Stages Of Thermal Maturation Research Articles

Pyrolysis S2-peak characteristics of Raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity

The Permian shales of the Raniganj basin, India, have experienced a dramatic burial history of rapid subsidence (Jurassic-Early Cretaceous) followed by igneous intrusion (Cretaceous) and rapid uplift and erosion (Late Cretaceous-Tertiary). This has left these shales with mixed kerogen macerals with a characteristic thermal signature, ranging from early mature to post mature, which is reflected in the characteristics of their pyrolysis S2 peak. Many of these shales are today at peak thermal maturity but reached that condition more than 100 million years ago. They have significant potential to be exploited as a shale gas resource and their S2 peak characteristics should help to identify sweet spots for such exploitation. Here we analyze single-rate and multi-rate heating ramp Rock-Eval data from a suite of these shales at varying stages of thermal maturity. The S2 peak shapes provide significant insight to the kerogen kinetics involved in their thermal evolution. However, detailed fitting of the peak shapes with kerogen-kinetic mixing models indicate that factors other than static first-order reaction kinetics are also involved in their S2-peak-shape characteristics. Such factors likely include the catalytic effects, influenced by sulfur and charcoal, on some kerogen components, and kerogen pore-size distribution changes during their complex burial and thermal maturation histories. It is likely that the peak-mature shales contain significant, already generated, gas trapped within some of the kerogen nanopores that may be released during the S2 pyrolysis heating ramp rather than during the S1 heating ramp. This causes the S2 peak to broaden in the mature shales, a characteristic that could be used as an exploration marker for zones best suited to shale gas exploitation. Cited as : Wood, D.A., Hazra, B. Pyrolysis S2-peak characteristics of raniganj shales (India) reflect complex combinations of kerogen kinetics and other processes related to different levels of thermal maturity. Advances in Geo-Energy Research, 2018, 2(4): 343-368, doi: 10.26804/ager.2018.04.01

Heterogeneity of organic-rich lacustrine marlstone succession and their controls to petroleum expulsion, retention, and migration: A case study in the Shulu Sag, Bohai Bay Basin, China

Abstract We documented a new type of self-sourced unconventional reservoir consisting of interbedded organic-rich marlstone and calcareous conglomerates developed in lacustrine carbonate successions in the Eogene Shahejie formation (Es33) of Shulu Sag, Bohai Bay Basin. The Es33 interval used to be regarded as a set of homogeneous source rock for oil plays in the upper strata due to their high abundance of organic-matter. However, the Es33 interval actually has very strong heterogeneity in their organic richness and hydrocarbon generation ability among different stratigraphic sequences (the Es33 interval can be divided into sequence SQ1 to SQ5 from bottom to up). To better understand the heterogeneity in the unconventional reservoir and its effect on the hydrocarbon retention and migration, thin sections and scanning electronic microscopes were used to characterize the pore system in the reservoir, together with a amount of collected well database including wireline logging, gas logging, and physical property data (e.g. porosity and permeability). Intensive sampling from the Es33 interval of Well ST1H was performed and samples were measured with Rock-Eval and TOC analysis. The rock extracts were analyzed with SARA and gas chromatography - Mass spectrum (GC-MS) analysis to examine the fluid geochemical characteristics and molecular biomarkers composition. The results show that although the whole Es33 are characterized by low and ultra-low porosity and permeability, but the pore types in different lithology are different. The organic-rich marlstones develop large amount of organic matter pore and dissolved mineral pores, while the conglomerates developed inter-partical or inter-crystalline mineral pores dominantly. The sequence SQ2 has high quality of source rock for hydrocarbon generation, possessing moderate to high content of organic matter (TOC range 2–5 wt %) with Type I-II kerogen predominantly, basically in the thermal maturity stage of the peak oil window. OM and lithology play significant roles in controlling hydrocarbon expulsion and retention. Oil retained in the organic-rich marlstone was observed to absorb on the surface of OM and clay-rich matrix, which is also supported by the positive correlation between retained oil (represented by Rock-Eval S1) and TOC. Organic-lean conglomerates in the sequence SQ3 obtain abnormal high content of low mature oil determined by biomarker composition, which suggests the oil were derived from oil migration and mixture. Thermal maturity profile based on hydrocarbon biomarkers composition of rock extract provides a method to determine the effect of the hydrocarbon migration or retention within source rock. The organic-lean intervals adjacent or close to organic-rich source rock can be favorable targets for oil exploration.

