High Levels Of Thermal Maturity Research Articles

Control of fracture toughness of kerogen on artificially-matured shale samples: An energy-based nanoindentation analysis

Understanding controls on mechanical properties of organic-rich shale is essential in exploration and successful production from hydrocarbon reservoirs. In previous works, most researchers have focused on the influence of thermal maturity and organic type on elastic and viscoelastic properties of organic matter. However, fracture toughness, an important parameter in engineering design, has been less investigated. In this study, shale samples with different thermal maturity were obtained by programmed heating. Then, the fracture toughness of organic matter in shale samples was measured using an energy-based nanoindentation method, and the influence of geochemical features was determined. Organic matter was classified as inertinite, vitrinite and bitumen, and the fracture toughness of tested organic matter was in the range of 0.023–0.081 MPa*m0.5. The results indicated that the fracture toughness of vitrinite increased with thermal maturity. Additionally, both the reduced modulus of vitrinite and bitumen increased, while the viscosity of all types of organic matter decreased, with higher levels of thermal maturity. Moreover, a comparison between mechanical parameters of artificially-matured samples, and those of natural samples, was conducted. The fracture toughness of organic matter obtained in this study is crucial for parameter estimation of fracture propagation and homogenization models.

Spatial evolution and temporal stability of hydrothermal processes at sediment-covered spreading centers: Constraints from Guaymas Basin, Gulf of California

The Guaymas Basin, Gulf of California is a hydrothermally active sediment-covered oceanic spreading center in the early stages of rifting. Hot-spring fluids were collected from its southern trough in 1998, 2003, and 2008 and analyzed for the concentration and isotopic composition of organic and inorganic aqueous species to assess subseafloor geochemical processes. Fluids discharged from the seafloor through hydrothermal edifices with measured temperatures of 91 to 317 °C. In general, fluids exiting larger structures were characterized by higher temperatures than fluids venting from smaller structures. Measured pH (25 °C) ranged from 5.7 to 7.1. Endmember fluids were characterized by near-zero concentrations of Mg and SO4, depletions in Na, and enrichments in K, Ca, and Cl relative to seawater, reflecting extensive interaction with sediment during circulation. Thermal maturation of sedimentary organic matter resulted in the addition of abundant ΣNH4+, ΣCO2, CH4, short-chain n-alkanes, and carboxylic acids to solution. Organic compounds added to fluids during recharge pass through high temperature deep-seated reaction zones and reach high levels of thermal maturity while others may be added by entrainment of lower temperature sedimentary pore fluids in hydrothermal upflow zones.The relative abundance of many organic compounds mobilized during hydrothermal alteration is consistent with metastable states of thermodynamic equilibrium that likely record subseafloor temperature conditions. The isotope composition of low molecular weight hydrocarbons and elevated concentrations of dissolved Cl suggest that temperatures may have exceeded the two-phase boundary for seawater and subsequently cooled before discharging at the seafloor. Periods of high temperature fluid-sediment or fluid-rock interaction followed by cooling may provide a mechanism for the aqueous mobilization and concentration of sulfide-forming metals in subseafloor mineral deposits. Fluid compositions have remained constant at the southern trough of Guaymas Basin for at least 26 years, indicating decadal stability in the physical and chemical conditions in subseafloor environments as well as the km-scale regional recharge zones containing unaltered sediment.

Hydrocarbon Potential of Middle Jurassic Sediments (Stefanets Mb. of Etropole Fm.) from the Western Part of Balkan Orogenic System, Bulgaria

Sediments of Stefanets Mb. (Etropole Fm.), consisting mainly of shale and siltstones, are investigated by Rock-Eval pyrolysis. The samples from the Middle Jurassic section (Bajocian in age), outcropping within the western part of the Balkan orogenic system in Bulgaria, were analyzed to study their hydrocarbon generative potential. The obtained TOC contents are in the range of 0.69–1.97 wt.%. Inorganic carbon (TIC) and total sulphur (TS) contents are low and coincide with previously published data. The values of S1 and S2 are between 0.01 and 0.10 (mg HC/g rock) because of the high thermal maturity level, as indicated by Tmax values of 566-610 °C. The rocks are in the postmature stage and consequently the HI values are very low (< 10 mg HC/g TOC). The fair to good quantity, low quality, as well as the high level of thermal maturity of the organic matter, assume minor remaining gas-prone generation potential of Stefanets Mb.

