, several tens of metres of source rock within the overlying succession are exposed on Bach Long Vi island and in the surrounding seafloor, and the well did not reach the base of the source rock succession. Although the net‐source rock thickness of the ENRECA‐3 well is estimated to be 233 m, the net thickness of the entire source rock succession will be greater. The present study is the first organic geochemical assessment of a thick lacustrine source rock section in the petroliferous NE Song Hong Basin, and the promising results may be applied not only to other parts of the basin but also to other Cenozoic basins with syn‐rift successions containing significant source rock intervals.     

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.     

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

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

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.     

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.     

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.     

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.     

ORGANIC AND INORGANIC GEOCHEMICAL AND MINERALOGICAL ASSESSMENTS OF THE SILURIAN AKKAS FORMATION,WESTERN IRAQ

The Silurian Akkas Formation has been reported and described only in the subsurface of western Iraq. The formation is divided into the lower Hoseiba Member, which contains two high‐TOC “hot” shale intervals that together are around 60 m thick, and the overlying Qaim Member that is composed of lower‐TOC “cold” shales. This study investigates the source rock potential of Akkas Formation shales from the Akkas‐1and Akkas‐3 wells in western Iraq and assesses the relationship between their mineral and elemental contents and their redox depositional conditions and thermal maturity. Twenty‐six shale samples from both members of the Akkas Formation from the Akkas‐1and Akkas‐3 wells were analysed. The results showed that the upper, ~20 m thick“hot” shale interval in the lower Hoseiba Member has good source rock characteristics with an average TOC content of 5.5 wt% and a mean Rock‐Eval S₂ of 10 kg/tonne. Taken together, the two “hot” shale intervals and the intervening “cold” shale of the Hoseiba Member are ~125‐150 m thick and have an average TOC of 3.3 wt% and mean S₂ of 6.2 kg/tonne. The samples from the Hoseiba Member contain mixed Type II / III or Type III kerogen with an HI of up to 296 mgS₂/gTOC. Visual organic‐matter analysis showed that the samples contain dark brown, opaque amorphous organic matter with minor amounts of vitrinite‐like and algal (Tasmanites) material. Pyrolysis – gas chromatography undertaken on a single sample indicated a mature (or higher) algal‐dominated Type II kerogen. High spore and acritarch colour index values and weak or absent fluorescence similarly suggest that the lower part of the Akkas Formation is late mature to early post‐mature for oil generation. “Cold” shales from the Qaim Member in the Akkas‐3 well may locally have good source rock potential, while samples from the upper part of the Qaim Member from the Akkas‐1 well have little source rock potential. Varied results from this interval may reflect source rock heterogeneity and limited sample coverage. Mineralogically, all the shale samples studied were dominated by clay minerals – illite and kaolinite with minor amounts of chlorite and illite mixed layers. Non‐clay minerals included quartz, carbonates, feldspars and pyrite along with rare apatite and anatase. Palaeoredox proxies confirmed the general link between anoxia and “hot” shale deposition; however, there was no clear relationship between TOC and U suggesting that another carrier of U could be present. Rare Earth Element (REE) contents suggested a slight change in sediment provenance during the deposition of the Akkas Formation. The presence of common micropores and fractures identified under SEM indicates that these shales could become potential unconventional reservoirs following hydraulic fracturing. Evidence for the dissolution of carbonate minerals was present along fractures, suggesting the possible passage of diagenetic fluids. Palynological analysis combined with existing graptolite studies support a Wenlock ‐ Pridoli/Ludlow age for the Akkas “hot”shales. This is younger than many other regional “hot shale” age estimates and warrants further detailed investigation.     

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.     

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.     

