Showing papers in "AAPG Bulletin in 2021"

Sealing mechanisms in volcanic faulted reservoirs in Xujiaweizi extension, northern Songliao Basin, northeastern China

Abstract: Distribution of volcanic reservoirs in Xujiaweizi half graben is controlled by both faults and sealing layers where their integrity could have been compromised. This paper documents the distribution of sealing units of the Denglouku and Yingcheng Formations based on seismic and well-log data to delineate all of the reservoirs with proper cap rocks within the volcanic Yincheng Formation via the relationship between the fault system and reservoir rocks. Based on the regional sealing effect of Denglouku Formation, two hydrocarbon traps are identified: the lower primary and upper secondary gas reservoirs where the formation with a mudstone percentage of more than 50% within the second member seals the primary reservoirs. The upper secondary trap is controlled by faults that have been activated during the structural reversal phase, causing the regional sealing layers in the Denglouku Formation to get displaced with a cap rock juxtaposition thickness of less than 35 m. This has created a series of fault-seal, dual-control reservoirs. The local seals within the Yingcheng Formation consist of mudstone, tight volcanic rock, and clayey breccia covering each volcanic eruption cycle. These local seals separate the volcanic gas reservoirs with a minimum thickness of 20 m. The local top seals in this tectonically active zone were placed on the hanging wall via the juxtaposition of the reservoir and overlying mudstone and/or clayey breccia. It was concluded that gas has migrated vertically through the faults and accumulated in the fault-controlled traps where sharp changes in the lithology (juxtaposition) form the seal, whereas the gas-water contact is controlled by the depth of the reservoir rock. Finally, this study concludes that the primary reservoirs are distributed in a sinusoidal configuration around the fault zone because of the dolphin effect of the Xuzhong strike-slip fault system that has connected the source and reservoir rocks.

Consideration of the limitations of thermal maturity with respect to vitrinite reflectance, Tmax, and other proxies

Abstract: Many of those assessing geochemical data have taken a “cookbook” approach to interpretation. Such an approach generally does not take into consideration the limitations of the different data sets. Among these data sets are those associated with thermal maturity, which guides the interpretation of the extent of generation and hydrocarbon phase. The temperature of peak pyrolysis generation (Tmax) is commonly used to map thermal maturity directly or through a conversion to vitrinite reflectance equivalent values. Such efforts do not take into consideration analytical uncertainties or natural variability within a stratigraphic unit at any given locality. Furthermore, when presented as vitrinite reflectance equivalents, the associated error in the conversion is not considered, yet the values are presented as “absolutes.” When examining vitrinite reflectance, there are also several issues that should be considered. Individual mean values are commonly considered out of context. All thermal maturity indicators, including vitrinite reflectance, need to be placed into a geologic framework, and trends rather than discrete values should be considered. The nature of the studied samples is also significant. Whole-rock and isolated kerogen analyses yield different results, commonly because of the lack of a statistically meaningful number of individual measurements because of either low organic carbon or low concentrations of vitrinite when examining whole-rock samples. Such differences are not trivial, with final interpretation of hydrocarbon phase boundaries potentially being shifted. Bitumen reflectance shares some of the same issues as vitrinite reflectance measurement, including misidentification, the presence of multiple populations and insufficient measurements, and the possibility that environmental factors may influence the observed reflectance. Conversion issues of bitumen to vitrinite reflectance are similar to those identified for the Tmax conversion.

Geological-petrophysical insights in the deep Cambrian dolostone reservoirs in Tarim Basin, China

Abstract: Cores, thin sections, and cathodoluminescence (CL) analysis were integrated to document the occurrence and petrology of dolomites, and their pore systems in the Cambrian of Tarim Basin, China. Depositional facies, pore types and dolomitization processes of various dolostone reservoir types are determined. Six types of dolomite are recognized, including microbial dolomite, dolomicrite, fabric retentive dolomite, fabric-obliterative dolomite, fine to medium crystalline dolomite cement, and saddle dolomite cement. Pore systems are dominantly vugs, anhydrite dissolution pores, intercrystalline pores, intercrystalline dissolution pores, fabric dissolution pores and microfractures. Four porous dolostone reservoirs include sabkha dolostone, seepage-reflux dolostone, burial dolostone, hydrothermal dolostone. Fractures play an important role in enhancing reservoir quality in dolostone reservoirs. Conventional wireline logs and image logs are calibrated with cores and related thin sections. Sabkha dolostone reservoirs are characterized by dark and bright spots on the image logs. Seepage-reflux dolostone reservoirs are related to high-energy depositional facies and are characterized by low gamma-ray amplitude, increasing sonic transit time and neutron porosity but reducing bulk density values. Evident dark spots (vugs) are recognized on image logs, and all three porosity logs suggest relatively high reservoir quality in burial dolostone reservoirs. Hydrothermal dolostone reservoirs are recognized by high gamma-ray response caused by hydrothermal minerals (fluorite), and porosity curves indicate good reservoir quality, which is supported by dark spots (vugs) on the image logs. Rapid decrease in resistivity, increasing in sonic transit time values, and the dark sinusoidal waves on the image logs are typical of fractured dolostone reservoirs. The distribution of dolostone reservoirs in each well is predicted using a comprehensive analysis of conventional and image logs, and they are calibrated with oil test data. The research provides insights in the analysis of genetic model of deeply buried dolostone reservoirs and establishes the predictable model for reservoir quality in dolostones via well logs.

