Mature Stage Of Hydrocarbon Generation Research Articles

Sedimentary Facies, Palynology, and Organic Geochemistry of Eocene Kalumpang Formation in Lariang and Karama Areas, West Sulawesi, Indonesia

The Kalumpang Formation was deposited in a delta plain setting. A Middle to Late Eocene age (Proxapertites operculatus zone) was inferred from palynological analysis, with a paleoenvironment in a coastal plain setting with a strong terrestrial influence. Samples from the Kalumpang Formation indicate a marginal to early mature stage for hydrocarbon generation. It is mostly composed of gas-prone to oil and gas-prone Type III kerogen facies. The biomarker character of both the rock and oil samples suggests a terrestrial origin, with a significant contribution of estuarine or bay organic material. The oil derives from a non-carbonate lithology, while the rock samples are from carbonate/calcareous shale origin. The abundance of oleanane compound and C30 resins suggests higher plant angiosperm input of Late Cretaceous or younger age for both the rock and the oil samples. The oil seep contains more abundant oleananes compared to the carbonaceous mudstone of the Kalumpang Formation. This suggests that the oil originated from more marine facies than the rock samples, which were deposited in a delta plain setting. This study demonstrated the agreement of depositional environment interpretation and age assessment between lithofacies, palynological, and organic geochemistry analysis.

Organic Geochemical Characteristics and Organic Matter Enrichment of the Upper Permian Longtan Formation Black Shale in Southern Anhui Province, South China.

Although previous studies have yielded valuable insights into shale gas reservoirs, a comprehensive understanding of the organic geochemical characteristics and organic matter enrichment of marine-continental transitional shale has yet to be achieved. The Longtan Formation transitional shales were extensively deposited in Southern Anhui Province, South China, during the Late Permian. Our analysis of twenty-two rock samples from one core (Gangdi-1 well) and two outcrops (Daoshanchong outcrop and Changqiao outcrop) revealed that the Longtan Formation shale extracts exhibit a wide range of C11-C35n-alkanes and acyclic isoprenoids, with unimodal, bimodal, and multimodal distributions. The carbon peak ranges from nC15 to nC24, with high quantities of medium-chain n-alkanes (nC22-nC25), indicating that the organic matter in Longtan Formation shale originates from a mixed source of higher plant debris and lower aquatic organisms. Our conclusion is supported by the ternary diagram of C27-C28-C29 regular steranes and the variations of the δ13C values of C15-C32n-alkanes, which is higher than the corresponding value (<1.6‰) of n-alkanes from a single source. Furthermore, thermal maturity proxies based on organic petrography (Ro and Tmax) and biomarkers, such as the ratios of C31 22S/(22S + 22R), C29 20S/(20S + 20R), and C29 ββ/(αα + ββ), suggest that organic matter is in a mature stage of hydrocarbon generation. By analyzing the Pr/Ph ratio and pyrite morphology combined with a plot of total organic carbon (TOC) versus total sulfur (TS) and the Pr/nC17-Ph/nC18 diagram, we speculate that the Longtan Formation shales were chiefly developed in a dysoxic-to-oxic water environment. Finally, we establish depositional models of organic matter enrichment in deltaic and tidal flat-lagoon environments, emphasizing that the abundant mixed-sourced organic matter can significantly enhance primary productivity, and a higher sedimentation rate can distinctly shorten organic matter exposure time in the oxidized water environment, thereby promoting organic matter accumulation in such a setting.

Application of biomarkers in characterization of organic matter source, maturity and palaeoredox condition of black shales from the upper Permian Dalong Formation in Southern Anhui Province, South China

