Hydrocarbon Generation Potential Research Articles

Bio-environmental interactions and associated hydrocarbon generation in a saline lake basin: A case study of the Palaeogene interval in the Dongpu Sag, eastern China

• Different hydrocarbon-generating organisms occur in different saline palaeoenvironments. • The palaeoenvironment affects the hydrocarbon-generating organisms and source rock potential. • Source rocks deposited in saline environments have a low oil generation threshold and are characterised by multi-stage oil generation. • Saline environments form source rocks with a good organic matter type and high hydrocarbon generation potential. Saline lake basins are important Cainozoic petroliferous basins in China. There are significant differences in the palaeoenvironments of these basins. Different biological assemblages resulted in varying hydrocarbon generation characteristics and potential. Therefore, the bio-environmental interactions are key to understanding the oil generation from terrestrial organic matter. In this study, we investigated the organic petrology and geochemistry of the Palaeogene Shahejie Formation in the Dongpu Sag, Bohai Bay Basin, China. The depositional palaeoenvironment varied from saline to freshwater. Cyanobacteria and coccolithophores were deposited in the saline environment, and green algae and higher plant debris were deposited in the freshwater to brackish water environments. The algal biomass in the sediments increased with salinity. Thermal and pyrolysis experiments revealed differences in the hydrocarbon generation potential of the source rocks deposited in different sedimentary environments. The source rocks deposited in the saline water environment have a high hydrocarbon generation potential. Two immature to low-mature oil generation peaks were observed, which are mainly due to the pyrolysis of coccolithophores, cyanobacteria, and dinoflagellates. Only one oil generation peak was observed for source rocks deposited in the freshwater environment, which is mainly due to the pyrolysis of dinoflagellates and green algae. The hydrocarbon generation potential and two stages of oil generation of the source rocks deposited in the saline environment may be due to the type of hydrocarbon-generating organisms and the catalytic effect of the high-salinity diagenetic environment. The results show that the sedimentary environment of saline lake basins affects the hydrocarbon-generating organisms and hydrocarbon generation process.

Evaluation of Source Rock Potential for Hydrocarbon Generation in Shallow Offshore, Lamu Basin, Kenya

Evaluation of Source Rock Potential for Hydrocarbon Generation in Shallow Offshore, Lamu Basin, Kenya

Sub- and supercritical water conversion of organic-rich shale with low-maturity for oil and gas generation: using Chang 7 shale as an example

Organic-rich shale resources are large reserves with high hydrocarbon generation potential but are difficult to exploit due to their high solid kerogen content.

Source rock and reservoir qualities of middle Jurassic Lianggaoshan lacustrine shale at fuxing area, Sichuan Basin: Implication for shale-oil enrichment

The shale oil exploration, in the Middle Jurassic Lianggaoshan Formation in the Fuxing area of Sichuan Basin, is in preliminary stage, requiring further in-depth study on shale oil and gas enrichment conditions. The lithological, organic geochemical, and reservoir characteristics of the Lianggaoshan Formation shale were analyzed using a suite of tests, including common thin section observation, organic carbon determination, pyrolysis experiment, combined N 2 -high pressure mercury test and argon ion polishing-scanning electron microscope, to elucidate source rock and reservoir qualities and their variation in vertical. Results suggest that the medium-carbon argillaceous shale, medium-carbon shell calcareous-argillaceous shale, and low-carbon argillaceous shale facies were mainly developed in Member 1 and Member 2 of the Lianggaoshan Formation. The medium-carbon argillaceous shale facies in the sub-layer ④ was rich in organic matter, with abundant sapropel, chitinous and secondary organic components, which were considered as a set of medium-quality source rocks. The medium-carbon shell calcareous-argillaceous shale and low-carbon argillaceous shale in the sub-layers ② and ③ have relatively low organic matter abundance, with vitrinite and inertinite as major organic microscopic components, revealing poor hydrocarbon generation potential. The porosity of shale reservoirs in sub-layers ②‒④ was higher than 3.0%, with predominant mesopores, followed by macropores, consisting of mainly clay mineral pores, organic pores, and microfractures related to organic matter. The medium-carbon argillaceous shale facies at the Lianggaoshan Formation is high-quality source rocks and reservoirs and is thus a potential target for lacustrine shale oil exploration in the Fuxing area of the Sichuan Basin. • The medium carbon clayey shale, medium carbon shell calcareous-clayey shale, and low carbon clayey shale were mainly developed in Member 1 and Member 2 of the Lianggaoshan Formation. • The medium carbon clayey shale facies in the sub-layer ④ exhibits adequate potential as hydrocarbon source rock and reservoir. • Sub-layer ④ is thus a potential target for continental shale oil exploration in the Fuxing area of the Sichuan Basin.