Passive versus active salt diapirism

Abstract: Existing definitions for passive and active salt diapirism are somewhat overlapping and ambiguous. These terms are also equated to downbuilding and upbuilding, respectively, which are problematic concepts as originally conceived and even as subsequently modified. This results in conflicting usage and lack of consensus in the literature, creating confusion and decreasing the utility of the terms. For example, a diapir with a thin roof is defined as active by some but passive by others. In this short contribution, we first review historical definitions and then focus on several inherent problematic aspects including (1) the applicability of the concepts of downbuilding and upbuilding, (2) using the absence or presence and thickness of a diapir roof as criteria to classify diapirs as active or passive, and (3) the related concept of halokinetic sequences. We offer three suggestions in the hope of improving understanding and communication. First, we suggest that the terms downbuilding and upbuilding should be abandoned. Second, we argue that passive diapirism should be used sensu lato in that the presence or absence of a thin roof should not be the key defining factor. Third, we propose that active diapirism should be reserved for two specific scenarios: (1) uplift and folding of a thick roof during diapir rejuvenation and (2) the single brief stage when salt in a precursor structure (e.g., reactive diapir, salt-cored contractional fold, or salt pillow) breaks through its roof to subsequently rise as a passive diapir.

A study of the gas–water characteristics and their implications for the coalbed methane accumulation modes in the Southern Junggar Basin, China

Abstract: Gas and water samples were collected from coalbed methane (CBM) wells, rivers, and springs in the southern Junggar Basin (SJB). These samples were analyzed for gas composition, stable isotopes, 16s ribosomal ribonucleic acid sequence, chemical compositions, and radioisotopes. The objective of this study was to understand CBM genesis in the Junggar Basin, the reason for abnormal CO2 accumulation, the development of microbial communities, the source of coalbed water, and the timing of methanogenesis. The CBM genesis is complex in the SJB, but it is closely related to microbial activities. The stagnant zone, which experiences limited groundwater recharge, may represent a relatively closed system where CO2 is easily trapped and the residual CO2 becomes progressively enriched in 13C. Only two families of methanogens (i.e., Methanobacteriaceae and Methanospirillaceae) are present in the coalbed waters, indicating that CO2 reduction is the main pathway for generating microbial gas. The coalbed water samples from the Houxia and Manasi–Hutubi regions plot around the local meteoric water line (LMWL), indicating recharge by modern meteoric water and rivers. However, the samples from the Miquan and Fukang regions plot below the LMWL, reflecting older snowmelt water recharge. Isotopic dating indicates that the age of coalbed water in the Miquan and Fukang regions is 43.5–2000 ka. Early coalification and later hydrological events collectively determined the regional variations in CBM genesis and gas composition in the SJB.

Depositional environment and hydrothermal controls on organic matter enrichment in the lower Cambrian Niutitang shale, southern China

Abstract: The purpose of this research was to examine paleoenvironments, hydrothermal activity, and seawater restriction of the lower Cambrian Niutitang Formation shale gas reservoir in the eastern Xuefeng uplift and to determine factors affecting organic matter (OM) enrichment. In the studied borehole Xiangan 1 well in western Hunan Province, the Niutitang Formation can be subdivided into the Niu1, Niu2, and Niu3 Members based on geological and geochemical features, including trace element enrichment, lithology, and fossil content. Total organic carbon values of the Niutitang Formation are variable, averaging 1.5 wt. % in the Niu1 Member, 12.7 wt. % in the Niu2 Member, and 5.1 wt. % in the Niu3 Member. Paleoclimatic changes were responsible for changes in biota, which impacted patterns of OM enrichment. Climate proxy (chemical index of alteration) and productivity proxies (biogenic Ba, Cu/Al, and Ni/Al) consistently indicate higher paleoproductivity in the Niu2 Member. The Niu1 and Niu2 Members may be affected by hydrothermal events, whereas hydrothermal activity was absent during deposition of the Niu3 Member. Hydrothermal activity may provide nutrients and silica but may also enhance the reducing condition of the water column. In addition, hydrothermal events may have possibly influenced biological survival in the different environments, which in turn increased their reproduction within the early Cambrian ocean and affected OM production. Redox proxies (Mo and U enrichment factors) imply that the Niu1, Niu2, and Niu3 Members were deposited in suboxic, euxinic, and ferruginous environments, respectively. Redox conditions, strongly restricted water environments, and hydrothermal events were conducive to OM enrichment during the early Cambrian.

Source rocks in foreland basins: A preferential context for the development of natural hydraulic fractures

Abstract: Bedding-parallel veins of fibrous calcite (also called “beef”) occur in many sedimentary basins, especially those containing low-permeability strata with organic source material for petroleum. The formation of such veins is commonly linked with fluid overpressure in these source rocks. In this review, we demonstrate that beef veins are most commonly present in foreland basins worldwide or in basins that recorded a compressive tectonic period. The formation of beef veins is related to two main phases: (1) the initiation of bedding-parallel fracture and (2) the infilling of the fracture. Previous structural studies have shown that formation of beef veins occurred during a period of compressive stress activity. This is especially the case for the Wessex Basin (United Kingdom) and the Neuquen Basin (Argentina). In this paper, we provide more observations for other basins: the Cordillera Oriental (Colombia), the Paris Basin (France), the northern Pyrenees (France), the Uinta Basin (United States), the Tian Shan Mountains (central Asia), and the Appalachian Mountains (United States). In the Paris Basin, beef vein formation is dated at 155 Ma (U/Pb calcite method) and is coeval with the compressional deformation in the eastern part of the basin. Because of the timing of generation for such veins and even if the theory and the experiments of fracturing demonstrate that bedding-parallel fractures can be generated only with a distributed fluid overpressure, the formation of beef veins seems to be a consequence of both fluid overpressures and a compressional tectonic stress.