The organic‐rich shale in the upper Permian Dalong Formation in Southern Anhui Province is not only regarded as a high‐quality hydrocarbon source rock, but one of the potential targets for shale oil and gas exploration in Southern China. Organic matter types in such a setting remain a subject of debate. The major point of controversy is whether they are dominated by oil‐prone types or gas‐prone types. A total of 20 rock samples collected from Gangdi‐1 well were conducted for analysis of organic geochemistry. Results show that Dalong Formation shale extracts exhibit a wide range of C12‐C35 n‐alkanes and acyclic isoprenoids. The chromatograms display an unimodal distribution with carbon peak in the range of nC18‐nC22 and low quantities of long‐chain (nC25+) n‐alkanes. Relatively high ratios of nC21‐/nC22+ and C27/C29 regular steranes demonstrate that organic matter is mainly originated from lower aquatic organisms and followed by higher plants in a local area. This is also supported by the variations of the δ13C values of C13‐C26 n‐alkanes for the target samples being in the range of 3.0‰–5.6‰ offset, which is slightly higher than the corresponding value (1.6‰) of n‐alkanes from a single source. All these pieces of information decipher that the organic matter in Dalong Formation shale may be dominated by type I and followed by type II1. Moreover, the maturity proxies according to both organic petrography (Ro and Tmax) and biomarkers such as ratios of C29 20 S/(20 S + 20R) and C29 ββ/(αα + ββ) together indicate that organic matter in Dalong Formation shale is in a mature stage of hydrocarbon generation. Furthermore, a cross‐plot of total organic carbon versus total sulphur as well as Pr/Ph ratio and Pr/nC17‐Ph/nC18 diagram elucidates that Dalong Formation shales were mainly formed in a marine reducing environment. Finally, two depositional models of organic matter enrichment are proposed. The abundant lower aquatic organisms with few terrestrial detrital inputs and the reducing water environment together promote organic matter accumulation.

Assessment of the hydrocarbon potentiality of the Late Jurassic formations of NW Iraq: A case study based on TOC and Rock-Eval pyrolysis in selected oil-wells

AbstractThe Late Jurassic Naokelekan and Barsarin formations of northwestern Iraq have been investigated in three wells to assess their potentiality for hydrocarbon generation.The results of Total Organic Carbon content (TOC) and Rock-Eval Pyrolysis reveal fair to excellent content of hydrocarbon and suggest that the depositional conditions were suitable for the production and preservation of organic matter. The Thermal Maturity Proxy indicates that the studied formations were mature stage of hydrocarbon generation, with an exception of three samples from the Naokelekan Formation in Shaikhan-8 well, and two samples from the Barsarin Formation in Atrush-1 and Shaikhan-8 wells were at an immature stage.The S1and TOC relationship shows that all the samples are indigenous in nature. Most of samples from the Naokelekan Formation belong to kerogen Type II/III, and that in the Barsarin Formation belongs to kerogen Type II is dominant.The Pr/Ph, Pr/n-C17and Ph/n-C18ratios for the extracted bitumen of both the formations indicate that they were originated from marine organic matter under reducing conditions. Theδ13CSatandδ13CArorange from −28.7 to −27.7‰ and −28.8 to −27.7‰ respectively. These biomarkers show high contribution of marine organic matters preserved under relatively anoxic conditions in the studied formations.

Organic geochemistry and palynology of coals and coal-bearing mangrove sediments of the Neogene Sandakan Formation, Northeast Sabah, Malaysia

The coals and coal-bearing mangrove sediments of Sandakan Formation have been evaluated for their source rock potential, paleoredox conditions and source of organic input, as well as the age and paleovegetation distribution using geochemical and petrographical methods. The studied samples were generally rich in organic carbon, which varied from 0.60 (massive mudstone) to 62.37wt% (coal). The studied samples have vitrinite reflectance (Ro) ranging from 0.31 to 0.49% and Tmax values ranging from 353 to 436°C indicating an immature to very early mature stage for hydrocarbon generation. The sediments were dominated by Type III kerogen, with some Type II/III kerogen, suggesting a significant land plant contribution to the organic matter. The bimodal distribution displayed by gas chromatogram, with a clear odd/even carbon number and skewed to higher molecular weight carbon (nC31), indicating a transitional depositional environment. The variation in pristane/phytane ratio, varied from 0.71 to 2.97, suggesting an alternating anoxic and oxic deposition conditions. The presence of marine dinoflagellate cyst in the mangrove and offshore mudstones were consistent with the relatively higher sulphur content in the studied samples which indicate marine inundations.Palynomorph recovered in this study, with abundant mangrove and freshwater types of pollen, suggesting a biogeographical distribution of ancient mangrove vegetation that expanded landward into the freshwater peat swamp setting and hinterland. The presence of marker species, viz. Florschuetzia levipoli, F. meridionalis and F. semilobata delineated an Early Miocene to Middle Miocene age for the Sandakan sediments.