HYDROCARBONS IN THE MIDDLE MIOCENE JERIBE FORMATION,DYALA REGION,NE IRAQ

The Lower Miocene Jeribe Formation in northern and NE Iraq is composed principally of dolomitic limestones with typical porosity in the range of 10–24% and mean permeability of 30 mD. The formation serves as a reservoir for oil and gas at the East Baghdad field, gas at Mansuriya, Khashim Ahmar, Pulkhana and Chia Surkh fields, and oil at Injana, Gillabat, Qumar and Jambur. A regional seal is provided by the anhydrites of the Lower Fars (Fat'ha) Formation. For this study, oil samples from the Jeribe Formation at Jambur oilfield, Oligocene Baba Formation at Baba Dome (Kirkuk field) and Late Cretaceous Tanuma and Khasib Formations at East Baghdad field were analysed in order to investigate their genetic relationships. Graphical presentation of the analytical results (including plots of pristane/nC₁₇ versus phytane/nC_l8, triangular plots of steranes, tricyclic terpane scatter plots, and graphs of pristanelphytane versus carbon isotope ratio) indicated that the oils belong to a single oil family and are derived from kerogen Types II and III. The oils have undergone minor biodegradation and are of high maturity. They were derived from marine organic matter deposited with carbonate‐rich source rocks in suboxic‐anoxic settings. A range of biomarker ratios and parameters including a C₂₈/ C₂₉ sterane ratio of 0.9, an oleanane index of 0.2 and low tricyclic terpane values indicate a Late Jurassic or Early Cretaceous age for the source rocks, and this age is consistent with palynomorph analyses. Potential source rocks are present in the Upper Jurassic – Lower Cretaceous Chia Gara Formation and the Middle Jurassic Sargelu Formation at the Jambur, Pulkhana, Qumar and Mansuriya fields; minor source rock intervals occur in the Balambo and Sarmord Formations. Hydrocarbon generation and expulsion from the Chia Gara Formation was indicated by pyrolysate organic matter, palynofacies type (A), and the maturity of Gleichenidites spores. Oil migration from the Chia Gara Formation source rocks (and minor oil migration from the Sargelu Formation) into the Jeribe Formation reservoirs took place along steeply‐dipping faults which are observed on seismic sections and which cut through the Upper Jurassic Gotnia Anhydrite seal. Migration is confirmed by the presence of asphalt residues in the Upper Cretaceous Shiranish Formation and by a high migration index (Rock Eval SI / TOC) in the Chia Gara Formation. These processes and elements together form a Jurassic/Cretaceous – Tertiary petroleum system whose top‐seal is the Lower Fars (Fat'ha) Formation anhydrite.     

Comparison of Mississippian Barnett Shale,Northern-Central Texas,USA and Silurian Dadas Formation in Southeast Turkey

The organic-rich Barnett Shale is the primary source rock and the main unconventional reservoir in the Fort Worth Basin, Texas. The Early Silurian-Early Devonian Dadas Formation is one of the main source rocks in southeastern Turkey and it is the Turkish equivalent of Silurian hot shales in the Middle East and North Africa. In this study, similarities and differences between the Dadas Formation and the Barnett Shale are presented to indicate the unconventional reservoir potential of the Dadas Formation which covers similar acreage of the Barnett Shale. Main factors that form the basis for comparison are: depositional environment, tectonic setting, thickness, depth, organic geochemical properties and thermal maturity. Both formations have similar depositional environment and they have organic-rich, basal hot shale units indicated by a high gamma-ray log response. Thicknesses of both formations are appropriate to perform horizontal drilling and hydraulic fracturing, however, the Dadas is thicker than the Barnett Shale. Both formations have high Total Organic Carbon (TOC) and Potential Yield (S₁ + S₂) values. Both formations have gas prone and oil prone regions. However, the gas prone zone of the Barnett is larger. The Dadas Formation is penetrated by only a limited number of wells in comparison to the Barnett Shale. In contrast to the Barnett Shale, which is mainly in the gas zone in the Fort Worth Basin, the Dadas Formation is deeper, and is generally in the oil window.     

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.     