Geochemistry of high-maturity crude oil and gas from deep reservoirs and their geological significance: A case study on Shuntuoguole low uplift, Tarim Basin, western China

Abstract: The oils of Shuntuoguole low uplift of Tarim Basin in western China have high contents of saturated hydrocarbons and a high loss of light hydrocarbon components because of volatilization. These oils are characterized by low abundance of hopanes and high abundance of C28–30 tricyclic terpanes and dibenzothiophenes and relative high abundance of C20–23 terpanes, C21–22 5α-steranes, and diasteranes in the oils. Quantitative analysis of carbon isotope and biomarkers show that the oils in the Ordovician carbonate rocks are sourced by deep Cambrian and Ordovician marine shales and marls. Geochemistry of the oils indicates that the reservoir has undergone multistage accumulations, with the late-stage oils obscuring traces of biodegradation of paleo-oils charged in the early stage. The concentration of methyl adamantanes and steranes demonstrates that oils occurred in an early stage of intense oil-to-gas cracking. Most of the gases are wet, with dryness lower than 90%, and geochemical analysis suggests that they are mainly from thermal degradation of kerogen. This study suggests that in addition to oils sourced by deeper source rocks in the Shuntuoguole low uplift in situ, there are oils that migrated from the Manjiaer depression into the Shuntuoguole low uplift.

Petroleum distribution in the Montney hybrid play: source, carrier bed and structural controls

Abstract: The main controls on petroleum accumulations in sedimentary basins include source rock distribution, thermal maturity, migration pathways, as well as structural and stratigraphic traps. While shale plays and conventional reservoirs are endmembers governed by contrasted geological processes, unconventional hybrid systems represent a continuum between them and share common characteristics with both. The Montney Formation provides a well-documented example of such a play, where petroleum distribution is controlled by a combination of downdip increase of thermal maturity, fluid migration influenced by lateral and vertical permeability variations, and pressure compartmentalization. In this paper, we integrate publicly available data from thousands of wells within a well-defined stratigraphic framework, to illustrate these regional and local controls on petroleum distribution in the Montney hybrid play. We demonstrate that produced gas compositional mapping is a powerful tool that complements comparatively sparse data from core or cuttings-based organic geochemistry and petrography methods, to provide an unparalleled level of detail of petroleum distribution at various scales. Coupling this compositional mapping with reservoir pressure data and published faults reveals a strong control of the structural framework on petroleum migration routes. The main targets of horizontal drilling in the Montney play are carrier beds that were charged by up-dip migrating petroleum and experienced further thermal maturation during the burial history. The relative contribution of different source rocks to this petroleum system remains speculative and further investigation is needed to solve this conundrum.

Geological parameters controlling the bedding-parallel vein distribution in Vaca Muerta Formation core data, Neuquén Basin, Argentina

Abstract: It is important to understand the occurrence of bedding-parallel veins in the Vaca Muerta Formation because this helps to predict their presence away from well controls so that they can ultimately be incorporated in reservoir simulators and hydraulic fracturing modelers. Given that their occurrence has a significant impact on the propagation of hydraulic fractures, their spatial distribution will help to select sweet spots for unconventional resource development. In this study, we try to identify the key parameters that control bedding-parallel veins. Therefore, detailed sedimentological core descriptions were performed on 10 different wells, including total organic carbon measurements at a spacing of 0.5 cm and several degrees of maturity ranging from 0.7% to 1.8% vitrinite reflectance. Through a comparison between bedding-parallel vein localization and sedimentological descriptions, we built a statistical method to identify key parameters controlling the localization of such veins within the Vaca Muerta Formation. We show that bedding-parallel veins are primarily located at facies boundaries (70%) rather than in homogeneous facies (30%). The major rheological discontinuities, such as ashbeds and calcitic concretion boundaries, as well as organic-rich facies have a significant impact on the localization of both bedding-parallel veins. The total organic carbon seems to influence the generation of bedding-parallel veins by locating these fractures in organic-rich areas with more than 2 wt. % in total organic carbon. We also found a correlation between the degree of maturity of the source rock within a same sequence stratigraphy and the (1) number of bedding-parallel veins and (2) thickness of the bedding-parallel vein, suggesting a strong link between the generation of hydrocarbons during the burial of the rock with the generation and distribution of bedding-parallel veins.

Multiple thrust detachments and their implications for hydrocarbon accumulation in the northeastern Sichuan Basin, southwestern China

Abstract: The northeastern Sichuan Basin thrust belt located in southwestern China, is a large-scale intracontinental thrust system with multiple detachments represented by a series of subparallel chevron anticlines. We conduct a comprehensive study of the geometry and kinematics of the thrust belt and its implications for the petroleum system based on seismic-reflection profile interpretation, field investigation, analysis of wells, and geochronology. Two major detachments occur within the allochthonous succession: the (1) gypsum-bearing lower to middle Cambrian Longwangmiao and Gaotai Formations and (2) Lower Triassic Jialingjiang Formation. The dark gray shales in the lower Silurian Longmaxi Formation are a favorable source rock that may also act as a third detachment in this study area. The stratigraphic succession is divided by three detachments into three structural intervals: (1) lower Cambrian–Silurian structural interval, (2) middle Silurian–Triassic structural interval, and (3) upper Triassic–Jurassic structural interval. The lower structural interval may be a good candidate for hydrocarbon exploration because of the occurrence of high-quality source rock and its reservoir-trapping evolutionary history.

