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.     

Oil Families and Their Potential Sources in the Southern Gulf of Suez,Egypt

Abstract

Four oil families are identified in the southern Gulf of Suez, through high-resolution geochemical studies including gas chromatography, gas chromatography–mass spectrometry, and carbon isotope analyses. Biological features characterize oils in family 1a, suggesting tertiary carbonate source rocks for these oils, rich in type II organic matter and deposited under anoxic depositional environment. Family 1b oil shows minor variations in the source of organic matter and the depositional environment, as it was derived from carbonate source rock with more algal and bacterial contribution and minor input of terrestrial organic sources, deposited under less saline condition compared to family 1a oil. Family 2 oil, although genetically related to family 1a oil, has some distinctive features, such as diasterane to sterane and pristane to phytane ratios, which suggest clay-rich source rocks and a more oxic depositional environment. Also, the lack of oleanane indicates pre-tertiary source rocks for this oil. In contrast, family 3 oil is of mixed sources (marine and non-marine), generated from low sulfur and clay-rich source rock of tertiary and/or younger age. Family 4 oil seems to be mixed from family 1b and family 3 oils, sourced mainly from carbonate source rocks rich in clay minerals with algal and bacterial contributions. Family 4 oil is highly mature, family 1b oil lies within equilibrium values (peak oil generation stage), while the other families are more or less near equilibrium.     

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.     

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.     

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.     

Upper Cretaceous Duwi Formation shale’s oil potentiality Safaga-Quseir,Red Sea,Egypt

Duwi Formation shale deposits at Safaga – Quseir area were assessed by rock eval pyrolysis for its shale oil potentiality. The studied shale’s organic matter are mainly of type I, type II, mixed type I/II in addition to some of type III. The studied shale is described as very good source rock with total organic carbon (TOC?>?2?wt%). The kerogen maturation in the studied samples is immature according to PI and Tmax. Extracted shale oil from the studied samples as bitumen was fractionated by liquid chromatography (LG) into saturated hydrocarbon, aromatic hydrocarbon, resin and asphaltene. The saturated hydrocarbon was described by gas chromatography (GC), the pristane/phytane, isoprenoids/n-alkane and CPI ratios show that, samples were deposited in marine environment with some input of terrestrial environment and are characterized by immature level.The X-Ray Diffraction (XRD) analysis for the studied shale samples show their bulk minerals are mainly quartz, calcite, dolomite, gypsum, hematite and pyrite in addition to apatite and fluorapatite. While their clay minerals are mainly smectite and kaolinite. The chemical composition of the studied samples showed high concentration of trace elements such as Co, Cr, Cu, Ni, V and Zn which in turn through more lights on the depositional environment of the organic matter.     

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.     

Oil Families and Their Potential Sources in the Southern Gulf of Suez, Egypt

Four oil families are identified in the southern Gulf of Suez, through high-resolution geochemical studies including gas chromatography, gas chromatography-mass spectrometry, and carbon isotope analyses. Biological features characterize oils in family 1a, suggesting tertiary carbonate source rocks for these oils, rich in type II organic matter and deposited under anoxic depositional environment. Family 1b oil shows minor variations in the source of organic matter and the depositional environment, as it was derived from carbonate source rock with more algal and bacterial contribution and minor input of terrestrial organic sources, deposited under less saline condition compared to family 1a oil. Family 2 oil, although genetically related to family 1a oil, has some distinctive features, such as diasterane to sterane and pristane to phytane ratios, which suggest clay-rich source rocks and a more oxic depositional environment. Also, the lack of oleanane indicates pre-tertiary source rocks for this oil. In contrast, family 3 oil is of mixed sources (marine and non-marine), generated from low sulfur and clay-rich source rock of tertiary and/or younger age. Family 4 oil seems to be mixed from family 1b and family 3 oils, sourced mainly from carbonate source rocks rich in clay minerals with algal and bacterial contributions. Family 4 oil is highly mature, family 1b oil lies within equilibrium values (peak oil generation stage), while the other families are more or less near equilibrium.     