Petroleum source-rock potential of the Piranj oil field, Zagros basin

Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle Cretaceous–Early Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential source rock's name Gurpi and Pabdeh formations. To evaluate the candidate source rocks, 50 cuttings and core samples of these rock units from well M-11 (the only well drilled up to the probable source rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these source rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite source rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI < 300. Moreover, Pabdeh formation can be classified generally as fair to very good source rocks, with kerogens of type II, while Gurpi formation contain mostly kerogens of type II/III. The average values of Vitrinite reflectance (VR) (from 0.44% to 1.23%) indicate that samples from the well M-11 have reached maturities corresponding to early to peak oil generation. Reconstruction of the thermal history suggests various steady heat flow values (53–91 mW/m2) resulted in the best fit between the observed and the calculated bottom hole temperatures (BHT) and Vitrinite reflectance (VR) in the model. Rock-Eval pyrolysis results and Vitrinite reflectance (VR) suggest that the most of samples are in the early mature to mature stage of hydrocarbon generation. Furthermore, according to the modelling results, petroleum generation from the studied source rocks has began after deposition of related seal-rocks and formation of traps which ensures entrapment and preservation of migrated hydrocarbon.

Multidisciplinary approach to constrain kinematics of fault zones at shallow depths: a case study from the Cameros–Demanda thrust (North Spain)

Thrusting at shallow depths often precludes analysis by means of structural indicators effective in other geological contexts (e.g., mylonites, sheath folds, shear bands). In this paper, a combination of techniques (including structural analysis, magnetic methods, as anisotropy of magnetic susceptibility and paleomagnetism, and paleothermometry) is used to define thrusting conditions, deformation, and transport directions in the Cameros–Demanda thrust (North Spain). Three outcrops were analyzed along this intraplate, large-scale major structure having 150 km of outcropping length, 30 km of maximum horizontal displacement, and 5 km of vertical throw. Results obtained by means of the different techniques are compared with data derived from cross sections and stratigraphic analysis. Mixed-layer illite–smectite and vitrinite reflectance indicating deep diagenetic conditions and mature stage of hydrocarbon generation suggests shallow depths during deformation, thus confirming that the protolith for most of the fault rocks is the footwall of the main thrust. Kinematic indicators (foliation, S/C structures, and slickenside striations) indicate altogether a dominant NNW movement of the hanging wall in the western zone and NE in the eastern zone of the thrust, thus implying strain partitioning between different branches of the main thrust. The study of AMS in fault rocks (nearly 400 samples of fault gouge, breccia, and microbreccia) indicates that the strike of magnetic foliation is oblique to the transport direction and that the magnetic lineation parallelizes the projection of the transport direction onto the k max/k int plane in sites with strong shear deformation. Paleomagnetism applied to fault rocks indicates the existence of remagnetizations linked to thrusting, in spite of the shallow depth for deformation, and a strong deformation or scattering of the magnetic remanence vectors in the fault zone. The application of the described techniques and consistency of results indicate that the proposed multidisciplinary approach is useful when dealing with thrusts at shallow crustal levels.

Paleoenvironment characteristics and hydrocarbon potential of the Lower Miocene bituminous shales in Sivas Basin (Central Anatolia, Turkey)

This study is based around Karayun which is in the Sivas Tertiary Basin, one of the important sedimentary basins in Turkey. The units observed in the study area and nearby are Oligocene Hafik, Lower Miocene Karayun and Lower-Middle Miocene Karacaoren Formations and Quaternary alluvium. This study focused on samples from the Karayun Formation due to the presence of alternations of bituminous shale levels in the formation. The studied bituminous shales are characterized by relatively high total organic carbon values up to 10.44 % and S2 values ranging from 0.01 to 89.02 HC/g rock, indicating fair to excellent source rock. Most of the bituminous shales are at the immature to early mature stage for hydrocarbon generation. Generally, genetic potential values are over 2 mg HC/g rock. The hydrogen index value of samples are between 9 and 887 mg HC/g total organic carbon (TOC) (on average 333.62 mg HC/g TOC). Oxygen index values vary between 17 and 557 mg CO2/g TOC (on average 135.35 mg CO2/g TOC). On the basis of Rock-Eval pyrolysis analysis, kerogens are type I/II and type II/III mixed. Dominant organic matter observed in this formation is algal amorphous organic matter. Thermal alteration index (TAI), Spore colour index (SCI), vitrinite reflectance values (Ro) and Tmax evaluations indicate that maturity of the unit is between diagenesis and the early mature zone, and at the beginning of the hydrocarbon-producing stage. As a result of a series of analyses, it was found that the Karayun Formation has organic facies of B, BC and C and limited hydrocarbon generation potential in the basin.