Pore structure evolution characteristics of continental shale in China as indicated from thermal simulation experiments

Abstract: Organic matter (OM) pores in shale can provide abundant storage space for gas. However, there are different types of OM with different compositions and structures in continental shale, and their pore structure evolution lacks direct observations. In this study, anhydrous thermal simulation experiments in an open system were conducted on a continental Jurassic Ziliujing Formation shale sample with a low initial thermal maturity, taken from an outcrop in the northeastern Sichuan Basin. Changes in the pore structure of a specific OM at different thermal maturities were captured by field emission–scanning electron microscopy (FE-SEM). These FE-SEM images processed by image processing software were combined with N2 adsorption and high-pressure mercury intrusion porosimetry data to help clarify the pore structure evolution characteristics. Our results show that OM developed in Ziliujing Formation shale can be divided into four types based on their morphological characteristics. The pore structure evolution process is closely related to the processes of petroleum generation, migration, and thermal cracking. More specifically, the filling of pores by generated oil at lower temperature caused a decrease of the macropore volume in the shale sample and these filled macropores were released at higher temperature by thermal cracking of oil. In addition, there were no OM pores larger than 10 nm created during thermal simulation experiments, which indicates that the development of such sized OM pores is largely dependent on the original composition and structure of the parent OM.

Meter-scale lithofacies cycle and controls on variations in oil saturation, Wolfcamp A, Delaware and Midland Basins

Abstract: Typical meter-scale lithofacies cycles from the Wolfcamp A in the Delaware and Midland Basins comprise basal carbonate facies overlain by calcareous or siliceous mudrocks. Siliceous mudstones are the most organic-rich facies with high total organic carbon (TOC > 3 wt. %), whereas thin carbonate beds have the lowest organic matter (OM) content among the lithofacies present (TOC TOC, programmed pyrolysis analysis, and residual gas analysis from rock crushing. Oil saturation index (OSI) (the amount of free oil normalized by TOC; OSI = S1 × 100/TOC) is used as an indicator of oil enrichment or depletion in the reservoir, where S1 is volatile oil in programmed pyrolysis (temperature = 300°C). Both TOC-lean carbonate and TOC-rich mudstone lithofacies have high OSI in these meter-scale cycles (average OSI is 124.5 mg HC/g TOC for carbonate beds), indicating that migrated oil is present. Residual gas analyses show lower dryness values (C1/C1–5) and higher oil indicator values (100 × C4+5/C1–5) in TOC-lean carbonate beds compared to the TOC-rich mudstones, likely indicating a cumulative oil and gas charging effect through source rock maturation. Oil and gas generated at different stages of thermal maturation were partially expelled from OM-rich siliceous/calcareous mudstones into adjacent OM-lean carbonate beds. This study shows oil expulsion from source to adjacent carbonate beds is a key factor in variations of oil saturation in the Wolfcamp A.

Organic geochemistry and petrology of Devonian shale in eastern Ohio: Implications for petroleum systems assessment

Abstract: Recent production of light sweet oil has prompted reevaluation of Devonian petroleum systems in the central Appalachian Basin. Upper Devonian Ohio Shale (lower Huron Member) and Middle Devonian Marcellus Shale organic-rich source rocks from eastern Ohio and nearby areas were examined using organic petrography and geochemical analysis of solvent extracts to test ideas related to organic matter sources, oil–source rock correlation, thermal maturity, and distances of petroleummigration. The data from these analyses indicate organic matter in the Ohio and Marcellus Shales primarily was derived from marine algae and its degradation products, including bacterial biomass. Absence of odd-over-even n-alkane distributions (n-C13 to n-C21 range) in gas chromatograms and low gammacerane index values in Devonian source rocks are similar to those of Devonian-reservoired oils in eastern Ohio, suggesting an oil–source rock correlation. Lower Paleozoic oils from eastern Ohio, in contrast, are characterized by the presence of odd-over-even n-alkane distributions (n-C13 to n-C21 range) and higher gammacerane values, which discriminate them from Devonian shale-derived oils. Thermal maturity estimates from equilibrium(?) biomarker isomerization ratios suggest that some of the Devonian source rock samples are at middle to peak oil window conditions (i.e., approximate vitrinite reflectance values of 0.8%–0.9%). This observation requires local to short-distance (<50 mi) lateral migration for emplacement of Devonian-sourced oils into Devonian reservoirs of eastern Ohio and may impact exploration and assessment of petroleum resources in the Upper Devonian Berea Sandstone. AUTHORS Paul C. Hackley ~ US Geological Survey (USGS), Reston, Virginia; phackley@ usgs.gov Paul C. Hackley is a research geologist at USGS in Reston, Virginia, where he oversees the Organic Petrology Laboratory. He holds degrees from Shippensburg University (B.A.), George Washington University (M.Sc.), and George Mason University (Ph.D.). His primary research interests are in organic petrology and its application to fossil fuel assessment. Robert T. Ryder ~ Retired, USGS, Reston, Virginia; roberttredryder@gmail.com Robert T. Ryder is a retired research geologist with the USGS (Denver, Reston). He retired in 2011 after 38 years. Previously, he worked for Shell Oil Company. Ryder holds degrees from Michigan State University (B.S.) and Pennsylvania State University (Ph.D.). He has studied the geologic framework and petroleum systems of many United States (Rocky Mountains, Appalachian) and Chinese basins.

Origin and charging histories of diagenetic traps in the Junggar Basin

Abstract: Oil and gas accumulations in the sandy conglomerate diagenetic traps that developed in the fan delta of the Triassic Baikouquan Formation of the Mahu sag, Junggar Basin, differ from stratigraphic accumulations controlled by sedimentary facies. This study uses conventional gas chromatography–mass spectrometry measurements, mineralogical and petrological data, fluid inclusion analyses, and geophysical inversion to confirm the trap type and accumulation processes. The results indicate that accumulations in the sandy conglomerate formed in distributary channels of the fan-delta front, with the boundary controlled by reservoir quality. In turn, reservoir quality was controlled by differential diagenesis caused by detrital-feldspar content, paleotemperature, and formation fluids, suggesting that the trap is a diagenetic trap. The diagenetic trap formed from secondary pores developed in the fan-delta front facies with seals forming through a combination of altered sandy beds and mudstone. The critical physical property of the reservoir, based on the ratio of its average capillary radius to the ratio of its seal, is a crucial parameter for describing diagenetic trap boundaries. Here, it effectively distinguishes between reservoirs at different burial depths. A good correlation exists between the formation of the diagenetic traps and hydrocarbon filling. Three hydrocarbon charging and two accumulation stages are identified. The diagenetic traps primarily formed in the Jurassic, and the last charging stage of highly mature oil charge occurred in the Early Cretaceous. Few studies have investigated the conglomerate diagenetic trap studied herein, so this study should improve the understanding of oil and gas traps.