Gas generation and its isotope composition during coal pyrolysis: Potential mechanism of isotope rollover

Recent studies on both conventional (thermogenic gas) and unconventional (shale gas) gases show comparable carbon/hydrogen isotope rollover, i.e., before the rollover point, carbon/hydrogen isotope increases with increasing thermal maturity (or decreasing gas wetness), while after the rollover point, the gas component (i.e., ethane, propane, etc.) becomes more depleted in 13C or 2H with increasing thermal maturity. In order to further investigate potential mechanism of the isotope rollover, combined with previous researches on isotope rollover, this study carried out two batches of pyrolysis experiments on a low mature coal sample from the Songliao Basin, China at constant temperatures for about 72 h under the condition with added water and without added water. The results demonstrate that carbon and hydrogen isotope rollover of ethane and propane started at 500 °C, no matter with added water or without added water. Combined with previous studies on gases of various origins, it is found that such isotopic anomalies were a common phenomenon at high thermal mature stage, despite of what kind of the source rocks and whether adding water or not under the laboratory condition. This is likely caused by the mixing of gases directly from the decomposition of macromolecule of kerogen and those from the tightly entrapped straight-chain species in kerogen at relatively high thermal mature stage. These straight-chain species are normally entrapped in the kerogen, and will probably be released at high thermal maturation stage. Marine facies source rocks from southern China also demonstrate the existence of such tightly entrapped hydrocarbons at very high thermal maturity. The results may have important significance on the gas exploration at relatively high mature stage and have a guidance on the gas production changes during the exploration.

Porosity-preserving mechanisms of marine shale in Lower Cambrian of Sichuan Basin, South China

Porosity preservation is of great significance in the capacity of gas shale reservoir. Whether pore space can be preserved at the later diagenetic stage controls the capacity of shale reservoir. In this study, porosity-preserving mechanisms of marine shale from Lower Cambrian, both inside and at the margin of Sichuan Basin, South China, were investigated via a combination of the X-ray diffraction (XRD), organic geochemistry analysis, gas adsorption analysis and focused ion beam milling-scanning electron microscopy (FIB-SEM) in both two-dimension (2-D) and three-dimension (3-D). The results showed that there was little difference in mineralogical compositions between samples of Qiongzhusi shales and Niutitang shales that brittle minerals and clay were predominate components. The mean value of the total organic carbon (TOC) of Qiongzhusi shales was 1.44 wt% lower than that of Niutitang shales (4.37 wt%), whereas Qiongzhusi shales were at relatively lower thermal maturity stage with equal-vitrinite reflectance (Ro) ranging from 2.66% to 2.8% compared with Niutitang shales (3.06%<Ro<3.59%). Nitrogen (N2) and Carbon dioxide (CO2) adsorption revealed that micropore-mesopore (0.4–60 nm) volumes (PV) of Qiongzhusi shale samples (averaging 0.0305 ml/g) were higher than those of Niutitang shale samples (averaging 0.0251 ml/g), whereas the mean micropore-mesopore surface area (PSA) of Qiongzhusi samples (20.77 m2/g) was relatively lower than that of Niutitang samples (26.71 m2/g). FIB-SEM (2-D) observation manifested three distinctive pore types in terms of pores of rigid framework, pores associated with clay minerals and organic matter (OM)-hosted pores. FIB-SEM (3-D) reconstruction illustrated that pore networks possessed appropriate connectivity in the upside of Qiongzhusi shale samples.These observations suggest that brittle mineral grains can function as rigid frameworks or grain supporters due to high brittleness which preserves ductile matrix relating pores (OM-hosted pores and clay associated pores) from collapse by sharing the effective stress; in addition, either excessive OM abundance (TOC>5.0 wt%) or over thermal maturity (Ro>3.3%) is detrimental to pore preservation; moreover, poor sealing ability of shale systems might deteriorate pore preserving ability through losing overpressure environment or stress supporting mechanism.