Organic geochemical characteristics and depositional environment of the Tertiary Tanjong Formation coals in the Pinangah area, onshore Sabah, Malaysia

The Tertiary Tanjong Formation coals exposed in the west middle block of the Pinangah Coalfield, central part of southern Sabah were analyzed, and their depositional environments were interpreted. The Tertiary Tanjong coals are humic and generally dominated by vitrinite, with significant amounts of liptinite and low amounts of inertinite macerals. Total organic carbon contents (TOC) of the coals range from 51.2 to 77.7wt.%, and yield of bitumen values ranging from 57,300 to 140,000ppm, which meet the standard as a source rock with good hydrocarbon-generative potential. In support, good liquid hydrocarbons generation potential can be expected from the Tanjong coals based on significant liptinitic content (>15%). This is supported by their high hydrogen index up to 300mg HC/g TOC, consistent with Type II and mixed Type II–III kerogens and Py–GC (S2) pyrograms with n-alkane/alkene doublets extending beyond C30. The coal samples have vitrinite reflectance values in the range of 0.42%–0.66 Ro%, indicating immature to early mature stage for hydrocarbon generation. These vitrinite reflectance values also indicated that the Tanjong coals are with sub-bituminous B–A and high volatile bituminous C rank. Tmax values ranging from 419 to 451°C are good agreement with the vitrinite reflectance data. This is supported by biomarker maturity parameters as suggested by the C32 homohopane. The saturated fraction of the Tanjong coals are characterized by dominant odd carbon numbered n-alkanes (n-C23 to n-C33), high Pr/Ph ratios (8–18), high Tm/Ts ratios (6–28), and predominant of regular sterane C29. All biomarker parameters clearly indicate that the organic matter was derived from terrestrial inputs and deposited under oxic condition.

Geochemical characterization of solid bitumen (migrabitumen) in the Jurassic sandstone reservoir of the Tut Field, Shushan Basin, northern Western Desert of Egypt

Abstract Asphaltene-rich solid bitumen was identified within the pore spaces of the Middle Jurassic Khatatba sandstone reservoir in the Tut Field, Shoushan Basin, Egypt. Despite good reservoir properties have been detected, the solid bitumen forms barriers in the reservoir, which prevents economic petroleum production. Petrographical and organic geochemical techniques were applied in order to characterize the source rock of the bitumen and its formation mechanisms. Organic geochemical results confirm the presence of actively migrating non-biodegraded hydrocarbons within the Khatatba sandstones. Biomarker data suggest that the solid bitumen originated from a marine shale source rock that was deposited in mildly anoxic to suboxic conditions. Biomarker oil-source rock correlation with the organic‐rich sediments of the Khatatba Formation indicates that the shale and coaly shale within the Khatatba Formation are an effective source rock in the area. The natural deasphalting is the predominant mechanism for the formation of the asphaltene rich solid bitumen in the Khatatba sandstones. Adsorption of asphaltenes onto authigenic kaolinite played a major role in the fixation of bitumen. Furthermore, gas deasphalting caused by gas injection may have contributed to a phase change in the reservoir fluid and deposition of solid bitumen. The injected gas is generated from Khatatba Type III kerogen or older source rocks in the Shoushan Basin during the mature stage of hydrocarbon generation.

