Petroleum System Research Articles

A new objective function designed for the calibration of stratigraphic forward models

This paper presents a novel and quantitative method of comparing facies successions of distinct sizes and resolutions, adapted for the automated calibration of stratigraphic forward models (SFM). The method, which corresponds to the calculation of an objective function, consists of correlating time-sampled SFM results with space-sampled well logs using a strategy inspired by methods of automated well log correlation. The method was designed to be generic and to accept multi-variate definition of facies, so that it can be applied in a variety of geological contexts (e.g., mixed carbonate-clastic environments). The method demonstrated properties suitable for automated calibration, such as a smooth and almost convex relationship with individual simulation parameters. The method was applied to a case-study using gradient-based, meta-heuristic, Bayesian, and random optimization strategies in an 8-dimensional uncertain space. The results show that calibrated models can be found, but there are still non-uniqueness issues due to compensation effects between uncertain parameters. Therefore, a calibration strategy capable of identifying these multiple solutions is necessary to propagate geological uncertainties in petroleum system assessments and field production predictions.

Geochemistry of oils and condensates from the lower Eagle Ford formation, south Texas. Part 4: Diamondoids

A rich variety of diamondoid indices exists that are assumed to be diagnostic of source facies, thermal maturity, the extent of oil cracking, mixed oils, and reservoir alteration processes. These parameters were developed either from empirical relationships observed in source rocks and oils produced from conventional reservoirs or laboratory experiments. Diamondoid parameters are now being routinely applied to unconventional oils; however, their accuracy and reliability have not been rigorously tested in these petroleum systems.Here, we examine diamondoid compositions in a suite of lower Eagle Ford oils and condensates with well-constrained source facies and thermal maturity established by other geochemical measurements and basin modeling. Diamondoid concentrations are low in samples from ∼0.8 to 1.35 %Ro, and then increase significantly at higher maturity due to the cracking of less stable hydrocarbons. Most published maturity-dependent diamondoid indices are not diagnostic when maturity is ≲ 1.1 %Ro and are influenced by source facies. Based on our data, their predictive accuracy is no better than ±0.2 %Ro at higher maturity. Published source indices are not diagnostic of a specific kerogen type or lithofacies but may be used to differentiate sources in complex petroleum systems. Quantitative diamondoid analysis can be used to calculate the degree of oil-to-gas conversion; however, the natural variance in the baseline concentration of 3-+4-methydiamantanes limits its accuracy at maturities ≲1.35 %Ro. Three lower Eagle Ford oils associated with Karnes Trough faults exhibit anomalous diamondoid distributions behavior that these reservoirs received secondary charges from a source other than lower Eagle Ford (likely Austin Chalk). Evidence for a secondary charge was not apparent from the study of the saturated and aromatic biomarkers. In summary, established diamondoid maturity and source indices based on compound ratios should be used with caution to characterize unconventional oils/condensates while quantitative diamondoid analysis can be used with greater confidence and can provide insights that are not apparent from other geochemical parameters provided that highly accurate determination of diamondoid concentrations can be obtained. In the case of the Eagle Ford oils and extracts, analyses must be accurate to less than 1 ppm.

Geophysical Modeling and Its Contribution on the Reservoir Characterization of Al Baraka in El Gallaba Plain, South Egypt

Summary The early Cretaceous formations in recent years are considered significant potential hydrocarbon-bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon-bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in-depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low-water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.

Oil and gas potential of the eocene-paleocene deposits of the Black Sea-Caspian region based on basin analysis and bm&psm modeling

Background. Issues associated with the investigation of hydrocarbon prospects of the Paleocene-Eocene section of the sedimentary cover in the Black Sea-Caspian region are considered.Aim. Assessment of the oil and gas potential of the Paleocene-Eocene deposits under consideration.Materials and methods. A comprehensive basin analysis concerning petroleum system concepts based on published geological, geophysical and geochemical data, as well as paleogeographic reconstructions, geological mapping and database creation with subsequent BM&PSM accomplishment.Results. The identified and examined substantive Paleocene-Eocene petroleum systems were assessed in terms of geological risks with the purpose of recognizing the most promising areas for further exploration.

