One-dimensional Basin Modeling Research Articles

Hydrocarbon Generation from Low-Mature Saline Lacustrine Sediments Studied Using Machine Learning and Chemometric Methods: The Succession of the Sikeshu Sag, Junggar Basin, NW China.

Significant attention has been given to the extensive development of saline environments in petroliferous basins. Further exploration and studies have discovered that saline environments, such as those for the deposition of source rocks in the Paleogene Anjihaihe (E2-3 a) Formation of the Sikeshu Sag, are ubiquitous in terrestrial lake basins. Previous studies have suggested that the oil reservoirs in the Sikeshu Sag and its peripheral regions are predominantly derived from the black mudstone and coal measures of the Lower Jurassic Badaowan (J1 b) Formation. However, with deeper exploration of the study area, a growing number of reservoirs with geochemical characteristics different from the J1 b oil source have been discovered, indicating that there are oil sources other than the J1 b source rocks. In this study, various machine learning algorithms were used (random forest, RF; convolutional neural networks, CNN; extreme gradient boosting, XGBoost; ElasticNetCV; Bayesian Ridge; and particle swarm optimization-support vector regression) to select the most suitable algorithm for predicting and comparing the quality of potential source rocks. A violin plot and Taylor diagram were applied to visually compare the reliability and application effectiveness of the models. The results demonstrated that XGBoost and RF can become essential tools for predicting the quality of potential source rocks. Moreover, the measured and predicted values of total organic carbon (TOC), hydrocarbon potential (S1 + S2), and hydrogen index indicate that there are three main source rocks: the E2-3 a, Lower Jurassic Sangonghe (J1 s), and J1 b formations. The thermal maturity of the E2-3 a source rocks is still early mature because of the saline-brackish water nature of these rocks, although large-scale hydrocarbon generation and expulsion can be achieved in the early mature stage. Based on their geochemical characteristics and stepwise discriminant analysis, the oils in the Sikeshu Sag and its peripheral regions can be categorized into two types: groups A and B. Comprehensive organic geochemical evidence suggests that genetically, group A oils are originated from E2-3 a less-mature saline lacustrine sedimentary rocks, while group B oils indicate similar affinity to the Jurassic source. Fluid inclusion microthermometry and one-dimensional basin modeling showed that the oil charging periods of group A and B oils were Middle-Late Miocene (13-8 Ma) and Late Oligocene (23-20 Ma), respectively. Quantitative grain fluorescence (QGF) analysis further propose that the hydrocarbon supply region of the E2-3 a sources is mainly located east of the Western Chepaizi Uplift and the interior area of the Sikeshu Sag, which breaks through the previous understanding that the Jurassic coal-derived oil source is the only main contributor in this study area. The research results can be widely applied to assess the petroleum resources of source rocks in similar areas worldwide.

The Contribution of Petroleum Charging Episodes to Different Strike-Slip Fault Zones in the Shunbei Area, the Tarim Basin, NW China

In recent years, newly discovered ultra-deep fault-karst reservoirs in the Shunbei area of the Tarim Basin have greatly increased the prospectivity of the basin and become a hotspot for further hydrocarbon exploration. In this study, the diagenetic sequences of the Lower-Middle Ordovician reservoir were established through observation of thin sections under transmitted light, reflected light, and cathode luminescence. The hydrocarbon charge history in the Shunbei area was reconstructed and associated with a series of diagenetic events using fluid inclusion microthermometric measurements combined with one-dimensional basin modeling. The results show that the Shunbei area has experienced three hydrocarbon charging episodes in total, in the late Caledonian, late Hercynian, and late Himalayan. Finally, the relationship between measured QF-535 factors and the API gravity of crude oil was used to quantify the level of contribution of each of the petroleum charging episodes to the No. 1, No. 5, and No. 7 fault zone reservoirs. The contribution of early hydrocarbon charging episodes gradually increases from west to east in the Shunbei area. This increase was driven by different tectonic events throughout geological history and the subsequent evolution of paleo-structural patterns. This study has a significant impact on marine carbonate reservoir evaluation in strike-slip fault zones in China.