Quantitative characterization of organic acid generation, decarboxylation, and dissolution in a shale reservoir and the corresponding applications—A case study of the Bohai Bay Basin

In order to study the generation of organic acids and their dissolution effects on reservoirs, the type, yield and stability of common organic acids in the stratum were analyzed by laboratory simulations of the organic acid generation from kerogen and the decarboxylation of these organic acids. A kinetic model for the generation of organic acids and thermodynamic models of the decarboxylation of organic acids and the dissolution reaction were established. Acetic acid was used as an example to characterize the integration of the organic acid generation, decarboxylation, and dissolution under geological conditions. In addition, the process of dissolution pore development in shale reservoirs of various ages was reproduced. The results show that among the organic acids produced in the kerogen thermal simulation, the most stable is acetic acid with a decarboxylation temperature higher than 250 °C, followed by formic acid, and oxalic acid is the least stable. A large amount of organic acids can be produced in the middle thermal maturation stage (Ro = 0.89%–1.25%) of organic matter (OM). The modeling method combining kinetics and thermodynamics can achieve the quantitative characterization of the process of dissolution pore development. According to the calculation results, if the organic acids dissolve the reservoir as a whole, the porosity increment produced by the dissolution of the reservoir’s minerals is not significant. In other words, the dissolution of the reservoir by organic acids does not have an overall significance. However, if the organic acids only move along the predominant pathway (such as fractures) after their generation and dissolved the surrounding minerals of this channel, obvious dissolution can be produced. Comparison of the mineral composition and crack development of shale reservoirs indicates that organic acids could preferentially dissolve the reservoir cracks, so as to improve the porosity and permeability of the reservoir.

Magmatic activities and their impacts on oil/gas formation in the southwestern Ordos Basin, Central China

The southwestern area of the Ordos Basin, China, contains good oil/gas systems, similar to the main basin. However, no oil/gas reserves have been found because some magmatic rocks with different occurrences developed in the region, it resulted in the suspension of oil/gas exploration in the 1980s. By means of integrated research based on field investigation, geophysical interpretation, and data of drilling wells, this paper indicates that magmatic activities in the southwestern Ordos Basin display different properties over multiple periods. The Proterozoic and Palaeozoic magmatic rocks are mainly distributed as a large batholith in the Qinling Orogen, and the Qilian Orogen around the southwestern margin of the Ordos Basin. These Proterozoic and Paleozoic plutons have no effect on hydrocarbon source rocks and oil/gas generation in the Ordos Basin. However, the Mesozoic magmatic activities developed within the basin have obvious effects on oil/gas generation. Three kinds of exploration regions were selected within the southwestern Ordos Basin according to the distribution of hydrocarbon source and magmatic rocks as well as the thermal degree: (a) the marginal area of the basin, (b) the region of the Longmen Uplift distributed with concealed magmatic rocks within the basin, and (c) the region within the basin far away from concealed magmatic rocks. Three sets of gas source rocks, that is, the Upper Proterozoic algal dolostone, the Middle Ordovician dark shale, the Upper Paleozoic black mudstone of coal system, and one set of oil source rocks of the Upper Triassic lacustrine black mudstone and oil shale, are exposed in outcrops near the margin of the basin. They all display a low thermal degree with vitrinite reflectance (Ro) below 1.3%, and they do not contribute to oil/gas accumulation because of earlier tectonic uplift. The gas source rocks and oil source rocks, which occur within the basin area of the Longmen Uplift, where the concealed magmatic rocks, display an abnormal thermal degree of over maturation with Ro over 3.4% and underwent dry gas generation because of heating from magmatic activity, and they have gas exploration potential. The source rocks distributed within the basin area away from concealed magmatic rocks display a normal thermal degree and oil/gas generation. The Ro of the Upper Triassic oil source rock is 1.0–1.6%, which is under the thermal maturity stage of liquid oil generation, whereas that of the Upper Paleozoic gas source rocks is 2.0–2.5% under the thermal maturity stage of gas generation. Measured Ro and burial depth of source rocks in the region show a linear relationship, which indicate that source rocks experienced thermal evolution and oil/gas generation under the normal burial thermal condition rather than the magmatic activity. This region has the most potential for both oil and gas exploration.