Hydrocarbon Source Rock Assessments of the Late Jurassic Black Shales (Tokmar Formation) in the Central Taurus Region of Turkey

Abstract

The hydrocarbon source rock potential and the thermal maturity of the Late Jurassic Tokmar Formation in the Bo?untu area of the central Taurus region have been investigated. Tokmar Formation includes organic matter–rich dark grey shales alternating with carbonates that were deposited under dysoxic to anoxic marine conditions prevailed in the Late Jurassic. A total of 14 samples have been analyzed by Leco and Rock-Eval pyrolysis for determination of their hydrocarbon source rock characteristics and organic maturity. The total organic carbon content of the samples range from 0.26 to 1.53 wt%. The actual Rock-Eval pyrolytic yields (S₁ + S₂ peak values) are between 0.25 and 3.63 mg HC/g rock. The calculated hydrogen index and oxygen index values imply that the main organic matter types are Type II and Type III kerogens. T_max versus hydrogen index values indicate that the Bo?untu samples are thermally mature and took place in the oil generation window.     

COMPOSITION AND PETROLEUM POTENTIAL OF LAKE FACIES IN THE FA-MS-48-73 WELL, MAE SOON STRUCTURE, FANG OILFIELD, NORTHERN THAILAND

The Fang Basin is one of a series of Cenozoic rift‐related structures in northern Thailand. The Fang oilfield includes a number of structures including the Mae Soon anticline on which well FA‐MS‐48‐73 was drilled, encountering oil‐filled sandstone reservoirs at several levels. Cuttings samples were collected from the well between depths of 532 and 1146 m and were analysed for their content of total organic carbon (TOC, wt%), total carbon (TC, wt%) and total sulphur (TS, wt%); the petroleum generation potential was determined by Rock‐Eval pyrolysis. Organic petrography was performed in order to determine qualitatively the organic composition of selected samples, and the thermal maturity of the rocks was established by vitrinite reflectance (VR) measurements in oil immersion. The TOC content ranges from 0.75 to 2.22 wt% with an average of 1.43 wt%. The TS content is variable with values ranging from 0.12 to 0.63 wt%. Rock‐Eval derived S₁ and S₂ yields range from 0.01–0.20 mg HC/g rock and 1.41–9.51 mg HC/g rock, respectively. The HI values range from 140 to 428 mg HC/g TOC, but the majority of the samples have HI values >200 mg HC/g TOC and about one‐third of the samples have HI values above 300 mg HC/g TOC. The drilled section thus possesses a fair to good potential for mixed oil/gas and oil generation. On an HI/T_max diagram, the organic matter is classified as Type II and III kerogen. The organic matter consists mainly of telalginite (Botryococcus‐type), lamalginite, fluorescing amorphous organic matter (AOM) and liptodetrinite which combined with various TS‐plots suggest deposition in a freshwater lacustrine environment with mild oxidising conditions. T_max values range from 419 to 436°C, averaging 429°C, and VR values range from ～0.38 to 0.66% R₀, indicating that the drilled source rocks are thermally immature with respect to petroleum generation. The encountered oils were thus generated by more deeply buried source rocks.     

BIOMARKER GEOCHEMISTRY OF PALEOGENE CRUDE OILS AND SOURCE ROCKS FROM THE RAOYANG SAG,BOHAI BAY BASIN,NE CHINA: AN OIL – SOURCE ROCK CORRELATION STUDY