Innovation in assessment of the geothermal energy potential of abandoned hydrocarbon wells in the southern and southeastern foreground of the Bükk Mountains, northeast Hungary

An innovative methodology is introduced to study abandoned oil exploration drillings for possible geothermal energy production at a test area in northeast Hungary. An evaluation method supported by robust statistical analysis was elaborated to provide the possible future investors with adequate technical and earth-science related information for their decision-making processes. All the available data of 161 abandoned hydrocarbon wells, with different physical conditions, were examined based on the proposed evaluation system to provide information about the geothermal energy potential for each well, as well as over a bigger area. The abandoned wells and their environments, the quantity of stored heat, and the fluid temperature and geothermal heat were the key parameters determined, which are critical when considering geothermal energy utilization or thermal water production. The maximum amount of stored energy was determined as the sum of the amount of energy extractable from the rock and the fluid. The heat stored in the rock was determined by basin modelling. The evaluation process, using one-dimensional (1D) basin modelling and 3D lithological-stratigraphic modelling, was successfully applied in the pilot area. The maximum amount of heat stored in the fluid can be determined by subtracting the heat stored in the rock from the total heat. Drilling and completing geothermal wells are rather expensive in Hungary, depending on the depth and the types of geological formations. The application of this research could greatly reduce the cost and risk of creating new geothermal energy systems based on production wells or abandoned wells in Hungary or elsewhere.

Unraveling the early petroleum migration of the Potiguar Basin, Brazil: Constraints from fluid inclusions of the Ubarana and Lorena oilfields

A coupled study of fluid inclusions and one-dimensional basin modeling allowed the reconstruction of the early hydrocarbon filling history of the main petroleum systems of the Potiguar Basin, Brazil. Confocal laser scanning microscopy, microthermometry and fluorescence spectra measurements were used to model PVTx properties of petroleum inclusions in samples from the onshore Lorena and the offshore Ubarana oilfields. The fluid inclusion data and basin modeling suggest that the initial filling of the Lorena reservoir (Pendência Formation) occurred during the rift stage in two scenarios at 62.7–80.6 °C (11–16.8 MPa): (i) the late rift phase in the Barremian–Early Aptian (ca. 129–124 Ma) or during the beginning of the uplifting phase in the Aptian (ca. 118–117 Ma). In the Ubarana Oilfield, hydrothermal fluids migrated alongside petroleum during the reservoir initial filling. Fluid inclusion homogenization temperatures for both the Açu (mode interval of homogenization temperatures, Th(LV→L)mode interval = 124–128 °C) and Ponta do Mel (Th(LV→L)mode interval = 115–130 °C) formations are higher than the present-day reservoir temperature (110 °C). Isochoric modeling of saddle dolomite-hosted fluid inclusions from the Ponta do Mel Formation indicates trapping temperatures between 128.9 and 133.1 °C and pressures between 10.6 and 12.9 MPa. Temperatures and salinities (16 and 20 mass % equivalent in NaCl + CaCl2) of aqueous inclusions hosted in saddle dolomite are similar to those of the fluid inclusions trapped in hydrothermal minerals in Mississippi Valley-Type Pb–Zn deposits. No specific timing can be suggested for the hydrothermal event in Ubarana Oilfield. However, this atypical (hydrothermal) petroleum system could be linked to two possible scenarios: (i) the onset of petroleum migration of the Alagamar Formation during the Cenozoic Macau (ca. 48–8.8 Ma) magmatic event; or (ii) an earlier activity of the petroleum system, prior to the peak oil generation (50–10 Ma).

OIL AND GAS MODELING GENERARION IN THE JURASSIC SEDIMENTS IN THE SOUTH-EASTERN OF THE WEST SIBERIAN PETROLEUM PROVINSE

The article presents the one-dimensional basin modeling performed in four wells to reconstruct the thermal history of deposits and reconstruct the effective values of the heat flow density.

Effective source rock selection and oil\u2013source correlation in the Western Slope of the northern Songliao Basin, China

This study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

Timeframe of hydrocarbon migration in the Paleogene Shahejie Formation in the Dongying depression, Bohai Bay Basin (northeastern China) based on fluid inclusions and oil geochemistry