Geochemistry, reservoir characterization and hydrocarbon generation potential of lacustrine shales: A case of YQ-1 well in the Yuqia Coalfield, northern Qaidam Basin, NW China

Ever since a breakthrough of marine shales in China, lacustrine shales have been attracting by the policy makers and scientists. Organic-rich shales of the Middle Jurassic strata are widely distributed in the Yuqia Coalfield of northern Qaidam Basin. In this paper, a total of 42 shale samples with a burial depth ranging from 475.5 m to 658.5 m were collected from the Shimengou Formation in the YQ-1 shale gas borehole of the study area, including 16 samples from the Lower Member and 26 samples from the Upper Member. Geochemistry, reservoir characteristics and hydrocarbon generation potential of the lacustrine shales in YQ-1 well were preliminarily investigated using the experiments of vitrinite reflectance measurement, maceral identification, mineralogical composition, carbon stable isotope, low-temperature nitrogen adsorption, methane isothermal adsorption and rock eval pyrolysis. The results show that the Shimengou shales have rich organic carbon (averaged 3.83%), which belong to a low thermal maturity stage with a mean vitrinite reflectance (Ro) of 0.49% and an average pyrolytic temperature of the generated maximum remaining hydrocarbon (Tmax) of 432.8 °C. Relative to marine shales, the lacustrine shales show low brittleness index (averaged 34.9) but high clay contents (averaged 55.1%), high total porosities (averaged 13.71%) and great Langmuir volumes (averaged 4.73 cm−3 g). Unlike the marine and marine-transitional shales, the quartz contents and brittleness index (BI) values of the lacustrine shales first decrease then increase with the rising TOC contents. The kerogens from the Upper Member shales are dominant by the oil-prone types, whereas the kerogens from the Lower Member shales by the gas-prone types. The sedimentary environment of the shales influences the TOC contents, thus has a close connection with the hydrocarbon potential, mineralogical composition, kerogen types and pore structure. Additionally, in terms of the hydrocarbon generation potential, the Upper Member shales are regarded as very good and excellent rocks whereas the Lower Member shales mainly as poor and fair rocks. In overall, the shales in the top of the Upper Member can be explored for shale oil due to the higher free hydrocarbon amount (S1), whereas the shales in the Lower Member and the Upper Member, with the depths greater than 1000 m, can be suggested to explore shale gas.

The characteristics of bound biomarkers released from asphaltenes in a sequence of naturally biodegraded oils

Previous studies have showed that the hydrocarbon biomarkers bound in asphaltenes can preserve original geochemical information during subsequent thermal alteration and biodegradation relative to their free counterparts in crude oil. In the present study, asphaltenes separated from a set of heavy oils which possess an identical source origin and similar thermal maturity, but have experienced different degrees of biodegradation, were analysed to study the influence of biodegradation on the bound biomarkers of asphaltenes. On-line flash pyrolysis directly coupled with gas chromatography–mass spectrometry (Py–GC–MS) was used on these asphaltenes to release the hydrocarbon biomarkers bound within the asphaltene structure. Additionally, the free biomarker profiles in these oils were investigated by GC–MS for a comparison with the bound phase in the corresponding asphaltenes. The results reveal that most of the free biomarkers in the reservoired oils were significantly altered at heavy to severe biodegradation stages, and thus lost much original geochemical information. However, the biomarkers bound in the asphaltenes show very little alteration due to biodegradation, and they also appear to be less mature than their free counterparts in the corresponding oils. This indicates that the bound biomarker profiles in asphaltene flash pyrolysates can represent “original oils” at an early and low thermal maturity stage. Therefore, the biomarker parameters on the basis of asphaltene flash pyrolysates can still be used as indices for correlation studies even though the oils were heavily to severely biodegraded.

Study of thermal maturation processes of sulfur-rich source rock using compound specific sulfur isotope analysis

