ALBERT

Description: 〈span〉〈div〉ABSTRACT〈/div〉Late Cretaceous–to–present-day mixed carbonate–clastic deposition along the Nicaraguan platform, western Caribbean Sea, has evolved from a tectonically controlled, rifted upper Eocene shallow–to–deep-marine carbonate–siliciclastic shelf to an upper Miocene–to–present-day tectonically stable shallow-marine carbonate platform and passive margin. By integrating subsurface data of 287 two-dimensional seismic lines and 27 wells, we interpret the Cenozoic stratigraphic sequence as 3 cycles of transgression and regression beginning with an upper Eocene rhodolitic–algal carbonate shelf that interfingered with marginal siliciclastic sediments derived from exposed areas of Central America bordering the margin to the west. During the middle Eocene, a carbonate platform was established with both rimmed reefs and isolated patch reefs. A late Eocene forced regression produced widespread erosion and subaerial exposure across much of the platform and was recorded by a regional unconformity. The Oligocene–upper Miocene sedimentary record includes a southeastward prograding delta of the proto-Coco river, which drained the emergent area of what is now northern Nicaragua. The late Miocene–to–present-day period marks a period of strong subsidence with the development of small pinnacle reefs. We describe favorable petroleum system elements of the Nicaraguan platform that include (1) Eocene fossiliferous limestone source rocks documented as thermally mature in vintage exploration wells and seen as active gas chimneys emanating from inferred carbonate reservoirs; (2) upper–to–middle Eocene reservoirs in patch and pinnacle reefs, middle Eocene calcareous slumps, and Oligocene fluvial-deltaic facies documented in wells; and (3) regional seal intervals that consist of both regional unconformities and Eocene–Oligocene intraformational shale.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Fault damage zones may significantly affect subsurface fluid migration and the development of unconventional resources. Most analyses of fault damage zones are based on direct field observations, and we expand these analyses to the subsurface by investigating the damage zone structure of an approximately 32-km (∼10〈sup〉5〈/sup〉-ft)-long right-lateral strike-slip fault in Oklahoma. We used the three-dimensional (3-D) seismic attribute of coherence to first define its regional and background levels, and then we evaluated the damage zone dimensions at multiple sites. We found damage zone thickness of approximately 1600 m (∼5300 ft) at a segment that is dominated by subsidiary faults, and it is slightly thicker at a segment with a pull-apart basin. The damage zone intensity decays exponentially with distance from the fault core, in agreement with field observations and distribution of seismic events. The coherence map displays a strong asymmetry of the damage zone between the two sides of the 3-D fault, which is related to the subsidiary structures of the fault zone. We discuss the effects of heterogeneous stress field on damage zone evolution through the detected subsidiary structures. It appears that seismic coherence is an effective tool for subsurface characterization of fault damage zones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Some fault zones leak vertically to the ground surface or seafloor, whereas most others remain naturally sealed. Understanding the factors that cause this leakage is essential for predicting and preventing such leakage for both conventional reservoir development and subsurface CO〈sub〉2〈/sub〉 storage. This study, a comparison of leaking and nonleaking natural CO〈sub〉2〈/sub〉 gas accumulations, provides such constraints. We compare and contrast trap configurations, fluid pressures, and stress states for several natural CO〈sub〉2〈/sub〉 accumulations from the Colorado Plateau. Extensive surface geologic data are integrated with subsurface data from a large suite of groundwater and hydrocarbon wells. Leakage of CO〈sub〉2〈/sub〉 is documented by geochemical surveys and the occurrence of extensive travertine deposits. The leakage occurs exclusively in fault fracture damage zones where the total fluid pressure reduces the minimum horizontal effective stress to approximately zero. These results are consistent with natural and accidentally induced fault seeps from some deep-water hydrocarbon reservoirs. These criteria can be used to evaluate the potential for fault zones to provide vertical leakage pathways and loss of fluid containment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The three-dimensionally complex, highly progradational mixed siliciclastic–carbonate strata of the San Andres and Grayburg Formations have long been the backbone of conventional hydrocarbon reservoir production from the Permian Basin, and significant recovery continues via waterflooding and CO〈sub〉2〈/sub〉 injection. Besides, nonreservoir equivalents of these formations have recently taken increasing significance as produced water disposal targets. However, seismic-stratigraphic interpretations are challenged by complex internal shelfal-stratal geometries and numerous laterally continuous but vertically thin fluid barriers in overlying platforms. We built a three-dimensional (3-D) geocellular model of Guadalupian 8–13 high-frequency sequences (G8–G13 HFSs) and then conducted forward seismic modeling (35-Hz 0° phase). This allows investigations on the validity of applying conventional reflection-geometry–based interpretation to delineate the G9 HFS top and base, which can potentially serve as bounding/constraining surfaces for upper San Andres shelf–Grayburg platform reservoirs. This study contributes to 3-D modeling methodologies by introducing a query tree to select geostatistical methods for modeling dual-scale heterogeneities and by integrating data from diverse sources for seamless and realistic 3-D models. Our seismic-stratigraphic evaluation demonstrates that conventional reflection–geometry-based interpretation does not adequately resolve the G9 top and base; deviations from the geocellular model reach up to 80 m (260 ft) and are thus well beyond the maximum acceptable error limits of ±0.5 wavelength. We suggest improving conventional interpretations of the G9 base by selective interpolation or mixed-polarity event picking near the error-prone shelf margin and upper slope. Besides, instead of picking the highly discontinuous seismic peak as G9 top, bulk-shifting of a shallower trough horizon near actual G10 top should deliver a more accurate surface representing G9 top.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Paleogene shale of the Dongying depression, a continental basin in eastern China, is taken as the study subject to examine the microscopic features of lacustrine shale reservoirs in the oil window. This study shows that shale pores in this evolutionary stage are present at the micrometer to nanometer scale, but fractures commonly have extension distances at the millimeter scale. Pores and fractures can be divided into three types, namely, primary pores, secondary pores, and cracks. Primary pores commonly have good connectivity at shallow burial depth. With the increase of burial depth, primary porosity is reduced because of compaction and cementation. Secondary pores are important in shale, including dissolved pores inside grains and at grain edge, and dissolution pores inside the hybrid of organic matter (OM) and clay minerals, and evaporite minerals, including carbonates or sulfates. Types of cracks were observed: bedding fissures, dissolution fractures, and structural fractures. The development of bedding fissures is related to the deposition of shale laminae. The formation of dissolution fractures is related to acidic fluids, such as organic acids and hydrogen sulfide, whereas the formation of structural fractures is jointly controlled by fault development, fluid overpressure, and lithofacies. The pores and fractures in the oil window of lacustrine shale can store and channel oil and gas. The hybrid OM–clay–carbonate (sulfate) and the pores inside are important through the oil window. Moreover, the development of the pores depends not only on hydrocarbon generation but also on the interaction of hydrocarbons and organic acid dissolution. This finding has important significance in the accumulation of oil and gas in continental shales.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the past, determination of rock properties using image analysis relied upon petrographic transmitted-light images, but with limited success because of a lack of resolution and restricted computer processing power. A new technique that employs confocal laser scanning microscopy (CLSM) can be considered complementary to laboratory measurements and applicable to several samples, saving time and money and requiring only a limited amount of rock sample for analysis. We have studied several types of rocks with CLSM and fluorescent dye–impregnated thin sections. The two-dimensional scans of each thin section images is an area of 12 mm〈sup〉2〈/sup〉, with a pixel size of 0.198 µm and were used to simulate capillary pressure curves for pore bodies and pore throats. The CLSM technique also enables three-dimensional (3-D) visualization of the rock porosity. The studied rock samples were taken from diverse oil and gas field reservoirs: case A, a conventional sandstone (15.1% porosity, 29.8 md permeability); case B, a tight sandstone (3.7%, 0.02 md); case C, an oolitic carbonate (9.6%, 0.1 md); case D, a rhodolithic algal carbonate (19.8%, 43.7 md); case E, dolomitized carbonate (17%, 21.7 md); and case F, a naturally fractured carbonate (2.4%, 0.6 md). Our results confirm that the CLSM technique can be applied to rocks of contrasting porosity and permeability to obtain computed synthetic capillary pressure curves faster than with conventional measurement methods. The technique quantifies different pore-body and pore-throat sizes and distributions, with the added ability to visualize 3-D porosity and to extract from thin section analysis petrologic properties.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Oil API gravity predictions using published basin modeling source rock (SR) reaction kinetics have displayed poor matches between modeled output and field observations because these kinetic models do not predict increasing API gravities with increasing maturity. Ideally, an SR kinetic model should use at least two liquid components of different densities, which are generated and expelled from the SR such that the API gravities are a consequence of relative mixing. Very few available kinetic models predict APIs with reasonable trends, but those are either not adjustable to calibrate to field observations or do not consider sorption, which is a necessary process when evaluating unconventional resources. Five new kinetics data sets are presented in this paper, each representing a standard SR type, which provide geologically reasonable API gravity trends and ranges. Each kinetic model uses two liquid pseudocomponents and two vapor pseudocomponents. The relative ratios between the pseudocomponents at full kerogen transformation are average ratios available from public and proprietary kinetic data sets. The primary generation follows published activation energies, including minor shifts, which allow peak generation to occur at lower activation energies for the heavier liquid pseudocomponent and at higher energies for the lighter one. This systematic shift of activation energies thus results in a constant change in API gravity as primary generation progresses. Additional in-SR sorption and secondary cracking schemes support the primary generated API gravity trends. The default ranges of API gravity for the new five kinetic models represent observed averages but can be adjusted easily.