The Dongying depression is an important oil-producing area in northeastern China, where the Paleogene Shahejie Formation is the main oil-bearing feature. Although petroleum migration and accumulation in the Dongying depression have been extensively studied, the charging history is still unclear. This paper defines the timeframe of petroleum migration on the basis of a comprehensive investigation of fluid inclusions coupled with basin modeling. According to the petrography and microthermometry of the fluid inclusions, types of fluid inclusion with low-peak-range distributions of the homogenization temperature (Th) (85–95 °C for the Niuzhuang sag and 90–105 °C for the Lijin sag) and high-peak-range Th distributions (105–120 °C for the Niuzhuang sag and 115–130 °C for the Lijin sag) were identified. By recovering the burial and thermal histories of Niuzhuang and Lijin sags with pressure–volume–temperature–composition simulation and one-dimensional basin modeling, it can be inferred that the trapping pressures of two types of hydrocarbon inclusions were higher than the corresponding paleopressure. (42.4 and 42.0 MPa, respectively), indicating rapid hydrocarbon charging resulting from abnormally high pressure. Two hydrocarbon charging events associated with the regional tectonic evolution of the Dongying depression, namely, continuous deposition and tectonics in the Paleogene Dongying Formation (Ed) and rapid deposition and tectonics in the Paleogene Minghuazhen Formation (Em), were inferred. The direction of oil charging was traced from the center to the margin in the north, and from the center to the central fault in the southeastern part of the depression in general, as indicated by the molecular maturity parameters, which roughly coincided with the abnormal pressure.

Investigation of fluid inclusion and oil geochemistry to delineate the charging history of Upper Triassic Chang 6, Chang 8, and Chang 9 tight oil reservoirs, Southeastern Ordos Basin, China

Abstract The Chang 6, Chang 8, and Chang 9 reservoirs of the Upper Triassic Yanchang Formation in the Zhenjing area of the Ordos Basin are characterized by low porosity, low permeability, high oil saturation, and large oil reserves, which indicate huge tight oil potential. To comprehensively investigate the hydrocarbon contributors and charging history, fluid inclusions were systemically studied coupled with basin modeling and oil geochemical analysis. According to the petrographic characteristics, two episodes of fluid inclusions occurred in each of the three reservoirs. Microthermometry analysis suggests that the hydrocarbon inclusions of the first episode in each reservoir are distributed mainly along overgrowth quartz or secondary microcracks and exhibit light yellow or light brown fluorescence; the coeval aqueous inclusions display low homogenization temperature (Th) peaks with 80–100 °C. The hydrocarbon inclusions of the second episode in each reservoir are mainly distributed in microcracks that cut across or within quartz grains and exhibit light green or bluish-green fluorescence; the coeval aqueous inclusions are characterized by high Th peaks with 110–120 °C. The different characteristics of the two episodes of the fluid inclusions imply the existence of two episodes of hydrocarbon charging events. The burial and geothermal histories of the various reservoirs were reconstructed using one-dimensional basin modeling and pressure–volume–temperature–composition (PVTX) simulation coupled with the authigenic illite K–Ar dating. The reconstruction implied the time of the two hydrocarbon charging episodes to be Early Cretaceous and Late Cretaceous. Oil-source correlation studies illustrate that the Chang 6, Chang 8, and Chang 9 crude oils all originate from the Chang 7 source rock. The migration characteristics and directions were comprehensively analyzed by using maturity parameters. This explanation of the charging history and oil migration pathway of the Upper Triassic Yanchang Formation in the Zhenjing area provides a theoretical basis for further exploration.

Charging of Carboniferous volcanic reservoirs in the eastern Chepaizi uplift, Junggar Basin (northwestern China) constrained by oil geochemistry and fluid inclusion

Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (Th) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range Th distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C20 + C21 triaromatic steroids/C20 + C21 + C26–C28 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.

Hydrocarbon generation modeling and source rock characterization of the Cretaceous\u2013Paleocene Taratu Formation, Great South Basin, New Zealand

Hydrocarbon generation modeling and source rock characterization have been carried out on rock samples of the Taratu Formation in the Great South Basin, New Zealand. The Paleocene and Late Cretaceous Taratu Formation samples from Tara-1 well are utilized for geochemical studies. Rock-Eval pyrolysis results show that Taratu formation accommodates organic matter of excellent quantity and quality, with proliferous kerogen type II-III (oil and gas prone) and minor kerogen type III (gas prone). Hydrogen index (HI) of this formation ranges from 165.0 to 327.5 mg HC/g TOC and only Late Cretaceous source rock samples are thermally mature, with maximum pyrolysis temperature (Tmax) up to 459 °C and vitrinite reflectance (% Ro) from 0.40 to 1.15% Ro. One-dimensional basin modeling shows a best fit in a calibration of measured and modeled temperatures and vitrinite reflectance. The top of oil window was encountered 51 Ma ago at 3100 m and gas generation took place at 4132 m in 8 Ma ago.

