Petroleum Source Rocks Research Articles

Rare earth element geochemistry of petroleum source rocks from northwestern Niger Delta

Geochemical investigation of forty two rock samples from three fields in the northwestern Niger Delta was carried out in order to determine their rare earth elements (REEs) content and their geochemical significances. The rare earth elements and trace elements in the rock samples were determined using inductively coupled plasma – mass spectrometry (ICP-MS) and instrumental neutron activation analysis (INAA). The results indicate that nickel is most abundant trace elements in ML field while cobalt is most abundant in MF and MJ fields. Vanadium had the least concentration in the three fields. Nickel had enhanced concentrations over vanadium in the three fields. The concentrations and ratios of the trace elements indicated that the source rocks in the three fields had strong terrestrial organic matter input and were deposited under oxic conditions. Gadolinium is the most abundant rare earth element in three fields. Neodymium had the least concentration in ML and MJ fields while praseodymium had the least concentration in MF field. The REE distribution patterns of source rocks from the three fields are similar, indicating similar genetic origin. Pearson correlation matrix revealed that europium, dysprosium, lanthanum and samarium are potential redox and source indicators.

Egypt far Western Desert basins petroleum charge system as defined by oil chemistry and unmixing analysis

Source rock analysis and maturity modeling in Egypt’s Far Western Desert basins indicates that several Jurassic and Cretaceous petroleum source rocks could be mature and expelling hydrocarbons over much of the area. Highly variable oil characteristics suggest that more than one charge system may be present. Reservoir crude oil chemistry indicates that the fluids originated from a single source facies generated over a wide range of organic maturity. Secondary alteration mechanisms include water washing, biodegradation, and evaporative fractionation. Crude oils in the upper reservoirs tend to be most affected by biodegradation and water washing. Condensates and light crude oils in the deepest reservoirs appear to be the residual phase from evaporative fractionation.The broad variation in fluid properties and chromatogram character can be attributed to a multi end-member mixing system: early mature waxy oil, later high maturity volatile oil, low level biodegradation, migrated phase evaporative fractionation, and residual phase evaporative fractionation. A statistical “unmixing” algorithm was used to determine end-member compositions and relative mixing proportions for each crude oil sample. Remigration and mixing of the products from multi-phase generation and alteration results in complex reservoir fluid compositions, such that no single reservoired oil represents a compositional end-member, rather the oil samples are mixtures of various amounts of multiple end-members. Mixing proportions show regional trends and variations in different reservoirs within a single field. The crude oil geochemical data and unmixing analysis support a complex charge history from a single source rock, rather than mixing of oils from two source rocks.

Paleoproductivity and paleoredox condition of the Huai Hin Lat Formation in northeastern Thailand

The petroleum exploration has been conducted in the Khorat Plateau since 1962 and two gas fields have been discovered and commercially produced. The lacustrine facies of the Huai Hin Lat Formation is believed to be one of the main source rocks of the gas. Therefore, investigation and analysis of the Huai Hin Lat shale for understanding the paleoenvironment and petroleum source rock are carried out in this study. Petrographical study and geochemical analysis of shale samples were performed to explain the paleoproductivity and past redox condition. The palynofacies assemblage comprises abundant AOM, acritarchs, phytoclasts, and very small amount of spores and pollen. Geochemical analysis was used to determine the total organic carbon (TOC) and the concentration of major, trace, and rare earth elements. The paleoproductivity proxies are composed of palynofacies, TOC, excess SiO2, Ba/Al, and P/Al. They reflect a high paleoproductivity except the middle of the lower part (bed 3) and the lower bed 13 of the upper part. Bed 3 shows the highest peak of TOC and the lower bed 13 exhibits a relatively lower TOC, which can be explained by the excellent and the poorer preservation condition, respectively. The paleoredox proxies consist of U/Th, V/Cr, NiCo, (Cu+Mo)/Zn, Ni/V, and Ce anomaly. They are used to establish the depositional environments, to characterize the organic matter content, and to assess the source rock potential. They reflect many high peaks and predominantly high values of paleoredox proxies except the middle part and the lower bed (lower bed 13) of the upper part. They indicate that the section was mainly under anoxic or reducing condition, which is supported by the high Ce/Ce* (>0.8) and V/Cr (>2.0) values. The middle of the lower part (bed 3) shows lower productivity but it contains the highest peak of TOC, which is conformed to be the excellent preservation of organic matters in the strong reducing condition. The middle part, which shows high productivity, contains relatively lower TOC as it possesses a less reducing condition compared to the more reducing intervals. The lower bed 13 of the upper part shows a less reducing condition and a lower TOC, which conforms to a lower productivity. The organic matters of the Huai Hin Lat Formation consist mainly of AOM and acritarchs and possess good to excellent TOC (2%–7%). They belong mainly to type I and type II kerogens with some mixture of type III as indicated by the presence of phytoclasts, spores, and pollen. The organic matters of the Huai Hin Lat Formation, based on the kerogen type and the thermal history, have already generated significant amount of oil and some gas to the Sap Phlu Basin.