Raman analysis of a shocked planetary surface analogue: Implications for habitability on Mars

AbstractThe scientific aims of the ExoMars Raman laser spectrometer (RLS) include identifying biological signatures and evidence of mineralogical processes associated with life. The RLS instrument was optimised to identify carbonaceous material, including reduced carbon. Previous studies suggest that reduced carbon on the Martian surface (perhaps originating from past meteoric bombardment) could provide a feedstock for microbial life. Therefore, its origin, form, and thermal history could greatly inform our understanding of Mars' past habitability. Here, we report on the Raman analysis of a Nakhla meteorite analogue (containing carbonaceous material) that was subjected to shock through projectile impact to simulate the effect of meteorite impact. The characterisation was performed using the RLS Simulator, in an equivalent manner to that planned for ExoMars operations. The spectra obtained verify that the flight‐representative system can detect reduced carbon in the basaltic sample, discerning between materials that have experienced different levels of thermal processing due to impact shock levels. Furthermore, carbon signatures acquired from the cratered material show an increase in molecular disorder (and we note that this effect will be more evident at higher levels of thermal maturity). This is likely to result from intense shearing forces, suggesting that shock forces within basaltic material may produce more reactive carbon. This result has implications for potential (past) Martian habitability because impacted, reduced carbon may become more biologically accessible. The data presented suggest the RLS instrument will be able to characterise the contribution of impact shock within the landing site region, enhancing our ability to assess habitability.

Comparative Study on Hydrocarbon Generation in Different Tectonic Zones: A Case Study from the Upper Jurassic Naokelekan Formation at the Imbricated and High Folded Zones, Kurdistan Region, Iraq

The impact of tectonic activities from different tectonic zones on hydrocarbon generation in the Upper Jurassic Naokelekan Formation was addressed in this study. The Upper Jurassic Naokelekan Formation is an important potential of source rocks for hydrocarbon generation that charges most of the Cretaceous and younger reservoirs in the Kurdistan Region, Iraq. A total of 5 rock specimens from the Warte outcrop and 7 cutting samples from Well Bina Bawi-1 were collected for Rock-Eval pyrolysis to investigate the relationship between the ability of the formation to generate hydrocarbons and tectonic activities. The results of Rock-Eval analysis on the analyzed samples showed an average of 2.65 wt% and 0.9 wt% total organic carbon (TOC) for Warte and Well Bina Bawi-1, respectively. Based on the TOC data, the Naokelekan Formation, in general, has a good to very good source rock potential. The qualitative properties of the organic matter (OM) of the formation were inferred from the kerogen types. The Warte section mostly contains type III kerogen that is gas prone, whereas the Well Bina Bawi-1 section contains mixed type I-II kerogen that is oil prone. It should be taken into consideration that the values for the hydrogen index (HI) of the Warte section are unreliable for interpretation of the organic type, because the HI is considerably reduced owing to the high level of thermal maturity. The Tmax values showed that the Warte section is thermally more mature than the Well Bina Bawi-1 section. The difference in the thermal maturity can likely be attributed to the differential effects of the tectonic activities on the studied areas. Depending on the proximity or distance of the area in relation to the subduction zone, the sediments in the Imbricated Zone were more affected by the tectonic activities than the sediments in the High Folded Zone. Accordingly, the main factors that might have caused a higher thermal maturity in the Imbricated Zone include a high paleo heat flow, overthrusting, and hydrothermal activities.

Discussion about the contribution of water to the shale gas reserves within high-over matured shale rocks

The shale gas currently exploited in China is mainly featured by high thermal maturity level and the methane concentration is generally more than 95% (v/v). The H/C atomic ratios of residual kerogen gradually decreased with the maturity whereas the source of elemental hydrogen contribution to the shale gas generation within high-over matured shale rocks is still vague. In recent years, some work indicated that the methane generation and its hydrogen isotope characteristics were greatly affected by elemental hydrogen from external water at the over-mature stage in shale rocks. The significance of water should be probed in the processes of geochemical degradation of residual kerogen and hydrocarbon generation in shales. It will be very meaningful to perform the hydrous pyrolysis experiments with heavy water to quantitatively appraise the impact of water on the hydrocarbon generation within shale rocks. A better understanding of the role that water plays on the shale gas generation and enrichment can be hopefully attained.