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Shale gas in the Sichuan Basin and its periphery potentially plays an important role in the world shale gas industry. An understanding of remigration and leakage from continuous shale reservoirs is very important for shale gas exploration, especially in the Sichuan Basin and its periphery. The shale gas accumulation models that relate to remigration and leakage were developed within the Wufeng and Longmaxi black shales in the Jiaoshiba and the Youyang blocks. First, a tectono-sedimentary history of the Wufeng and Longmaxi black shales in the Sichuan Basin and its periphery was developed based on the published literature. The history exhibits a continuous distribution of high-quality Wufeng and Longmaxi black shale, which is the foundation of the shale gas formation. Second, the shale gas remigration–accumulation model in the anticlines was clarified by using data collected from the shale gas fields in Jiaoshiba block. The shale gas model for the Jiaoshiba block was developed on the basis of a continuous shale reservoir distribution, differentiated structural deformation, and a gas self-sealed system. Third, the shale gas fault failure leakage model in the fault blocks and the erosion model in the residual areas were revealed based on the shale reservoir and shale gas content heterogeneity in the Youyang block. These two models were validated by available data including 13 two-dimensional seismic lines and 2 shale gas exploration vertical wells in the Youyang block. Shale gas areas with high gas resource and gas production rates in the anticlines were defined by the remigration–accumulation model. The fault failure leakage model was used to find shale gas with limited commercial potential, whereas commercial shale gas was largely lacking according to the erosion residual model. The study on remigration and leakage from continuous shale reservoirs in the Sichuan Basin and its periphery can be used to better understand and improve the exploration efforts based on resource preservation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉For both modeling and management of a reservoir, pathways to and through the seal into the overburden are of vital importance. Therefore, we suggest applying the presented structural modeling workflow that analyzes internal strain, elongation, and paleogeomorphology of the given volume. It is assumed that the magnitude of strain is a proxy for the intensity of subseismic scale fracturing. Zones of high strain may correlate with potential migration pathways. Because of the enhanced need for securing near-surface layer integrity when CO〈sub〉2〈/sub〉 storage is needed, an interpretation of three-dimensional (3-D) seismic data from the Cooperative Research Centre for Greenhouse Gas Technologies Otway site, Australia, was undertaken. The complete 3-D model was retrodeformed. Compaction- plus deformation-related strain was calculated for the whole volume. The strain distribution after 3-D restoration showed a tripartition of the study area, with the most deformation (30%–50%) in the southwest. Of 24 faults, 4 compartmentalize different zones of deformation. The paleomorphology of the seal formation is determined to tilt northward, presumably because of a much larger normal fault to the north. From horizontal extension analysis, it is evident that most deformation occurred before 66 Ma and stopped abruptly because of the production of oceanic crust in the Southern Ocean. Within the seal horizon, various high-strain zones and therefore subseismic pathways were determined. These zones range in width from 50 m (164 ft) up to 400 m (1312 ft) wide and do not simply follow fault traces, and—most importantly—none of them continue into the overburden. Such information is relevant for reservoir management and public communication and to safeguard near-surface ecologic assets.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the last 30 yr, basin and petroleum system modeling (BPSM) has evolved into a large and diverse field encompassing a broad range of scientific disciplines. As BPSM is applied to an increasingly wide range of problems, what are, or should be, the future directions in the evolution of BPSM comes into question.To address this question, a survey was conducted at the AAPG Hedberg Research Conference on “The Future of Basin and Petroleum Systems Modeling,” held in Santa Barbara, California, April 3–8, 2016. To capture the full range of thoughts, participants were asked to list in priority order what they think are the three most important future directions in BPSM. The responses were collated into six general categories for analysis. The categorization process involved some qualitative judgements because some areas spanned several of the general areas.The results show that the most frequently cited directions are related to BPSM workflows, organizations, and processes. This category includes how modelers are used in an organization, how projects are executed, and how the results are interpreted and integrated.Migration modeling (primary and secondary) is the most frequently cited technical need. The results indicate that migration processes are not well understood and there are still substantial differences of thought about the processes involved and the best ways to model them.Some subjects, such as uncertainty and unconventionals, were mentioned in several of the general categories, whereas other subjects, such as increased functionality in the models, were only seldom mentioned.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Using recently acquired three-dimensional seismic data, we summarize typical patterns for seismic-based identification and stage analysis of sedimentary units in the Eocene succession of the southern slope-break belts of the Bozhong sag, Bohai Bay Basin, China. The sedimentary units in the study area are characterized by progradational reflectors and mound-shaped, bidirectional downlapping reflectors in dip and strike directions, respectively. Differential characteristics of a distinct sedimentary unit within one lobe are documented. The major provenance direction is defined and characterized by the largest dip angles of reflectors, the longest transport distance of sediments, and the thickest deposits in comparison to other dip directions—all recognized in this study and serving as typical characteristics for sedimentary unit identification and separation from the overlapped sedimentary complex. This study also summarizes diverse patterns—including collateral and prograding types—of sedimentary unit contact relationships and stage analysis along dip and strike directions. Collateral patterns are composed of three subtypes: superimposed, antithetic, and isolated. Three sedimentary units—S1, S2, and S3—are recognized in the study area. Summarized patterns of sedimentary unit contact relationships indicate that S1 was deposited earliest and S3 latest. The proposed patterns supplement seismic-based sedimentologic studies. This work may serve as a useful reference for sand-body characterization and stage analysis in other basins and similar areas.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Instead of using discrete values for properties that influence the volumetric calculation for recoverable reserves from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in the Williston Basin in North Dakota, an uncertainty-based assessment method was used. Various estimates have been published in the past that attempt to quantify recoverable reserves from the Bakken petroleum system. The Bakken–Three Forks trend is regarded as an unconventional tight oil play typical of a continuous-type basin-centered accumulation. However, production data reveal that areas are unequal and that certain regions stand out as sweet spots whereas others exhibit fairly high water cuts. This paper is based on 28 well models, which have been porosity-calibrated and adjusted for the prevalent thermal regime. The area of interest was delineated by geological parameters such as shale maturity and reservoir rock presence as well as existing production data. The purpose of this study is to use an uncertainty assessment method based on hundreds of basin model simulations that sample ranges of probable input parameters to quantify the recoverable reserves from the Bakken petroleum system in North Dakota. The results are displayed in reverse cumulative probability plots, tornado sensitivity charts, as well as in maps of the 10% chance, 50% chance (P50), 90% chance values. This means that there is an X% chance of success or an X probablity of realizing a certain amount of hydrocarbon. The P50 results of the uncertainty assessment indicate that approximately 4 billion bbl of oil and 3.6 tcf (102 billion m〈sup〉3〈/sup〉) of gas are recoverable from the Middle Bakken, Pronghorn, and Three Forks reservoir rocks in North Dakota. The Bakken–Three Forks trend appears to be an overcharged petroleum system, where the available pore space in reservoir rocks is the limiting factor for each accumulation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Węglówka oil field is located in the outer Carpathians. The outer Carpathians are a region where hydrocarbons were discovered and exploited at the end of the nineteenth century in several dozen oil fields, which are relatively small. The Węglówka oil field is one of the largest in this region. In the 150 yr or so of hydrocarbon exploration in the area, more than 1 million t (〉1,237,000 tons [〉8,841,000 bbl]) of oil have been produced. Hydrocarbons are concentrated in Lower Cretaceous sandstones (Grodziszcze and Lgota sandstones) that form an anticline sealed by Upper Cretaceous marls called the Węglówka marls. These cap rocks are up to 600 m (2000 ft) thick. Because of the thrust-related exhumation, they were exposed at the surface and represent the youngest deposits in the region. The present work is focused on a detailed petrographic characterization of the Węglówka marls. This study allows petroleum geologists to better understand the evolution of porosity in these cap rocks and can serve as a foundation for the prediction of their sealing properties. The marls appear as a succession of interbedded red and green varieties, which occur in up to 2-m (6-ft)-thick beds. These beds are nonarenaceous, soft, and bioturbated. Grain size corresponds to approximately 80% clay and less than 20% silt fractions. X-ray diffraction (XRD) reveals that the marls contain, on average, 54% clay, 28% calcite, 16% quartz, up to 3% feldspars and, in red marls, 3% hematite. The XRD patterns of clay are typical of mixed-layer illite–smectite ([I–S]; 40% illite in I–S). The clay structures are dioctahedral with similar octahedral Mg and relatively high Fe〈sup〉3〈/sup〉〈sup〉+〈/sup〉 contents both in the red and green intervals. As revealed by standard petrography combined with high-resolution petrography performed through the use of a field emission scanning electron microscope, the marls have mudstone textures according to Dunham’s (1962) classification and are mostly composed of coccoliths and clay with rare nanoquartz. This rock may be considered an impure chalk. Sealing properties of the Węglówka marls are indicated by the specific surface area, porosity, pore size, and permeability, calculated using N〈sub〉2〈/sub〉 gas adsorption, helium, and mercury porosimetry. The sealing potential is postulated to result from a combination of the following: (1) origin of components (i.e., deposition of minute calcareous bioclasts and volcanic material as a source for clay); (2) oxygenated sedimentary environment (as a result of the presence of oxygen in the sediments, burrowing caused the rocks to be homogenized); and (3) tectonic-induced clogging of pore space because of reorganization of clay flakes (the rocks were strongly tectonically deformed, which resulted in reduction of porosity in clay aggregates).〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Calcite cementation has been identified as an active process in the Upper Triassic Yanchang Formation throughout its burial history and as a major diagenetic factor causing strong reservoir heterogeneities. The origins of calcite cements and their relevance to reservoir heterogeneities were investigated using a suite of petrographic and geochemical methods, including optical microscopy with fluorescence and cathodoluminescence, scanning and backscattered electron microscopy with energy-dispersive spectrometry, x-ray diffraction, x-ray fluorescence, electron probe microanalysis, quantitative evaluation of minerals by scanning electron microscopy, fluid inclusion analysis, and carbon and oxygen stable isotope analyses. The sandstones are compositionally immature with relatively high amounts of volcanic rock fragments. The two generations of calcite cements are Ca-I and Ca-II. The Ca-I calcites are distributed along the interface of sandstone and mudstone units and were formed during the Late Triassic to Early Jurassic at formation temperatures of approximately 90°C. The Ca-II calcite mainly developed in the lower part of the fining-upward sandstone units and was formed in the Late Jurassic at higher temperatures of approximately 110°C. The origins of calcite cements were constrained by geochemical and isotope measurements, fluid inclusion homogenization temperature, and in situ element analysis. The Ca-I calcite cement originated from dissolution of the lacustrine depositional carbonates in the interbedded mudstones and reprecipitation in the adjacent sandstones. The Ca-II calcite was mainly related to organic matter decarboxylation, with Ca〈sup〉2+〈/sup〉 having been provided internally by volcanic fragment alteration and plagioclase dissolution. Calcite cementation had caused strong reservoir heterogeneities in the Yanchang Formation tight sandstones. The Ca-I calcite cementation destroyed reservoir properties along the interface of sandstones and mudstones. The lower parts of the fining-upward sandstone units were tightly cemented by Ca-II calcite, although they originally had high porosity and permeability. The middle–upper parts of the fining-upward sandstone units contain less calcite cements and thus have better preserved reservoir pores because of oil emplacement inhibiting the calcite cementation processes.