Maximum burial and unroofing of Mt. Judica recess area in Sicily: implication for the Apenninic–Maghrebian wedge dynamics

We integrated X-ray diffraction (XRD) data concerning the illite content in mixed-layer illite–smectite with data derived from Fourier Transform Infrared spectroscopy (FTIR) on H-rich organic matter to constrain the burial-exhumation path of the Mt. Judica sedimentary succession cropping out in tectonic window in Eastern Sicily.Thermal structural model constrained by organic and inorganic thermal parameters showed that the Mt. Judica succession experienced paleo-temperatures in the range of 100–130°C in deep diagenetic conditions and early mature stage of hydrocarbon generation. Specifically, the illite content in mixed-layer I–S ranges from 50 to 76% and FTIR-derived indexes suggest a thermal maturity equivalent to VRo values of at least 0.5–0.7%. As a whole, the Mt. Judica succession experienced maximum tectonic burial (ranging between 2.4 and 3.2km) during the Middle Miocene as a result of the emplacement of the allochthonous units atop it. The subsequent breaching phase characterized by up-thrust geometries, and erosion during Pliocene times ruled out the Mt. Judica exhumation. This last tectonic phase did not overprint thermal maturity because the extent of overthrusting was negligible when compared with the magnitude of vertical movements. Restoration of balanced cross sections revealed an increase of shortening from the salient to the Mt. Judica recess with values from 12.3 to 23.9km, consistent with the increase of tectonic thickening of the fold-and-thrust belt. Integration of maximum burial and shortening values along the curvature of the Sicilian fold-and-thrust belt allowed us to reconstruct the wedge paleo-geometry in the Mt. Judica recess area, to investigate the along-strike variations of the tectonic overburden, and to discuss the geodynamic causes of these changes. These results were compared with theoretical models of wedge dynamics.

Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt

The Shoushan Basin is an important hydrocarbon province in the Western Desert, Egypt, but the origin of the hydrocarbons is not fully understood. In this study, organic matter content, type and maturity of the Jurassic source rocks exposed in the Shoushan Basin have been evaluated and integrated with the results of basin modeling to improve our understanding of burial history and timing of hydrocarbon generation. The Jurassic source rock succession comprises the Ras Qattara and Khatatba Formations, which are composed mainly of shales and sandstones with coal seams. The TOC contents are high and reached a maximum up to 50%. The TOC values of the Ras Qattara Formation range from 2 to 54 wt.%, while Khatatba Formation has TOC values in the range 1–47 wt.%. The Ras Qattara and Khatatba Formations have HI values ranging from 90 to 261 mgHC/gTOC, suggesting Types II-III and III kerogen. Vitrinite reflectance values range between 0.79 and 1.12 VRr %. Rock−Eval T max values in the range 438–458 °C indicate a thermal maturity level sufficient for hydrocarbon generation. Thermal and burial history models indicate that the Jurassic source rocks entered the mature to late mature stage for hydrocarbon generation in the Late Cretaceous to Tertiary. Hydrocarbon generation began in the Late Cretaceous and maximum rates of oil with significant gas have been generated during the early Tertiary (Paleogene). The peak gas generation occurred during the late Tertiary (Neogene).

Composition, porosity, and reservoir potential of the Middle Jurassic Kashafrud Formation, northeast Iran

In the Kopet-Dagh Basin of Iran, deep-sea sandstones and shales of the Middle Jurassic Kashafrud Formation are disconformably overlain by hydrocarbon-bearing carbonates of Upper Jurassic and Cretaceous age. To explore the reservoir potential of the sandstones, we studied their burial history using more than 500 thin sections, supplemented by heavy mineral analysis, microprobe analysis, porosity and permeability determination, and vitrinite reflectance. The sandstones are arkosic and lithic arenites, rich in sedimentary and volcanic rock fragments. Quartz overgrowths and pore-filling carbonate cements (calcite, dolomite, siderite and ankerite) occluded most of the porosity during early to deep burial, assisted by early compaction that improved packing and fractured quartz grains. Iron oxides are prominent as alteration products of framework grains, probably reflecting source-area weathering prior to deposition, and locally as pore fills. Minor cements include pore-filling clays, pyrite, authigenic albite and K-feldspar, and barite. Existing porosity is secondary, resulting largely from dissolution of feldspars, micas, and rock fragments, with some fracture porosity. Porosity and permeability of six samples averages 3.2% and 0.0023 mD, respectively, and 150 thin-section point counts averaged 2.7% porosity. Reflectance of vitrinite in eight sandstone samples yielded values of 0.64–0.83%, in the early mature to mature stage of hydrocarbon generation, within the oil window. Kashafrud Formation petrographic trends were compared with trends from first-cycle basins elsewhere in the world. Inferred burial conditions accord with the maturation data, suggesting only a moderate thermal regime during burial. Some fractures, iron oxide cements, and dissolution may reflect Cenozoic tectonism and uplift that created the Kopet-Dagh Mountains. The low porosity and permeability levels of Kashafrud Formation sandstones suggest only a modest reservoir potential. For such tight sandstones, fractures may enhance the reservoir potential.