Artificial thermal maturation of source rocks at different thermal maturity levels: Application to the Triassic Montney and Doig formations in the Western Canada Sedimentary Basin

Artificial thermal maturation of petroleum source rocks is widely performed by either open- or closed-system pyrolysis. These experiments are performed usually on immature source rock or isolated kerogen samples to quantify petroleum generation potential and to calculate kinetic parameters. Here, we characterize a maturation series from the Triassic Montney and Doig formations in the Western Canada Sedimentary Basin (WCSB), in order to investigate the evolution of the source rock properties and their corresponding kerogen kinetic parameters as a function of the thermal maturity. Organic petrography determined the thermal maturity and the spatial distribution of organic matter particles. Rock-Eval Shale Play analyses were then applied to assess the presence of both free and sorbed hydrocarbons still contained in the sample as well as the hydrocarbon generation potential. Based on vitrinite reflectance values, three kerogen samples from the Doig Formation and one kerogen sample from the Montney Formation at different thermal maturity levels were selected for analysis of bulk kinetic parameters (e.g., activation energy distribution, frequency factor) using programmed open-system pyrolysis. Additionally, we evaluated the type of hydrocarbons and determined the molecular composition of organic compounds that comprise the first two Rock-Eval peaks (Sh0 and Sh1) obtained during the improved thermovaporization. TD–GC–MS–FID analyses were carried out on rock samples sequentially from 100°C to 200°C and then from 200°C to 350°C in order to characterize the composition of hydrocarbons represented by each Rock-Eval Shale Play peak. Free and sorbed low-to-medium molecular weight aliphatic and aromatic hydrocarbons (<C20) are the main hydrocarbon components released in the temperature range corresponding to the Rock-Eval Shale Play Sh0 parameter. Medium and high-molecular weight hydrocarbons (C10–C30 aromatics and saturates) are predominant components thermally released in the temperature range corresponding to the Rock-Eval Shale Play Sh1 parameter. Results show both an increasing activation energy and loss of petroleum generation potential as thermal degradation proceeds. The Shale Play method has been developed to better discriminate the generated fluids (Sh0+Sh1) from the residual kerogen (Sh2) providing a more accurate Rock-Eval Tmax. Sh0 and Sh1 parameters also offer a practical way for an early estimate of oil in place.

Petroleum source rock evaluation of the Alum and Dictyonema Shales (Upper Cambrian–Lower Ordovician) in the Baltic Basin and Podlasie Depression (eastern Poland)

We present geochemical characteristics of the Lower Palaeozoic shales deposited in the Baltic Basin and Podlasie Depression. In the study area, this strata are represented by the Upper Cambrian–Lower Ordovician Alum Shale recognized in southern Scandinavia and Polish offshore and a equivalent the Lower Tremadocian Dictyonema Shale from the northern Estonia and the Podlasie Depression in Poland. Geochemical analyses reveal that the Alum Shale and Dictyonema Shale present high contents of organic carbon. These deposits have the best source quality among the Lower Palaeozoic strata, and they are the best source rocks in the Baltic region. The bituminous shales complex has TOC contents up to ca. 22 wt%. The analysed rocks contain low-sulphur, oil-prone Type-II kerogen deposited in anoxic or sub-oxic conditions. The maturity of the Alum and Dictyonema Shales changes gradually, from the east and north-east to the west and south-west, i.e. in the direction of the Tornquist-Teisseyre Zone. Samples, located in the seashore of Estonia and in the Podlasie region, are immature and in the initial phase of “oil window”. The mature shales were found in the central offshore part of the Polish Baltic Basin, and the late mature and overmature are located in the western part of the Baltic Basin. The Alum and Dictyonema Shales are characterized by a high grade of radioactive elements, especially uranium. The enrichment has a syngenetic or early diagenetic origin. The measured content of uranium reached up to 750 ppm and thorium up to 37 ppm.