Biomarker geochemistry of Qaiyarah, Butmah and Ain Zala crude oils, northern Iraq: Implications for the Jurassic source rocks

Fifteen crude oils from the Qaiyarah, Butmah, and Ain Zala fields were investigated using organic geochemistry to infer organic matter maturity, redox conditions of the depositional environment, and lithology of the corresponding source rocks. Carbon isotope compositions and sulfur contents were measured for all samples and saturated and aromatic biomarkers were analyzed by GC-MS.Low pristane/phytane (0.68–0.82) and high C35 S/C34S (1.03–1.66) and homohopane indices (0.14–0.24) in the oil samples indicate anoxic or euxinic conditions for the corresponding source rocks. In addition, sulfur content, C30 norhopane/C30 hopane, and C31 R/C30 hopane, Ts/Tm and C27 diasteranes/regular steranes values suggest carbonate source rocks with variable amounts of clays. These source rocks contain mainly type II-S kerogen. Moretane/hopane, hopane and sterane isomerization ratios suggest generation from early mature organic matter. Hierarchical cluster analysis identified three families charged from carbonate source rocks with variable amounts of clays and maturity. Oil-source rock correlation (based on published data) and age-related biomarkers suggest that these oils were generated from Jurassic source rocks (Sargelu, Naokelekan, and/or Chia Gara formations). Jurassic rocks in Ain Zala and Butmah area have low potential for hydrocarbon generation, therefore, the Ain Zala and Butmah oils were charged from Jurassic formations outside the Ain Zala area, but within the neighboring area northeast of Butmah and Ain Zala.

Investigation of the hydrocarbon generative potential of Eocene, Cretaceous, and Late Triassic age sequences in the Punjab Platform Basin, Pakistan, using geochemical and petrophysical techniques

Investigation of the hydrocarbon generative potential of Eocene, Cretaceous, and Late Triassic age sequences in the Punjab Platform Basin, Pakistan, using geochemical and petrophysical techniques

Paleoenvironmental, paleoclimatic, and organic matter assessment of the hybrid Kharita Formation (Albian) in the Abu Gharadig Basin, Egypt: Integration between palynology, organic petrography, and organic geochemistry

The Early Cretaceous (Albian) was a time of equatorial to polar temperature warming and increased environmental perturbations of the global carbon cycle and oceanic anoxia, which resulted in the widespread accumulation of organic carbon-rich sediments. During the Albian, the southern margin of the Tethys Ocean was characterized by marginal to shallow water conditions with minor phases of enhanced stratification and bottom water anoxia in northern Egypt. At this time, accumulation of the thick siliciclastic succession of sandstones versus shale intercalations of the Kharita Formation took place in the Abu Gharadig Basin. The Kharita Formation is investigated for palynological composition and palynofacies analysis, organic matter characterization, hydrocarbon generation potential, and thermal maturity assessment based on 30 and 26 drill cuttings samples from the BED2-3 and BED2-1x wells, respectively. A rich palynological assemblage of herbaceous hygrophilous plants, including pteridophyte spores and water ferns, along with Elaterates and Afropollis pollen indicated warm humid climate conditions. Furthermore, abundant occurrences of Araucariaceae and Cheirolepidiaceae, including Araucariacites, Inaperturopollenites, and Classopollis, reinforcing warm climatic conditions and their climax in areas near coastal vegetation. Statistical cluster analysis identified two palynofacies assemblages (PFA) based on stratigraphic variation in the particulate organic matter (POM). The PFA-1 characterized all samples of the BED2-3 and some intervals of the BED2-1x wells and comprised moderate abundances of phytoclasts and amorphous organic matter (AOM) that defined a kerogen Type II, whereas the PFA-2 was recorded only in the BED2-1x well and is dominated by phytoclast fragments of kerogen Type III. The geochemical screening revealed, based on the low average values of TOC (1.2 wt%), S2 (1.8 mg HC/g rock), and HI (146 mg HC/g TOC), that the Kharita Formation is characterized by a kerogen Type III of gas-prone hydrocarbon but with low generation potential. Tmax and vitrinite reflectance measurements along with greenish-to golden-yellow liptinite macerals indicated that the thermal maturity of preserved organic matter is still in the immature to the early mature stage of the oil window. Inconsistency in kerogen types between PFA-1 and geochemical deductions was interpreted in terms of microscopic investigations of the recovered AOM. Morphologic characteristics observed that most AOM particles were of terrigenous origin due to the impact of biodegradation and transformation of phytoclast particles into AOM, confirming a kerogen Type III of gas-prone hydrocarbons instead of Type II that was elucidated by palynofacies ternary diagrams. The occurrence of coaly matter in the BED2-1x infers closer proximity to fluvio-deltaic sources during deposition of the lower part of the Kharita Formation than in the BED2-3.