Investigation of Oil Potential in Saline Lacustrine Shale: A Case Study of the Middle Permian Pingdiquan Shale (Lucaogou Equivalent) in the Junggar Basin, Northwest China

The Pingdiquan shale (Lucaogou equivalent) is a typical saline lacustrine deposit in China and is one of the most significant petroleum source strata for the oil and natural gas fields in the Junggar Basin in northwestern China, which is widely acknowledged to have a large shale hydrocarbon potential. This article characterizes the Pingdiquan shale in the eastern Junggar Basin from the geochemical and geological perspectives, describes its oil potential, and compares the results with those from freshwater lacustrine shales. The Pingdiquan shale is highly heterogeneous in its mineral composition, with a big variation in each composition compared to that of freshwater lacustrine shales. The Pingdiquan shale can generally be classified into clastic shale and dolomite shale, where the clastic shale is distributed across the eastern Junggar Basin and thins from north to south, whereas the dolomite shale is developed only in the Jimusaer Sag and at the foot of the Kelameili Mountains. The Pingdiquan shale (both the clastic shale and dolomite shale) has a good petroleum potential and primarily consists of types II and III organic matter with thermal maturity ranging from early to late mature. The oil content (S1) of clastic shale and dolomite shale ranges from 0.01 to 4.96 mg/g and 0.02 to 3.23 mg/g, respectively. The oil content and oil saturation index (OSI) of the Pingdiquan shale reach a maximum value at the early to peak mature zone (Tmax of 445–450 °C). Similar trends can be observed in some typical freshwater lacustrine shales. In the Pingdiquan Formation, the dolomite shale has a higher total organic carbon content and genetic potential (S1 + S2) than the clastic shale; however, its oil content and OSI are lower than those of the clastic shale, as is its production index (PI). The results of one-dimensional basin modeling show that the dolomite shale and clastic shale have had almost the same petroleum transformation ratio values throughout geological history. However, the permeability of dolomite shale is orders of magnitude larger, which allows for more petroleum to be expelled from source rocks. In addition, positive correlations between specific surface areas and OSI and clay content are observed, indicating that high clay content also assists in maintaining the petroleum within the rocks. Therefore, less oil can be retained within dolomite shale than in clastic shale.

Numerical modeling of the tectonic and thermal history of the Kyndal Graben of the Bureya Basin (Far East of Russia)

One-dimensional basin modeling of the Kyndal Graben, Bureya Basin, is conducted in three deep wells. The basin modeling technique and its basic algorithms are described. The geological and geophysical characteristics of the studied object are reported in brief, emphasizing the modeling parameters. The general and tectonic history of the subsidence, sedimentation velocities, geodynamic parameters of the extension, and thermal history of the formation and evolution of the Kyndal Graben, Bureya Basin, are calculated.

Geochemical characteristics of crude oil from a tight oil reservoir in the Lucaogou Formation, Jimusar sag, Junggar Basin

Jimusar sag, which lies in the Junggar Basin, is an important tight oil study area in China. However, the properties and origin of the crude oil and the geochemical characteristics of the tight oil from the Lucaogou Formation have not yet been studied. In the present study, 23 crude oil samples from the Lucaogou Formation were collected for analysis, including physical properties (density and viscosity), bulk composition, saturated hydrocarbon gas chromatography–mass spectrometry, and calculation of various biomarker parameters. Source rock evaluation and porosity permeability analysis were applied to the mudstones and siltstones. To analyze the hydrocarbon generation history of the Lucaogou source rocks, one-dimensional basin modeling was performed. The oil-filling history was also investigated by means of basin modeling and microthermometry. Biomarkers of suitable source rocks (total organic carbon content is >1%, summation of the free and volatile hydrocarbon and remaining hydrocarbon generative potential is >6 mg HC/g rock, and vitrinite reflectance is between 0.7% and 1%) were analyzed for oil–source correlation. The results indicate that low-maturity to mature crude oils originated from the source rocks containing terrigenous organic matter, which were deposited in a saline lake. The source rocks are of mainly type II kerogen. Oil in the lower section of the Lucaogou Formation is relatively dense and viscous and has elevated nonhydrocarbon content. In addition, a higher proportion of bacteria and algae is shown to have contributed to the formation of crude oil in the lower section when compared with the upper section of the Lucaogou Formation. Oil–source correlations demonstrate that not all mudstones within the Lucaogou Formation contribute to oil accumulation. Thin section observation indicates organic macerals surround the grains of some siltstones within the porous and permeable subsections, which proves the siltstones contribute to hydrocarbon generation. Crude oils from the upper and lower sections mainly originate from thin-bedded mudstones interbedded and siltstones within the porous and permeable subsections. The mudstones over or beneath the porous and permeable subsections consist of seals and prevent the vertical movement of oil by capillary forces. Despite being thicker, mudstones between the two porous and permeable subsections make no obvious contribution to the oil accumulation because of their low permeability and distance from the porous and permeable subsections, which is consistent with the principle of near-source charging for tight oil accumulations. Lucaogou oil has been charged twice, once from 235 to 210 Ma and again from 180 to 150 Ma, coinciding with oil generation time.