Evaluation of shale gas potential of Cambrian Jiulaodong Formation in Wei-201 well block in Sichuan Basin, China

The Cambrian Jiulaodong Formation of the Wei-201 well block in the Sichuan Basin was investigated for shale gas potential. In the subsurface, the thermally mature formation attained a stable thickness of 234 m encompassing an area of approximately [Formula: see text] and representing a potential gas resource. The total gas content measurements from canistered samples was more than the estimated total gas storage capacity of the free gas, absorbed gas, and gas dissolved in water and in oil. The canister gas content ranged between 0.971 and [Formula: see text] and averaged [Formula: see text]. The average estimated gas in place was 2.5 billion cubic meters for the formation in the Weiyuan area. Reflectance measurements for thermal maturity range between 2.60% and 3.06% and average 2.84%. The results of our total organic carbon content (TOC) content analysis conducted on the core shale samples indicate that the TOC content of the formation ranges from 0.87% to 3.57% and averages 2.2%. The mineral composition of marine mudstone formation of the Jiulaodong shale is relatively consistent. Brittle mineral content increases with organic carbon content and is approximately 32%–43%, of which quartz content is 29%–40% with a very low amount of clay mineral as the mixed layer. The amount of illite-smectite ranges from 0% to 1% and the brittleness index range from 37% to 62% and average 57.1%. The Cambrian Jiulaodong Formation ha very good petroleum-source rock potential due to its average TOC content of greater than 2%, average canister gas content of [Formula: see text], good type I kerogen, high maturity with average 2.84% of source rocks that are characterized by a fairly high abundance of organic matter increasing from top to bottom and a large thickness of 234 m. Natural fractures, cracks, and pores developed in the Jiulaodong Formation also provide space for shale gas storage, and its average brittleness index is greater than 57%, which is good for fracability.

Organic geochemical and petrographic characteristics of the oil shales in the Lajjun area, Central Jordan: Origin of organic matter input and preservation conditions

Oil shales, located in Lajjun area (Central Jordan), were analyzed based on organic geochemistry, coupled with microscopical study to define the origin, type of organic matter input, and the influencing factors that govern organic matter (OM) enrichment, including the OM preservation conditions. Oil shales are thermally immature petroleum-source rocks for oil that require artificial heating to generate oil of commercial value. The analyzed oil shales have high total sulfur content values in the range of 2.08–4.06wt%, and the organic carbon contents are also consistently high (>10%). The high total sulfur content and its relation with organic carbon values indicate that the Jordanian oil shales were deposited in a marine environment under reducing conditions. The organic matter input and paleoenvironmental conditions have also been evidenced from their biomarker distributions and microscopic study. The microscopical investigation indicated that the oil shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous) and planktonic foraminifera). The presence of these liptinitic materials and planktonic foraminifera assemblages in the oil shale samples, further suggests a marine origin. Their biomarkers also provide evidence for a high contribution of marine plankton/algal and microorganisms and persevered under highly hypersalinity reducing conditions. The good preservation under reducing conditions contributes to the high amounts of organic matter enrichment during deposition of these oil shale sediments. Consequently, the Jordanian oil shales have very good oil generative potential, owing to high content of hydrogen rich Type I/II oil-prone kerogen.

Thermal maturity history and petroleum generation modelling for the Lower Cretaceous Abu Gabra Formation in the Fula Sub-basin, Muglad Basin, Sudan