Application of higher diamondoids in hydrocarbon mudrock systems

Diamondoids are ultra-stable geochemical tools applicable to both unconventional and conventional petroleum system analysis. Unlike classic geochemical parameters such as biomarkers, diamondoid stability to geological conditions makes them an ideal tool for deciphering petroleum generation, migration, and accumulation in the subsurface. A collection of hydrocarbon fluid samples and rock extracts were investigated using gas-chromatography triple quadrupole mass-spectrometry techniques for quantitative extended diamondoid analysis (QEDA). Applications of higher diamondoids shown here include: 1) identifying mixing of hydrocarbons having various thermal maturities in the STACK play of Oklahoma, 2) correlating high-maturity fluids to source-rocks in the Permian Basin of Texas, and 3) allocating unconventional petroleum production from the Eagle Ford Formation of Texas through time-series diamondoid analysis.Identifying sweet-spots and allocating produced hydrocarbons are crucial requirements for successful exploitation of unconventional hydrocarbon mudrock systems. Since produced fluids within the most economically successful unconventional reservoirs are at a high thermal maturity level, correlation and allocation of oils to various zones can be difficult. One reason is that classical biomarkers typically used for correlation are generally absent or in low concentrations. Here we show that the ultra-stable diamondoids provide a novel technique to fingerprint fluids in both unconventional and highly mature conventional plays.

Geological process of Late Paleozoic shale gas generation in the eastern Ordos Basin, China: Revelations from geochemistry and basin modeling

During the Meso-Cenozoic, the eastern Ordos Basin (EOB) underwent a complex tectonothermal process influenced by the destruction of North China Craton, significantly affecting the thermal maturation of the Late Paleozoic source rocks. Tectonothermal modeling and maturation of coal-bearing shales were performed in the EOB to reveal the geological process of shale gas generation. Organic geochemical data for shales show that TOC values vary from 0.96 wt% to 21.36 wt% and Ro values range from 1.56% to 2.47%, as well as that organic matter mainly consists of type III kerogen—indicating excellent potential, and sufficient maturity, for gas generation. Thermal modeling suggests that heat flow in the EOB significantly increased as a result of intense magmatic activities during the Yanshanian orogeny, with peak values of 108 and 128 mW/m2 in the northern and southern regions, respectively. Consequently, great variations in maturation history are seen in different regions of the EOB, with the Taiyuan and Shanxi shales reaching the wet gas and dry gas stages, respectively, in the northern region and all shales reaching the dry gas stage in the southern region. Hydrocarbons were generated at 237 Ma and peaked around 162 Ma, whereas hydrocarbon expulsion began at 230 Ma and peaked at 131 Ma. Rapid subsidence in the Triassic brought the shales to the oil generation window and Early Cretaceous magmatic activities led to rapid maturation of shales, again reaching the gas generation stage. Accordingly, extremely high levels of thermal maturity are well documented in hydrocarbons' alkane composition and stable carbon isotope ratio. Gas geochemical data (δ13C1 vs. C1/C2+3, δ13C1 vs. C2+) imply that that hydrocarbons are from highly mature thermogenic gas generated mainly from humus, and this offers great support for thermal maturation modeling. Regionally, coal-bearing shales have been steadily uplifted and eroded since the Late Cretaceous, causing partial destruction of gas reservoirs. The tectonothermal evolution and hydrocarbon generation of EOB were controlled primarily by magmatic thermal effects resulting from the westward subduction of the Pacific plate.