This study presents a systematic geochemical analysis of Paleogene crude oils and source rocks from the Raoyang Sag in the Jizhong sub-basin of the Bohai Bay Basin (NE China). The geochemical characteristics of fifty-three oil samples from wells in four sub-sags were analysed using gas chromatography (GC) and gas chromatography – mass spectrometry (GC-MS). Twenty core samples of mudstones from Members 1 and 3 of the Eocene-Oligocene Shahejie Formation were investigated for total organic carbon (TOC) content and by Rock-Eval pyrolysis and GC-MS to study their geochemistry and hydrocarbon generation potential. The oils were tentatively correlated to the source rocks. The results show that three groups of crude oils can be identified. Group I oils are characterized by high values of the gammacerane index and low values of the ratios of Pr/Ph, Ts/Tm, 20S/(20S+20R) C₂₉ steranes, ββ/(ββ+αα) C₂₉ steranes, C₂₇ diasteranes/ C₂₇ regular steranes and C₂₇/C₂₉ steranes. These oils have the lowest maturity and are interpreted to have originated from a source rock containing mixed organic matter deposited in an anoxic saline lacustrine environment. The biomarker parameter values of Group III oils are the opposite to those in Group I, and are interpreted to indicate a highly mature, terrigenous organic matter input into source rocks which were deposited in suboxic to anoxic freshwater lacustrine conditions. The parameter values of Group II oils are between those of the oils in Groups I and III, and are interpreted to indicate that the oils were generated from mixed organic matter in source rocks deposited in an anoxic brackish–saline or saline lacustrine environment. The results of the source rock analyses show that samples from Member 1 of the Shahejie Formation were deposited in an anoxic, brackish – saline or saline lacustrine environment with mixed organic matter input and are of low maturity. Source rocks in Member 3 of the Shahejie Formation were deposited in a suboxic to anoxic, brackish – saline or freshwater lacustrine environment with a terrigenous organic matter input and are of higher maturity. Correlation between rock samples and crude oils indicates that Group I oils were probably derived from Member 1 source rocks, while Group III oils were more likely generated by Member 3 source rocks. The Group II oils with transitional characteristics are likely to have a mixed source from both sets of source rocks.     

Petroleum Source Rock Characteristics of the Lower Tertiary Formations in the Ereğli-Ulukışla Basin,Southern Central Anatolia,Turkey

Abstract

Potential source rocks in the Ere?li-Uluk??la basin include Campanian-Maastrichtian limestones and marls, Upper Paleocene-Lower Eocene deep-marine shales, and Middle-Upper Eocene continental slope deposits, including shales and sandstones. Organic geochemical analyses and palynofacies observations show that the organic components in Upper Paleocene-Upper Eocene sediments are mainly coaly and woody, with minor herbaceous and algal-amorphous-like organic matter, indicating that they are terrigenous (mainly Type III and Type IV kerogen). The organic carbon content of these rocks ranges from 0.04 to 0.73%, and they have marginal source rock quality for oil generation. A plot of HI versus T-max values implies that the Upper Paleocene-Lower Eocene samples are in the early stage of oil generation, while the Middle-Upper Eocene samples are thermally immature. The pristane/phytane ratio for Tertiary samples corresponds to a transition from anoxic to oxic depositional conditions.     

Investigating Geochemical Characterization of Asmari and Bangestan Reservoir Oils and the Source of H2S in the Marun Oilfield

Abstract

Geochemical evaluation is one of the most important and applicable methods for optimization of hydrocarbon exploration and production. In this article, the geochemistry of Asmari and Bangestan reservoir oils of Marun oil field was experimentally studied. Marun oil field is one of the giant oil fields in southwest Iran and has two oil reservoirs (Asmari and Bangestan) and one gas reservoir (Khami). The main goal of this study is to investigate the genetic behavior of the above oil reservoirs, focusing mainly on hydrogen sulfide pollutants. Biomarkers of saturated and aromatic fractions were studied on five polluted, three unpolluted Asmari, and two Bangestan reservoir oils. A triangular diagram was used to determine the chemical composition of the studied oil. The results show relatively higher oil maturity for both reservoirs with no biodegradation. The carbon preference index of both reservoir oils was also around 1, which indicates mature oil samples. The pristane-to-phytane ratio, Pri/nC₁₇ versus Phy/nC₁₈, terrigenous/aquatic ratio (TAR), and geochemical data all show that the source rock for both Asmari and Bangestan reservoirs is the same. This source rock was deposited in a reducing environment with algae (kerogen type II) organic matter and without any higher plants. Genetic potential studies of probable source rocks, by means of Rock-Eval VI analysis in Marun oilfield, present Kazhdomi and Garu as main source rocks. Biomarkers of sulfur compounds and structural analysis of Marun oil field revealed that hydrogen sulfide gas pollution in the Asmari reservoir originated from the Bangestan reservoir. In addition, thermal sulfate reduction was a possible main process for hydrogen sulfide formation.     