DEPOSITIONAL ENVIRONMENT AND SOURCE‐ROCK CHARACTERISATION OF ORGANIC‐MATTER RICH UPPER SANTONIAN – UPPER CAMPANIAN CARBONATES,NORTHERN LEBANON

Samples of Turonian – upper Campanian fine‐grained carbonates (marls, mud‐ to wackestones; n = 212) from four boreholes near Chekka, northern Lebanon, were analysed to assess their organic matter quantity and quality, and to interpret their depositional environment. Total organic carbon (TOC), total inorganic carbon and total sulphur contents were measured in all samples. A selection of samples were then analysed in more detail using Rock‐Eval pyrolysis, maceral analyses, gas chromatography – flame ionization detection (GC‐FID), and gas chromatography – mass spectrometry (GC‐MS) on aliphatic hydrocarbon extracts. TOC measurements and Rock‐Eval pyrolysis indicated the very good source rock potential of a ca. 150 m thick interval within the upper Santonian – upper Campanian succession intercepted by the investigated boreholes, in which samples had average TOC values of 2 wt % and Hydrogen Index values of 510 mgHC/gTOC. The dominance of alginite macerals relative to terrestrial macerals, the composition of C₂₇–C₂₉ regular steranes, the elevated C₃₁ 22R homohopane / C₃₀ hopane ratio (> 0.25), the low terrigenous / aquatic ratio of n‐alkanes, as well as δ¹³C_org values between ?29‰ and ?27‰ together suggest a marine depositional environment and a mainly algal / phytoplanktonic source of organic matter. Redox sensitive geochemical parameters indicate mainly dysoxic depositional conditions. The samples have high Hydrogen Index values (413–610 mg/g TOC) which indicate oil‐prone Type II kerogen. T_max values (414 – 432°C) are consistent with other maturity parameters such as vitrinite reflectance (0.25–0.4% VRr) as well as sterane and hopane isomerisation ratios, and indicate that the organic matter is thermally immature and has not reached the oil window. This study contributes to the relatively scarce geochemical information for the eastern margin of the Levant Basin, but extrapolation of the data to offshore areas remains uncertain.     

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     

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.     

MONITORING GAS DISTRIBUTION AND ORIGIN IN THE CULZEAN FIELD,UK CENTRAL NORTH SEA,USING DATA FROM A CONTINUOUS ISOTOPE LOGGING TOOL AND ISOTUBE AND TEST SAMPLES

The high pressure – high temperature Culzean field, UK Central North Sea, contains lean gas condensate in the Triassic Joanne sandstones and the Middle Jurassic Pentland sandstones. A comprehensive gas analysis programme was installed as an integrated part of field development in order to monitor gas composition, distribution and origin in the reservoirs and overburden pre‐ production start‐up. Isotube OUT and isotube IN gas samples were collected. The isotube IN data show that some gas is recycled, including alkenes representing contamination from the degradation of mud additives; but concentrations are minor, and do not seem to affect the isotope values derived from the C₂ and C₃ isotube OUT gases significantly. ¹³C‐enriched methane derived from drill‐bit metamorphism is recorded in the isotube IN gas, but likewise in low concentrations. Gas data were also acquired from a Continuous Isotope Logging Tool (CILT) which measures real‐time gas concentrations and isotope values of C₁–C₃ each foot through the entire drilled section. The CILT thus provides a continuous trend of methane isotope values versus depth, and this trend is useful in identifying changes in gas composition. However, concerns related to CILT include: (i) C₁–C₃ stable carbon isotope detection limits for isotube OUT gas analyses are considerable lower than for CILT; due to the lower isotube gas concentrations required for measurement of C₃ isotopes, isotubes are able to map a shallower vertical thermogenic gas migration front in the overburden. (ii) Discrepancies between isotube OUT and CILT isotope values may be significant and cannot be assigned to analytical uncertainty; by contrast, test gas and isotube OUT isotope values are comparable. Hence, CILT isotope values from specific depths cannot stand in isolation but must be complemented by isotube OUT isotope measurements. Gas in the Pentland reservoir is the most coaly in composition due to self‐sourcing from the Pentland coals. The coals are the primary source rock for the gas encountered in the entire reservoir interval at Culzean, but the underlying Joanne sandstones contain contributions from highly mature marine shales in the Kimmeridge Clay Formation and/or Heather Formation. The Lower Cretaceous seal on top of the Pentland reservoir is relatively tight but some minor migration/leakage of thermogenic gas into the overburden is recorded by the detection of C₃ isotopes. Thermogenic gas also occurs in high porosity intervals in the Upper Cretaceous succession but this gas is interpreted to have migrated laterally in porous carrier beds and did not enter these intervals at the well locations.     