Multiphase activation of the boundary fault system of the eastern Dampier subbasin, Northwest Shelf of Australia

Abstract: Investigating the timing, structural style, and development of multiphase extensional fault systems is essential for understanding rift basin evolution and for assessment of structural trap integrity. Borehole-controlled interpretation and analysis of two-dimensional and three-dimensional seismic data sets from the eastern Dampier subbasin indicate that a northeast-trending basement weakness zone was subjected to west-northwest–east-southeast oblique extension in the latest Triassic–late Middle Jurassic, resulting in systematic segmentation of the Rosemary fault system (RFS). Temporal stress change during Cretaceous north-south extension produced complex fault systems along the RFS, including (1) east-west–trending isolated faults with maximum displacement close to their center; (2) east-west–trending abutting faults, which initially nucleated as isolated faults, later abutted against the main structure, showing large displacement accruement on the composite fault; and (3) northeast-southwest–trending splay faults characterized by systematic left-stepping segmentation, with maximum displacement occurring at the point where the splay faults deviate from the main structure. In the Miocene, the RFS was locally reactivated by northwest-southeast compression in the northeastern part of the fault system, developing a compressive fault-propagation fold at the upper tip of the inverted extensional fault. This study suggests that the style of basin boundary fault reactivation depends largely on preexisting structures and temporal stress changes. The fault reactivation style is also a significant factor in influencing basin architecture, sediment distribution, fault linkage processes, and petroleum basin prospectivity.

West Texas (Permian) Super Basin, United States: Tectonics, structural development, sedimentation, petroleum systems, and hydrocarbon reserves

Abstract: The West Texas (Permian) Super Basin is the prototype super basin. The basin has produced 28.9 billion bbl of oil and 203 TCF of gas (63 billion BOE, 1920–2019). The US Geological Survey and Bureau of Economic Geology estimate this super basin has remaining reserves of 120–137 billion BOE, twice the volume produced during the first 100 yr of hydrocarbon production. During the past decade, the West Texas Super Basin has been the driver of production growth in the United States and has decades of remaining economic production and reserve growth. The West Texas Super Basin is a complex Paleozoic basin built on a varied Proterozoic crust. After Cambrian rifting, regional subsidence began in the Middle Ordovician and continued into the Devonian, forming the Tobosa Basin. The early Paleozoic Tobosa Basin subsidence terminated during Mississippian epeirogenic uplift. A later stage of subsidence began in the Late Mississippian accompanied by large-scale faulting and moderate folding. This tectonic and structural development was controlled by basement terrains, earlier tectonic, and structure reactivated by compression of the Ancestral Rocky Mountains and Marathon-Ouachita orogenic events. These formed the Permian Basin. The Marathon-Ouachita tectonic event ended in the Wolfcampian (early Permian). Subsidence continued to the end of the Permian (Ochoan). Periodic subsidence during the Mesozoic was likely caused by Rocky Mountain (Laramide) deformation. Cenozoic (late Paleogene–Neogene) western uplift tilted the basin to the east. Each of these events has a significant influence on the basin petroleum systems. The basin has multiple source rocks and petroleum systems formed during various stages of basin development. During the formation of the early Paleozoic Tobosa Basin, Simpson Group and Woodford Shale source rocks were deposited. During the transitional basin development phase, the Barnett Shale source rocks were deposited, and during Permian Basin subsidence, the Wolfcamp and middle Permian (Leonardian and Guadalupian) source rocks were deposited. Continued subsidence into the Mesozoic resulted in the deposition of additional strata. These Mesozoic intervals are now mostly eroded but provided sufficient burial depths for thermal development and increased the extent of thermal effect for maturation and migration of hydrocarbons within these Paleozoic petroleum systems. Leonardian and Guadalupian conventional reservoirs have produced 71% of the resources from all conventional West Texas Super Basin reservoirs. These reservoirs are typically most abundant on the shelf crest (shelf to edge), where reservoir development is maximized and becomes a focus of hydrocarbon migration from the deeper Delaware and Midland Basins source rocks and shallower, more-proximal shelf and platform source rock systems. Unconventional resource reservoir oil production in the West Texas Super Basin accounted for just under 90% of total basin daily production at the close of the last decade (2010–2019). Total West Texas Super Basin production peaked in March 2020 at 4.7 million BOPD. Since that time, production has declined because of lower rates of investment driven by lower product prices. The West Texas Super Basin economic oil and gas production has benefited from an extensive infrastructure, a large geologic and engineering community, regulatory and public support, open access, sufficient capital availability, and a scalable service industry. The paradigm toward new drilling, completion, and production technology has been driven by unconventional resource reservoir development in the basin. These West Texas Super Basin technological developments have lead industry technology for unconventional resource development worldwide. Maintaining talented human resources and capital are challenges that time will tell if individual firms and the industry will meet to develop the hydrocarbon resources within the basin.