Hydrocarbon Vertical Continuity Evaluation in the Cretaceous Reservoirs of Azadegan Oilfield, Southwest of Iran: Implications for Reservoir Geochemistry

AbstractA collection of data obtained from analytical methods in geochemistry along with the reservoir engineering and geologic data were used to investigate the reservoir continuity in the Cretaceous Fahliyan, Gadavan, Kazhdumi and Sarvak reservoirs of the super‐giant Azadegan oilfield, SW Iran. The geochemical data indicate that the oil samples, with medium to high level of thermal maturity, have been generated from the anoxic marine marl/carbonate source rock(s). The Sargelu (Jurassic) and Garau (Cretaceous) formations are introduced as the main source rocks for the studied oils. The dendrogram obtained from the cluster analysis of high‐resolution gas chromatography data introduces two main oil groups including Fahliyan reservoir, and Kazhdumi along with Sarvak/Gadvan reservoirs. This is confirmed by C7 Halpern star diagram, indicating that, the light oil fraction from Fahliyan reservoir is distinct from the others. Also, different pressure gradient of the Fahliyan Formation (over‐pressured) relative to other reservoirs (normally‐pressured) show the presence of compartments. The relation between toluene/n‐heptane and n‐heptane/methylcyclohexane represents the compartmentalization due to maturation/evaporative fractionation for Fahliyan and water washing for other studied reservoirs. Also, the impermeable upper part of the Fahliyan Formation and thin interbedded shaly layers in the Kazhdumi, Sarvak and Gadvan formations have controlled reservoir compartmentalization.

DIAMONDOIDS AND BASIN MODELLING REVEAL ONE OF THE WORLD'S DEEPEST PETROLEUM SYSTEMS, SOUTH CASPIAN BASIN, AZERBAIJAN

The South Caspian Basin has been one of the world's most prolific petroleum provinces since the 19th Century. However, despite the large number of discovered petroleum accumulations, the source rock sequence has not been penetrated by the drill in the offshore basin and is therefore poorly defined. In this paper, geochemistry together with broad estimates of in‐place volumes of petroleum fluids, onshore outcrop data and basin modelling have been used to place constraints on the source rock description.Diamondoids, the most thermally stable group of hydrocarbons, have been measured in a suite of liquid petroleum samples from Pliocene fluvio‐deltaic sandstone reservoirs at the Shah Deniz gas‐condensate field and the Azeri‐Chirag‐Gunashli oil field, offshore Azerbaijan. Samples from both fields exhibit elevated concentrations of diamondoids and C29 steranes, indicating a mixture of thermally cracked and non‐cracked petroleum. We use diamondoid concentrations to estimate that 4.8 B brl of oil may have been cracked to 12 Tcf of gas below the Shah Deniz reservoirs. Source rock properties from the outcropping Oligocene – Miocene Maikop and Diatom Formations have been used to model source rock maturation. The results indicate that pre‐cracking volumes of petroleum could be explained reasonably by the presence of source rock intervals in the offshore that are of similar richness but increased thickness compared to measured onshore outcrops.Relatively high diamondoid concentrations in Shah Deniz condensate (up to 160 ppm 3‐ + 4‐methyldiamantanes) are in agreement with gas isotope compositions (δ13C1 – δ13C3) with respect to thermal maturity. Both parameters indicate the presence of source rock that is at a high level of thermal maturity at a vitrinite reflectance equivalent (VRE) of ca. 1.5–2.0% Ro. Given the low geothermal gradients in the South Caspian Basin (16 – 17°C/km at Shah Deniz) and the relatively high temperatures required for maturation due to rapid, relatively recent burial and heating, the source rock must be buried to depths in excess of 13 km in the Shah Deniz drainage area. In the absence of any evidence of a working Mesozoic petroleum system in the South Caspian Basin, this depth of burial highlights the significant thickness of Paleogene sediments in the offshore basin. Of prolific petroleum‐producing basins, only in the deep‐water Gulf of Mexico are actively‐generating source rocks buried to similar depths.

Burial and thermal history of the Upper Silesian Coal Basin (Poland) constrained by maturity modelling – implications for coalification and natural gas generation