GEOCHEMICAL CHARACTERISTICS OF THE SKRUGARD OIL DISCOVERY,BARENTS SEA,ARCTIC NORWAY: A “PALAEO‐BIODEGRADED – GAS REACTIVATED” HYDROCARBON ACCUMULATION

This paper investigates the filling history of the Skrugard and Havis structures of the Johan Castberg field in the Polheim Sub‐Platform and Bjørnøyrenna Fault Complex, Barents Sea (Arctic Norway). Oil and gas occurs in the Early Jurassic and Middle Jurassic Nordmela and Stø Formations at Johan Castberg, and both free oil and bitumen are interpreted to be sourced from the Upper Jurassic Hekkingen Formation (Kimmeridge Formation equivalent). The geochemical characteristics of the petroleum from Skrugard and Havis, including the GOR, API and facies and maturity signatures, can be understood within a complex fill history which includes a palaeo oil charge, Tertiary uplift (>2 km), dismigration, in‐reservoir biodegradation, and late‐stage refill with gas. The API and GOR of the Skrugard oil are 31° and 60m³/m³, respectively. The petroleum is geochemically similar to that in the nearby Havis structure, to that in the Snøhvit region to the south of the Loppa High, and also to the petroleum recorded as traces in well 7219/9‐1, approximately 16 km SW of Johan Castberg field. However, the petroleum differs from the oil in the Alta well 7120/2‐1, located in the southern part of the Loppa High, illustrating the complexity of the regional petroleum systems. The Skrugard oil is of medium maturity (ca. 0.8–0.9% R_c), and is significantly biodegraded despite being gas‐saturated. Evidence for biodegradation includes the reduced concentrations of C₁₀‐C₂₅ n‐alkanes and the presence of a prominent unresolved complex mixture (UCM) in gas chromatogram traces. However non‐biodegraded C₄‐C₈ range hydrocarbons are also present in the reservoir. This suggests a recent charge of gas/condensate into the structure which therefore contains a mixture of palaeo‐degraded and unaltered petroleum. Oil‐type inclusions within authigenic quartz and feldspar from reservoir sandstones at Skrugard were analysed. The results indicate that the structure (present‐day depth 1276–1395m) underwent Tertiary uplift by ca. 2–3km following an earlier phase of oil emplacement. The presence of the oil type inclusions, both in the current gas zone (Stø Formation) and in the oil zone (Stø and Nordmela Formations), indicates that the positions of the oil‐water and gas‐oil contacts have changed over time. This is consistent with a recent gas charge to the upper part of the reservoir, and also with the gas being at dew point. These observations are supported by analyses of core extracts which show an increasing bitumen content towards the OWC, and the oil‐type bitumen in the present‐day gas zone. A charge history model for the Skrugard structure is proposed which integrates both the observations concerning the petroleum inclusions and the biodegraded oil together with observations of seismically‐monitored gas fluxes along the rim of the Loppa High. Improved understanding of the Skrugard structure and its filling history will assist exploration in similar settings in other parts of the Barents Sea and worldwide, particularly where multiple source rocks and a multi‐stage charge history have controlled reservoir filling.