Semi-open pyrolysis experiments were conducted on a thermally immature, organic and sulfur-rich source rock (Ghareb Formation, Israel). Structural and sulfur isotope ratio (34S/32S) changes in specific organic sulfur compounds were studied along with bulk sulfur phases (H2S, kerogen, oil) during thermal maturation and oil formation. Oil, gas and rock samples were collected sequentially at several points along the maturation path and were analyzed. In addition, four natural crude oils from Israel were analyzed and the results were compared to the pyrolytic oils.The results showed relatively large δ34S variability (∼10‰) of the organic sulfur compounds (OSCs) in the bitumen of the unheated rock and first pyrolytic oil. This variability was probably a remnant of the original sulfur isotopic signature acquired during the sulfurization of the organic matter in the early diagenetic process. At later stages of thermal maturation, the variability of the sulfur isotopic values in the kerogen gradually decreased to ∼2‰. Three mechanisms were suggested to explain the structural changes and isotopic fractionations of OSCs in the kerogen and generated oils: (A) Cleavage of weak SS and CS bonds leading to the release of large amounts of H2S and to cyclization of the precursors in the kerogen with small fractionations. Thus, the OSCs released by this mechanism preserved their distinct δ34S values. (B) Re-reaction of the released S species with hydrocarbons and generation of new OSCs within the kerogen (or bitumen) matrix. (C) Cleavage of stronger CC bonds and transformation of OSCs to create more stable compounds (e.g. dibenzothiophenes) from multiple sulfur sources. Mechanisms (B) and (C) homogenized the δ34S values of the different OSCs which reflected that of the bulk kerogen.The bulk organic sulfur phases (bitumen, oil, kerogen) were 34S enriched by<1‰ despite large amounts of 34S-depleted H2S (53% of total S) that was released continuously (“open system”). Therefore, the preferential loss of H2S during thermal maturation may not be responsible to the 34S enrichment of oils as reported in some petroleum basins. The overall outcome of the maturation process yields OSCs with δ34S values that closely reflect the kerogen and can be used as a fingerprint for oil-oil and oil-source rock correlation over wide ranges of thermal maturity. The applicability of such correlation is demonstrated by the very good correlation of δ34S values of specific OSCs between artificial and natural oil samples.

Geochemistry of Late Devonian oils of the Timan-Pechora basin

The composition of biomarkers and aromatic hydrocarbons of Late Devonian oils of the Timan-Pechora Basin has been studied. It shows that the organic matter of oil-generating deposits is at the close stages of thermal maturity, which are within the early and middle stages of the oil window. Five groups of oils have been recognized, three of which were generated by organic matter of Domanik deposits and the other two formed from organic matter of another source. Most of the studied oil samples contain derivates of isorenieratene indicating that the organic matter of oil source rocks formed in the photic-zone anoxia of the paleobasin.

Analysis and characterisation of petroleum source rocks in Queensland

A project to improve the understanding of petroleum source rocks across Queensland’s basins was proposed through the Industry Priorities Initiative. The study has identified new source rocks, improved characterisation of known source rocks, and examined their potential as unconventional reservoirs. Round 2 of the project sampled known source rock formations in the Adavale, Bowen, Cooper and Eromanga basins, all with proven petroleum potential. Forty-eight samples from these basins were screened through Rock-Eval and total organic carbon by LECO to determine candidates for further analysis. Pyrolysis gas chromatography was conducted on selected samples (n = 15) to understand the bulk chemical signatures of kerogens with fluids extracted to derive isotopic and biomarker signatures. Organic petrology (n = 11) examined kerogen components and reflectance. Immature samples were analysed for bulk kinetics (n = 10) to determine the stability of kerogens while some were sent for compositional kinetics (n = 7), to predict the gas to oil ratio (GOR) and saturation pressure. Some more mature samples were sent for late gas analysis (n = 6) to understand hydrocarbon generation at later stages of thermal maturation. The results indicate that the marls in the Bury Limestone may have promising potential, that the Permian coals are the principal source rocks in the Cooper and Bowen basins and that the coals and mudstones of the Birkhead Formation have potential to generate. High production index values were noted in the Bury Limestone, as well as coal and mudstone samples from the Cooper and Bowen basins, suggesting that some of these source rocks also have good retention capabilities.