Petroleum accumulation in the deeply buried reservoirs in the northern Dongying Depression, Bohai Bay Basin, China: New insights from fluid inclusions, natural gas geochemistry, and 1-D basin modeling

The deeply buried reservoirs (DBRs) from the Lijin, Shengtuo and Minfeng areas in the northern Dongying Depression of the Bohai Bay Basin, China exhibit various petroleum types (black oil-gas condensates) and pressure systems (normal pressure-overpressure) with high reservoir temperatures (154–185 °C). The pressure-volume-temperature-composition (PVTX) evolution of petroleum and the processes of petroleum accumulation were reconstructed using integrated data from fluid inclusions, stable carbon isotope data of natural gas and one-dimensional basin modeling to trace the petroleum accumulation histories.The results suggest that (1) the gas condensates in the Lijin area originated from the thermal cracking of highly mature kerogen in deeper formations. Two episodes of gas condensate charging, which were evidenced by the trapping of non-fluorescent gas condensate inclusions, occurred between 29-25.5 Ma and 8.6–5.0 Ma with strong overpressure (pressure coefficient, Pc = 1.68–1.70), resulting in the greatest contribution to the present-day gas condensate accumulation; (2) the early yellow fluorescent oil charge was responsible for the present-day black oil accumulation in well T764, while the late blue-white oil charge together with the latest kerogen cracked gas injection resulted in the present-day volatile oil accumulation in well T765; and (3) the various fluorescent colors (yellow, blue-white and blue) and the degree of bubble filling (Fv) (2.3–72.5%) of the oil inclusions in the Minfeng area show a wide range of thermal maturity (API gravity ranges from 30 to 50°), representing the charging of black oil to gas condensates. The presence of abundant blue-white fluorescent oil inclusions with high Grain-obtaining Oil Inclusion (GOI) values (35.8%, usually >5% in oil reservoirs) indicate that a paleo-oil accumulation with an approximate API gravity of 39–40° could have occurred before 25 Ma, and gas from oil cracking in deeper formations was injected into the paleo-oil reservoir from 2.8 Ma to 0 Ma, resulting in the present-day gas condensate oil accumulation. This oil and gas accumulation model results in three oil and gas distribution zones: 1) normal oil reservoirs at relatively shallow depth; 2) gas condensate reservoirs that originated from the mixture of oil cracking gas with a paleo-oil reservoir at intermediate depth; and 3) oil-cracked gas reservoirs at deeper depth.The retardation of organic matter maturation and oil cracking by high overpressure could have played an important role in the distribution of different origins of gas condensate accumulations in the Lijin and Minfeng areas. The application of oil and gas accumulation models in this study is not limited to the Dongying Depression and can be applied to other overpressured rift basins.