Maturity modelling was carried out using basin and petroleum system modelling (BPSM) software in the lithologic sections of 17 wells of the Upper Silesian Coal Basin (Poland). The best fit between calculated and measured vitrinite reflectance (VR), porosity and density data was obtained by applying a thickness of eroded sedimentary overburden from 1700 m in the east to 4500 m in the west and relatively low to moderate heat flow values during the maximum late Carboniferous burial. These heat flow values were in the range 50–71 mW/m 2 , most likely owing to rapid deposition of molasse sediment that led to a downward deflection of the isotherms. The upper Carboniferous strata were heated to temperatures in the range c. 90–170 °C, which is in accordance with the moderate to high levels of thermal maturity of these rocks (c. 0.6–1.7%VR). The coal rank pattern was reached before the Variscan tectonic inversion at the transition between the Carboniferous and the Permian (c. 300 Ma). This coalification level was not overprinted by any later thermal processes. The coalification resulted in the generation of natural gases. The upper Carboniferous strata are characterized by early to late phases of hydrocarbon generation. The kerogen transformation ratio (c. 5–75%TR) values vary across the basin. Most coals generated significant amounts of hydrocarbons, which reached over 80 mg of methane per gram of total organic carbon. Although most hydrocarbons generated most likely were lost during the intense post-Variscan exhumation, the hydrocarbon potential of the basin is still substantial.

Pyrolysis analysis, organic petrology and thermal effects of volcanics on Bima Formation shales, Yola Sub-basin, Northern Benue Trough, Nigeria

The shale sediments of Bima Formation from the Yola Sub-basin of the Northern Benue Trough, northeastern nigeria were studied based on pyrolysis analysis (rock-eval pyrolysis) and organic petrology (vitrinite reflectance and palynofacies) to determine the thermal effects of Tertiary (Neogene) volcanics on the organic matter thermal maturity. The study revealed that shale samples are of Type III and Type IV kerogens. This indicates high thermal maturity level and classified the samples as late-oil window to post-mature stage of hydrocarbon generation. This high thermal maturity could be attributed due to the Tertiary volcanic intrusion in most part of the basin. The samples however, appeared as a good source of oil- and gas-prone hydrocarbons. This study therefore, suggests that, the initial oil and gas-prone of the Type II and II-III kerogens in the shales have been cracked into thermogenic gas probably due to the high thermal effects of Tertiary volcanic intrusion in the basin. This has yield the present-day Types III and IV kerogens. The volcanic plugs however, intruded the Cretaceous sedimentary successions of the Northern Benue Trough during the Tertiary period and as such, they enhanced thermal maturity of the organic matters within the shale samples.

Geochemical characterization and methane adsorption capacity of overmature organic-rich Lower Cambrian shales in northeast Guizhou region, southwest China

The Niutitang Shale (Lower Cambrian) is another set of organic-rich shale in addition to the Lower Silurian Longmaxi Shale in southwest China. In this study, methane adsorption capacities of both whole rock and organic matter were investigated based on adsorption isotherms measured at various temperatures (40–120 °C) and pressures (up to 35.0 MPa) for eleven Niutitang Shale samples collected from northeast Guizhou Province. The investigated samples cover a wide range of TOC contents, varying from 1.8 to 11.3%, with an average equivalent vitrinite reflectance (EqVRo) value of approximately 4.0%; their BET specific surface areas and micropore volumes range from 11.1 to 26.2 m2/g rock and between 4.3 and 11.2 cm3/kg rock, respectively, both of which are positively correlated to TOC content. Model-fitted methane maximum absolute adsorption capacities (n∞) range from 1.80 to 5.85 cm3/g rock at 60 °C and are found to largely increase with increasing TOC; this suggests that the TOC control on methane adsorption capacity obtained by other authors for other shales with relative low thermal maturity levels may be extended to a very high thermal maturity level, e.g., EqVRo≈4.0%. The methane adsorption capacity of organic matter (OM) in our shale samples, however, is somehow reduced as compared to the Lower Silurian Longmaxi Shale and other shales that display EqVRo values smaller than 3.0%, indicating thermal maturity may adversely affect methane adsorption capacity of shales when it evolves to be EqVRo≈4.0%. Nevertheless, this reduction in adsorption capacity may be compensated by the very enrichment of OM in the Niutitang Shale. In addition, a higher thermal maturity level results in a lower Langmuir pressure value, which makes it more difficult for methane desorption at reservoirs conditions. The temperature dependency of adsorption parameters was also investigated, which could be used to predict the changes of methane adsorption with burial depth under geological conditions beyond experimental temperature and pressure ranges.