Source rock evaluation of some upper and lower Cretaceous sequences,West Beni Suef Concession,Western Desert,Egypt

West Beni Suef Concession is located at the western part of Beni Suef Basin which is a relatively under-explored basin and lies about 150 km south of Cairo. The major goal of this study is to evaluate the source rock by using different techniques as Rock-Eval pyrolysis, Vitrinite reflectance (%Ro), and well log data of some Cretaceous sequences including Abu Roash (E, F and G members), Kharita and Betty formations. The BasinMod 1D program is used in this study to construct the burial history and calculate the levels of thermal maturity of the Fayoum-1X well based on calibration of measured %Ro and T_max against calculated %Ro model. The calculated Total Organic Carbon (TOC) content from well log data compared with the measured TOC from the Rock-Eval pyrolysis in Fayoum-1X well is shown to match against the shale source rock but gives high values against the limestone source rock. For that, a new model is derived from well log data to calculate accurately the TOC content against the limestone source rock in the study area. The organic matter existing in Abu Roash (F member) is fair to excellent and capable of generating a significant amount of hydrocarbons (oil prone) produced from (mixed type I/II) kerogen. The generation potential of kerogen in Abu Roash (E and G members) and Betty formations is ranging from poor to fair, and generating hydrocarbons of oil and gas prone (mixed type II/III) kerogen. Eventually, kerogen (type III) of Kharita Formation has poor to very good generation potential and mainly produces gas. Thermal maturation of the measured %Ro, calculated %Ro model, T_max and Production index (PI) indicates that Abu Roash (F member) exciting in the onset of oil generation, whereas Abu Roash (E and G members), Kharita and Betty formations entered the peak of oil generation.     

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.     

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.     

SOURCE ROCK PROPERTIES OF LACUSTRINE MUDSTONES AND COALS (OLIGOCENE DONG HO FORMATION), ONSHORE SONG HONG BASIN, NORTHERN VIETNAM

Oligocene lacustrine mudstones and coals of the Dong Ho Formation outcropping around Dong Ho, at the northern margin of the mainly offshore Cenozoic Song Hong Basin (northern Vietnam), include highly oil‐prone potential source rocks. Mudstone and coal samples were collected and analysed for their content of total organic carbon and total sulphur, and source rock screening data were obtained by Rock‐Eval pyrolysis. The organic matter composition in a number of samples was analysed by reflected light microscopy. In addition, two coal samples were subjected to progressive hydrous pyrolysis in order to study their oil generation characteristics, including the compositional evolution in the extracts from the pyrolysed samples. The organic material in the mudstones is mainly composed of fluorescing amorphous organic matter, liptodetrinite and alginite with Botryococcus‐morphology (corresponding to Type I kerogen). The mudstones contain up to 19.6 wt.% TOC and Hydrogen Index values range from 436–572 mg HC/g TOC. From a pyrolysis S₂ versus TOC plot it is estimated that about 55% of the mudstones’TOC can be pyrolised into hydrocarbons; the plot also suggests that a minimum content of only 0.5 wt.% TOC is required to saturate the source rock to the expulsion threshold. Humic coals and coaly mudstones have Hydrogen Index values of 318–409 mg HC/g TOC. They are dominated by huminite (Type III kerogen) and generally contain a significant proportion of terrestrial‐derived liptodetrinite. Upon artificial maturation by hydrous pyrolysis, the coals generate significant quantities of saturated hydrocarbons, which are probably expelled at or before a maturity corresponding to a vitrinite reflectance of 0.97%R₀. This is earlier than previously indicated from Dong Ho Formation coals with a lower source potential. The composition of a newly discovered oil (well B10‐STB‐1x) at the NE margin of the Song Hong Basin is consistent with contributions from both source rocks, and is encouraging for the prospectivity of offshore half‐grabens in the Song Hong Basin.     