Hydrocarbon source rock potential in the southwestern Gulf of Suez graben: Insights from organic geochemistry and palynofacies studies on well samples from the Ras El Bahar Oilfield

Palynological and biomarker characteristics of organic facies recovered from Cretaceous–Miocene well samples in the Ras El Bahar Oilfield, southwest Gulf of Suez, and their correlation with lithologies, environments of deposition and thermal maturity have provided a sound basis for determining their source potential for hydrocarbons. In addition to palynofacies analysis, TOC/Rock-Eval pyrolysis, kerogen concentrates, bitumen extraction, carbon isotopes and saturated and aromatic biomarkers enable qualitative and quantitative assessments of sedimentary organic matter to be made. The results obtained from Rock-Eval pyrolysis and molecular biomarker data indicate that most of the samples come from horizons that have fair to good hydrocarbon generation potential in the study area. The Upper Cretaceous–Paleocene-Lower Eocene samples contain mostly Type-II to Type-III organic matter with the capability of generating oil and gas. The sediments concerned accumulated in dysoxic–anoxic marine environments. By contrast, the Miocene rocks yielded mainly Type-III and Type-II/III organic matter with mainly gas-generating potential. These rocks reflect deposition in a marine environment into which there was significant terrigenous input. Three palynofacies types have been recognized. The first (A) consists of Type-III gas-prone kerogen and is typical of the Early–Middle Miocene Belayim, Kareem and upper Rudeis formations. The second (B) has mixed oil and gas features and characterizes the remainder of the Rudeis Formation. The third association (C) is dominated by amorphous organic matter, classified as borderline Type-II oil-prone kerogen, and is typical of the Matulla (Turonian–Santonian) and Wata (Turonian) formations. Rock-Eval Tmax, PI, hopane and sterane biomarkers consistently indicate an immature to early mature stage of thermal maturity for the whole of the studied succession.

Hydrocarbon gas generation from pyrolysis of extracts and residues of low maturity solid bitumens from the Sichuan Basin, China

Two sets of pyrolysis experiments were performed on bitumen “A” (BA) and extracted organic matter (ER) from low-maturity solid bitumen at heating rates of 2°C/h and 20°C/h in confined systems (gold capsules). The main observations can be listed as follows: (1) BA and ER have high generation potential of hydrocarbons and were a significant secondary hydrocarbon source. (2) Both have similar evolutionary characteristics of hydrocarbon gas generation, and have high C1/C1–5 values than those from an Ordovician normal oil. Ea distributions of the methane generated from pyrolysis of BA and ER is far lower than that of Ordovician normal oil. (3) The evolution of stable carbon isotope values of individual hydrocarbon gases can be divided into three stages. Plots of lnC1/C2 versus lnC2/C3, δ13C1–δ13C2 versus ln(C1/C2) and δ13C2–δ13C3 versus ln(C2/C3) clearly illustrate the characteristics of hydrocarbon gases generated from BA and ER at different thermal maturity stages. (4) Basin modelling reconstructions of the hydrocarbon generation history of BA and ER in Sinian and Cambrian strata respectively indicate: Hydrocarbon gases generation from ER started in the Middle Jurassic, and ended in the Early Cretaceous with a maturity equivalent to Easy%Ro≈2.2%. The final conversion rate of C1–5 and C1 are 0.71 and 0.48, respectively. Hydrocarbon gas generation from BA started in the Early Jurassic, and ended in the Early Cretaceous with an Easy%Ro≈3.0%. The final conversion rate of C1–5 and C1 are 0.90 and 0.81, respectively.

New Rock-Eval Method for Characterization of Unconventional Shale Resource Systems

Unconventional resources such as tight, fractured and hybrid shale gas and oil plays as well as oil or kerogen shale systems, are considered exploitable self-contained source and reservoir rocks. A better understanding of the thermal cracking of sedimentary organic matter, hydrocarbons generation, expulsion, storage and retention mechanisms constitutes a key point, estimating the oil and gas in-place, free or adsorbed, for their exploration and exploitation. Herein, we introduce a new ready to use method of analysis and interpretation for the Rock-Eval 6 device for better assessment of free or sorbed hydrocarbons in unconventional shale plays. This method was developed at IFP Energies nouvelles (France) and was tested on 15 actual or potential unconventional shale samples from Silurian Shale (Algeria), Mississippian Barnett Shale (USA), Early Jurassic Shale (France), Late Jurassic Bazhenov Shale (Russia) and Eocene Green River Shale at different thermal maturity stages. Results indicate a better quantification of free and/or sorbed hydrocarbons (Sh0 and Sh1 peaks) as well as a more accurate determination of the Rock-Eval T max maturity parameter.