Prediction of TOC in Lishui–Jiaojiang Sag Using Geochemical Analysis, Well Logs, and Machine Learning

Total organic carbon (TOC) is important geochemical data for evaluating the hydrocarbon generation potential of source rocks. TOC is commonly measured experimentally using cutting and core samples. The coring process and experimentation are always expensive and time-consuming. In this study, we evaluated the use of three machine learning (ML) models and two multiple regression models to predict TOC based on well logs. The well logs involved gamma rays (GR), deep resistivity (RT), density (DEN), acoustic waves (AC), and neutrons (CN). The ML models were developed based on random forest (RF), extreme learning machine (ELM), and back propagation neural network (BPNN). The source rock of Paleocene Yueguifeng Formation in Lishui–Jiaojiang Sag was taken as a case study. The number of TOC measurements used for training and testing were 50 and 27. All well logs and selected well logs (including AC, CN, and DEN) were used as inputs, respectively, for comparison. The performance of each model has been evaluated using different factors, including R2, MAE, MSE, and RMSE. The results suggest that using all well logs as input improved the TOC prediction accuracy, and the error was reduced by more than 30%. The accuracy comparison of ML and multiple regression models indicated the BPNN was the best, followed by RF and then multiple regression. The worst performance was observed in the ELM models. Considering the running time, the BPNN model has higher prediction accuracy but longer running time in small-sample regression prediction. The RF model can run faster while ensuring a certain prediction accuracy. This study confirmed the ability of ML models for estimating TOC using well logs data in the study area.

Origins of Organic Matter, Paleoenvironment, and Hydrocarbon Potential of the Carboniferous Source Rocks from Shibei Sag, Junggar Basin, NW China

The organic-rich sediments of the Carboniferous in the Shibei Sag, Junggar Basin, China are potential source rocks with good hydrocarbon generation conditions for oil and gas exploration. Thus, it is meaningful to analyze their geochemical characteristics, including the hydrocarbon generation potential, genetic types of kerogen, thermal maturity, the origin of organic matter (OM), and sedimentary environment. The results reveal that the Carboniferous source rocks have fair to excellent hydrocarbon generation potential. They are mainly gas-prone with type III-IIkerogens. Random vitrinite reflectance (Rr) of the studied samples ranges from 0.63 to 1.04%, suggesting a primarily mature stage, which is also supported by the maturity-related hopane and sterane ratios. Stable carbon isotopic compositions, organic petrological macerals, and biomarker characteristics all indicate a predominant higher plant input. Abundant bicyclic sesquiterpenoids and diterpenoid biomarkers in the studied samples suggest the conifer inputs. In particular, high amounts of phyllocladanes, retene, and kauranes suggest the contribution of gymnosperms, pre-gymnosperms, pteridophytes, or bryophytes in swamps. From the early Carboniferous to the late Carboniferous, the environment became more oxic, the water level dropped, and higher plants flourished. Based on the abovementioned results, the Carboniferous source rocks were likely to be deposited in a transitional environment under lacustrine-fluvial conditions. Specifically, source rocks from the Batamayineishan Formation were deposited in a peat environment during the interval of the volcano eruptions. Considering the quantity and maturity of OM and their large thickness, the Carboniferous sediments have a good petroleum exploration potential.