Organic geochemistry, petrology and palynofacies of Middle Devonian lacustrine flagstones in the Orcadian Basin, Scotland: depositional environment, thermal history and petroleum generation potential

AbstractDuring Middle Devonian time a thick succession of organic-rich, mainly lacustrine flagstones developed within the Orcadian Basin. These petroleum source rocks crop out in northern Scotland. Nineteen samples were studied using organic petrology, palynology and organic geochemistry in order to characterize kerogen type, depositional environment, thermal maturity and petroleum generation potential. Corg, carbonate and sulphur content as well as hydrogen index (HI) values are quite variable (e.g. HI from 79 to 744 mg HC/g Corg). Based on biomarker data, organic material mainly originates from aquatic organic matter deposited under lacustrine conditions with oxygen-depleted, but not permanently anoxic, bottom waters. Petrography reveals small quantities of vitrinite particles, indicating minor input of terrestrial material. This is supported by biomarker data and the palynofacies, which is characterized by a high amount of oil-prone amorphous organic matter (AOM) and generally few miospores. Maturity of the succession studied in Caithness and Orkney is between immature and oil mature. One-dimensional basin modelling shows that a significant remaining hydrocarbon generation potential exists within the Middle Devonian succession. In contrast to the low hydrocarbon generation in the onshore area, offshore oil generation was significant, especially after deposition of thick Upper Jurassic – Upper Cretaceous sediments. At the end of Cretaceous time, hydrocarbon generation ceased due to uplift. The contribution to known oil fields from the Devonian flagstones is a realistic scenario, including a contribution to the Beatrice oil field in the south of the modelled area.

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.

Burial and thermal maturity modeling of the Middle Cretaceous–Early Miocene petroleum system, Iranian sector of the Persian Gulf

The Cretaceous Kazhdumi and Gurpi formations, Ahmadi Member of the Sarvak Formation, and Paleogene Pabdeh Formation are important source rock candidates of the Middle Cretaceous–Early Miocene petroleum system in the Persian Gulf. This study characterizes generation potential, type of organic matter, and thermal maturity of 262 cutting samples (marls and argillaceous limestones) from these rock units taken from 16 fields in the Iranian sector of the Persian Gulf. In addition, the burial and thermal histories of these source rocks were analyzed by one-dimensional basin modeling. Based on the total organic carbon and genetic potential values, fair hydrocarbon generation potential is suggested for the studied samples. Based on T max and vitrinite reflectance values, the studied samples are thermally immature to mature for hydrocarbon generation. The generated models indicate that studied source rocks are immature in central wells. The Gurpi and Pabdeh formations are immature and the Ahmadi Member and Kazhdumi Formation are early mature in the western wells. The Pabdeh Formation is within the main oil window and other source rocks are at the late oil window in the eastern wells. The hydrocarbon expulsion from the source rocks began after deposition of related caprocks which ensures entrapment and preservation of migrated hydrocarbon.

Petroleum generation and expulsion characteristics of Lower and Middle Jurassic source rocks on the southern margin of Junggar Basin, northwest China: implications for unconventional gas potential

Jurassic strata along the southern margin of Junggar Basin are important petroleum system elements for exploration in northwest China. The Lower and Middle Jurassic source rock effectiveness has been questioned as exploration progresses deeper into the basin. These source rocks are very thick and are distributed widely. They contain a high total organic carbon composed predominantly of Type III kerogen, with some Type II kerogen. Our evaluation of source rock petroleum generation characteristics and expulsion history, including one-dimensional basin modeling, indicates that Jurassic source rocks are gas prone at deeper depths. They reached peak oil generation during the Early Cretaceous and began to generate gas in the Late Cretaceous. Gas generation peaked in the Paleogene–Neogene. Source rock shales and coals reached petroleum expulsion thresholds at thermal maturities of 0.8% and 0.75% vitrinite reflectance, respectively, when the petroleum expulsion efficiency was ∼40%. The petroleum generated and expelled from these source rocks are 3788.75 × 108 and 1507.55 × 108 t, respectively, with a residual 2281.20 × 108 t retained in the source rocks. In these tight reservoirs, a favorable stratigraphic relationship (where tight sandstone reservoirs directly overlie the source rocks) indicates short vertical and horizontal migration distances. This indicates the potential for a large, continuous, tight-sand gas resource in the Lower and Middle Jurassic strata. The in-place natural gas resources in the Jurassic reservoirs are up to 5.68 × 1012 − 15.14 × 1012 m3. Jurassic Badaowan and Xishanyao coals have geological characteristics that are favorable for coal-bed methane resources, which have an in-place resource potential between 3.60 × 1012 and 11.67 × 1012 m3. These Lower and Middle Jurassic strata have good shale gas potential compared with active US shale gas, and the inferred in-place shale gas resources in Junggar Basin are between 20.73 × 1012 and 113.89 × 1012 m3. This rich inferred conventional and unconventional petroleum resource in tight-sand, coal-bed, and shale gas reservoirs makes the deeper Jurassic strata along the southern margin of Junggar Basin a prospective target for future exploration.