Shale gas potential of the Lower Permian Gufeng Formation in the western area of the Lower Yangtze Platform, China

China is beginning to explore unconventional gas resources in the Lower Yangtze Platform. In the last two years, we conducted undiscovered hydrocarbon resource assessment to investigate the geological and geochemical characteristic of the Lower Permian Gufeng Formation, which is considered as one potential exploration layers in this area. Four outcrops and one well were used to determine the stratigraphic correlation, and 40 available samples were used for an analytical investigation.Because of continuous changes in the sedimentary environment, the “shale” of the Gufeng Formation not only includes black shale but also calcareous mudstone, silicalite, siliceous mudstone and carbonaceous shale. The thickness of the Gufeng Formation is between 0 m and 200 m, and it has two small depositional centers with an SW–NE strike on plane.The shale in the Gufeng Formation shows a high average TOC (total organic carbon) content of 3.41wt% (based on test of 40 samples), but the TOCs in different tract systems have significant differences (EHST-early highstand systems tract, average 9.85wt%; LHST-late highstand systems tract, average 0.96wt%; CS-condensed section, average 2.61wt%; TST-transgressive systems tract, average 0.76wt%). The shale is in the post-mature stage of thermal maturity (Tmax-temperature of maximum pyrolysis output = 339–518 °C) and is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance value, Ro = 1.24–1.99%). Clay minerals dominate the mineralogy followed by quartz minerals. Pyrite only is found in some samples of EHST, which is consistent with the presence of less anoxic conditions and lower levels of sediment dilution during sediment deposition.The EHST shale of the Gufeng Formation, which has a high content of organic carbon, tentatively could be regarded as a potential shale gas exploration target in this area. However, because the complex multistage tectonic background could have caused gas loss, the tectonic background and the hydrocarbon preservation condition must also be considered.

EVALUATION OF THE HYDROCARBON POTENTIAL, MINERAL MATRIX EFFECT AND GAS-OIL RATIO POTENTIAL OF OIL SHALE FROM THE KABALAR FORMATION, GÖYNÜK, TURKEY

The present study focuses on the evaluation of the hydrocarbon potential, retention effect of mineral matrix and the gas-oil ratio potential (GORP) of oil shale from the Kabalar Formation in the Goynuk area, Turkey, to assess the quality of its organic matter. The results of Rock-Eval pyrolysis generally suggest relatively high organic carbon content (TOC) for Kabalar oil shale, ranging from 1 to 13.23 wt%. These values are consistent with data on source rocks that may have a good to excellent source rock potential. The kerogen in Kabalar oil shale was characterized based on Hydrogen Index (HI) value, S2/S3 ratio, and organic petrographic studies. The results indicate that most of the studied samples are characterized as containing oil prone (type I and II kerogen) organic matter. The low spore color index (SCI) and high S2/S3 ratio with a commonly low Tmax (< 440 °C) demonstrate that most of the oil shale samples are in the immature to early mature stages of thermal maturity. After calculating the transformation ratio (TR), the oil shale samples were divided into mature (TR = 0.2) and immature (TR = 0) subdivisions in order to take the maturity effects on organic carbon content (TOC) and hydrocarbons retention into account and also select the appropriate GORP overlay. After correcting the mineral matrix effect in the immature subdivision, the mean HI value of the Kabalar Formation increased by about 268 and reached 855 mg HC/g TOC. Due to the relatively higher thermal maturity values, the mineral matrix effect is minimized in the mature subdivision. Based on GORP factor, the TOC(live) of Kabalar oil shale is composed only of oil prone material, which is in good agreement with the results inferred from organic petrographic and pyrolysis studies.

The biogenic methane potential of European gas shale analogues: Results from incubation experiments and thermodynamic modelling