Triassic source rocks of the Eastern Ciscaucasia

Background. Triassic deposits of the Eastern Ciscaucasia belong to the upper part of the transient zone, which is considered promising for hydrocarbon exploration. The presence of numerous deposits, as well as non-commercial hydrocarbon flows in boreholes, indicate the existence of petroleum systems in this part of the section. However, issues related to the sources of hydrocarbons in the Triassic deposits still remain unresolved.Aim. To identify and study the possible source rocks for the Triassic deposits of the Eastern Ciscaucasia, as well as to assess their contribution to the hydrocarbon potential of the upper part of the transient zone.Materials and methods. Research materials involved all available geological, geophysical and geochemical data published on the section under study, as well as reports from the Russian Federation geological repository. The collected data were analyzed as part of the conducted basin analysis. Numerical basin modeling and paleogeographic reconstructions were performed.Results. The paleogeographic conditions of the Eastern Ciscaucasia and the adjacent areas of the Caspian Sea at the Triassic period were studied. The results of basin analysis were used to construct the distribution maps of Neftekumskaya, Kultaisko-Demyanovskaya and Kizlyarskaya source rocks and to assess their charging ability for Lower and Middle Triassic reservoirs.Conclusion. The conducted numerical modelling revealed several pods of still active source rocks in the Neftekumskaya, Kultaisko-Demyanovskaya and Kizlyarskaya sections. Lower Triassic reservoirs charged from both the Neftekumskaya and Kultaisko-Demyanovskaya source rocks, unlike Middle Triassic reservoirs that charged from the Kizlyarskaya source rocks. Thus, independent petroleum systems separated by the Anisian seal at the two stratigraphic levels in the Triassic part of the transitional complex of Eastern Ciscaucasia were identified.

Rapid and integrated petroleum systems analysis with dynamic gas fraction and flexural reconstructions: Application to hydrocarbon charge and commodity risk

The most time consuming and computationally intensive steps in petroleum systems analysis involve building heat flow boundary conditions that are consistent with regional geologic observations, solving the transient heat equation, and translating a range of hydrocarbon charge predictions from source intervals into prospect specific predictions that can be used for decision making in oil and gas exploration. Furthermore, three-dimensional regional flexure, which can have a significant impact on paleo-migration pathways, often is not included in the critical step of translating charge calculations into trap specific predictions due to the time-consuming nature of map preparation. In this paper, an efficient and integrated petroleum systems analysis (IPA) workflow is presented with a new fast, semi-analytical, decoupled approach for solving the transient heat equation that is fully integrated with a rapid inversion methodology for transient heat flow boundary conditions and a 3D regional flexural reconstruction that uses standard basin modeling inputs and requires little to no additional map preparation. A charge-to-trap model is also described that translates hydrocarbon expulsion calculations with dynamic parameterized gas fractions that vary with transformation ratio into trap specific predictions using flexurally restored migration polygons. This fully integrated and efficient approach enables rapid interactive investigation of uncertainty space and fast probabilistic modeling that is ideal for evaluating hydrocarbon charge and commodity risk in data-sparse frontier basins. The applicability of this approach is demonstrated for assessing charge and commodity risk with a case study from the Colorado Basin, Argentina, whereby two alternative hydrocarbon accumulation hypotheses that postulate that traps are filled to structural spill with undersaturated oil are tested for reservoirs located in the upper Colorado Formation that are charged by postulated Aptian and Neocomian source rocks. This application indicates that it is unlikely that the tested traps are filled to structural spill with undersaturated oil, and how incorrect conclusions on hydrocarbon commodity may be reached if 3D regional flexure is not considered during petroleum systems analysis. Finally, it is also shown how this integrated and efficient approach can be implemented with low-cost computational platforms such as Python Anaconda or in spreadsheet programs that empower modelers to rapidly translate their ideas into benchmarked prototypes that can be immediately leveraged by the geoscience community (www.github.com/eakneller/ipatoolkit3D).