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling shale gas field is located in a mountainous area, with well-developed underground rivers and karst caves. It also has a highly concentrated population, so the shale gas development in this field is faced with environmental protection problems. Combined with the characteristics of surface natural environment in the Fuling shale gas field and the features of shale gas development engineering, the main environmental issues encountered in the development of the Fuling shale gas field were analyzed. Studies on intensive land use, water conservation and protection, harmless use and disposal of oil-based drill cuttings, recycling of wastewater from drilling and fracturing, and green environment management mode for shale gas development were conducted, and the green development technology system suitable for the Fuling shale gas field was established. Field applications showed that, after applying the green development technology, the land occupation was reduced by 62.l%, the recycling rate of drilling and fracturing wastewater was up to 100%, the oil content of treated oil-based drill cuttings was less than 0.3%, and carbon dioxide emission was reduced by 64.47 × 10〈sup〉4〈/sup〉 t (1.41 × 10〈sup〉9〈/sup〉 lb). Thus, the goal of zero contamination was realized during shale gas field development. Research showed that the green and environmental protection development technology for the Fuling shale gas field has served as a valuable demonstration in the environmental protection in large-scale development of shale gas fields in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Increased oil and gas production in many areas has led to concerns over the effects these activities may be having on nearby groundwater quality. In this study, we determine the lateral and vertical extent of groundwater with less than 10,000 mg/L total dissolved solids near the Lost Hills–Belridge oil fields in northwestern Kern County, California, and document evidence of impacts by produced water disposal within the Tulare aquifer and overlying alluvium, the primary protected aquifers in the area.The depth at which groundwater salinity surpasses 10,000 mg/L ranges from 150 m (500 ft) in the northwestern part of the study area to 490–550 m (1600–1800 ft) in the south and east, respectively, as determined by geophysical log analysis and lab analysis of produced water samples. Comparison of logs from replacement wells with logs from their older counterparts shows relatively higher-resistivity intervals representing the vadose zone or fresher groundwater being replaced by intervals with much lower resistivity because of infiltration of brines from surface disposal ponds and injection of brines into disposal wells. The effect of the surface ponds is confined to the alluvial aquifer—the underlying Tulare aquifer is largely protected by a regional clay layer at the base of the alluvium. Sand layers affected by injection of produced waters in nearby disposal wells commonly exhibit log resistivity profiles that change from high resistivity in their upper parts to low resistivity near the base because of stratification by gravity segregation of the denser brines within each affected sand. The effects of produced water injection are mainly evident within the Tulare Formation and can be noted as far as 550 m (1800 ft) from the main group of disposal wells located along the east flank of South Belridge.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km〈sup〉2〈/sup〉 (10,000 mi〈sup〉2〈/sup〉). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity is one of the most important rock properties in describing hydrocarbon reservoirs. Tests on core samples provide direct and representative porosity data, and the measurement of porosity at high confining pressures is recognized to correlate well with subsurface reservoir porosity. Whereas theoretical deductions of the changes and relationships of pressures, volumes, and compressibility suggest that porosity is reduced during the coring and lifting processes, the porosity measurement at elevated confining pressure does not evaluate original reservoir porosity. This theory is quantitatively validated by repeated laboratory experiments of loading and unloading on sandstone core samples. When the in situ confining pressure is approximately 30–35 MPa (∼4350–5076 psi), coring and lifting would cause a porosity reduction of approximately 1.2%–1.6%, and the porosity test under high confining stress results in further porosity loss. A revised approach in calculating reservoir porosity from cored samples is proposed and can have significant implications for reserve calculations, recovery factors, and geostatistical reservoir models. The study is important for both conventional and unconventional reservoirs because it discusses a fundamental mechanism of porosity change.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In this paper, high-resolution three-dimensional seismic data are used to interpret a transpressional salt tectonic structure in the Yingxiongling area, Qaidam Basin, China. The geometries of the salt structure and the Shizigou fault system that intersects it are precisely depicted. The Shizigou fault system is composed of suprasalt and subsalt components. The suprasalt component is a Y-shaped reverse fault, and the subsalt component is a complex flower structure. In previous studies, suprasalt and subsalt components were interpreted as two independent fault systems. This paper proposes instead that the suprasalt and subsalt faults are kinematically related and decoupled across the salt layer.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum mobility in shale is closely correlated with the attributes of shale petroleum and pores; however, the relationship between these attributes is poorly understood. To characterize petroleum mobility in self-sourcing reservoirs, a suite of mature Eocene shales was selected and subjected to organic solvent extraction, and both the raw and solvent-treated samples were analyzed using pyrolysis, nitrogen adsorption, and x-ray diffraction. The results show that the pore surface area and pore volume of these shales are mainly controlled by their clay and quartz content rather than their organic matter (OM) content and are limited by the presence of carbonates. Correlations of soluble OM with pore surface area and volume after solvent extraction indicate that petroleum mobility of studied shales is initiated when the petroleum content reaches 0.70 wt. % of the rock and the pore diameter is over 12.1 nm. These thresholds are established in the studied area and should be similar for the self-sourcing reservoirs from similar sedimentary environments. This work proposes a method to reveal the thresholds of petroleum content and pore diameter for petroleum mobility in self-sourcing reservoirs, which is useful in the assessment of petroleum producibility and is of significance for unconventional petroleum exploration and exploitation.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉For oil-rich shales, current solvent extraction– and thermal extraction–based methods inaccurately measure hydrocarbon-filled porosity (〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉). Moreover, the hydrocarbon composition is not characterized by either method. Here, we show how open-system programmed thermal extraction and pyrolysis, LECO total organic carbon, Archimedes bulk density, and helium pycnometry measurements are integrated to calculate oil and gas pore volumes, characterize their composition, and estimate mobility. Use of a modified multiramp, slow-heating thermal extract, and pyrolysis temperature program further subdivides the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. Saturate–aromatic–resin–asphaltene (SARA) separation and gas chromatography of solvent-extracted organic matter and thermally extracted oils are used to compositionally classify the 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉. The segregated bulk compositions of gas- and oil-filled porosity measured via this method are shown to overlap and are broken into the following categories: gas-filled porosity (∼C〈sub〉1〈/sub〉–C〈sub〉14〈/sub〉), light oil–filled porosity (∼C〈sub〉6〈/sub〉–C〈sub〉36〈/sub〉), and heavy oil–filled porosity (∼C〈sub〉32〈/sub〉–C〈sub〉36〈/sub〉+). Furthermore, slow-heating multiramp thermal extraction can subdivide the light oil–filled porosity into four components capturing the C〈sub〉11〈/sub〉–C〈sub〉13〈/sub〉, C〈sub〉12〈/sub〉–C〈sub〉16〈/sub〉, C〈sub〉14〈/sub〉–C〈sub〉20〈/sub〉, and C〈sub〉17〈/sub〉–C〈sub〉36〈/sub〉 ranges of the extractable organic matter. Analysis of solvent-extracted oils by SARA identifies abundant saturates and aromatics in the light oil–filled porosity and abundant resins and asphaltenes in the heavy oil–filled porosity. Low-maturity shales can be dominated by heavy (C〈sub〉32〈/sub〉+) oils rich in asphaltene and resin fractions not observed in the produced fluid. The ratios of SARA components in the C〈sub〉15〈/sub〉+ fraction of produced fluid and core extract can be used to better estimate the potentially mobile 〈span〉φ〈/span〉〈sub〉〈span〉HC〈/span〉〈/sub〉.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Fuling gas field in Sichuan Basin, China, has produced greater than 1.5 × 10〈sup〉10〈/sup〉 m〈sup〉3〈/sup〉 (0.53 tcf) of natural gas from overmature Upper Ordovician Wufeng and lower Silurian Longmaxi shales. To systemically investigate the characteristics of wettability and connectivity and to understand the underlying causes of production behavior, we study five samples of Wufeng and Longmaxi shales with different total organic carbon contents and mineral compositions. Complementary approaches include mercury intrusion capillary pressure (MICP), contact angle measurement, spontaneous imbibition and saturated diffusion, and tracer (both nonsorbing and sorbing) migration mapped via laser ablation inductively coupled plasma mass spectrometry. According to measured contact angles and imbibition tests conducted on aqueous (deionized water and brine) and oleic (n-decane) phases, Wufeng and Longmaxi shales are strongly oil wet and moderately strong water wet. The lower boundary of estimated permeability obtained from n-decane imbibition can reach 137 nd, which is higher than the geometric mean permeability derived from the MICP method (5.5–68.8 nd). Effective diffusion coefficients of the Wufeng and Longmaxi shales are in the range of 10〈sup〉−13〈/sup〉 m〈sup〉2〈/sup〉/s (1.1 × 10〈sup〉−12〈/sup〉 ft〈sup〉2〈/sup〉/s). Tests of imbibition and saturated diffusion using tracer-containing brine show that concentrations of nanometer-sized tracers decrease rapidly (a factor of 〉10) over a migration distance of a few millimeters from the sample edge, suggesting the presence of poorly edge-connected water-wet pores. Sparsely connected hydrophilic pores, mixed wettability, and highly restricted pathways collectively contribute to the limited migration of nano-sized tracers, which probably results in the production behavior of initial steep decline and low overall recovery in the Fuling gas field.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field.Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉In the Paleocene to Eocene Wilcox Group in the northern Gulf of Mexico, exploration targets are reaching into deep to ultradeep burial depths. At these great depths, reservoir quality (porosity and permeability) becomes an important risk factor in determining the chance of encountering an economic reservoir. Major controls on reservoir quality are pore types and abundances, pore-throat sizes, and pore network composition. These factors can be analyzed by integrating petrographic, core plug porosity and permeability, and mercury injection capillary pressure (MICP) analyses. The Wilcox sandstones are mostly lithic arkoses and feldspathic litharenites that contain primary interparticle pores, secondary dissolution pores, and micropores. However, these pore types evolve with depth and temperature. As temperature increases, the relative abundance of primary interparticle pores decreases, whereas the relative abundance of secondary dissolution pores and nano- to micropores increases. Associated with this evolution of pore networks with increasing temperature, there is a decrease in reservoir quality. This decrease in reservoir quality is caused by a transition to finer pore-throat sizes that correspond to changes in pore types. Petrographic analysis provides information on pore types, core plug porosity and permeability analysis provides information on volume of pores and effectiveness of flow, and MICP analysis provides information on pore-throat radius distribution. Through forecasting the pore network in the target temperature zone, a realistic porosity versus permeability transform can be selected to estimate permeability from wire-line log porosity.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Canning Basin is a largely unexposed and underexplored frontier basin, formed mostly in the Paleozoic. Geological knowledge of this basin is based predominantly on sparse regional “vintage” two-dimensional seismic and small three-dimensional (3-D) seismic surveys and less than 230 exploration wells. Following seismic interpretation, an integrated interpretation was completed on airborne gravity gradiometer (AGG), magnetic, seismic, well, and complementary data along the southwestern margin of the Fitzroy trough and Gregory subbasin. Seismic data were reinterpreted using AGG data to produce a better constrained geological model. A basement structure map, two intrasedimentary structure maps, and a formation distribution map were produced. The interpretation of seismic profiles, validated through 2.5-dimensional gravity gradiometer modeling, is essential to this workflow.Repeatedly reactivated west–northwest and northwest structural trends, inherited from Proterozoic orogenies, respectively delineate the Fitzroy trough and the Gregory subbasin with its northwestern structural extension into the Fitzroy trough, the Gregory subbasin trend. Subsidence occurred during two periods of extension. An asymmetric extensional system of the Fitzroy trough controlled Ordovician–Silurian deposition of the Carribuddy Group. Devonian–Carboniferous subsidence defines the Gregory subbasin trend. This Pillara extension reactivated structures in the east of the Fitzroy trough. Simultaneous activity of both extensional fault systems and growth faulting controlled the facies and thickness distribution of carbonates and clastics of the early Carboniferous Fairfield Group. The Meda and Fitzroy transpressional phases inverted faults of the Gregory subbasin trend and Fitzroy trough, producing prospects by structural interference.The improved understanding of tectono-stratigraphic relationships, including the 3-D distribution of carbonate reservoirs, benefited the planning of seismic surveys, prospect evaluation, drilling, and acreage relinquishment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal conductivity is a major influencing factor on subsurface conductive heat transport and resulting temperature distribution, which in turn is a key parameter in basin modeling. Basin modeling studies commonly use representative literature values of thermal conductivity despite their impact on modeling results. We introduce a workflow for quantifying the effect of uncertain thermal conductivity on subsurface temperature distribution and thus on basin modeling results and test this workflow on a two-dimensional generic model from the Nordkapp Basin; a prior ensemble of possible models is conditioned according to Bayes’ theorem to incorporate prior knowledge of temperature data. This conditional probability yields a posterior ensemble of temperature fields with a significantly reduced standard deviation. To verify our approach, we use five characteristic scenarios from the posterior ensemble for transient petroleum systems modeling. How considering uncertain thermal conductivity affects variance in hydrocarbon generation is assessed by modeling corresponding vitrinite reflectances (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉).Temperature uncertainty increases with depth. It also increases with increasing offset from the salt diapirs, which can be associated with a large lateral heat-flow component in the complex tectonic environment of the Nordkapp Basin. The introduced workflow can reduce temperature uncertainty significantly, especially in regions with high prior uncertainty. The 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 is very sensitive to changes in thermal conductivity because the onset depth of the gas window in the Nordkapp Basin may vary by up to 800 m (2600 ft) within the 95% confidence interval. This demonstrates the importance of quantification of the uncertainty in thermal conductivity on thermal basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Yinggehai–Song Hong Basin has received a large amount of terrigenous sediment from different continental blocks since the Paleogene. The Yingdong slope, which is located on the eastern side of this basin, is an important potential gas province, but the provenance of the marine sediments in this area are poorly understood. The detrital zircon U-Pb geochronology of sedimentary rocks from the lower Miocene to Quaternary is examined in this study to investigate the temporal and spatial variations in provenance since the early Miocene. The U-Pb ages of detrital zircon range from 3078 to 30 Ma, suggesting that sediment input is derived from multiple sources. Detailed analyses of these components indicate that both the Red River and Hainan are likely the major sources of the sediments on the Yingdong slope, with additional minor contributions from central Vietnam (eastern Indochina block) and possibly the Songpan–Garze block. Variations in the dominant detrital zircon populations within stratigraphic successions display an increasing contribution from the Red River since the middle Miocene. This resulted from the progradation of the Red River Delta in the northern basin and may have also been influenced by regional surface uplift and associated climate changes in East Asia. This study shows that the Red River has had a relatively stable provenance since at least the early Miocene, indicating that any large-scale drainage capture of the Red River should have occurred before circa 23 Ma.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Jurassic black mudstone and coal beds in the central Junggar Basin, northwestern China, are the major source rocks for the basin with type II〈sub〉2〈/sub〉 and type III (gas-prone) kerogens. Widespread overpressures are developed in the Jurassic stratigraphic interval. Sonic and resistivity logs display strong characteristic responses of overpressure in the mudstones, with anomalously high acoustic traveltimes and low resistivity compared with the normally pressured mudstones. The overpressured Jurassic sediment sequences appear to have undergone normal compaction because the mudstones exhibit no anomalously low bulk density. The overpressured mudstones deviate from the normally pressured mudstones in density–effective vertical stress space. The overpressure in the Jurassic source rocks is, therefore, not caused by disequilibrium compaction. The overpressured Jurassic sandstone reservoirs are predominantly oil and gas saturated or oil bearing. The well-log responses of the overpressured mudstones and seismic velocity characteristics indicate that the top depth of the overpressure zone ranges from 3800 to 4600 m (12,500 to 15,100 ft), corresponding to formation temperatures of approximately 94°C to 111°C (∼201°F to 232°F), with estimated vitrinite reflectance values of 0.6% to 0.75%. The Jurassic source rocks with overpressure are capable of generating hydrocarban at present and are currently overpressured. All the evidence suggests that the overpressure in the Jurassic source rocks in the central Junggar Basin is caused by hydrocarbon (HC) generation. The overpressure evolution was modeled quantitatively in response to pressure changes caused by HC generation during basin evolution. The results indicate that multiple episodes of overpressure development and release occurred within the Jurassic source rocks, suggesting multiple episodes of HC expulsion. The timing and numbers of these episodes of HC expulsion were thus determined from the modeled overpressure evolution.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Thermal properties of rocks are essential parameters for investigating the geothermal regime of sedimentary basins, and they are also important factors in assessments of hydrocarbon and geothermal energy resources. The Tarim Basin, the largest basin located in the north of the Tibetan Plateau, northwestern China, has great hydrocarbon resource potential and is an ongoing target for industry exploration. However, the thermal properties of sedimentary rocks within the basin are yet to be systematically investigated at a basin scale, thereby limiting our understanding of the thermal regime in the basin. Here, we collected 101 samples of sedimentary rocks and measured their thermal properties. Our results show that the ranges (and means) of thermal conductivity, radiogenic heat production, and specific heat capacity are 1.08–5.35 W/mK (2.52 ± 0.99 W/mK), 0.03–3.24 μW/m〈sup〉3〈/sup〉 (1.24 ± 0.87 μW/m〈sup〉3〈/sup〉), and 0.75–1.10 kJ/(kg·°C) (0.87 ± 0.07 kJ/(kg·°C)), respectively. Volumetric heat capacity and thermal diffusivity at the temperature of 40°C range from 1.61 to 2.79 MJ/(m〈sup〉3〈/sup〉·K) (2.26 ± 0.25 MJ/[m〈sup〉3〈/sup〉·K]) and 0.44–2.95 × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s ((1.12 ± 0.53) × 10〈sup〉−6〈/sup〉 m〈sup〉2〈/sup〉/s), respectively. The thermal properties vary considerably for different lithologies, even within the same lithotype, indicating that thermal properties alone cannot be used to distinguish lithology. Thermal conductivity increases with increased burial depth, density, and stratigraphic age, suggesting the dominant influence is porosity variation on thermal conductivity. Furthermore, a strong contrast in the thermal properties of rock salt and other sedimentary rocks perturbs the geothermal pattern, which should be taken into consideration when performing basin modeling.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The relationship between base metal deposits, especially Mississippi Valley–type (MVT) Pb–Zn deposits, and hydrocarbons is not well constrained. This is despite the fact that hydrocarbons generally occur in MVT deposits; the ores are emplaced in the same temperature range as hydrocarbon maturation and migration, and the deposits commonly occur in proximity to metal-rich black shales. Better understanding should lead to better exploration models for both hydrocarbons and MVT deposits. This connection is better understood with the help of Pb isotope patterns. Sphalerite Pb isotope compositions from the northern Arkansas and Tri-State mining districts and Woodford–Chattanooga and Fayetteville Shales were determined to assess the potential of shales as source rocks for the ore metals. The ores in both districts have a broad range of Pb isotope ratios and define linear trends, suggesting mixing of Pb from two distinct end members. Current results and previous depositional environment studies indicate the following: (1) shales deposited mainly under nonsulfidic anoxic conditions represent the less radiogenic end member, or (2) shales are the only source of ore metals. Given the array of organic molecules, each with their own thermochemical range, and the ways metals can be associated with them, the release of metals may cover varying ranges. Thus, the compositions of the released fluids would change through time and not have a single static composition, closely approximating the isotopic composition of the released metals at various times. Mineralization derived from a dynamically evolving fluid may show apparent end members, without the need to call on mixing of fluids from separate sources.