Source rock characteristics and hydrocarbon generation modelling of Upper Cretaceous Mukalla Formation in the Jiza-Qamar Basin, Eastern Yemen

The Upper Cretaceous Mukalla coals and other organic-rich sediments which are widely exposed in the Jiza-Qamar Basin and believed to be a major source rocks, were analysed using organic geochemistry and petrology. The total organic carbon (TOC) contents of the Mukalla source rocks range from 0.72 to 79.90% with an average TOC value of 21.50%. The coals and coaly shale sediments are relatively higher in organic richness, consistent with source rocks generative potential. The samples analysed have vitrinite reflectance in the range of 0.84–1.10 %Ro and pyrolysis Tmax in the range of 432–454 °C indicate that the Mukalla source rocks contain mature to late mature organic matter. Good oil-generating potential is anticipated from the coals and coaly shale sediments with high hydrogen indices (250–449 mg HC/g TOC). This is supported by their significant amounts of oil-liptinite macerals are present in these coals and coaly shale sediments and Py-GC (S2) pyrograms with n-alkane/alkene doublets extending beyond nC30. The shales are dominated by Type III kerogen (HI < 200 mg HC/g TOC), and are thus considered to be gas-prone.One-dimensional basin modelling was performed to analysis the hydrocarbon generation and expulsion history of the Mukalla source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial/thermal maturity histories in order to improve our understanding of the of hydrocarbon generation potential of the Mukalla source rocks. Calibration of the model with measured vitrinite reflectance (Ro) and borehole temperature data indicates that the present-day heat flow in the Jiza-Qamar Basin varies from 45.0 mW/m2 to 70.0 mW/m2 and the paleo-heat flow increased from 80 Ma to 25 Ma, reached a peak heat-flow values of approximately 70.0 mW/m2 at 25 Ma and then decreased exponentially from 25 Ma to present-day. The peak paleo-heat flow is explained by the Gulf of Aden and Red Sea Tertiary rifting during Oligocene-Middle Miocene, which has a considerable influence on the thermal maturity of the Mukalla source rocks. The source rocks of the Mukalla Formation are presently in a stage of oil and condensate generation with maturity from 0.50% to 1.10% Ro. Oil generation (0.5% Ro) in the Mukalla source rocks began from about 61 Ma to 54 Ma and the peak hydrocarbon generation (1.0% Ro) occurred approximately from 25 Ma to 20 Ma. The modelled hydrocarbon expulsion evolution suggested that the timing of hydrocarbon expulsion from the Mukalla source rocks began from 15 Ma to present-day.

Hydrocarbon Potentials, Thermal and Burial History in Herwa-1 Well from the Nigerian Sector of the Chad Basin: An Implication of 1-D Basin Modeling Study

This research study attempt to evaluate the hydrocarbon potentials, thermal and burial history and the timing of hydrocarbon generation in Herwa-1 well within the Nigerian Sector of the Chad basin. Organic geochemical study of some ditch cuttings samples from Herwa-1 well and a One-dimensional basin modeling study was carried out. The result of the geochemical analysis revealed a moderate to good TOC greater than 0.5wt% in Fika and Gongila formation, the Hydrogen Index (HI) ranges from 150-300 (mgHC/g) and the Tmax values falls within the range of greater than or equal to 430°C. The hydrocarbon potentials in Herwa-1 well was further supported with the values of S1+S2 which is greater than or equal to 2 mg/g of rock in almost all the samples, suggesting a good hydrocarbon potentials. The 1-D basin model was constructed for Herwa-1 well in order to assess the burial history and thermal maturity of the potential source rocks in the Nigerian sector of the Chad basin. The modeling results indicate that maximum burial occurred in the late Miocene and suggesting erosion might have been the cause of the thinning of the Tertiary sediments in the present time. The calibration of Vitrinite reflectance against Temperature revealed the present day heat flow to be at 60 mW/m² and Paleo heat flow falls within the range of 68 mW/m². However, it is also revealed that Oil Window begins at (0.60-1.30% VRr) at the depth of (2000-3000 m) in the middle Cretaceous and the Gas Window start during the late Cretaceous to Tertiary with a value of (1.3-2.5% VRr) at a depth greater than (3500 m).