Perspectives on geologic carbon storage

Geologic carbon storage (GCS) is a fundamental pillar of carbon management that helps mitigate greenhouse gas emissions and addresses the negative effects of climate change. Viable CO2 storage sites share some of the same elements required for successful petroleum systems. For example, while reservoir, seal, and trap are required, migration pathway and timing are not important for CO2 storage, because rather than withdrawing fluid from a trap, CO2 storage involves injection into a geologic trap. Conceptually, this represents a form of reverse production. Numerous petroleum traps around the world, as well as naturally occurring CO2-producing fields and natural gas storage sites attest that safe, long-term storage is possible. Research over the past two decades identified five methods of Geologic Carbon Storage which have been validated through several demonstration and pilot projects around the world: (1) storage in depleted oil and gas fields, (2) use of CO2 in enhanced hydrocarbons recovery (3) storage in saline formations/aquifers, (4) injection into deep unmineable coal seams, and (5) in-situ/ex-situ carbon mineralization. The greatest volumetric potential for GCS is found in saline aquifers which are present throughout the world’s sedimentary basins.

Use of multibeam bathymetry and backscatter to improve seabed geochemical surveys — Part 1: Historical review, technical description, and best practices

Oil and gas seeps have been a key tool in hydrocarbon exploration since ancient times. Basin-wide reconnaissance exploration, focused on basic geology and identification of hydrocarbon seepage, has been typical of onshore basin analysis since the beginning of the petroleum industry. Since the discovery of marine chemosynthetic “cold seep” communities in the mid-1980s, and their association with offshore oil and gas seepage, the energy industry has been mapping seeps to target them for exploration and avoid them in development. For exploration, the successful sampling of oil or gas at the seafloor reduces exploration risk by demonstrating generative source rock, maturation, migration, and charge — all key data about the subsurface petroleum systems. In the marine environment, seep communities and associated diagenetic precipitates can modify the bathymetry and/or the backscatter and can be imaged by multibeam echo sounder (MBES). MBES can provide detailed bathymetry of the seafloor; multibeam backscatter can provide not only potential targets for seep sampling but also information on the seafloor characteristics at or just below the seafloor, and multibeam water column data can image gas plumes rising from the seafloor. Multibeam was introduced outside of military applications in the 1970s with the application of multibeam to seep science in the oil and gas industry, and the use of ultrashort baseline-positioned cores in a real-time geographical information system (GIS) to target seeps, began in the late 1990s, with the first proprietary survey in 2000. We review the history of multibeam, the history of seep science, and “lessons learned” over decades to best practices in seep hunting, from vessel specification to dry dock to presurvey to survey operations to target selection.

Modes of gas migration and seepage on the salt-rooted Palmahim Disturbance, southeastern Mediterranean

Mass transport complexes often form key elements of petroleum systems, affecting sedimentary structures, seepage pathways and biodiversity hotspots on the seafloor. Yet, the feedback and interaction between these elements is not well constrained. This study investigates the modes of gas accumulation, migration, and seepage at the toe of Palmahim Disturbance (PD), a major salt-rooted mass transport complex across the southeastern Mediterranean margin, and adjacent edge of the eastern deep-sea fan of the Nile. Interpretation of a 3D time migrated seismic reflection dataset was calibrated with visual seafloor observations of active seepage. The toe of PD, in the eastern part of the study area, comprises four km-scale NE-SW oriented bathymetric ridges. At the crests of the eastern three of these ridges are six, hundreds-of-meters wide pockmark systems, four of which host verified seeps. Multiple sub-circular tens-of-meters wide pockmarks are mapped in the Nile fan west of PD. Active seepage was also identified within two elongate pockmarks along the flanks of the bordering Levant Channel. The seismic data reveal that the PD toe pockmarks and ridges overlie anomalous high amplitude seismic reflections (HASRs) from just beneath the surface to hundreds-of-meters deep intervals - below, at the base of and within a buried paleo mass transport deposit (MTD). These HASRs are interpreted to represent multiple gas-bearing intervals within thrust-faulted and folded blocks and their intermittent sealing, primarily at the base of the MTD. The Nile fan pockmarks overlie pervasive sub-seafloor HASRs that are overlain by low amplitude reflections, interpreted as gas-bearing channel-lobe sediments. Gas migration occurs via lateral to updip flow within depositional features and deeper folded sediments, and via sub-vertical flow, associated with the formation and leakage of transient reservoirs. Extension of fan sediments towards the PD pockmarks suggests additional updip focusing of gas, complementing sub-vertical gas flow to the PD pockmarks.