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A subaqueous clinoform system has been identified from high-quality three-dimensional seismic data from the northeast Exmouth Plateau, North West Shelf, Australia, and was interpreted as a shelf–slope–basin clinoformal component of a Jurassic fluviodeltaic system (the Legendre delta). Several geomorphological features associated with shelf-slope development and subsequent rift tectonics were identified, including (1) submarine channels at slope to basin floor; (2) gullies on the slope; (3) slumps on the shelf; and (4) canyons, canyon-derived gravity flow deposits, and a fan lobe developed in subsequent rift processes.The results of this study provide insights into the controlling factors on the sinuosity, degree of erosion, and sediment gravity flows of channels developed at slope to basin-floor settings, which shed light on the way fluvial sands were transported across the shelf and slope to the basin floor. The geometries and distributions of gravity flow deposits, if confirmed by drilling, may serve as an analog for reservoir prediction in the deep-water fluviodeltaic settings. The gullies on the slope were interpreted as a result of dilute, sheetlike flows. The slumps on the shelf were interpreted as a result of nonslope-related causes.The syntectonic canyons, the canyon-derived gravity flow deposits, and the fan lobe present vivid examples of the erosion and sedimentation processes during active rift tectonics and have significant implications for understanding the rift processes of the North West Shelf, Australia, as well as other rift-related basins.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Giant petroleum accumulations worldwide with burial depths more than 7000 m (〉23,000 ft) occur mostly in Mesozoic and Cenozoic reservoirs and yield predominantly natural gas. Recently, however, a giant oil accumulation with reservoir depths between 7000 m (23,000 ft) and 8000 m (26,000 ft) was discovered in the lower Paleozoic section in the southern part of the Halahatang region in the Tarim Basin, China. Petroleum sourced from lower Paleozoic rocks is contained in Ordovician karst fracture-cave reservoirs and sealed by Middle–Upper Ordovician limestones and mudstones. The newly discovered superdeep accumulation is among the deepest black single-phase oil accumulations worldwide and opens up new avenues for petroleum exploration in deep-marine carbonate reservoirs. Reservoir pressures are between 75 MPa (10,878 psi) and 85 MPa (12,328 psi), with pressure coefficients between 1.2 and 1.7 and temperatures ranging between 140°C (284°F) and 172°C (342°F). Charging and accumulation of petroleum occurred during the late Hercynian orogeny, followed by subsequent gradual deep burial, which took place before rapid subsidence beginning circa 5 Ma. Following subsidence, the thickness of overlying strata increased by more than 2000 m (〉6600 ft) before finally attaining current depth. Therefore, this oil accumulation represents a well-preserved ancient petroleum system. Based on the geochemical features of oils and gases, the crude oils can be classified as mature, sourced from mixed marine organofacies of shale, marl, and carbonate, whereas the gases were cogenerated with oils. Despite very high present-day reservoir temperatures, no oil cracking has occurred because of the relatively short exposure of oils to high temperatures in a low geothermal gradient regime. Thus, there is significant exploration potential under similar conditions for liquid petroleum in superdeep strata. Faults and reservoirs are major factors controlling petroleum accumulation. Interlayer karsts with excellent fracture-cavity connectivity developed adjacent to faults, generally resulting in the enrichment of oil and gas along fault zones. High-quality reservoirs in this area are easy to identify because they exhibit strong bead-like amplitude features in seismic sections. Wells located near faults produce relatively large amounts of oil and gas. Effective karst fracture-cave reservoirs with noncracked oil may exist below 8000 m (26,000 ft) in the Tarim Basin and represent a significant exploration target in China.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Substantial amounts of petroleum were recently discovered in the Carboniferous andesite, tuff, breccia, and basalt reservoirs of the Chepaizi uplift in the western Junggar Basin. However, the charging history of the Carboniferous petroleum reservoir is poorly understood. Oil–oil correlation studies indicate that all of the oils were mainly derived from the middle Permian Wuerhe Formation source rocks, possibly mixed with a small contribution from Carboniferous Baogutu Formation source rocks in the neighboring Changji sag. Based on the petrographic and microthermometry of fluid inclusions, two hydrocarbon charging episodes are defined; these episodes were characterized by a low-peak-range homogenization temperature (〈span〉Th〈/span〉) distribution (80°C–90°C) and high salinity (13.22–13.42 wt. % NaCl) and a high-peak-range 〈span〉Th〈/span〉 distribution (120°C–130°C) and low salinity (4.89–11.72 wt. % NaCl), respectively. Through one-dimensional basin modeling and pressure–volume–temperature–composition simulation, the burial-thermal histories for wells P61, P66, P668, and P663 were reconstructed, and their trapping temperatures of the hydrocarbon inclusions were calculated to be higher than their corresponding highest paleotemperature (i.e., 56.8°C, 53.7°C, 60.9°C, and 58.1°C, respectively), implying fast hydrocarbon charging processes promoted by deep hydrothermal fluids. Associated with the hydrocarbon generation history, sealing process of the Hongche fault, and regional tectonic evolution, these two hydrocarbon charging events were deduced as the adjustments of oils previously accumulated along the Hongche fault zone, because of the tectonic extension in the Paleogene and regional tilting in the Neogene, respectively. The general direction of oil charging was traced from south to north and from east to west, as indicated by the molecular parameters of nitrogen-bearing compounds and C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 triaromatic steroids/C〈sub〉20〈/sub〉 + C〈sub〉21〈/sub〉 + C〈sub〉26〈/sub〉–C〈sub〉28〈/sub〉 triaromatic steroids (TA(I)/TA(I+II)), which roughly coincided with the active fracturing.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Modern oil and gas seismic surveys commonly use areal arrays that record continuously, and thus routinely collect “excess” data that are not needed for the conventional common reflection point imaging that is the primary goal of exploration. These excess data have recently been recognized to have utility not only in resource exploration but also for addressing a diverse range of scientific issues.Here we report processing of such discarded data from recent exploration surveys carried out in southeastern New Mexico. These have been used to produce new three-dimensional (3-D) seismic reflection imagery of a layered complex within the crystalline basement as well as elements of the underlying crust. This enigmatic basement layering is similar to that found on industry and academic seismic reflection surveys at many sites in the central United States. Correlation of these reflectors with similar features encountered by drilling in northwestern Texas suggest that they may be part of an extensive, continental-scale network of tabular mafic intrusions linked to Keweenawan rifting of the igneous eastcentral Unites States during the late Proterozoic. More importantly, this analysis clearly demonstrates that the new generation of continuously recorded 3-D exploration datasets represent a valuable source of fresh information on basement structure that should be examined rather than discarded. Such basement information is not only important to understanding crustal evolution, it is directly relevant to assessing risks associated with fossil fuel extractions, such as induced seismicity related to waste water injection.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The detailed depositional systems and basin evolution of Lower Cretaceous coal-bearing strata in the Erlian Basin of northeastern China were analyzed based on extensive borehole and outcrop data. A total of 7 facies associations are interpreted and consist of 14 distinct lithofacies, with lithologies including conglomerates, sandstones, siltstones, mudstones, shales, and coals. Five third-order sequences were recognized, and their internal lowstand, transgressive, and highstand systems tracts were defined based on six key sequence stratigraphic boundaries. These boundaries were represented by regional unconformities, basal erosional surfaces of incised valley fills, interfluvial paleosols, and abrupt depositional facies-reversal surfaces. Sequences I–V correspond to the rift-initiation stage, the early-rift climax stage, the late-rift climax stage, the immediate postrift stage, and the late postrift stage of the basin, respectively. The preferred sites for coal accumulation were braided fluvial delta plain, meandering fluvial delta plain, and littoral–shallow lake environments. The major coal seams formed during the early and late transgressive systems tract of sequences III, IV, and V, which were well developed in the eastern, northeastern, and northeastern parts of the Erlian Basin, respectively. Three coal depositional models were summarized in the sequence stratigraphic framework, including types 1, 2, and 3, corresponding to the Newark type, Newark–Richmond type, and Richmond type, respectively. These coal depositional models were closely related to the basin evolution. These results could provide preferred depositional environments and favorable areas of coal and coalbed methane (CBM) for the exploration and development of coal and CBM in the Erlian Basin, with the Jiergalangtu, Huolinhe, Baiyinhua, and A’nan sags recommended as the key sags.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Different from most tight oil reservoirs, the tuffaceous tight oil of the Tiaohu Formation is not in situ oil, and no close contact exists between the source rock and reservoir in the Malang sag (Santanghu Basin, China). This study determined the mechanism of hydrocarbon accumulation of this tuffaceous tight oil reservoir through an integrated analysis of oil–source rock correlation, reservoir characteristics, and rock wettability combined with a comprehensive analysis of geological conditions. An oil–source rock correlation using biomarkers and stable carbon isotopes shows that the crude oil originated from underlying source rocks in the Lucaogou Formation. The oil in the tuffaceous tight reservoir is not indigenous but has migrated over a long distance to accumulate in these reservoirs. Faults and fractures that developed at the end of the Cretaceous are the oil migration pathways. Vitric and crystal-vitric tuffs constitute the main rock types of the tuffaceous tight reservoir. Matrix-related pores in the tuffs mainly comprise interparticle pores between minerals and dissolution intraparticle pores formed by devitrification. The adsorption of polar components of the oil generated from original organic matter in the tuff leads to wettability of lipophilicity, which is the main reason for hydrocarbon charging and accumulation. To our knowledge, this is the first comprehensive study reporting this finding.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Predicting vertical and lateral facies variations in various depositional environments remains a major challenge in the oil and gas industry because it impacts petroleum system assessments and the associated exploration-risking phase. The use of multidisciplinary constraints (geomorphology, geology, geophysics) in forward stratigraphic models sheds light on the complex interaction of local, regional, and global driving mechanisms that influence sediment transport and deposition along continuously evolving landscapes. In this paper, we develop an integrated statistical approach to examine the sensitivity of forward stratigraphic models in complex salt provinces to several parameters, including water discharge, sedimentary load, grain size and associated diffusion coefficients, and slope. This statistical analysis was applied to the Barremian–Albian sequence of the central Scotian Basin (Canada) and highlights the influence of complex salt kinematics on sediment pathway diversion and accumulation around salt domes and canopies. Forward stratigraphic modeling results point to regions of higher probability of Lower Cretaceous sandy reservoirs. Automating simulation runs significantly reduced the time required to achieve a statistically valid number of simulations and allowed the sensitivity of the model to be evaluated.〈/span〉