North slope transition zone of Songnan-Baodao sag in Qiongdongnan Basin and its control on medium and large gas fields, South China Sea

Based on analysis of newly collected 3D seismic and drilled well data, the geological structure and fault system of Baodao sag have been systematically examined to figure out characteristics of the transition fault terrace belt and its control on the formation of natural gas reservoirs. The research results show that the Baodao sag has the northern fault terrace belt, central depression belt and southern slope belt developed, among them, the northern fault terrace belt consists of multiple transition fault terrace belts such as Baodao B, A and C from west to east which control the source rocks, traps, reservoirs, oil and gas migration and hydrocarbon enrichment in the Baodao sag. The activity of the main fault of the transition belt in the sedimentary period of Yacheng Formation in the Early Oligocene controlled the hydrocarbon generation kitchen and hydrocarbon generation potential. From west to east, getting closer to the provenance, the transition belt increased in activity strength, thickness of source rock and scale of delta, and had multiple hydrocarbon generation depressions developed. The main fault had local compression under the background of tension and torsion, giving rise to composite traps under the background of large nose structure, and the Baodao A and Baodao C traps to the east are larger than Baodao B trap. Multiple fault terraces controlled the material source input from the uplift area to form large delta sand bodies, and the synthetic transition belt of the west and middle sections and the gentle slope of the east section of the F12 fault in the Baodao A transition belt controlled the input of two major material sources, giving rise to a number of delta lobes in the west and east branches. The large structural ridge formed under the control of the main fault close to the hydrocarbon generation center allows efficient migration and accumulation of oil and gas. The combination mode and active time of the main faults matched well with the natural gas charging period, resulting in the hydrocarbon gas enrichment. Baodao A transition belt is adjacent to Baodao 27, 25 and 21 lows, where large braided river delta deposits supplied by Shenhu uplift provenance develop, and it is characterized by large structural ridges allowing high efficient hydrocarbon accumulation, parallel combination of main faults and early cessation of faulting activity, so it is a favorable area for hydrocarbon gas accumulation. Thick high-quality gas reservoirs have been revealed through drilling, leading to the discovery of the first large-scale gas field in Baodo 21-1 of Baodao sag. This discovery also confirms that the north transition zone of Songnan-Baodao sag has good reservoir forming conditions, and the transition fault terrace belt has great exploration potential eastward.

Hydrocarbon yield evolution characteristics and geological significance in temperature-pressure controlled simulation experiment

A semi-open system temperature-pressure controlled hydrocarbon generation and expulsion simulation experiment was carried out to explore the hydrocarbon generation and expulsion potential and mechanism of deep environment “coal measure” source rocks in the Qaidam Basin. A WYNN-3 high temperature and high pressure (HTHP) simulator and Middle Jurassic source rocks (III type organic matter, carbonaceous mudstone, and coal, RO is 0.67% and 0.64%, respectively) of Well DMG1 in the northern margin of the Qaidam Basin were used during the investigation. The results demonstrated that: (1) The maximum total oil yields of carbonaceous mudstone and lignite, which respectively measured at 79.38 mg/gTOC and 37.30 mg/gTOC, revealed a “double peaks” evolution law as a whole. (2) In the lower evolution stages (T ≤ 300 °C, P ≤ 42.0 MPa), the expelled/discharged oil yields of the two types of source rocks were lower than those of the residual oil, and the hydrocarbon expulsion efficiencies were low. However, at 400 °C (51.0 MPa), they significantly increased reaching 76.84% and 83.72%, respectively. (3) The main group components of the discharged oil were resin and asphaltene, and the component yields were generally comparable to those of liquid hydrocarbons. The yields of expelled oil group components of carbonaceous mudstone were higher than those of coal. (4) The simulated gas was primarily composed of hydrocarbon gas and non-hydrocarbon gas (CO2, N2), and with the elevated thermal evolution, the yields of total hydrocarbon gas/gaseous hydrocarbon increased. The two types of source rocks had maximum hydrocarbon gas yield of 116.46 mL/gTOC and 36.85 mL/gTOC, respectively. (5) The vitrinite reflectance (RO) increased as temperature and pressure conditions enhanced, and it exhibited good temperature consistency. The results of this temperature-pressure controlled simulation experiment showed that temperature was still the dominant factor in the thermal evolution of organic matter, fluid pressure had a “dual” control on the formation of type III organic hydrocarbon products, and “coal measures” source rocks still had a strong potential for hydrocarbon generation in the later stages of evolution. This research provided a certain data reference for the hydrocarbon generation and expulsion law of Jurassic deep “coal measures” source rocks in the northern margin of the Qaidam Basin.