Two petroleum source rock intervals of the Lower Cretaceous Abu Gabra Formation at six locations within the Fula Sub-basin, Muglad Basin, Sudan, were selected for comprehensive modelling of burial history, petroleum maturation and expulsion of the generated hydrocarbons throughout the Fula Sub-basin. Locations (of wells) selected include three in the deepest parts of the area (Keyi oilfield); and three at relatively shallow locations (Moga oilfield). The chosen wells were drilled to depths that penetrated a significant part of the geological section of interest, where samples were available for geochemical and source rock analysis. Vitrinite reflectances (Ro %) were measured to aid in calibrating the developed maturation models.The Abu Gabra Formation of the Muglad Basin is stratigraphically subdivided into three units (Abu Gabra-lower, Abu Gabra-middle and Abu Gabra-upper, from the oldest to youngest). The lower and upper Abu Gabra are believed to be the major source rocks in the province and generally contain more than 2.0 wt% TOC; thus indicating a very good to excellent hydrocarbon generative potential. They mainly contain Type I kerogen. Vitrinite reflectance values range from 0.59 to 0.76% Ro, indicating the oil window has just been reached. In general, the thermal maturity of the Abu Gabra source rocks is highest in the Abu Gabra-lower (deep western part) of the Keyi area and decreases to the east toward the Moga oilfied at the Fula Sub-basin.Maturity and hydrocarbon generation modelling indicates that, in the Abu Gabra-Lower, early oil generation began from the Middle- Late Cretaceous to late Paleocene time (82.0–58Ma). Main oil generation started about 58 Ma ago and continues until the present day. In the Abu Gabra-upper, oil generation began from the end of the Cretaceous to early Eocene time (66.0–52Ma). Only in one location (Keyi-N1 well) did the Abu Gabra-upper reach the main oil stage. Oil expulsion has occurred only from the Abu Gabra-lower unit at Keyi-N1 during the early Miocene (>50% transformation ratio TR) continuing to present-day (20.0–0.0 Ma). Neither unit has generated gas. Oil generation and expulsion from the Abu Gabra source rocks occurred after the deposition of seal rocks of the Aradeiba Formation.

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin, eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.

Petroleum source rock potential of the Silurian Dadaş shales in the Hazro and Korudağ regions of Southeast Anatolia, Turkey

Shales of the Silurian Dadaş Formation exposed in the southeast Anatolia were investigated by organic geochemical methods. The TOC contents range from 0.24 to 1.48 wt% for the Hazro samples and 0.19 to 3.58 wt% for the Korudağ samples. Tmax values between 438 and 440 °C in the Hazro samples indicate thermal maturity; Tmax values ranging from 456 to 541 °C in the Korudağ samples indicate late to over-maturity. Based on the calculated vitrinite reflectance and measured vitrinite equivalent reflectance values, the Korudağ samples have a maximum of 1.91%R(g-v), in the gas generation window, while a maximum value of 0.79%R(amor-v) of one sample from the Hazro section is in the oil generation window. Illite crystallinity (IC) values of all samples are consistent with maturity results.Pr/Ph ratios ranging from 1.32 to 2.28 and C29/C30 hopane ratios > 1.0 indicate an anoxic to sub-oxic marine-carbonate depositional environment.The Hazro shales do not have any shale oil or shale gas potential because of their low oil saturation index values and early to moderate thermal maturation. At first glance, the Korudağ shales can be considered a shale gas formation because of their organic richness, thickness and thermal over-maturity. However, the low silica content and brittle index values of these shales are preventing their suitability as shale gas resource systems.

Evaluation of source rocks using one dimensional maturity modeling in Lower Indus Basin, Pakistan

Out of the numerous potential petroleum source rocks, present in the Lower Indus Basin, Sembar Formation is the most promising rock unit. One-dimensional maturity modeling of source rocks in Lower Indus Basin is conducted to find out the lateral and vertical extents of maturity levels of Sembar Formation. This study is also aimed to infer the extent of petroleum generation in the region. The study is based on one-dimensional basin modeling (maturity modeling) of 22 main exploration wells, drilled in the region. Stratigraphic input to model includes thickness, formation tops, ages of deposition and lithology, age and amounts of erosion, and ages of non-depositional events. Isopach map of Sembar Formation demonstrates the lateral and vertical extents of the formation, whereas temperature and vitrinite reflectance (Ro) contour maps indicate its maturity levels in different parts of the study area. It is inferred that the thickness of the overlying rock units (overburden) control the maturity level of the Sembar Formation. It may be noticed that the findings of this study are fully in conformity with the ground realities of the Lower Indus Basin. Discovery patterns and the lateral distribution of various types of hydrocarbons (such as oil, condensate, and dry gas) in the region coincide with the modeling results of the study, as can be seen from the burial history diagrams of the 12 wells. The study shows that Sembar Formation is mature enough to be considered as conventional petroleum source rock or can be exploit as unconventional shale gas/oil source.

Impact of high water pressure on oil generation and maturation in Kimmeridge Clay and Monterey source rocks: Implications for petroleum retention and gas generation in shale gas systems

This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources.