Description: 〈span〉In his comment on our paper about the hyperpycnites in the Triassic Yanchang Formation, G. Shanmugam puts forward that hyperpycnites do not exist. Consequently, he considers our interpretation that hyperpycnal flows are an important depositional process in the Yanchang Formation to be invalid. We unravel his arguments and demonstrate that evidence supports our assertion that hyperpycnal flows were an important sedimentary process in the lake in which the Yanchang Formation accumulated. Moreover, we provide proof from modern observations that hyperpycnal flows do exist in lakes.〈/span〉

Description: 〈span〉〈a href="https://pubs.geoscienceworld.org/aapgbull#b27"〉Yang et al. (2017b)〈/a〉 have advocated the importance of hyperpycnites by using a genetic facies model proposed for deposits of hyperpycnal flows by 〈a href="https://pubs.geoscienceworld.org/aapgbull#b14"〉Mulder et al. (2003)〈/a〉. The problem is that the authors have ignored experimental flume results and other empirical field data that discredited the model. This discussion is a rigorous evaluation of data, documentation, and the facies model.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉We analyze western Caribbean structural styles and depositional controls associated with Late Cretaceous–Cenozoic deformational events using a 1600-km (994-mi)-long, regional, northwest–southeast transect extending from the Cayman Trough in Honduras to northern Colombia. Different structural provinces defined along the transect include (1) the Cayman Trough and adjacent Honduran borderlands marking the North American–Caribbean transtensional plate boundary characterized by late Eocene–Holocene fault-controlled depocenters; (2) the Nicaraguan Rise that includes continental Paleocene–Eocene rocks deposited in sag basins, which are overlain by relatively undeformed Miocene–Holocene carbonate and clastic shelf deposits of the northern Nicaraguan Rise, following a Late Cretaceous convergent phase; (3) the Colombian Basin that includes thick Miocene clastic depocenters and the localized presence of Upper Cretaceous rocks overlying the basement and where much of the subsidence is likely isostatic and flexurally driven given its proximity to the subduction zone of northern Colombia; (4) the south Caribbean deformed belt, an active, accretionary prism produced by the subduction of the Caribbean large igneous province beneath the South American plate, which has deformed the Cenozoic prism and fore-arc section and produced thrust-fault–controlled accommodation space for upper Miocene–Holocene piggyback deposits; and (5) the onshore Cesar–Rancheria Basin in northern Colombia, which has recorded the uplift of its bounding mountain ranges, the Sierra de Santa Marta massif to the west and Perija Range to the east. Plate reconstructions place the various crustal provinces along the transect into the context of the Late Cretaceous–Cenozoic deformation events that can be partitioned into strike-slip, convergent, and extensional components.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The lacustrine shale of the Upper Cretaceous Qingshankou Formation is the principal prospective unconventional target lithology, acting as source, reservoir, and seal. Lithofacies and associated storage capacity are two significant factors in shale oil prospectivity. This paper describes an investigation of the lower Qingshankou Formation lacustrine shale based on detailed description and analysis of cores, shale lithofacies characteristics, depositional setting, and stacking patterns.Seven lithofacies are recognized based on organic matter content, sedimentary structure, and mineralogy, all exhibiting rapid vertical and lateral changes controlled by the depositional setting and basin evolution. An overall trend from shallow-water to deep-water depositional environments is interpreted from the characteristics of the infilling sequences, characterized by increasing total organic carbon (〈span〉TOC〈/span〉) and total clay content and decreasing layer thickness (i.e., from bedded to laminated then to massive sedimentary structures). Periods of deposition during shallowing cycles show a reverse trend in the sedimentary characteristics described above. The sedimentary rocks in the studied interval show three complete short-term cycles, each one containing progressive and regressive system tracts.Massive siliceous mudstones with both high and moderate 〈span〉TOC〈/span〉 are considered to have the best hydrocarbon generation potential. Laminated siliceous mudstones, bedded siltstones, and calcareous mudstones with moderate and low 〈span〉TOC〈/span〉 could have the same high hydrocarbon saturations as the high-〈span〉TOC〈/span〉 massive siliceous mudstones, but these lithologies contain more brittle minerals than the massive mudstones. Several siltstone samples show low or zero saturation of in situ hydrocarbons; this is considered to be related to a combination of fair to poor hydrocarbon generation potential and extremely low permeability, limiting migration. Moderate-〈span〉TOC〈/span〉 laminated siliceous mudstones were also observed to have connective pore-fracture networks. It can be demonstrated that successive thick sequences of moderate-〈span〉TOC〈/span〉 laminated siliceous mudstones, showing high volumes of hydrocarbon in situ, a high mineral brittleness index, and good permeability, combine to form shale oil exploration “sweet spots.”〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Helium and nitrogen variations in Panhandle–Hugoton field (PHF) gases are products of interaction between hydrocarbon gas from the Anadarko basin and at least two water masses with dissolved nitrogen and helium. The two most distinct water masses are from the Palo Duro basin (highest He/N〈sub〉2〈/sub〉) and the Hugoton embayment (lowest He/N〈sub〉2〈/sub〉). Geochemical data indicate several hundred million years of helium generation in porous rock. Helium migrated to the gas by diffusion through water-saturated rock and by west-to-east water flow.Sediment and basement helium generation and helium migration were modeled to validate timing and source of PHF helium. Models indicate a predominantly sedimentary helium source with some basement helium charge on the Amarillo uplift. Helium in the central and eastern PHF diffused from underlying rocks, whereas gases on the west and southwest sides were enriched in nitrogen and helium delivered by hydrodynamic water flow.Nitrogen in high-nitrogen gases was probably sourced as ammonium released from clays by cation exchange with brines derived from overlying salt units. The amount of mudrock (nitrogen and helium source) relative to other potential helium sources (arkose, radioactive dolomite) correlates to decreasing gas He/N〈sub〉2〈/sub〉.The high helium concentrations in PHF gases result from multiple favorable circumstances. Old pore water accumulated dissolved helium during hundreds of millions of years of helium generation in sediment. High water/gas and low pressure favored higher helium concentrations in gas. Hydrodynamic flow delivered helium-rich pore water from basins west of the PHF.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉As an important unconventional and alternative resource, shale gas has attracted worldwide attention. The breakthrough pressure is a major factor in the generation and migration of shale gas as well as in the evaluation of the caprock sealing capacity. Carboniferous shales are considered to have great potential for the exploitation of shale gas; thus, investigations of the breakthrough pressure and gas effective permeability are significant. Two shale samples taken from the Carboniferous Hurleg Formation in the eastern Qaidam Basin, China, were chosen to conduct breakthrough experiments to investigate the effects of water saturation and CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixed mole fractions on the breakthrough pressure and gas effective permeability. Prior to the experiments, various relevant parameters (e.g., the porosity, mineral composition, and organic geochemistry; the total organic content, thermal maturity and kerogen type; and microstructure) of these samples were also measured.The results of our breakthrough experiments show that the breakthrough pressure increases with the water saturation and decreases with the CO〈sub〉2〈/sub〉 mole fraction in the gas mixture. The situation for the gas effective permeability is just the opposite. Pore-size distribution measurements indicate that there are many nanoscale micropores that can easily be blocked by water molecules. This results in the reduced connectivity of gas pathways; thus, the breakthrough pressure increases and the gas effective permeability decreases with increasing water saturation. The breakthrough pressure decreases with the CO〈sub〉2〈/sub〉 mole fraction because the interfacial tension of the CO〈sub〉2〈/sub〉–water system is smaller than that of the CH〈sub〉4〈/sub〉–water system. The viscosity of the CO〈sub〉2〈/sub〉–CH〈sub〉4〈/sub〉 mixture was found to increase with the CO〈sub〉2〈/sub〉 mole fraction by fitting a series of values under the same temperature and pressure conditions, leading to an increase in the gas effective permeability. Furthermore, CO〈sub〉2〈/sub〉 molecules are smaller than CH〈sub〉4〈/sub〉 molecules, making it easier for CO〈sub〉2〈/sub〉 to move across pathways. After each breakthrough experiment, the CO〈sub〉2〈/sub〉 mole fraction in the effluent was less than that in the injected gas, and it increased over time until reaching the initial injected gas composition. This is because the adsorption and solubility of CO〈sub〉2〈/sub〉 in water are greater than those of CH〈sub〉4〈/sub〉. This study provides practical information for further investigations of shale gas migration and extraction and the sealing capacities of caprocks.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉A comprehensive study on rift stratigraphy requires a solid understanding of sequence architecture along the steep margins of rift basins. This study analyzes an Eocene lacustrine sequence along the steep margin of the Dongying depression in eastern China through integrated core, well-log, and three-dimensional seismic analyses. The lacustrine sequence is bounded by unconformities and their correlative conformities at the base and top and consists of three systems tracts, namely an early expansion systems tract (EEST), late expansion–early contraction systems tract (LEECST), and late contraction systems tract (LCST), which record a lake expansion–contraction cycle. These systems tracts differ in thickness and development of depositional systems. The EEST is the thickest and contains well-developed marginal and basinal fan systems with an overall retrogradational stacking pattern. The well-developed fan systems are the most striking features within the sequence. The LEECST is the most widespread and contains dominantly profundal–sublittoral deposits. The LCST is the thinnest, with poorly developed fan systems, and is characterized by significant erosion by fluvial incision. The variable thickness and development of depositional systems in the three systems tracts are the responses to the interplay of sediment supply and accommodation space. Accommodation space establishes the framework for sedimentary infill, and sediment supply determines spatial distribution and temporal evolution of depositional systems within each systems tract. This study provides a lake expansion–contraction scheme to divide a lacustrine stratigraphic sequence into systems tracts and highlights the feasibility of applying this approach in studying sequence stratigraphy along the steep margin of a lacustrine rift basin. The results also provide understandings for the development, distribution, and evolution of depositional systems and their controlling factors along the steep margin of other rift basins in the world.