A deep encoder-decoder neural network model for total organic carbon content prediction from well logs

• This work proposed a deep encoder-decoder neural network (DEDNN) for predicting TOC contents. • The DEDNN model shows more accurate and sensitive than ΔLogR method and CNN method. • The DEDNN model can highlight the contribution of individual logging curve to the TOC prediction. Total organic carbon (TOC) content is an important geochemical parameter for evaluating the hydrocarbon generation potential of unconventional oil and gas resources. The TOC content of source rocks significantly affects the responses of well logs so, in principle, well logs can be used for source rock appraisal. However, the complex relationships between TOC content and well logs involve nonlinear mapping with many parameters. It is sometimes difficult to obtain continuous and accurate TOC content values using conventional methods such as the ΔLogR method. In this study, we propose a TOC prediction model using a deep encoder-decoder neural network (DEDNN) based on mining and mapping of multiscale features of logging curves. The prediction performance of the model is validated by a series of tests using data from four exploration wells in the Longmaxi black shale in the Dingshan area of the Sichuan Basin. The TOC content prediction results confirm that the proposed DEDNN is more accurate than either the ΔLogR method or CNN, which is a state-of-the-art convolutional neural network. Furthermore, a saliency map derived from the DEDNN results shows the relative importance of different well logs to TOC contents.

Sedimentary Characteristics of the Permian Zhesi Formation in Eastern Inner Mongolia, China: Implications for Sedimentary Background and Shale Gas Resource Potential.

Eastern Inner Mongolia of China is located between the Siberian plate, the North China plate, and the Pacific plate and has a complex history of tectonic and sedimentary evolution. The sedimentary strata of the Zhesi Formation in the Middle Permian recorded rich environmental, structural, and petroleum geological information, which has great significance to the Paleozoic geological research in Northeast China. Through field outcrop observation and profile measurement, combined with geochemistry, mineralogy, and the reservoir physical property test, the sedimentary environment, tectonic setting, and shale gas resource potential of the Middle Permian Zhesi Formation are analyzed. The sedimentary facies of the Zhesi Formation are distributed in strips in the northeast direction, mainly developing littoral, shallow marine, and bathyal sedimentary environments. Clastic rock deposits are mainly developed in the littoral facies, carbonate platform and tempestite deposits are mainly developed in the shallow marine facies, and mudstone mixed with turbidite deposits are mainly developed in the bathyal facies. The sedimentary environment and chronological characteristics show that the Paleo-Asian Ocean was not completely closed in the Middle Permian, and its complete closure time should be later. The characteristics of source rocks and the shale gas resource potential in the Solon area are discussed. Controlled by the sedimentary environment, the Solon area mainly deposited thick dark shale mixed with turbidite sandstone, the accumulated thickness of the dark shale is more than 200 m, with an average vitrinite reflectance (Ro) of 2.44%, and the average residual total organic carbon (TOC) content is 0.85%. The average content of brittle minerals is 60.2% and the shale foliation fracture is developed, which is easy to form natural fractures and induced fractures, so the shale has good hydrocarbon generation potential, and the generated shale gas can exist in shale in an adsorbed state and a free state. In addition, the shale gas generated in the shale can migrate to the lenticular turbidite sand body in a short distance to form free shale gas. Therefore, there is a certain shale gas resource potential in the Solon area, and finding a favorable area with high TOC is the key to future exploration of Upper Paleozoic shale gas.