Sedimentation, organic maturity, and petroleum potential of the Oligocene–Miocene oil shale deposits, Yayu Basin, southwestern Ethiopia

Studies initiated in the search for domestic energy supplies for Ethiopia have confirmed the presence of oil shales in the Yayu Basin. This article presents some of the characteristics of these shales. The basin is located in the southwest of Ethiopia and consists of Precambrian basement and Cenozoic volcanic and sedimentary rocks. Three sedimentary successions reach a cumulative maximum thickness of 165 m (541 ft). Two oil shale horizons have been identified in the upper and lower sedimentary successions and reach a maximum thickness of 35 and 20 m (115 and 65 ft), respectively. Sedimentation in the basin occurred in fluvial and lacustrine depositional environments. The sandstone facies was deposited in a fluvial environment, whereas the oil-shale-bearing sediments were deposited in a lacustrine environment. Algal amorphous materials and minor amounts of woody materials characterize the studied oil shales with Botryococcus and Pediastrum, indicating a lacustrine environment. The studied oil shales are characterized by high total organic carbon values up to 61.2% and S2 (hydrocarbon-generating potential) values ranging from 10.78 to 119.07 HC g/kg, indicating excellent source rocks. Most of the oil shales are at the immature to early mature stage for hydrocarbon generation. Vitrinite reflectance measurements on the oil shale samples are less reliable because of the presence of abundant algal materials. Gas chromatogram results also indicate source rocks. The Yayu Basin is estimated to have up to 1 billion metric tons of oil shale reserves.

Organic Geochemistry of Source Rocks, Condensates, and Thermal Geochemical Modeling of Miocene Sequence of Some Wells, Onshore Nile Delta, Egypt

: The organic geochemical and biomarker analyses of the Miocene source rocks of some wells in the onshore Nile Delta, suggested that the Abu Madi Formation has poor immature to marginally mature source rocks of Type III Kerogen deposited under the terrestrial environment. The Sidi Salem Formation has fair-to-good mature source rocks of producing mixed oil and gas, originating mainly from marine organic sources. The Moghra Formation has mature good source rocks for Type (II/III) kerogen, derived from organic matter and rich in both terrigeneous and marine sources. The geochemistry of condensates revealed that the Abu Madi and Moghra condensates originated from marine organic matters with little input from a terrestrial source, while Sidi Salem condensate was derived from more contribution of terrestrial organic matters. Abu Madi condensate is less mature than Sidi Salem and Moghra condensate. The geochemical thermal modeling of the Miocene source rocks indicates that the Abu Madi formations are in the early stages of hydrocarbon up until the present time, while Moghra and Sidi Salem formations are in the mature stage of hydrocarbon generation up until the present time. This indicates that the studied condensates have probably migrated from deeply buried source rocks which are at a higher level of maturity rather than from less mature source rocks in the study area.

Fossil fuel energy resources of Ethiopia: Oil shale deposits

The energy crisis affects all countries in the world. Considering the price scenarios, many countries in Africa have begun to explore various energy resources. Ethiopia is one of the countries that depend upon imported petroleum products. To overcome this problem, geological studies suggest a significant occurrence of oil shale deposits in Ethiopia. The Inter-Trappean oil shale-bearing sediments are widely distributed on the South-Western Plateau of Ethiopia in the Delbi-Moye, Lalo-Sapo, Sola, Gojeb-Chida and Yayu Basins. The oil shale-bearing sediments were deposited in fluviatile and lacustrine environments. The oil shales contain mixtures of algal, herbaceous and higher plant taxa. They are dominated by algal-derived liptinite with minor amounts of vitrinite and inertinite. The algal remains belong to Botryococcus and Pediastrum. Laboratory results confirm that the Ethiopian oil shales are dominated by long-chain aliphatic hydrocarbons and have a low sulphur content. Type-II and Type-I kerogen dominated the studied oil shales. Type-II and Type-I are good source rocks for oil and gas generation. Hydrogen index versus T max value plots indicated that most of the oil shale samples fall within the immature-early mature stage for hydrocarbon generation, consistent with the Ro values that range from 0.3% to 0.64%. Pyrolysis data of the oil shales sensu stricto indicate excellent source rocks with up to 61.2% TOC values. Calorific value ranges from 400 to 6165 cal/g. Palynological studies confirmed that the oil shale-bearing sediments of Ethiopia range from Eocene to Miocene in age. A total of about 253,000,000 ton of oil shale is registered in the country. Oil shale deposits in Ethiopia can be used for production of oil and gas.