A review of the Bakken petroleum systems in the United States and Canada: Recognizing the importance of the Middle Member play

Abstract: The Williston Basin has proven to be a global super basin. Initially, development across this basin was dominated by conventional production from the Madison Group and Ordovician oil systems; however, with the development of unconventional play opportunities, the biggest resource in the Williston Basin is now the Middle Member of the Bakken Formation. The Middle Member was not pursued as a reservoir because of its low porosity and permeability, the low thermal maturity of the juxtaposed Bakken shales, low resistivity, and perceived lack of oil saturation. This paper will review how geochemical data were used to challenge and explain those initial assumptions with particular focus on the discovery and development of the Parshall field. Unconventional and hybrid plays are complex systems, and although much of the geochemical focus details organofacies or maturity concerns, numerous other processes including sorption, alteration, mixing, and evaporative fractionation can and commonly will influence the interpretation of the results and therefore must be considered. The geochemical techniques discussed in this paper are used to calculate oil saturation and more appropriately, mobile oil saturation, from core data requiring accounting for oil evaporative losses to fully define the workings of the Bakken petroleum system and the Middle Member as the key reservoir.

Ultimate expellable potentials of source rocks from selected super basins: What does “world class” look like?

Abstract: An important step in the evaluation of a play or prospect is to consider the potential supply of petroleum charge, which is ultimately constrained by masses and volumes supplied by the source bed. The two factors limiting the mass of petroleum expelled from the organic matter in the source bed are (1) its initial expulsion potential and (2) the cumulative fraction of potential that has been expelled up to its maximum state of maturation. To evaluate the initial expulsion potential, we introduce a workflow to estimate the ultimate expellable potential (UEP), divided into an oil potential (UEO) and a gas potential (UEG), which represent the cumulative masses of oil and gas that can be expelled upon complete maturation of the source rock. For use in resource estimation, these masses can be converted to surface volumes of oil and gas per unit area (million stock tank barrels per square kilometer and billion standard cubic feet per square kilometer or million barrels of oil equivalent per square kilometer, respectively). The UEP (UEO, UEG) can be mapped across the depositional extent of the source bed, just as a reservoir depositional system is mapped. These potentials per unit area constitute the first level of quantitative resource estimation in the evaluation of a play or prospect. We show examples of UEP (UEO, UEG) mapping based on available public data. Three of the example source rocks are aquatic organofacies that have charged major conventional petroleum systems: the Callovian to Oxfordian marine organofacies of the Arabian Basin, Saudi Arabia; the Volgian marine organofacies Bazhenov Formation of the West Siberian Basin, Russia; and the Eocene–Oligocene lacustrine freshwater organofacies Shahejie Formation of the Bohai Basin, China. We also include an unconventional system: the uppermost Devonian–lowermost Mississippian marine organofacies Bakken Formation of North Dakota, United States. The UEPs of the studied source rocks in the Arabian Basin and West Siberian Basin, with tens of millions of barrels of oil equivalent per kilometer over large areas, define world class in marine source rocks since these basins are ranked number one and number two in the world by oil endowment. Until more data are available on other lacustrine basins, we offer the UEP of the studied Bohai Basin source rock as an example. In contrast, the UEP of the Bakken Formation source rocks (combined Upper and Lower Members) is relatively modest despite its world class unconventional oil endowment. The Bakken's effectiveness, despite its relatively low UEP, reflects the negligible migration saturation losses involved in charging the Middle reservoir Member. This illustrates that the commonly touted term world class can be rather meaningless. It needs to be considered in context given the task in hand: the greater the (vertical) migration losses incurred in charging reservoirs, the higher the UEP needed to create the charge needed to overcome them.

Thermal history reconstruction from apatite fission-track analysis and vitrinite reflectance data of the Bongor Basin, the Republic of Chad

Abstract: The Bongor Basin in southern Chad is one of the Cretaceous–Paleogene rift basins developed on the Precambrian crystalline basement and has been confirmed as a petroliferous basin in the last decade. Less than 400 m of Cenozoic unconsolidated sediments are separated by an unconformity from an underlying section of Lower Cretaceous units, in turn separated by another unconformity from underlying Precambrian basement. In addition, there is a locally low-angle unconformity within the Cenozoic section. A synthesis of apatite fission-track analysis data in four wells from the basin reveals two cooling episodes from Late Cretaceous to early Paleocene (beginning between 75 and 60 Ma) and mid-Miocene, respectively. The results suggest that regionally synchronous cooling is a likely scenario. The first exhumation between 75 and 60 Ma affected the whole basin, and the magnitude of uplift and erosion was approximately 1100–1250 m across the whole basin. In contrast, the second exhumation during the Miocene affected mainly the northern part of the basin while the magnitude was weak and could not be detected in the southeast of the basin. Potential trapping structures, for example, fault blocks and synsedimentary anticlines, formed prior to and inverted anticlines as a result of the first cooling phase of exhumation (strong compressional inversion) and were available for hydrocarbon migration and accumulation during the main phase of hydrocarbon generation. The Miocene exhumation was less pronounced and had weak or no impact on the hydrocarbon generation and accumulation.