Geochemistry of the Tanshan Oil Shale in Jurassic Coal Measures, Western Ordos Basin: Implications for Sedimentary Environment and Organic Matter Accumulation

The Tanshan area is located in the southern section of the west margin of the Ordos basin. The Middle Jurassic Yan’an Formation is relatively thick and rich in coal and oil shale layers, having positive potential for energy development. In order to explore the sedimentary environment of oil shale and the controlling factors of organic matter accumulation, 18 oil shale samples collected from two boreholes (Guyou-3 and Guyou-4) in the Tanshan area were selected as the research objects, and organic geochemical and elemental geochemical tests were carried out systematically. The results show that oil shales have the characteristics of medium oil content, medium ash, high calorific value, low sulfur and low maturity stage, which constitutes good hydrocarbon generation potential. The organic matter is mainly humic type, resulting from terrigenous debris and higher plant debris. The indictors of C-value (mean 81.90), Th/U ratio (mean 3.44), CaO/(MgO·Al2 O3) ratio (mean 0.07), δEu (mean 0.71), δCe (mean 1.15), V/(V + Ni) ratio (mean 0.79), Ceanom index (mean −0.04), Babio index (mean 488.97 μg/g), P/Ti ratio (mean 0.08), TOC/S ratio (mean 59.80), Sr/Ba ratio (mean 0.57) and (La/Yb)N ratio (mean 14.71) indicate that Tanshan oil shales were formed in a warm–humid climate and anoxic-reducing environment, with a low-salinity water body and a low deposition rate but also a relatively low initial paleoproductivity. Paleoclimate conditions, organic matter sources and redox properties of paleowater are the main controlling factors affecting the accumulation of organic matter in oil shales. Although low paleoproductivity and deposition rates are not conducive to the preservation of organic matter, under the conditions of warm and humid climate and a reducing water environment, the continuous and stable input of terrigenous debris and higher plant debris can also cause the enrichment of organic matter.

Geochemical and Petrological Characterization of the Early Eocene Carbonaceous Shales: Implications for Oil and Gas Exploration in the Barmer Basin, Northwest India.

Carbonaceous shales of the Early Eocene Dharvi/Dunger Formation in the onshore Barmer Basin, northwest India were studied for the first time by integrating geochemical and organic petrological analyses. The carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are characterized by a higher organic carbon content (TOC) of >10 wt % and consist mainly of a mixture of organic matter of types II and III kerogen, with exhibited hydrogen index values ranging between 202 and 292 mg HC/g TOC. The dominance of such kerogen is confirmed by the high amounts of huminite and fluorescent liptinite macerals. Consequently, the carbonaceous shales of the Early Eocene Dharvi/Dunger Formation are promising source rocks for both oil and gas generation potential, with oils of high wax contents, according to pyrolysis-gas chromatography results. The chemical and optical maturity results such as low values huminite/vitrinite reflectance, production index, and T max show that most of the examined carbonaceous shale rocks from the outcrop section of the Kapurdi mine have entered the low maturity stage of oil generation, exhibiting a range of immature to the very early-mature. Therefore, as highlighted in this study, the substantial abundance in hydrocarbon generation potential from these carbonaceous shales in the Dharvi/Dunger Formation may represent future conventional petroleum exploration in the southern part of the Barmer Basin, where the Dharvi/Dunger Formation has reached deeper burial depths.

A quick comparison of Pliocene and Upper Miocene shale resources in northern, central and southern parts of Song Hong basin with reference to their gas potential

This research is a follow-up of a more comprehensive PhD study on assessment of shale gas resources in the northern Song Hong basin that was conducted at the Asian Institute of Technology (AIT). The Song Hong basin, a typical pull-apart Cenozoic basin, had experienced a post-extensional stage accompanied by seafloor spreading from Upper Oligocene to Lower Miocene with its stratigraphy characterised by a fault-controlled syn-rift continental sequence followed by a post-rift marine sequence. In recent years, a number of gas fields have been discovered in the Song Hong basin with the Oligocene-Eocene and the Lower-Middle Miocene shales as the major and minor source rocks, respectively. On the other hand, the Pliocene and Upper Miocene shales, present in the stratigraphy from the north to the south of the Song Hong basin, have generally been considered as the seals, but not the source rocks in some previous studies. In July 2020, an exploration well (Ken Bau-2X) was drilled in Block 114 by ENI, reaching a total depth of 3,658 m and encountering a pay of about 110 m in several intervals of Upper Miocene sandstones interbedded with shales, confirming a considerable gas accumulations discovered in Vietnam so far. The interesting thing is that this well only encounter the Pliocene and Upper Miocene shales, the Oligocene-Eocene or Middle-Lower Miocene sediments underlying is absent or very thin. Therefore, potential source rock of these shales should be considered in the area, in particular with reference to petroleum system of the central Song Hong basin.
 