Core samples from the Lower Jurassic Posidonia Shale (Lower Toarcian), Wealden black shales (both from the Lower Saxony Basin, northern Germany), and from the Cambrian–Ordovician Alum Shale (southern Sweden) have been investigated for their biogenic gas potential in incubation experiments. The sample set represents all stages of thermal maturity (from immature to overmature). Methane and to a higher degree carbon dioxide are generated from all samples by added microorganisms. In general, overmature samples (Rr>1.5%) show lowest gas generation rates. The highest generation rates for produced methane (up to 89μmolg−1day−1) and carbon dioxide (139μmolg−1day−1) were detected in immature Alum Shale samples, when different hydrocarbon-degrading inocula where added; whereas the lowest methane production rates were detected in Wealden sediments. The lightest δ13C values for produced methane and carbon dioxide have been detected in Posidonia Shale samples of oil window maturity. Such samples are some of the most sensitive for gas generation and exhibit the strongest decreases of hydrogen indices after incubation.Hydrogeochemical modelling of methane generation, fate and behaviour showed that methane formed during the early diagenesis got lost from Posidonia Shale, the mainly investigated shale in this study. As the mature Posidonia Shale is according to the incubation experiments still sensitive for gas generation, a production scenario of generically generated methane due to oil degradation is simulated. The basic conditions resemble the conditions in the Antrim Shale in the Michigan Basin. Gas production due to dewatering and pressure decrease results in an increase of the gas volumes coupled to a progressive enrichment of carbon dioxide in the produced gas. Moreover, calcite scaling may be the consequence during progressive production similar to the Antrim Shale in the Michigan Basin. Such calcite precipitation has been demonstrated to predominantly occur in natural samples at oil window maturity.

Source Rock Potential and Thermal Maturity of the Eocene Nanka Formation (Ameki Group) In Anambra Basin: An Appraisal of Ogbunike Reference Locality, South Eastern Nigeria

Source rock potential and thermal maturity of the Eocene Nanka Formation of Ogbunike,south eastern Nigeria was assessed in this research work.The rock-eval pyrolysis result recorded a value range of 0.04 to 0.11,0.44 to 1.32 and 0.44 to 0.49 forS1, S2 and S2/S3respectively. Production Index (PI) and Hydrogen Index (HI) results have a value range of 0.08 and 11.83 to 55.00 respectively. TheSoluble Organic Matter (SOM) has an average value of 0.013 wt. %(127.55ppm), while Total organic carbon (Toc) recorded a value range of 2.40wt. % to 4.50 wt. %. Thermal Alteration index (TAI) of +1 to -2 and Vitrinite reflectance (Ro %) of 0.2% to 0.3% was recorded. Particulate organic matter of the samples was also analysed. The results suggests that the studied area is a type 1VKerogen,immatured stage of thermal maturity, fair source bed,but has a high organic carbon that can generate oil

Changes in the composition of bitumen extracts and chemical structure of kerogen during hydrous pyrolysis

The paper presents data on the composition of biomarkers from bitumen extracts and the chemical structure of kerogen from Corg-rich sedimentary rocks before and after hydrothermal treatment in an autoclave at 300°C. Samples selected for this study are kukersite and Ordovician Dictyonema shale from the Baltics, Domanik oil shale from the Ukhta region, Upper Permian brown coal from the Pre-Ural foredeep, carbonaceous shale from the Oxfordian horizon of the Russian plate, and Upper Jurassic oil shales from the Sysola oil shale bearing region. The rocks contain type I, II, III, and II-S kerogens. The highest yield of extractable bitumen is achieved for Type II-S kerogen, whereas Type III kerogen produces the lowest amount of bitumen. The stages of organic matter thermal maturation achieved during the experiments correspond to a transition from PC2–3 to MC1–2. The 13C NMR data on kerogen indicate that the aromatic structures of geopolymers underwent significant changes.

Organic geochemistry, palynofacies and petroleum potential of the Mukalla Formation (late Cretaceous), Block 16, eastern Yemen

The late Cretaceous Mukalla Formation of the Mahra Group is present in the subsurface of eastern Yemen. The palynofacies, thermal maturation and hydrocarbon potential of this formation recorded from three exploratory wells in the Qamar Basin are discussed. Two of the wells are in the offshore part of Block 16 and one is in the onshore part. Both organic geochemical and palynofacies analyses indicate that the formation contains oil- and gas-prone kerogen. Rock-Eval pyrolysis and gas chromatography data show a peak thermal maturation stage for organic matter types II/III and III and good conditions for hydrocarbon generation and expulsion. Three major palynofacies types are identified through the succession. These indicate open marine, marginal- to shallow-marine and fluvio-deltaic environments, reflecting multiple marine transgressive and regressive phases during the period of deposition of the formation, which took place in a humid, subtropical to tropical climate.