Geochemical characterization of the Jurassic Amran deposits from Sharab area (SW Yemen): Origin of organic matter, paleoenvironmental and paleoclimate conditions during deposition

Calcareous shales and black limestones of the Jurassic Amran Group, located in the Sharab area (SW Yemen), were analysed based on organic and inorganic geochemical methods. The results of this study were used to reconstruct the paleoenvironmental and paleoclimatic conditions during Jurassic time and their relevance to organic matter enrichment during deposition of the Amran calcareous shale and black limestone deposits. The analysed Amran samples have present-day TOC and Stotal content values in the range of 0.25–0.91 wt % and 0.59–4.96 wt %, respectively. The relationship between Stotal and TOC contents indicates that the Jurassic Amran deposits were deposited in a marine environment as supported by biomarker environmental indicators. Biomarker distributions also reflect that the analysed Amran deposits received high contributions of marine organic matter (e.g., algal and microbial) with minor amount of land plant source inputs. Low oxygen (reducing) conditions during deposition of the Jurassic Amran deposits are indicated from low Pr/Ph values and relatively high elemental ratios of V/Ni and V/(V + Ni). Enrichment in the pyrite grains and very high DOPT and high Fe/Al ratios further suggest reducing bottom waters. This paleo-redox (i.e., reducing) conditions contributed to preservation of organic matter during deposition of the Jurassic Amran deposits. Semi-arid to warm climatic conditions are also evidenced during deposition of the Amran sediments and consequently increased biological productivity within the photic zone of the water column during deposition. Therefore, the increased bio-productivity in combination with good preservation of organic matter identified as the major mechanisms that gave rise to organic matter enrichment. This contradicts with the low organic matter content of the present-day TOC values of less than 1%. The biomarker maturity data indicate that the analysed Amran samples are of high thermal maturity; therefore, the low present-day TOC is attributed to the thermal effect on the original organic matter. This high thermal maturity level is due to the presence of volcanic rocks, which have invaded the Jurassic rocks during Late Oligocene to Early Miocene.

Organic geochemistry of crude oils from the Intisar oil field (East Sirte Basin, Libya)

Four crude oil samples from the oil fields Intisar A, Intisar D and Intisar E (Sirte Basin, Libya) were investigated in order to define depositional environment, lithology, thermal maturity and geologic age of the corresponding source rocks. Saturated biomarkers (n-alkanes, isoprenoids, steranes and triterpanes) were determined using gas chromatography – mass spectrometry (GC–MS) and gas chromatography – mass spectrometry – mass spectrometry (GC–MS–MS). Aromatic hydrocarbons (phenanthrene, methylphenanthrenes, methyl-dibenzothiophenes and trimethyl-naphtalenes) were analyzed by GC–MS.The Intisar crude oils were generated from siliciclastic source rocks containing a mixture of marine and terrestrial organic matter. Maturation parameters indicated high level of thermal maturity corresponding to the main phase of oil generation. The analysis of the age-specific biomarker ratios suggested Cretaceous, most probably Lower Cretaceous age for the Intisar oils. Two source rocks for the Intisar oils were identified, similar in the precursor organic matter type, lithology, maturity and geologic age but different in the redox conditions in the environment during their deposition. The oils generated from these different sources probably migrated over different migration pathways.

Pore characteristics of shale gas reservoirs from the Lower Paleozoic in the southern Sichuan Basin, China

Data was acquired from both the drillings and core samples of the Lower Paleozoic Qiongzhusi and Longmaxi Formations' marine shale gas reservoirs in the southern Sichuan Basin by means of numerous specific experimental methods such as organic geochemistry, organic petrology, and pore analyses. Findings helped determine the characteristics of organic matter, total porosity, microscopic pore, and pore structure. The results show that the Lower Paleozoic marine shale in the south of the Sichuan Basin are characterized by high total organic carbon content (most TOC>2.0%), high thermal maturity level (RO = 2.3%–3.8%), and low total porosity (1.16%–6.87%). The total organic carbon content and thermal maturity level of the Qiongzhusi Formation shale are higher than those of the Longmaxi Formation shale, while the total porosity of the Qiongzhusi Formation shale is lower than that of the Longmaxi Formation shale. There exists intergranular pore, dissolved pore, crystal particle pore, particle edge pore, and organic matter pore in the Lower Paleozoic Qiongzhusi Formation and Longmaxi Formation shale. There are more micro-nano pores developed in the Longmaxi Formation shales than those in the Qiongzhusi Formation shales. Intergranular pores, dissolved pores, as well as organic matter pores, are the most abundant, these are primary storage spaces for shale gas. The microscopic pores in the Lower Paleozoic shales are mainly composed of micropores, mesopores, and a small amount of macropores. The micropore and mesopore in the Qiongzhusi Formation shale account for 83.92% of the total pore volume. The micropore and mesopore in the Longmaxi Formation shale accounts for 78.17% of the total pore volume. Thus, the micropores and mesopores are the chief components of microscopic pores in the Lower Paleozoic shale gas reservoirs in the southern Sichuan Basin.