 In this study, a preliminary comparison of the Pliocene and Upper Miocene shale resources in the northern, central and southern blocks in the Song Hong basin was conducted based on the analysis results of XRD, Rock-Eval pyrolysis, vitrinite reflectance, respectively. While the Pliocene and Upper Miocene shales in many areas of Song Hong basin, show a very low or no hydrocarbon generation potential, the very deep and thick Pliocene and Upper Miocene shales in the center and adjacent areas, deposited in a marine environment under the special conditions of abnormal pressure and high geothermal gradient, can be potential source rocks that have possibly generated and released a large amount of hydrocarbons. Further geochemical analyses and petroleum system modelling of the Pliocene and Upper Miocene shales in particular and for the whole central Song Hong basin are recommended.

Burial history and thermal maturity of the atypical petroleum system of the Paraná Basin (Irati and Ponta Grossa formations), Brazil

The main characteristic of the intracratonic sedimentary Paraná Basin, southern Brazil, is the atypical hydrocarbon generation through the heat from basic intrusive rocks. Potential hydrocarbon source shales from the Irati and Ponta Grossa formations were identified and characterised via stratigraphic data, total organic carbon (TOC - LECO) analyses and pyrolysis (Rock-Eval 6) of well samples. Geochemical analyses showed that in wells under study, the Irati Formation has organically rich shales, and the Ponta Grossa Formation has low potential for hydrocarbon generation. 1D generation modelling using 16-well 1D and PetroMod® software was developed aiming to establish the thermal and subsidence history in the area and to determine hydrocarbon generation and expulsion. Geochemical data from the wells was used, and information on sedimentology and stratigraphy was obtained from the literature. Thermal history was calibrated using values of vitrinite reflectance, Tmax and downhole temperature, and the geothermal gradient used in the models was 28–42 °C/km. The relative erosive thicknesses of the stratigraphic units were estimated. The results showed that in regions without igneous intrusions, the Irati shales are immature for hydrocarbon generation and do not have an organic matter transformation rate, which is consistent with the results of Rock-Eval pyrolysis and %Ro. However, in wells containing igneous intrusive rocks in the Irati shales, the transformation rates varied according to the thickness and number of intrusions, reaching 100% organic matter transformation; due to its quality (Type I kerogen), this rate is favourable for oil and gas generation. The Ponta Grossa source rock showed thermal maturation by subsidence corresponding to the oil generation window, with higher maturation anomalies near igneous intrusions. The organic matter transformation rate reached 70% in the absence of igneous intrusions and nearly 100% in the presence of igneous intrusions. Despite having good maturity, the characteristics regarding the quantity and quality of organic matter suggest a moderate potential for gas generation in the Ponta Grossa Formation in the study area. The depositional history model showed that the highest subsidence rate occurred during the Early Cretaceous and was related to the burial associated with the basalt thickness of the Serra Geral Formation.

Characteristics of Liquid-Hydrocarbon Yield and Biomarkers in Various Thermal-Evolution Stages: A Simulation Experiment with the Middle Jurassic Source Rocks in the Northern Margin of the Qaidam Basin

Although there are many studies on the Jurassic source rocks in the northern margin of the Qaidam Basin, the characteristics of biomarkers and products with the same source rock in different evolutionary stages are still not well understood. Such an understanding is essential for accurately estimating oil and gas resources. In order to explore the hydrocarbon-generation potential of high-quality source rocks of the Middle Jurassic and the evolution of liquid hydrocarbons and biomarkers, we carried out simulation research (under hydrous conditions) at various temperatures (250, 300, 350, 400 and 450 °C) with the mudstone of the Yu 33 well in the Yuka Sag. The results revealed that the “oil window” of the Middle Jurassic source rocks in the Yuka area was 300 °C (simulation temperature, Ro = 0.84%), but this was not the peak of hydrocarbon expulsion, which was gradually reached and stabilized above 350 °C. Overall, the concentration of alkanes and aromatics increased with temperature; although the concentration of alkanes was complex in the low evolutionary stages, temperature (simulated maturity) was still the main factor controlling the change in alkanes and aromatics. Among the maturity parameters of biomarkers, the ratio of ∑tricyclic terpanes/∑hopanes was the most effective parameter for indicating the maturity evolution of the Yuka area, but others were complicated by the increasing temperature. Therefore, when evaluating maturity, the applicability of other parameters needed to be fully considered. The results obtained offer new insights in the research on liquid-hydrocarbon and biomarker evolution of the Middle Jurassic source rocks in the Yuka Sag of the Qaidam Basin.