Investigation of the Fluid Behavior of Asphaltenes and Toluene Insolubles by High-Temperature Proton Nuclear Magnetic Resonance and Rheometry and Their Application to Visbreaking

The fluid behavior of asphaltenes at elevated temperatures impacts coke formation in a number of hydrocarbon conversion processes, including visbreaking and delayed coking. In this study, the asphaltenes from a number of sources, namely, a vacuum residue, a petroleum source rock (Kimmeridge clay) bitumen obtained by hydrous pyrolysis, and bitumen products from a sub-bituminous coal and pine wood obtained by thermolytic solvent extraction using tetralin, have been characterized using high-temperature proton nuclear magnetic resonance (1H NMR), and the results correlated with those from small-amplitude oscillatory shear rheometry. Further for comparison, the coke (toluene insolubles) obtained from visbreaking the vacuum residue was also characterized. All of the asphaltenes became completely fluid by 300 °C, with hydrogen being completely mobile with coke formation, identified as a solid phase, not occurring to a significant extent until 450 °C. Extremely good agreement was obtained between high-temperature 1H NMR and rheometry results, which confirmed that the asphaltenes were highly fluid from 300 °C, with initial signs of resolidification being observed at temperatures of around 450 °C. During softening, extremely good correlations between fluid hydrogen and phase angle were obtained as the asphaltenes softened. The toluene insolubles however did contain some fluid material; thus, it cannot be regarded as strictly solid coke, but clearly, with increasing temperature, the fluid material did convert to coke. Under actual process conditions, this fluid material could be responsible for coke adhering to reactor surfaces.

Кинетические спектры реакций преобразования органического вещества нефтегазоматеринских отложений

Кинетические спектры реакций преобразования органического вещества нефтегазоматеринских отложений

Cooper Basin source rock atlas

The Australian Petroleum Source Rocks Mapping project is a new study to improve understanding of the petroleum resource potential of Australia’s sedimentary basins. The Permian source rocks of the Cooper Basin, Australia’s premier onshore hydrocarbon-producing province, are the first to be assessed for this project. Quantifying the spatial distribution and petroleum generation potential of these source rocks is critical for understanding both the conventional and unconventional hydrocarbon prospectivity of the basin. Source rock occurrence, thickness, quality and maturity are mapped across the basin, and original source quality maps prior to the onset of generation are calculated. Source rock property mapping results and basin-specific kinetics are integrated with 1D thermal history models and a 3D basin model to create a regional multi-1D petroleum systems model for the basin. The modelling outputs quantify both the spatial distribution and total maximum hydrocarbon yield for 10 source rocks in the basin. Monte Carlo simulations are used to quantify the uncertainty associated with hydrocarbon yield and to highlight the sensitivity of results to each input parameter. The principal source rocks are the Permian coals and carbonaceous shales of the Gidgealpa Group, with highest potential yields from the Patchawarra Formation coals. The total generation potential of the Permian section highlights the significance of the basin as a world-class hydrocarbon province. The systematic workflow applied here demonstrates the importance of integrated geochemical and petroleum systems modelling studies as a predictive tool for understanding the petroleum resource potential of Australia’s sedimentary basins.

One Dimensional Evolution Modeling of Source Rocks in the Chaluhe Basin, Yitong Graben

Chaluhe Basin is in Jilin Province of China with a cumulative sedimentary rock thickness of about 6000 meters and has four subdivisions: Wanchang Structural High, Bo-Tai Sag, Xinanpu Sag, Liangjia Structure High and the Gudian Slope. The basin with its better source rock distribution and more favorable maturation indicators than the adjacent Moliqing and Luxiang Basins is expected to be a potential hydrocarbon-producing basin. Four (4) wells were used in determining the maturation hydrocarbon generating potential of the mudstone beds present in the Eocene Formations (Shuangyang, Sheling and Yongji). Obtained result revealed heat flow average of 71.8 mW/m2, oil generation between 3.15 mg/g TOC and 39.49 mg/g TOC with gas generation of 6.98 mg/g TOC to 92.83 mg/g TOC. In conclusion the Eocene Shuangyang mudstone is the main petroleum source rock.