Hydrocarbon maturation modeling of Paleocene to Lower Miocene source rocks in the Niger Delta Basin: implications for hydrocarbon generation

This study evaluates the hydrocarbon generation potentials and time of generation for Paleocene to Lower Miocene source rock horizons from A-1, B-1, B-2, and C-1 wells in the Niger Delta Basin using 1D Petromod modeling software. Wells A-1, B-1 and B-2, and C-1 are located within the Central Swamp, the Coastal Swamp, and the Shallow Offshore depobelts, respectively. The thermal history was derived from the rifting–subsidence heat flow model. Maturity modeling were carried out by using Easy%Ro kinetic model and a heat flow history predicting present-day heat flow which were calibrated with measured temperature data. Results of the study suggest that these potential source rocks have attained maturity status to generate hydrocarbons, with vast differences existing in the timing of the onset of oil generation. Basin modeling suggests that Paleocene source rocks entered the oil generative window from the Oligocene to Miocene times with thermal maturity window that varies from gas generation to early-mature phase. The Eocene source rocks have also attained maturity from Miocene to Pliocene times, and their thermal maturity ranges from gas generation to early maturity stage. The Oligocene source rocks also began to generate oil during the Miocene and are currently within the early-mature to mid-mature stage. The thermal maturity window for the Lower Miocene source rocks ranges from immature to early-mature stage. The present modeling results reveals that higher levels of thermal maturity are attained in areas with high geothermal gradients and heat flow values while the cooler areas exhibits lower levels of maturation. The onset of the oil window lies at 2859 m at A-1 (Central Swamp), 3240 m at B-2 (Coastal Swamp), 4732 m at B-1 (Coastal Swamp), and 4344 m at C-1 (Shallow Offshore). The depth to the onset of oil window is found deeper in the Shallow Offshore and western parts of the study area than in the eastern and northwestern parts. The result of this study suggest that the Paleocene, Eocene, Oligocene, and Lower Miocene source rocks are the principal source rocks for oil and gas generation in the Niger Delta Basin.

Accumulation conditions of Lower Paleozoic shale gas from the southern Sichuan Basin, China

Based on the raw data of the organic-rich shale in the Lower Cambrian Qiongzhusi Formation and Lower Silurian Longmaxi Formation which were collected from the drilling core, we investigated the accumulation conditions of the Lower Paleozoic marine shale gas in the southern Sichuan Basin, China. The results indicate that the Qiongzhusi and the Longmaxi Formations' black shales in this region are mainly deposited in the deep water shelf sedimentary environment. Both the Qiongzhusi and Longmaxi Formations in the southern Sichuan Basin have great organic-rich shale thickness (mainly 50–300 m). The marine shales of the Qiongzhusi and the Longmaxi Formations are characterized by high total organic carbon contents (average TOC>2%), I–II1 kerogen types, highthermal maturity level (equivalent RO>1.9%), abundant rich brittle mineral (average > 50%), micro- and nanometer pore development, as well as high gas content of shale (average > 1.8 m3/t). All these features are favorable for marine shale gas generation and enrichment in the southern Sichuan Basin. Compared to the Barnett shale in North America, in which shale gas has been explored and developed successfully, it is suggested that the Lower Paleozoic in the southern Sichuan Basin would possess good conditions for shale gas accumulation. Therefore, the Qiongzhusi and the Longmaxi Formations are considered as potential targets for marine shale gas exploration, and favorable areas for shale gas enrichment are also purposed. The favorable areas for shale gas enrichment for the Qiongzhusi Formation in the southern Sichuan Basin are the Zhigong-Yibin, Changning-Gongxian, Jianwei-Muchuan, and Weiyuan areas. The favorable areas for shale gas enrichment for the Longmaxi Formation in the southern Sichuan Basin are the Longchang-Rongchang, Yibin-Luzhou-Changning, and Weiyuan areas.