Thermal maturity of the axial zone of the southern Apennines fold‐and‐thrust belt (Italy) from multiple organic and inorganic indicators

AbstractThe reconstruction of the thermal history of folded and thrust units is crucial to define the pattern of tectonic loading and the time‐space evolution of an orogen where tectonic exhumation processes occurred at shallow crustal levels. In the present study, a well‐constrained reconstruction of the thermal maturity in the axial zone of the southern Apennines has been achieved by the combined use of different thermal indicators in diagenesis. The major results are: (i) documentation of a jump in thermal maturity from the Apenninic Platform derived tectonic unit (from immature to early mature stages of hydrocarbon maturation) to the Lagonegro Basin derived tectonic units (late diagenetic zone); (ii) documentation of along‐strike slighter variations in the Lagonegro units, concerning thermal maturity (thus maximum burial temperatures). This can be related to changes in amounts of tectonic burial and erosion/exhumation because of the lack of cylindricity of contractional structures; (iii) recognition of an independent thermal evolution of the allochthonous chain compared with the Apulian Platform tectonic unit with Mt Alpi area (in the late mature stage of hydrocarbon generation) interpreted as a sector of localized, intense exhumation within the External Zone of the orogen.

Geochemistry of natural gases in deep strata of the Songliao Basin, NE China

Chemical composition and stable carbon isotopic studies were undertaken for 27 gas samples from deep strata of the Xujiaweizi Depression in the Songliao Basin to investigate their origin. Gas molecular and carbon isotopic compositions show great variety. Methane is the main component for all studied samples and its content ranges from 57.4% to 98.2% with an average of 90.1%. Gas wetness ranges from 0.8% to 16.7% with an average of 2.7%. The main non-hydrocarbon gases are carbon dioxide and nitrogen with an average of 4.0% and 3.2%, respectively. Carbon isotope data suggest that these deep strata gases are mainly coal-type gases mixed with minor amounts of associated (oil-type) gases. Coal-type gases are characterized by heavier carbon isotopic values and drier chemical compositions. These gases were generated from the Lower Cretaceous Shahezi Formation coals interbedded shales with type III kerogen during the postmature stage of hydrocarbon generation. Oil-type gases are characterized by lighter carbon isotope and higher wetness, which were generated from the Lower Cretaceous shales with type II kerogen in the shallow strata during the early mature stage of hydrocarbon generation. Mixing of two different gases causes unusual carbon isotopic distribution patterns, with lighter isotopic values in higher numbered carbons in most gases. The discovery of coal-type gases in the Songliao Basin provides new prospects for the exploration in this region.

Thermal Maturation in the Ellef Ringnes Island and Surrounding Area, Sverdrup Basin