Origins of overpressure in the central Xihu depression of the East China Sea shelf basin

Abstract: The origins of overpressure in the central Xihu depression have been accepted to result from disequilibrium compaction and hydrocarbon generation. This study uses organic matter correction of the log data in source rocks and five empirical methods (the multilogging combination method, Bowers’ method, the sonic velocity–density cross-plot method, the porosity method, and the pressure inversion method) to understand the origins of overpressure in the central Xihu depression. Overpressure strata are mainly distributed in the following two areas: 1) the Pinghu Formation on the western slope of the central Xihu depression; 2) the Pinghu Formation and lower part of the Huagang Formation in the western sag and the central Inversion anticline belt. The areas contain two types of pressure profiles: normal pressure–overpressure and normal pressure–overpressure–normal pressure. At the western slope and the western sag, overpressure in source rock and nonsource rock was caused by hydrocarbon generation and pressure transfer, respectively. At the central inversion anticline belt, however, overpressure was caused by hydrocarbon generation and tectonic compression in source rock and by pressure transfer and tectonic compression in nonsource rock. We also propose criteria for confirming the combination of tectonic compression and hydrocarbon generation as the origin of overpressure, where the porosity distribution in the overpressured mudstone is consistent with the normal compaction trend or conforms to a higher level of normal compaction as the depth increases. In the sonic velocity–effective stress diagram, sonic velocity increases with decreasing effective stress, whereas density and sonic velocity both increase with increasing normal compaction in the density–sonic velocity diagram.

Variations in vertical stress in the Permian Basin region

Abstract: Constraining the magnitude of vertical stress (Sv), or overburden pressure, is key in determining a region’s stress state and has implications for reservoir geomechanics and the potential for induced seismicity. Of the principal stress orientations (Sv, minimum horizontal stress [Shmin], and maximum horizontal stress [SHmax]), Sv is the most straightforward to constrain using wire-line log data. The magnitude of Sv varies because of lithology and burial history, potentially causing local perturbations in the in situ stress field. Previous studies on the state of stress in the Permian Basin use a constant Sv, relying on determination of SHmax and Shmin, and yield an interpretation that the faulting regime transitions from normal faulting in the west to normal to strike-slip faulting in the east. Here, we present an interpretation of the spatial and depth variability in Sv trends in the Permian Basin based on density log integration. Where density measurements are absent, values are calculated from compressional velocity logs using a transform that is fit to local data. Notable variations include higher Sv gradient on carbonate platforms and shelves, where high-density carbonates are thicker and are found at shallower depths than in the basins. Within the basins, the magnitude of Sv gradient is as low as 1.06 psi/ft at depth. This work shows the potential for regional interpretations of Sv to gain insight into the effect of variations in Sv on state of stress.

Structural geometry and evolution of the Carter-Knox structure, Anadarko Basin, Oklahoma

Abstract: The Carter-Knox field is located on a northwest-southeast–trending faulted anticline in the southeastern part of the Anadarko Basin. Three-dimensional seismic and well data were used to develop a model for the geometry and evolution of the structure. The Carter-Knox structure formed during contractional deformation associated with the Wichita basement uplift in the Pennsylvanian. It is characterized by different structural styles in two main structural units. The lower unit, which includes the Cambrian Arbuckle Group to Mississippian Sycamore Limestone, is folded into a broad anticline associated with one or more frontal faults and back thrusts, with a change in vergence along trend. The upper unit, which includes the Upper Mississippian Springer shale to the Morrowan Primrose and the overlying Pennsylvanian growth units, is marked by a tight faulted detachment fold with a steep front limb, associated with multiple thrust faults that detach within the Springer shale. Kinematic reconstruction shows differential shortening between the two main structural packages. The evolution of the structure was episodic, resulting in two major angular unconformities within the Pennsylvanian. A major Permian unconformity truncates the structure. The southwestern flank of the structure was rotated along an active flexural hinge in the basement because of sedimentary loading, resulting in thickening of growth units on this flank. The Carter-Knox structure is an analogue for other thin-skinned structures in the Anadarko Basin and illustrates the impact of the thick-skinned Wichita uplift on the thin-skinned fold-thrust structures in the basin.

Timing and origin of multiple petroleum charges in the Solveig oil field, Norwegian North Sea: A rhenium-osmium isotopic study

Abstract: The Re-Os geochronometer constrains the timing of petroleum formation and provides an oil-source isotopic correlation tool for improved geologic knowledge and exploration success. However, the effects of secondary processes that may sometimes complicate interpretations are not well understood. This paper discusses Re-Os systematics in a petroleum system that experienced extensive asphaltene precipitation upon mixing of different oil phases. The Solveig oil field (formerly Luno II), Utsira high, Norwegian North Sea, comprises three structural compartments that capture different stages of the mixing process. In the central compartment, an Re-Os age of circa 40 Ma for whole-rock extracts sampling the residual (asphaltene-rich and biodegraded) oil below the oil–water contact is consistent with burial models for Paleocene–Miocene generation. A 10-m-thick, asphaltene-rich (65 wt. %) tar mat zone precipitated upon mixing of at least two components does not yield meaningful ages. The Re-Os isochrons for the free-flowing crude oil and whole-rock extracts from the oil leg above the tar mat zone indicate circa 10 to 0 Ma ages for the younger oil phase, supporting independent estimates for recent oil influx. Decreasing 187Os/188Os from maltenes to asphaltenes in oil from the southeastern compartment are highly unusual and provide geochemical evidence for recent mixing, consistent with the strong asphaltene-in-oil gradient. Very low and remarkably uniform Re/Os ratios for all petroleum phases, combined with relatively low and uniform 187Os/188Os ratios, strongly support isotopic overprint of the Re-Os system, likely during water–oil interaction. Despite this overprint, Re-Os ages retain information on primary events, whereas initial 187Os/188Os ratios are strongly affected.