确定烃源岩有效排烃总有机碳阈值的方法及应用

针对油气地质学中排烃源岩难以识别的问题,依据生排烃原理,利用常规烃源岩有机碳和热解（Rock-Eval）分析测试参数,建立了判别排烃源岩的实用方法。该方法主要基于生烃量参数[I_HC=S₁/w（TOC）]和沥青转化率[w（A）/w（TOC）],判别排烃源岩的总有机碳阈值,高于该值的烃源岩即为排烃源岩。根据分析测试资料,对准噶尔盆地和三塘湖盆地二叠系芦草沟组、酒泉盆地营尔凹陷和青西凹陷白垩系下沟组以及鄂尔多斯盆地上三叠统延长组长7段的排烃源岩进行判别,判别效果较好,应用该方法时要求烃源岩的母质特征与热演化程度接近。由于气态烃易散失,所以采用的参数主要反映烃源岩中生成的液态烃量。该方法对于油源岩的判别更为有效。      

ORGANIC GEOCHEMISTRY OF POTENTIAL SOURCE ROCKS IN THE TERTIARY DINGQINGHU FORMATION,NIMA BASIN,CENTRAL TIBET

The Tertiary Nima Basin in central Tibet covers an area of some 3000 km² and is closely similar to the nearby Lunpola Basin from which commercial volumes of oil have been produced. In this paper, we report on the source rock potential of the Oligocene Dingqinghu Formation from measured outcrop sections on the southern and northern margins of the Nima Basin. In the south of the Nima Basin, potential source rocks in the Dingqinghu Formation comprise dark‐coloured marls with total organic carbon (TOC) contents of up to 4.3 wt % and Hydrogen Index values (HI) up to 849 mg HC/g TOC. The organic matter is mainly composed of amorphous sapropelinite corresponding to Type I kerogen. Rock‐Eval T_max (430–451°C) and vitrinite reflectance (R_r) (average R_r= 0.50%) show that the organic matter is marginally mature. The potential yield (up to 36.95 mg HC/g rock) and a plot of S2 versus TOC suggest that the marls have moderate to good source rock potential. They are interpreted to have been deposited in a stratified palaeolake with occasionally anoxic and hypersaline conditions, and the source of the organic matter was dominated by algae as indicated by biomarker analyses. Potential source rocks from the north of the basin comprise dark shales and marls with a TOC content averaging 9.7 wt % and HI values up to 389 mg HC/g TOC. Organic matter consists mainly of amorphous sapropelinite and vitrinite with minor sporinite, corresponding to Type II‐III kerogen. This is consistent with the kerogen type suggested by cross‐plots of HI versus T_max and H/C versus O/C. The T_max and R_r results indicate that the samples are immature to marginally mature. These source rocks, interpreted to have been deposited under oxic conditions with a dominant input of terrigenous organic matter, have moderate petroleum potential. The Dingqinghu Formation in the Nima Basin therefore has some promise in terms of future exploration potential.     

Geochemistry,generation and maturation of the hydrocarbons at Wadi Al-Rayan oil field,Western Desert of Egypt

`The present work aims to study the organic chemistry, the generation and maturation of the hydrocarbons encountered at Abu Roash Formation, Wadi El Rayan oil field. The analysis of source rocks indicates the presence of two organic facies. The first is characterized by high total organic carbon of 0.93–3.39%, strongly oil-prone (Type II), and good potential for oil generation (pyrolysis S2 yields 4.54–23.26 mg HC/g rock and HI 488–705 mg HC/g TOC). The second attains good range of organic carbon from 0.90% to 1.57%, which is a mixed oil and gas (Type II–Type III) of fair hydrocarbon generation (pyrolysis S2 yield of 1.98–5.33 mg HC/g). The kerogen type consists of unstructured lipids and some terrestrial material. Plot of Pr/n-C17 versus Ph/n-C18 indicates that the crude oil was derived from mixed source rock, while the maturity profile assigns oil windows (0.6 R_o%) matching topmost of Abu Roash G Member.