Petroleum source, maturity, alteration and mixing in the southwestern Barents Sea: New insights from geochemical and isotope data

The Hammerfest Basin (HB) is an important area for petroleum exploration in the southwestern Norwegian Barents Sea. This contribution is aimed to characterize oils and condensates hosted in Triassic and Jurassic reservoirs, establish genetic relationships and to assess maturity, mixing and petroleum alteration processes. The research was based on geochemical as well as bulk and compound-specific stable carbon and hydrogen isotope analyses of oil and condensate samples from all major fields and discoveries in the HB, including extracts from Jurassic and Triassic source rocks. Interpretations of light hydrocarbon composition and isotope data clearly identify four main petroleum groups affected by microbial degradation, water washing, evaporative fractionation and high thermal maturity level. Based on polycyclic aromatic hydrocarbons (PAHs), marine and higher-plant-derived biomarkers and carbon isotopic composition (δ13C) of individual petroleum hydrocarbons, four petroleum families (I–IV) are recognized in the HB and a distinction can be made among oils and condensates from different stratigraphic levels and sectors of the Basin. Most oils and condensates from the HB consist of mixtures with small maturity variations; however, oils from Middle Triassic reservoirs in the Goliat field showed larger maturity variations according to biomarker, PAH and light hydrocarbon–maturity ratios. In the HB, geochemical and isotopic data allowed unraveling mixtures of hydrocarbons derived mainly from Jurassic, Triassic and Paleozoic source rocks.

Lithological dependency and anisotropy of vitrinite reflectance in high rank sedimentary rocks of the Ibbenbüren area, NW-Germany: Implications for the tectonic and thermal evolution of the Lower Saxony Basin

Covering a depth interval of 1200m thirty-one rock samples were collected from a well drilled in the Beust Field of the Ibbenbüren anthracite mine, Lower Saxony Basin, NW-Germany. These rock samples consist of high rank coals/anthracites, claystones, siltstones and sandstones of Pennsylvanian age. Analytical methods include the measurement of random vitrinite reflectance VRr, rotational reflectance VRrot as well as maximum and minimum reflectances VRmax and VRmin, enabling the evaluation of the lithological influence on vitrinite reflectance as well as the indication of tectonic stresses in the Lower Saxony Basin by applying the RIS (reflectance indicating surface) analysis method. This study shows that not only due to the high rank of the studied samples and associated anisotropic character but also due to lithological dependency a partially significant scatter of measured VRr can be observed. The scatter in coals is significantly less than in other sedimentary rocks, e.g., standard deviation in coals can be up to 7× less than in siltstones. The expected increase of standard deviation with increasing rank and accordant anisotropy was not observed for VRr but rather for VRmax with the exception of coals displaying a relatively constant and low deviation throughout the depth/maturity interval. Mean VRr values of coals differ from those of other sedimentary rocks at equal depths. VRr measured in claystones is consistently higher compared to associated coal seams and can be elevated by up to 10%. Silt- and sandstones always display lower VRr with differences of up to 16%.At very high levels of thermal maturity, vitrinite reflectance depends not only on maximum paleotemperature but also on lithology leading to differences in pressure propagation and thus deformation. Additionally, radioactive trace elements in coals and organic matter-rich claystones provide a local secondary heat source. 40K and 232Th are preferentially bound to clay particles which are enriched in the studied claystones and depleted in the silt- and sandstones possibly leading to higher vitrinite reflectance observed in the claystones.RIS analysis shows a predominantly negative biaxial distribution indicating the absence of thermal overprinting by a possible intrusion (Bramsche Massif) during the Late Cretaceous which would have induced a uniaxial distribution. Instead, this implies, in addition to vertical stresses due to depositional loading, the presence of a secondary stress field not perpendicular to bedding which is related to the inversion of the Lower Saxony Basin. This information presents, in combination with previous basin modeling results, additional evidence for deep subsidence with subsequent uplift being the cause for the present-day maturity patterns observed in the Lower Saxony Basin.