Depositional environment and source rock quality of the Woodbine and Eagle Ford Groups, southern East Texas (Brazos) Basin: An integrated geochemical, sequence stratigraphic, and petrographic approach

Abstract: X-ray fluorescence chemostratigraphy of the Cenomanian–Turonian Woodbine and Eagle Ford Groups in the southern parts of the East Texas Basin highlights significant mudstone chemical heterogeneities that commonly are difficult to observe or quantify at the macroscale. Several key elements, namely, Ca, Si, Mo, Mn, and Ni, were correlated to depositional conditions and used in a hierarchical cluster analysis to characterize five chemical facies (i.e., “chemofacies”) across 10 cored intervals of the Woodbine and Eagle Ford Groups: (1) argillaceous, organic-matter poor; (2) transitional, organic-matter poor; (3) transitional, organic-matter moderate; (4) calcareous, organic-matter rich; and (5) calcareous, organic-matter moderate. Characterizations of organic matter richness, mineralogy, and environmental conditions of deposition were established by correlating between key element abundances, total organic carbon measurements, x-ray diffraction measurements, and petrographic observations of lithologic composition, bioturbation, and sedimentary textures. Combined analysis of elemental geochemistry, stratigraphy, and petrographically observed sedimentary textures indicates that all chemofacies were deposited in an intrashelf basin above storm wave base. The most organic-rich chemofacies was deposited on a dominantly dysoxic distal shelf. Mudstone organic matter enrichment is driven dominantly by the minimization of siliciclastic dilution and secondarily enhanced by oxygen restriction. Regional correlations of chemofacies within a sequence stratigraphic framework developed from previous outcrop and subsurface work indicate a clear relationship between interpreted stratigraphy and chemofacies deposition. Generally, the highstand sequence sets of the Woodbine Group and upper Eagle Ford formation are dominated by mineralogically clay-rich, organic matter–lean, siliciclastic sedimentation and contain poor-quality source rock. Conversely, the transgressive sequence set of the lower Eagle Ford formation is dominated by organic matter–rich pelagic carbonate accumulation and contains excellent-quality source rock.

Carrier-bed plays in the Denver and Powder River Basins

Abstract: Carrier-bed plays are a new type of unconventional oil play that are currently being developed in North America. The reservoirs are generally low quality because of any of the following: thin beds (heterolithic strata), diagenesis, or burrowing (heterogeneous, mixing of sandstones or carbonates and mudstones). The carrier beds are pervasively hydrocarbon saturated and can occur over an areally extensive (greater than than 50 square miles, greater than 129 square kilometers) area. These low-quality reservoirs generally do not meet traditional petrophysical cutoffs and because of the clay content can create low resistivity, low contrast pays. The reservoirs may be composed of clastics or carbonates or a mixture of both. A sub-category of a carrier-bed play is a halo play. Halo plays are the low permeability flanking edges of a conventional oil accumulation (i.e., waste zone or the fringe). The low reservoir quality is generally stratigraphic in origin (facies change from high quality to low quality reservoirs). Carrier-bed and halo plays are being developed with horizontal drilling and multistage hydraulic fracturing. Traditional vertical drilling yields marginal to uneconomic wells but are a clue to the existence of a carrier-bed play. This paper reviews Upper Cretaceous carrier bed plays in the Denver (Codell SandstoneMember of the Carlile Shale) and Powder River (Turner Sandy Member of the Carlile Shale) basins.

Applying deep learning for identifying bioturbation from core photographs

Abstract: Advances and availability of deep learning (DL) software have recently allowed the development, testing, and deployment of automated image classification schemes for sedimentary features from core images. The development of these methods is especially relevant for extracting useful geological features from otherwise unused core photographs. This paper demonstrates and tests the use of a DL workflow for the automated extraction of bioturbation data from a core photograph data set. The proposed workflow includes extracting image tiles from core photographs along a grid and referencing each tile with collected sedimentary data. Each labeled image tile is then used as a training and testing input for a machine learning algorithm. This method allows users to quickly generate thousands of labeled training images. To demonstrate and test this workflow, a data set was collected using PyCHNO™, an open-source software specifically designed to collect sedimentary data from core photographs. The resulting data set comprising 13,545 tiles of 128 × 128 pixel resolution is used to train a DL algorithm to automatically predict if a core photograph contains evidence of bioturbation. The trained model was able to predict whether or not an image demonstrated evidence of bioturbation with up to 88% accuracy. The workflow demonstrates one of many possible applications for automatically extracting biogenic or physical sedimentary structure data from core photographs. Models built using this approach can be used to “seed” wells from a given area or interval, which can therefore significantly increase the value of core photograph data sets with relative ease.

Paleozoic sequence stratigraphy, depositional systems, and hydrocarbon habitats across the Arabian plate

Abstract: The Paleozoic sedimentary section of the Arabian plate recorded the effects of numerous fluctuations in sea level and gentle epeirogenic movements. Eustatic changes in sea level over the Arabian plate resulted in transgressions and regressions and created many local and regional unconformity surfaces, identified by missing section and nondeposition. The distant deformation of the Caledonian tectonic orogeny and mountain building of the North Atlantic region, and the later Hercynian tectonic event, are partially responsible for eustatic sea-level changes. Additionally, detailed evidence of Paleozoic glacial erosion and glacial eustasy in the regressive sedimentary section over uplifted paleohighs comes from deep wells penetrating local exotic tectonic blocks. The resulting surfaces mark the sea-level falls associated with the glacial events in the Ordovician, Late Devonian, and Carboniferous–early Permian sediments. The depositional settings of the Cambrian–upper Permian rocks include deltaic and glacial settings and are expressed as alluvial–fluvial fans that grade into braided plains and shallow-marine carbonates flanked by distal shales. Late Permian sediment fill accompanied the development of widespread accommodation, resulting from a major sea-level rise, coinciding with a major period of carbonate–evaporite deposition, in which clastic sediments were only a minor factor. The regional sedimentary facies have good reservoir quality and are juxtaposed to regional source rocks and seals associated with both structural and minor stratigraphic traps. Production occurs in Precambrian through Permian strata in which mature clastic and shallow-water carbonate reservoirs occur, commonly sealed by shales, and sourced by Silurian hot shales or older source rocks in the section.