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The purpose of this work is to identify genetic affinities among 48 crude oil samples from the onshore and offshore Santa Maria basins. A total of 21 source-related biomarker and stable carbon isotope ratios among the samples were assessed to assure that they were unaffected by secondary processes. Chemometric analysis of these data identifies six oil families with map and stratigraphic distributions that reflect organofacies variations within the Miocene Monterey Formation source rock. The data comprise a training set that was used to create a chemometric decision tree to classify newly collected oil samples. Three onshore families originated from two synclines, which may contain one or more pods of thermally mature source rock. Multiple biomarker parameters indicate that the six oil families achieved early oil window maturity in the range of 0.6%–0.7% equivalent vitrinite reflectance. The offshore oil samples consist of one family from Point Pedernales field and two families from the “B” prospect. Geochemical characteristics of these families indicate origins under differing water column and sediment oxicity and carbonate versus siliceous and detrital input in ‘carbonate,’ ‘marl,’ and ‘shale’ organofacies like those in the lower calcareous–siliceous, carbonaceous marl, and clayey–siliceous members of the Monterey Formation elsewhere in coastal California. The corresponding lithofacies and organofacies appear to be linked to the early–middle Miocene climate optimum and subsequent paleoclimatic cooling after circa 14 Ma, a systematic up-section increase in the stable carbon isotope composition of related oil samples, decreased preservation of calcium carbonate shells from planktic foraminifera and coccoliths, and increased preservation of clay-sized siliceous shells of diatoms and radiolarians. The results show that organofacies within the Monterey source rock are responsible for many of the geochemical differences between the oil families. This paleoclimate–organofacies model for crude oil from the Monterey Formation can be used to enhance future exploration efforts in many areas of coastal California.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC 〉 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Primary depositional mineralogy has a major impact on sandstone reservoir quality. The spatial distribution of primary depositional mineralogy in sandstones is poorly understood, and consequently, empirical models typically fail to accurately predict reservoir quality. To address this challenge, we have determined the spatial distribution of detrital minerals (quartz, feldspar, carbonates, and clay minerals) in surface sediment throughout the Ravenglass Estuary, United Kingdom. We have produced, for the first time, high-resolution maps of detrital mineral quantities over an area that is similar to many oil and gas reservoirs. Spatial mineralogy patterns (based on x-ray diffraction data) and statistical analyses revealed that estuarine sediment composition is primarily controlled by provenance (i.e., the character of bedrock and sediment drift in the source area). The distributions of quartz, feldspar, carbonates, and clay minerals are controlled by a combination of the grain size of specific minerals (e.g., rigid vs. brittle grains) and estuarine hydrodynamics. The abundance of quartz, feldspar, carbonates, and clay minerals is predictable as a function of depositional environment and critical grain-size thresholds. This study may be used, by analogy, to better predict the spatial distribution of sandstone composition and thus reservoir quality in ancient and deeply buried estuarine sandstones.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C〈sub〉7+〈/sub〉 fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval 〈span〉Tmax〈/span〉 release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution caused by extensive salt layers, even when only an exploratory view of the distribution of the reservoir facies is required. The aim of this study was to apply multi-attribute analysis using an unsupervised classification algorithm to map the carbonate facies of an exploratory presalt area located in the Outer high region of the Santos Basin. The interval of interest is the Barra Velha Formation, deposited during the Aptian, which represents an intercalation of travertines, stromatolites, grainstones and spherulitic packstones, mudstones, and authigenic shales, which were deposited under hypersaline lacustrine conditions during the sag phase. A set of seismic attributes, calculated from a poststack seismic amplitude volume, was used to characterize geological and structural features of the study area. We applied k-means clustering in an approach for unsupervised seismic facies classification. Our results show that at least three seismic facies can be differentiated, representing associations of buildup lithologies, aggradational or progradational carbonate platforms, and debris facies. We quantitatively evaluated the seismic facies against petrophysical properties (porosity and permeability) from available well logs. Seismic patterns associated with the lithologies helped identify new exploration targets.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Dibei gas field is a large tight gas field located in the Kuqa subbasin, Tarim Basin, northwestern China. The reservoir is within the Lower Jurassic Ahe Formation (J〈sub〉1〈/sub〉a) and has porosity and permeability ranges of 2%–8% and 0.01–1 md, respectively. Two episodes of hydrocarbon charge are identified based on a detailed study of fluid-inclusion petrography and microthermometry, fluorescence spectroscopy characteristics, and the thermal maturity of both gas and light oil. Low-maturity oil as represented by hydrocarbon inclusions with yellow-green fluorescence entered the reservoir circa 23–12 Ma, whereas high-maturity hydrocarbons, as indicated by hydrocarbon inclusions with blue-white fluorescence, have charged the reservoir since 5 Ma. The hydrocarbon charge process combined with porosity evolution determined the present gas–water distribution characteristics in the Dibei gas field. Porosity in the J〈sub〉1〈/sub〉a sandstone reservoir was relatively high during the first episode of hydrocarbon charge, which allowed oil to migrate upward and accumulate in structural highs under buoyancy. From 5 Ma to the present, the Dibei gas field experienced strong tectonic compression associated with intense thrust-fault reactivation, causing deformation and oil leakage from the reservoir. Continuous tight sand deposits along the slope areas, located far away from the active faults, became favorable accumulation sites for gas derived from the underlying Triassic source rocks. Hydrocarbon accumulation along the slope area in the Ahe Formation is dominantly controlled by equilibrium between hydrocarbon-generation pressure and capillary pressure.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This study examines the influences on fluid flow within a shale outcrop where the networks of two distinct paleoflow episodes have been recorded by calcite-filled veins and green alteration halos. Such direct visualization of flow networks is relatively rare and provides valuable information of fluid-flow behavior between core and seismic scale.Detailed field mapping, fracture data, and sedimentary logging were used over a 270 m〈sup〉2〈/sup〉 (2910 ft〈sup〉2〈/sup〉) area to characterize the paleo–fluid-flow networks in the shale. Distal remnants of turbidite flow deposits are present within the shale as very thin (1–10 mm [0.04–0.4 in.]) fine-grained sandstone bands. The shale is cut by a series of conjugate faults and an associated fracture network, all at a scale smaller than seismic detection thresholds. The flow episodes used fluid-flow networks consisting of subgroups of both the fractures and the thin turbidites. The first fluid-flow episode network was mainly comprised of thin turbidites and shear fractures, whereas the network of the second fluid-flow episode was primarily small joints (opening mode fractures) connecting the turbidites.The distribution of turbidite thicknesses follows a negative exponential trend. which reflects the distribution of thicker turbidites recorded in previous studies. Fracture density varies on either side of faults and is highest in an area between closely spaced faults. Better predictions of hydraulic properties of sedimentary-structural networks for resource evaluation can be informed from such outcrop subseismic scale characterization. These relationships between the subseismic features could be applied when populating discrete fracture networks models, for example, to investigate such sedimentary-structural flow networks in exploration settings.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The middle Cambrian Maryville–Basal sands in the interval of 4600–4720 ft (1402.1–1438.7 m) in the Kentucky Geological Survey 1 Hanson Aggregates well (i.e., muddy sandstones separated by sandy mudstones) were evaluated to determine effective porosity (ϕ〈sub〉〈span〉e〈/span〉〈/sub〉), clay volume (〈span〉Vc〈/span〉), and supercritical CO〈sub〉2〈/sub〉 storage capacity. Average porosity and permeability measured in core plugs were 8.71% porosity and 2.17 md permeability in the Maryville sand and 10.61% porosity and 15.79 md permeability in the Basal sand. The ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 were calculated from the density log using a multiple-matrix shaly sand model to identify four formation lithologies: muddy sandstone, sandy mudstone, dolomitic mudstone, and dolomitic claystone. Average ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 and 〈span〉Vc〈/span〉 calculated in the Maryville sand were 8.9% and 35.3%, respectively, and an average of 8.7% and 41.2% in the Basal sand, respectively. Calculated ϕ〈sub〉〈span〉e〈/span〉〈/sub〉 exhibits a good match with porosity measured in core plugs. Prior to step-rate testing, static reservoir pressure was 2020 psi (13.9 MPa), representing a 0.435 psi/ft (9.8 kPa/m) hydrostatic gradient, which is consistent with other underpressured reservoirs in Kentucky. The interval fractured at 2698 psi (18.0 MPa), yielding a fracture gradient of 0.581 psi/ft (12.7 kPa/m). Pressure falloff analysis suggests a dual-porosity/dual-permeability reservoir consistent with core data. Estimated 50th percentile supercritical CO〈sub〉2〈/sub〉 storage volume supercritical CO〈sub〉2〈/sub〉 storage volume, using 7% porosity cutoff for determining net reservoir volume, is 0.538 tons/ac (1.33 t/ha). Thin reservoir sands, low porosity and permeability, and low fracture gradient, however, preclude the Maryville–Basal sands as large-volume deep-saline CO〈sub〉2〈/sub〉 storage reservoirs in this area.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Porosity–permeability transforms were generated using an extensive data set covering two oil-bearing formations in Ohio: the Clinton Sandstone in eastern Ohio and the Copper Ridge Dolomite in central Ohio. The reservoirs were selected because of their historical importance as oil producers and their potential as targets for CO〈sub〉2〈/sub〉 use for enhanced oil recovery and associated geological storage. The porosity-permeability transforms generated in this study have coefficients of determination that are nearly double those in the published literature. Methods applying other information (e.g., lithofacies type and reservoir depth) to improve the transforms are also discussed. Ultimately, it was determined that although subdividing the Clinton Sandstone data by geologically similar areas constrained the porosity and permeability values, the data for most areas were too limited to yield robust correlations. Thus, the range of possible outcomes should be determined using the transform derived from all available data. The Copper Ridge values were largely not constrained when subdivided by depth.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The Pennsylvanian–Middle Triassic Cooper Basin is Australia’s premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays.This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics.The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin’s significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The strike-slip fault systems in the central Tarim Basin, China, afford an exceptional opportunity to document the structural characteristics and evolution process of small displacement intracratonic strike-slip faults using three-dimensional seismic reflection data. These strike-slip faults display subvertical segments at depth and en echelon normal fault zones where relatively shallow. Fault segmentation and flower structures can be commonly observed in plan view and cross-section view, respectively.Consistent with the notion that segment coalescence is the fundamental process for fault evolution, the mean segment length of representative strike-slip faults examined in this study is positively correlated to the measured fault offset. The width of the en echelon normal fault zone is positively correlated with the estimated maximum overburden thickness. The integrated data sets suggest that the evolution of the conjugate fault array followed a sequential evolution process instead of forming simultaneously. The switch in slip direction of the master fault of the conjugate fault array is attributed to the change of stress orientation. Regarding individual strike-slip faults, increase in displacement induces the formation of faults with lower fault-array angles linking initially formed en echelon normal faults. In cross sections, throughgoing fault surfaces can also form, connecting the lower subvertical fault segment and the upper en echelon normal faults.The presented data sets and evolution models established in this study can be used as tools to better predict the structural attributes of subsurface strike-slip fault systems with important consequences for reservoir formation and hydrocarbon accumulation in the Tarim Basin in particular, and in ancient marine basins in general.