Modeling the petroleum system of the Sabinas Basin, Northeastern Mexico; Part 1: Thermal evolution, hydrocarbon generation, and migration

Modeling the petroleum system of the Sabinas Basin, Northeastern Mexico; Part 1: Thermal evolution, hydrocarbon generation, and migration

Effect of thermal maturation on the isotopic compositions of volatile organic sulfur compounds released from a kerogen by hydrous and anhydrous pyrolysis

Volatile organic sulfur compounds (VOSCs) may provide an alternative and improved approach in the evaluation of source and thermal maturity of natural gas. However, the role of water in the generation and decomposition of VOSCs is still ambiguous. Hydrous pyrolysis experiments were conducted on the isolated type Ⅱ-S kerogen of a source rock collected from the Ghareb Formation, Israel at 200–360 ℃ for 72 h (Easy%Ro = 0.32–1.20). The evolved gases were quantified for C1-C5 hydrocarbons, CO2, H2S and VOSCs. Compound specific isotope analysis were conducted both on the VOSCs and H2S (δ34S), and also on the C1-C5 hydrocarbons and CO2 (δ13C, δ2H). The results show that thiols concentration increased from 200 ℃ to 300 ℃ and then decreased from 300 ℃ to 360 ℃. The formed thiols isotopically co-vary with H2S from 200 ℃ to 340 ℃ and present the opposite trend with H2S from 340 ℃ to 360 ℃. The δ34S values of thiols are usually 3–7‰ lighter than the parent kerogen and 0.5–4‰ heavier than H2S. The concentrations of thiophenes generally increased with thermal stress with peak generation at 360 ℃, the δ34S values of thiophenes are mostly < 2–4‰ lighter than the parent kerogen and 2–8‰ heavier than H2S through the experiments. The δ13C and δ2H values of gaseous hydrocarbons are gradually enriched in heavy isotopes with increased thermal maturity. VOSCs dominated by thiols and thiophenes are generated by two ways: 1. the interactions between H2S and hydrocarbon molecules (synthetic pathway), 2. thermal cracking of OMs including kerogen and associated bitumen primary cracking and hydrocarbon secondary cracking (thermal cracking pathway). The synthetic pathway played the major role in the generation of thiols at the immature and early mature stages (200–300 ℃, Easy%Ro = 0.32–0.71), the cracking pathway has the dominant effect on the occurrence of thiols at higher thermal maturity levels (300–360 ℃, Easy%Ro = 0.71–1.20). The main pathway of thiophenes formation throughout the experiments is by the thermal cracking pathway. In the hydrous experiments, water promotes the synthetic pathway that generated thiols and retarded the thermal cracking pathway that forms thiophenes, but had no significant impact on δ34S values of individual VOSCs, δ13C and δ2H values of gaseous hydrocarbons. Therefore, combining with carbon and hydrogen isotopic compositions of gaseous hydrocarbons, molecular and sulfur isotopic compositions of individual VOSCs in the gas phase can provide valuable clues for petroleum systems in sedimentary basins including gas sources, generation pathways, thermal maturity levels and petroleum secondary transformations, such as thermochemical sulfate reduction in the subsurface reservoirs.