Determining thermal maturity studies in the Ellef Ringnes Island area was complicated by numerous factors, such as the presence of cavings, bitumen staining, and igneous intrusions. Cavings are a problem in certain intervals in Hoodoo H-37, Dome Bay P-36, and Helicopter J-12. Bitumen staining resulting in suppression of reflectance has occurred in the lower part of the Jameson Bay shales in Elve M-40. Thick sills resulted in increase of Ro to 4.0%, whereas thin sills had a minimal impact on reflectance increase. Other features observed include overpressuring caused by hydrocarbon generation in the Schei Point source rocks as well as in the Jameson and Ringnes shales, and a “kinky” Ro profile caused by the presence of low-permeability gas-bearing reservoirs in the Heiberg sandstones in Jackson Bay G-16A. The presence of sapropelic coals with HI up to 329 mg HC/gTOC in Heiberg sandstones in Elve M-40 containing Botryococcus algae should also be noted. Calculated maturation gradients vary from 0.95 log°Ro/km in Helicopter J-12 to 0.23 log %Ro/km in Sirius K-28, but most are between 0.12 and O.l5 log %Ro/km. Geothermal gradients range from 16.5°C/km in Hoodoo H-37 to 37.8°C/km in Sirius K-28, with the majority being close to 20°C/km. The Tmax values range from 436–445°C in the Jameson Bay but reach 453°C at the base of the formation in Sirius K-28. Total organic carbon in Jameson Bay is 1.3–3.3 wt% and HI usually varies from 49–181 mg HC/gTOC, although a value of 374 was measured in Hoodoo Dome H-37. Tmax is also elevated in the Isachsen sandstones (444–445°C”. These values correspond to 0.83–0.90%Ro; however, measured Ro is much lower (0.45–0.50%Ro) pointing to a poor relationship between the two maturity parameters in this arenaceous formation. The Ringnes shales have Tmax of 430–434°C with corresponding HI of 209–244. The Schei Point Group shales, considered to be the main source rocks in the area, have Tmax of 441–443°C The underlying Blind Fiord has Tmax of 454°C, in good agreement with a TAI of 3 reported in the literature. Igneous sills have increased Tmax to 468–507°C in Helicopter J-12 and to 479°C in Louise 0–25. Anomalously high Tmax values in Hoodoo Dome N-52 have been attributed to the presence of salt domes and to the “warping up” effect in strata adjacent to and also deeper by the flanks of the dome. Hot fluid circulations in areas near the intrusives and high inertinite kerogen have also contributed to elevated Tmax values. In areas that have not been intruded, Ro increases from 0.36% in Eureka Sound to 0.43% in the Christopher and to 0.50% in the Isachsen. Coals in the latter formation have been oxidized, therefore, Ro is slightly higher. Reflectance increases from 0.42–0.48% in Deer Bay to 0.67% in the Ringnes, reaching 0.70% in the Jameson Bay shales. The Barrow shales have Ro of 0.7–0.95% increasing to >1.20% in the Pat Bay shales. The Schei Point shales are in the mature stage of hydrocarbon generation. The presence of oil and gas in a number of fields can be explained by the variations in thermal maturity.

Regional Maturation Study in the King Christian Island Area, Arctic Canada

The hydrocarbon potential of the Mesozoic succession in the vicinity of King Christian Island in central Sverdrup Basin was evaluated on the basis of maturation parameters and knowledge of the regional geology. The Triassic Schei Point Group, which is the main source rock interval in Sverdrup Basin, is in the mature stage of hydrocarbon generation (Ro>0.60%). The type of organic matter is mainly plank-tonic marine algae and bituminite, deposited in an offshore shelf setting. Rock-Eval Tmax values are in the range 428–444°Q in general agreement with reflectance. Organic richness is indicated by the high hydrogen index (HI) values in the shales (in excess of 300 mg HC/gTOC). Less rich source rocks are found in the Jurassic-age Jameson Bay and Ringnes formations, in accordance with previous studies in the nearby Lougheed and Melville islands. Numerous oil and gas fields have been discovered in King Christian Island to date. Geology shows that the presence or absence of liquid and gaseous hydrocarbons in the reservoirs is related to the development of a system of faults and fractures in the successions stratigraphically above the source rocks. These zones have acted as conduits for oil and gas migration and, ultimately, loss. The presence of bitumen staining and numerous populations of solid bitumen, interpreted as allochthonousty derived, support the theory of hydrocarbon migration in the King Christian Island succession. Migration has taken place over a vertical distance of 800 m to 1500 m. Problems were encountered in measuring vitrinite reflectance, related mainly to the presence of cavings, bitumen staining, vitrinite typing, oxidation of organic matter, and effect of igneous intrusions. The thermal effect from igneous sills and dykes resulted in thermal cracking of liquid hydrocarbons to gaseous in certain areas. A zone of paleo-overpressure was identified near the contact between a thick sandstone unit and overlying shales exhibiting a “kinky” vitrinite reflectance profile. Overpressure was attributed to a combination of hydrocarbon generation in the Schei Point or deeper source rocks, high rates of sedimentation in Jurassic to Cretaceous shale units, differential compaction of lithologies, and entrapment of pore water.