Origin and Characteristics of the Crude Oils and Condensates in the Callovian-Oxfordian Carbonate Reservoirs of the Amu Darya Right Bank Block, Turkmenistan

Abstract The Amu Darya Right Bank Block is located northeast of the Amu Darya basin, a large petroliferous sedimentary basin, with abundant natural gas resources in carbonate rocks under the ultra-thick gypsum-salt layer. Oil fields producing crude oils have recently been found around large gas fields. Unraveling the origins of the crude oils is crucial for effective petroleum exploration and exploitation. The origin of gas condensates and crude oils was unraveled through the use of comprehensively analytical and interpretative geochemical approaches. Based on oil-source correlation, the reservoir forming process has been restored. The bulk geochemical parameters of the local source rocks of the ADRBB indicated that the local sources have hydrocarbon generation and accumulation potential. The middle-lower Jurassic coal-bearing mudstone is gas prone, while the mudstone of the Callovian-Oxfordian gap layer is oil prone, and the organic matter type of Callovian-Oxfordian carbonate rocks is the mixed type between the two previous source rocks. The interpretation schemes for compositions of n-alkanes, pristane and phytane, C27–C28–C29 sterane distributions, C19+C20–C21–C23 tricyclic terpane distributions, extended tricyclic terpane ratio, and δ13C indicated that crude oil is likely from marine organic matter, while condensates mainly originate from terrestrial organic matter. However, from the perspective of the 18α-trisnorneohopane/17α-trisnorhopane and isomerization ratio of C29 sterane, condensates are too mature to have originated in the local source rocks of the ADRBB, whose maturity is well comparable with that of crude oils. The geochemical, geologic, and tectonic evolutions collectively indicate that the crude oils were most likely generated and migrated from the relatively shallow, lowly mature gap layer and Callovian-Oxfordian carbonate rocks of the ADRBB, while the condensates mostly originated from the relatively deep and highly mature middle-lower coal-bearing mudstone and Callovian-Oxfordian carbonate rocks in the Murgab depression in the southeast of the basin. Basement faults are the key factors affecting the types of oil and gas reservoirs. During the periods of oil and gas migration, traps with basement faults mainly captured natural gas and condensates and traps without basement faults were enriched with crude oils generated from local source rocks.

Evaluation of Hydrocarbon Generation Potential of Laiyang Formation Source Rocks in Ri-Qing-Wei Basin, Eastern Shandong

The Ri-Qing-Wei Basin is a newly discovered Late Mesozoic rift basin on the eastern Shandong coast in recent years. Thick, continuous deposited source rocks are found in the Lingshan Island scientific drilling project. Therefore, it is necessary to evaluate the distribution and hydrocarbon generation potential of source rocks in this area. Organic geochemical experiments were carried out on samples from the core of LK-1 and outcrops in the Lingshan Island, the Laoshan area, and the Jimo Zhougezhuang area to evaluate the maturity, abundance, and type of organic matter in source rocks. The results show that the cumulative thickness of the source rocks in the study area is more than 500 m, and the TOC content is generally greater than 1.0%. The organic matter type is good (mainly type II1 and type II2 kerogen) and the Ro value is more than 2.0. The thermal evolution degree of the organic matter is high with natural gas predominantly generated. We carried out Rock-Eval, PY-GC and gold tube experiments on low-maturity samples of Laikong 2 and established a chemical kinetic model to quantitatively evaluate the study area in combination with sedimentary burial history and thermal history data. The results show that the total resources of the five sags in the study area are about 476 billion cubic meters, and the average resource intensity is about 82.2 million cubic meters/km2. Among them, the resource intensities of the Lingshan Island Sag and Laoshan Sag are 112.6 million cubic meters/km2 and 98.8 million cubic meters/km2, respectively. Studied sites are “small and fertile” and may be used as favorable exploration prospect areas.