3D basin and petroleum system modelling of the early cretaceous play in the NW Persian Gulf

Petroleum systems analysis has become a key part of hydrocarbon resource exploration. Early Cretaceous petroleum system in the northwest of the Persian Gulf basin with prolific source rocks and reservoirs, is the main petroleum system in the region. Most Iranian offshore oils have been stored in this geological interval. Recent studies indicate that finding new resources is still possible. Therefore, for the first time, this study applied a 3D petroleum system modeling approach to predict new prospects based on available seismic and well data in ∼30,000 km2 area. Results showed that the Berriasian Garau, Albian Kazhdumi and Barremian upper Gadvan are the dominant source rocks. Most of the hydrocarbons have originated from the two Binak and Northern troughs as oil kitchens in the northern and northwest areas. Most anticlines formed in the Late Cretaceous before the critical moment of the source rocks. At first, traps adjacent to the Binak and Northern troughs oil kitchens were charged. Then, hydrocarbon migrated laterally to the far structures. The activity of normal faults has played an important role in vertical migration and reservoir oil mixing, especially in oilfields located above the Khafji-Norooz Arch. Albian Burgan sandstone distribution map from process-based forward stratigraphic modeling suggests low probability of stratigraphic traps. Nonetheless, the Burgan anticline reservoirs have the highest oil in place because they have broad drainage area. Finally, three new anticlinal traps with significant oil reserves were identified in the Yamama, Burgan, and Khalij formations in the northwest of the study area. Results of this study help to better understand Early Cretaceous petroleum system performance and identify new hydrocarbon prospects in the study area.

Use of multibeam bathymetry and backscatter to improve seabed geochemical surveys — Part 2: Best practices and case studies in seep hunting for exploration, with an emphasis on Indonesia

The successful sampling of seafloor oil and gas seeps can provide information on source rock, migration, maturation, and charge that can impact exploration decisions. Although 3D seismic data can be interpreted for potential seafloor seeps, multibeam can be acquired over larger areas at lower cost and in a shorter turnaround time, with bathymetry, backscatter, and water column imagery leading to the interpretation of potential seafloor seep targets. The use of multibeam-based exploration early in an exploration project can provide information on the petroleum systems in an area and also areas where no evidence of a petroleum system is present on the seafloor. We have developed case studies of block-specific seep hunting and regional multibeam surveys. For regional surveys, multibeam can be combined with 2D seismic data, ultrashort baseline (USBL)-positioned piston coring, heat flow, high-resolution subbottom profiles, marine gravity and magnetics, and core geochemistry to evaluate exploration potential. The first multibeam-for-exploration survey, with cores acquired for geochemistry, was carried out in 2000 offshore Barbados. Applying a tool used in academia and other industry projects, USBL positioning in real-time in a Geographical Information System (GIS) environment was used to confidently place a core barrel on a seafloor seep target beginning in 2002. In 2003, Unocal acquired the first basin-wide multibeam survey for exploration and demonstrated that multibeam can rapidly interrogate a very large area at a relatively modest cost. Indonesia basin- and regional-scale projects demonstrated the value of multibeam-based exploration through the successful farm-out of exploration blocks with a promotion (in which the farm-in-ee(s) pays a higher percentage of costs than their percentage of equity). We review several examples of seep studies, with an emphasis on Indonesia; target selection philosophy, criteria, and ranking; and target types. Mud volcano and hard substrate sampling can provide information on the subsurface without drilling.

The potential extent of Early Triassic Kockatea Shale equivalent source rocks in the Northern Carnarvon and Perth Basins, Western Australia