Estimation of petroleum source rocks based on the crude oil geochemistry in Amu Darya Basin, northern Afghanistan

Estimation of petroleum source rocks based on the crude oil geochemistry in Amu Darya Basin, northern Afghanistan

Exhumation charge: The last gasp of a petroleum source rock and implications for unconventional shale resources

Petroleum (oil and gas) forms from the bacterial or thermal breakdown of kerogen during progressive burial in sedimentary basins. During times of petroleum generation, kerogens in organic-rich source rocks expel petroleum to form a fluid phase in the pore system, capable of migrating under hydrodynamic and buoyancy forces to ultimately escape to the surface or accumulate within petroleum traps in the subsurface. The relative timing of petroleum charge and trap formation is a vital component in the accumulation of petroleum deposits. Exhumed basins have been historically viewed as higher-risk targets for conventional petroleum exploration because of, inter alia, the switch-off of petroleum generation in the source rock at the commencement of cooling during exhumation. However, even at the switch-off point, the source rock may retain a significant volume of petroleum sorbed in kerogen and within its pore system. Herein we demonstrate that if the source rock is exhumed to shallower depths after peak burial, pore pressure reduction and the associated volumetric expansion of the petroleum—particularly of the gaseous—phase in the pore system will result in the discharge of additional petroleum into the adjacent carrier bed or reservoir formations. Because most onshore sedimentary basins are characterized by major exhumation events at some point in their history, this represents an additional and underappreciated mechanism for a late-stage petroleum charge in exhumed sedimentary basins. The modeling also indicates that both the initial, pre-exhumation, total gas storage capacity and the exhumation gas charge are likely to be volumetrically more significant for gas-bearing source rocks that have been exposed to higher initial pressures and lower thermal gradients. The concepts presented here also have implications for petroleum resources retained within unconventional shale reservoirs because high-graded shale plays may be associated with systems where the magnitude or rate of relative overpressure dissipation has limited exhumation charge from the unconventional to conventional reservoirs within the basin.

Source rock characterisation of under-explored regions of Queensland

Historically, petroleum exploration in Queensland has focused on the Bowen-Surat and Cooper-Eromanga basins, with only cursory examination of other basins across the state. As part of the Queensland Industry Priorities Initiative, two projects (Round 1 and 2) were submitted to the Geological Survey of Queensland (GSQ) to examine the geochemical characteristics of potential petroleum source rocks throughout Queensland. The analysis conducted provides a better understanding of generative potential for petroleum, and predicts the timing, volume, composition, and physical state of hydrocarbons retained in and expelled from source rocks. It is an integral component to petroleum systems analysis used to identify the potential for undiscovered accumulations of petroleum from conventional and unconventional reservoirs. Of particular interest were the Georgina, Drummond, Eromanga, and Maryborough basins. Of these, the Georgina and Maryborough basins have known hydrocarbon shows identified through exploration drilling, though no commercial discoveries have yet been made. The Drummond Basin was targeted to identify a potential source for oil and gas shows encountered in drilling within the Galilee Basin. The Toolebuc Formation in the Eromanga Basin has been noted as having the potential for a shale oil play and this study is supporting further assessment to identify optimal areas for future exploration through predictive modelling. This report details the results from Round 1 of the study for samples taken from the Georgina Limestone and Scartwater, Ducabrook, Mount Hall, Toolebuc, and Maryborough formations, where limited analysis of source rock characteristics has historically been undertaken. Ninety-seven samples were chosen from nine wells and sent to Geos4 in Potsdam, Germany, for source rock analysis. All samples were screened for suitability of further analysis using Rock-Eval and TOC by LECO, with immature and organic-rich samples being preferentially selected for further testing. Screened samples were analysed using pyrolysis gas chromatography (n=27), thermovaporisation (n=23), bulk kinetics (n=5), compositional kinetics (n=4), late gas analysis (n=14), and biomarker and bulk isotope analysis (n=15). These results have been integrated with existing analyses to better understand the prospectivity of the under-explored basins of Queensland.

Ionic Liquid as Green Solvent for Leaching of Polycyclic Aromatic Hydrocarbons from Petroleum Source Rock

Microwave-assisted extraction of polycyclic aromatic hydrocarbons (PAHs) from petroleum source rock using ionic liquids was investigated and the conditions for optimum yields of the analytes were determined. Three ionic liquids showed similar extraction efficiencies and for further work 1-butyl-3-methylimidazolium bromide (BmimBr) was selected. The results showed that concentration and extraction temperature have significant effects on extraction yields of the PAHs. The 3.0 M ionic liquid solution was the best concentration for extraction of the PAHs. The highest yields of PAHs were obtained at an extraction time of 30 min. The optimum temperature for microwave-assisted ionic liquid extraction of all the PAHs from petroleum source rock was 100 °C. The results also show that microwave-assisted ionic liquid extraction is more efficient than accelerated solvent extraction and Soxhlet extraction. This study showed that microwave-assisted ionic liquid extraction (MAILE) is an efficient green analytical sample ...