In the northern Perth Basin (Western Australia), the Early Triassic Kockatea Shale is the primary petroleum source rock. Possible source rocks in the Northern Carnarvon Basin are more varied and include the Upper Jurassic Dingo Claystone as well as the Early Triassic Locker Shale. Biomarker analyses were conducted on petroleum samples from these basins to understand the nature of the petroleum systems. Many of the analysed petroleum samples contain carotenoids (okenane, chlorobactane and isorenieratane) derived from photosynthetic sulfur bacteria, suggesting that their source rocks were deposited under conditions of photic zone euxinia (PZE) and/or derived from microbialites. In the northern Perth Basin, the major lithofacies contributing to the source rock are dark coloured mudstones deposited under PZE conditions and/or derived from microbialites. In the southern Perth Basin, the potential source rock is either Permian, Jurassic or Cretaceous in age as indicated by the low concentrations or absence of carotenoids and the Triassic biomarker n -C 33 alkylcyclohexane. There is also a possibility that the Lower Triassic Locker Shale is the source rock of petroleum in the Tubridgi field on the Peedamullah Shelf of the Northern Carnarvon Basin, based on the similarity of biomarkers to Perth Basin petroleum sourced from the Kockatea Shale. However, the possibility of charge from the Upper Jurassic Dingo Claystone cannot be entirely excluded. Supplementary material: biomarker dataset is available at https://doi.org/10.6084/m9.figshare.c.6452153

BITUMEN RESOURCES OF THE EAST SIBERIAN BASIN

The so‐called East Siberian “Basin” extends over an ancient continental block, the Siberian Platform, and is made up of a number of smaller‐scale basement arches and basins with a variable sedimentary cover of mostly Proterozoic and Palaeozoic ages. The basin hosts the oldest large‐scale petroleum systems known. Proterozoic (“Riphean”: 1650‐650 Ma) marine source rocks, which were deposited on the passive margins which surrounded much of the Platform, generated hydrocarbons as they were buried, folded and thermally matured during a series of mostly Late Proterozoic to Cambrian continental collisions, with the final collision taking place in the Early Cretaceous along the northeastern (Verkhoyan) margin. The hydrocarbons were transported by long‐distance migration to reservoirs in the sedimentary successions which drape basement uplifts, there forming giant oil and gas accumulations which were sealed by extensive Cambrian evaporites. Subsequent uplift and unroofing, especially in the north and east of the Platform where the seal is not present, led to degradation of the oil to leave giant accumulations of bitumen, defined here as petroleum with an API gravity of less than 10° which is immobile under reservoir conditions. A significantly younger petroleum system, which may still be active, is present in the Vilyui Basin in the NE of the Siberian Platform. This basin was initiated as a mid‐Devonian rift and has a later Palaeozoic and Mesozoic fill.Bitumen accumulations in the East Siberian Basin occur mainly in Precambrian, Cambrian and Permian reservoir rocks, and began to form from precursor oils during the Permian. Around twenty‐five named fields have been described, many of which comprise portions of more extensive belts of bitumen occurrence. Although geological mapping of natural resources in the East Siberian Basin has been carried out since the 19th century, the region remains under‐explored and none of the bitumen accumulations has yet been developed.An attempt is made in this paper to catalogue and map all recorded occurrences of bitumen throughout the East Siberian Basin. Regional geological studies have been conducted in order to understand the origin and habitat of each occurrence. So far as possible, data on the areal extent and stratigraphic thickness of each bitumen occurrence has been collated, together with data on bitumen saturations and quality. These data were used to calculate resource volumes for each accumulation from first principles. Thus the total bitumen resources within the East Siberian Basin have been calculated as 24,640 MM (million) tonnes. Disregarding accumulations regarded as either of insufficient resource‐density or too small to merit consideration, this figure has been reduced to 14,760 MM tonnes. Recoverable reserves, by analogy with comparable resources worldwide, are calculated as 6100 MM tonnes (approximately 33,900 MM brl)

High Resolution ID‐TIMS Redefines the Distribution and Age of the Main Mesozoic Lacustrine Hydrocarbon Source Rocks in the Ordos Basin, China

AbstractUsing high‐precision zircon U‐Pb ID‐TIMS geochronology, tuffs from the Chang 9 shale and the Chang 7 shale were dated. The tuff in the Chang 9 shale is 241.47 ± 0.17 Ma, which falls between the top tuff age of 241.06 ± 0.12 Ma and the bottom tuff age of 241.558 ± 0.093 Ma in the Chang 7 shale. These reveal that the Chang 9 and Chang 7 shales are contemporaneous, belonging to the Ladinian stage of the Middle Triassic. This insight expands the region of the main source rock of Chang 7 to the northeast and will inform the search for the deep Chang 9 shale petroleum system, increasing the scope for exploring the Chang 7 shale system in northern Shaanxi. The research results clarify the relationship between the two sets of shale in the Yanchang Formation and redefine the distribution range of the Chang 7 shale in the Ordos Basin. At the same time, it shows that there is a cross‐layer problem in the stratigraphic division of the Yanchang Formation in different regions, the high‐precision U‐Pb dating technology providing a reference for the fine stratigraphic correlation of other continental basins in the world.

Upper Paleozoic total petroleum system and geological model of natural gas enrichment in Ordos Basin, NW China

Based on the analysis of Upper Paleozoic source rocks, source-reservoir-caprock assemblage, and gas accumulation characteristics in the Ordos Basin, the gas accumulation geological model of total petroleum system is determined. Then, taking the Carboniferous Benxi Formation and the Permian Taiyuan Formation and Shanxi Formation as examples, the main controlling factors of gas accumulation and enrichment are discussed, and the gas enrichment models of total petroleum system are established. The results show that the source rocks, faults and tight reservoirs and their mutual coupling relations control the distribution and enrichment of gas. Specifically, the distribution and hydrocarbon generation capacity of source rocks control the enrichment degree and distribution range of retained shale gas and tight gas in the source. The coupling between the hydrocarbon generation capacity of source rocks and the physical properties of tight reservoirs controls the distribution and sweet spot development of near-source tight gas in the basin center. The far-source tight gas in the basin margin is mainly controlled by the distribution of faults, and the distribution of inner-source, near-source and far-source gas is adjusted and reformed by faults. Generally, the Upper Paleozoic gas in the Ordos Basin is recognized in four enrichment models: inner-source coalbed gas and shale gas, inner-source tight sandstone gas, near-source tight gas, and far-source fault-transported gas. In the Ordos Basin, inner-source tight gas and near-source tight gas are the current focuses of exploration, and inner-source coalbed gas and shale gas and far-source gas will be important potential targets in the future.

Sandstone-hosted uranium deposits of the Colorado Plateau, USA

More than 4,000 sandstone-hosted uranium occurrences host over 1.2 billion pounds of mined and in situ U3O8 throughout the Colorado Plateau. Most of the resources are in two distinct mineral systems with deposits hosted in the Triassic Chinle and Jurassic Morrison Formations. In the Chinle mineral system, base metal sulfides typically accompany mineralization. The Morrison mineral system is characterized by V/U ratios up to 20. The uranium source was likely volcanic ash preserved as bentonitic mudstones in the Brushy Basin Member of the Morrison Formation, and lithic volcanic clasts, ash shards, and bentonitic clay in the lower part of the Chinle Formation. Vanadium originated from two possible sources: iron–titanium oxides that are extensively altered in bleached rock near deposits or from similar minerals in variably bleached red beds interbedded with and beneath the Morrison. In Chinle-hosted deposits, in addition to volcanic ash, a contributing source of both vanadium and uranium is proposed here for the first time to be underlying red beds in the Moenkopi and Cutler Formations that have undergone a cycle of reddening-bleaching-reoxidation. Transport in both systems was likely in groundwater through the more permeable sandstones and conglomerate units. The association of uranium minerals with carbonate and more rarely apatite, suggests that transport of uranium was as a carbonate or phosphate complex. The first comprehensive examination of paleoclimate, paleotopography, and subsurface structure of aquifers coupled with analysis of the geochronology of deposits suggests that that there were distinct pulses of uranium mineralization/redistribution during the period from about 259 Ma to 12 Ma when oxidized mineralizing fluids were intermittently rejuvenated in the Plateau in response to changes in tectonic regime and climate. Multiple lines of evidence indicate that deposits formed at ambient temperatures of about 25 °C to no greater than about 140 °C. In both systems, deposits formed where groundwater flow slowed and was subject to evaporative concentration. Stagnant conditions allowed for prolonged interaction of U- and V-enriched groundwater with ferrous iron-bearing reductants, such as illite and iron–titanium oxides, and more rarely organic material such as plant debris. Paragenetically late in the sequence, reducing fluids introduced additional organic matter to some deposits. Reducing fluids and introduced organic matter (now amorphous and altered by radiolysis) may originate from regional petroleum systems where peak oil and gas generation was from ∼ 82 to ∼ 5 Ma. Our novel analysis indicates that these reducing fluids bleached rock and protected affected deposits from remobilization during exposure and weathering that followed uplift of the Plateau (∼80 to 40 Ma).

Prediction of oil and gas occurrence in the Vilyui hemisineclise according to interpretation of geological and geophysical data and basin modeling (Republic of Sakha (Yakutia))

The paper is aimed at the prediction of oil and gas occurrence of the Upper Permian, Lower Triassic and Lower Jurassic deposits in the Vilyui hemisineclise. The basin modeling research implies the Upper Paleozoic and Mesozoic petroleum system model of the Vilyui hemisineclise. The initial generation time at the bottom of the Permian source rock is 270 Ma. The most intense generation of hydrocarbons is found to be in the late Permian and early Triassic. The generation power of the Permian source rock is 800 trillion m3. The hydrocarbon losses is up to 90% in consequence of unfavorable seal properties of the Lower Triassic and Lower Jurassic clay formations. All the potential hydrocarbon traps of the Vilyui hemisyneclise are considered to be formed during the Cretaceous stage of development. There is therefore an appropriate environment for the hydrocarbon accumulation to be in progress. The interpretation of geological and geophysical data identifies the areal extent prediction of sand reservoirs and overlying clay interlayers of high quality in the Upper Permian and Lower Triassic seals. The goal of a comprehensive approach to the sedimentary basin research is to divide the territory into oil and gas zones of various prospects in relation to the factors controlling hydrocarbon deposits.

Sedimentology and Paleodepositional Environment of the Early-Middle Miocene Tanjong Formation, Southeast Sabah: Evidence from Bulk Geochemistry and Palynology Analyses

Eight stratigraphic sections from well-exposed outcrops of the Early to Middle Miocene Tanjong Formation in the Kalabakan area, southeast Sabah, were investigated using an integrated approach, in which a comprehensive sedimentological facies analysis was linked with bulk geochemistry and palynological analyses. The integration of facies analysis, elemental CHNS, Fourier-transform infrared spectroscopy (FTIR), and palynological data provided a refined evaluation of the origin of organic matter (OM) and the reconstruction of the paleodepositional model. Seven facies associations were classified in the studied Tanjong Formation from 12 lithofacies components, interpreted as environments ranging from fluvial-deltaic to shallow marine: FA1—Floodplain, FA2—Fluvial channel, FA3—Coastal peat mires, FA4—Tidal flat, FA5—Delta front, FA6—Mouth bar, and FA7—Upper shoreface. Evaluation of the C/N ratio ranged between 4 and 48, and the total sulfur content ranged from 0.5 to 3. Elemental CHNS analysis suggests that the organic matter extracted from the coal and mudstone originated from terrestrial plants and fresh marine plankton. Accordingly, the three most prevalent FTIR spectra from the coal and mudstone samples were the OH- functional group stretching, the absorption spectrum of aromatic C=C stretching, and aromatic in-plane/out-of-plane C-H bending. Terrestrially derived organic matter within the examined samples was further validated by the predominance of aromatic compounds, and the palynological analysis indicated a back-mangrove freshwater pollen assemblage and a lower coastal plain setting proximal to the marine environment. The integrated findings from this research are vital in reconstructing a paleodepositional environment model that will improve the predictability of the petroleum system mechanisms and the future hydrocarbon potential for conventional petroleum exploration.