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Static formation temperature (〈span〉SFT〈/span〉) can be estimated from temperatures measured during wire-line logging (〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉). A large number of correction models for obtaining 〈span〉SFT〈/span〉 from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 have been suggested. Several studies have shown that 〈span〉SFT〈/span〉s yielded by such models are off by an average of 6°C–10°C (43°F–50°F) at burial depths of 1.5–3.5 km (0.9–2.2 mi) and thus have the potential to cause serious issues in thermal and hydrocarbon generation models. This paper explores the causes for erroneous 〈span〉SFT〈/span〉 predictions generated from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements and identifies factors that should be addressed to generate a globally applicable correction model. We also present an improved empirical correction model for 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 data from eight oil and gas fields, located on the Norwegian continental shelf. The new empirical model was designed to give correct average 〈span〉SFT〈/span〉 predictions and is applicable to single 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 measurements. It has been validated against temperatures recorded during drill-stem testing, which closely represent local 〈span〉SFT〈/span〉s. The expression yields improved results compared with other correction models applied to the data set. However, the average error in computed 〈span〉SFT〈/span〉 values varies by up to 10°C (18°F) between the investigated hydrocarbon fields. We conclude that these variations result from differences in operational practices such as fluid circulation and drilling velocities. Therefore, current empirical and physical models for 〈span〉SFT〈/span〉 prediction from 〈span〉T〈/span〉〈sub〉〈span〉m〈/span〉〈/sub〉 require local calibration. It is also suggested that more accurate compilations and analyses of operational data could lead to improved and more globally applicable models.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The petroleum system concept spans the spatial and temporal extent of all elements and processes required for the generation and preservation of petroleum. The critical moment of a petroleum system is the moment with the highest probability for the generation–migration–accumulation of hydrocarbons. It is an important concept in petroleum exploration risk assessment because the stratigraphic and geographic extents of a petroleum system are determined at the critical moment. In petroleum systems, thermal history data, burial history data, and vitrinite reflectance data may be unavailable, unreliable, or incomplete; this introduces significant uncertainty in the choice of the critical moment. We present here a quantitative probabilistic framework for estimating the critical moment and quantifying the associated uncertainty in such cases. We define a probabilistic early bound and late bound for the critical moment (which, combined together, we term the critical range) and then estimate the moment with the highest numerical probability of generation–migration–accumulation. We define the uncertainty associated with the critical moment as half the absolute value of the critical range. In cases with little ambiguity or duplicity in the timing of petroleum system elements and processes, the critical range converges to one point, which is also the critical moment. The probabilistic framework introduces consistency to the critical moment estimation problem and quantifies the level of uncertainty in the estimation. This reduces the risk involved in petroleum exploration assessment.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Very limited literature is available relating to gas production from ultradeep (〉9000 ft [〉2700 m]) coal seams. This paper investigates permeability enhancement in ultradeep coal seams of the late Carboniferous and early Permian to Late Triassic Cooper Basin in central Australia, using a time-lapse pressure transient analysis (PTA) approach for a pilot well. The gas production history and three extended shut-in periods are used to construct the time-lapse PTA for the study well. A new approach is introduced to construct a permeability ratio function. This function allows the calculation of permeability change resulting from competition between the compaction and coal-matrix shrinkage effects.Pressure transient analysis indicates that gas flow is dominated by a bilinear flow regime in all extended pressure buildup tests. Hence, reservoir depletion is restricted to the stimulated area near the hydraulic fracture. This implies that well-completion practices that create a large contact area with reservoirs, such as multistage hydraulically fractured horizontal wells, may be required for achieving economic success in these extremely low-permeability reservoirs. The permeability ratio is constructed using the slope of the straight lines in bilinear flow analysis. Because of uncertainty in average reservoir pressure, probabilistic analysis is used and a Monte Carlo simulation is performed to generate a set of possible permeability ratio values. The permeability ratio values indicate that coal permeability has increased during the production life of the wellbore because of the coal-matrix shrinkage effect. Permeability enhancement in this ultradeep coal reservoir has offset the effect of permeability reduction caused by compaction, which is beneficial to gas production.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Nanometer to micrometer mica and illite separates of indurated Cambrian and Ordovician oil-bearing sandstones from the Hassi Messaoud field (Algeria) were extracted, x-rayed, observed by scanning and transmission electron microscopy, and K-Ar dated. Electron microscope observations revealed typical euhedral shapes for the mica to illite particles of most size fractions; almost no odd-shaped detrital crystals were detected. The combined results document several generations of mineralogical and morphological identical mica to illite crystals that could not be differentiated by the traditional identification methods. Illite and mica genesis was multiphased with crystallization episodes at 340 ± 10 (ca. Middle Mississippian), 280 ± 10 Ma (ca. early Permian), and 170 ± 10 Ma (ca. Middle Jurassic). Younger than the stratigraphic age of the host rocks, which is incompatible with a detrital origin, the two older mica ages confirm that the hydrocarbon generation and emplacement had to start after the Variscan tectonothermal event and before exhumation of the meta-sediments. The younger K-Ar ages at 135 to 110 Ma (ca. Early Cretaceous) relate to further crystallization episodes, whereas those at circa 295, 265, and 210 Ma probably correspond to variable mixtures of the older and younger mica to illite end-members. Three average K-Ar values are statistically significant: the oldest at 340 ± 10 Ma corresponds to the start of the Variscan tectonic activity, and the intermediate at 280 ± 10 Ma sets its end, both episodes probably modifying the reservoir capacities of the potential hydrocarbon host rocks. The ages at 170 ± 10 Ma identify a further diagenetic activity characterized by illitization of dickite-type precursors in local reservoirs. These younger ages could correspond to the hydrocarbon charge into reservoirs, which stopped diagenetic illitization at a present-day depth of approximately 4000 m (∼13,000 ft).〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉This paper analyzes regional hydrogeological conditions and divides the study area into three hydrogeological types and seven hydrogeological units, to investigate hydrogeology and its effect on coalbed methane (CBM) enrichment in the southern Junggar Basin, China. From this work, it is found that the groundwater flow paths in the study area are the joint effects of south-to-north and west-to-east flows. This study also shows that microbial gases are widely developed, although the depth limit of microbial gas occurrence is still unclear in the study area. Microbial CO〈sub〉2〈/sub〉 reduction is the leading formation path in the study area, except for the Houxia region, where fermentation is the formation mechanism. The abnormally high CO〈sub〉2〈/sub〉 in stagnant zones (i.e., water flow is slow and stagnant) is mainly associated with methanogenesis, whereas relatively low CO〈sub〉2〈/sub〉 (microbial or thermogenic) is present where water flow is active. The average CBM content within the Xishanyao Formation changes within various hydrogeological units; moreover, the average CBM content within the Badaowan Formation of the same hydrogeological unit (e.g., Fukang) suggests that the hydrogeological and CBM enrichment conditions are different within various structural types. Overall, the hydrogeological conditions exert control on the gas content in the study area; that is, the gas content is high in stagnant zones. Finally, influenced by supplemental microbial gases, changes in the CBM oxidation zone are relatively complex in the study area, the depth of which has no obvious correlation with hydrogeological conditions and changes significantly from west to east.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉How and when sediment moves from terrestrial sources to deep-water sinks is a significant area of research. We have used an array of seismic, borehole, and gravity core data sets to explore the timing and magnitude of sediment-routing to Pearl River slope over the last 478 k.y. As predicted by existing sequence stratigraphic models, most sediment dispersal to deep water is shown to have occurred during glacial sea-level falls; however, clastic detritus was still being transported into deep water during interglacial sea-level rises. We suggest that sediment routing to deep water during interglacial sea-level rise is caused by summer monsoon strengthening and resultant warmer and wetter climates, both of which have enhanced effective precipitation and sediment supply. Although some models for the delivery of sediment to deep-water basins stress the importance of proximity of canyon heads and coeval shorelines, we observed that sediment routing to deep water could occur regardless of the distance between channel head and coeval shorelines. In the present case, the success of delivery is related to the combined effects of (1) the short duration and high amplitude of sea-level oscillations during the past 478 k.y. and (2) the enhanced sediment supply caused by more humid climates and greater temperature difference between glacial and interglacial period. This hypothesis is supported by (1) observations that outer Pearl River deltas prograded as an apron over preexisting shelf edges for 10–15 km (6–9 mi) and (2) the occurrence of slope channels extending back to prodelta reaches of Pearl River shelf-edge deltas.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉The discovery of carbonate gas fields in the Middle Triassic Leikoupo Formation of the Sichuan Basin has a complex history. In recent years, a series of structural fields have been discovered in the western Sichuan Basin. Their discovery confirms the immense exploration potential of the Leikoupo Formation. In this study, we analyze the characteristics of Leikoupo Formation exploration plays using exploration wells and test data, aiming to provide a reference for further discoveries. The Leikoupo Formation represents the uppermost unit in the Sichuan marine carbonate platform succession. During its deposition, the whole basin was characterized by a restricted and evaporitic platform. Two classes of reservoirs developed. One is pore–fracture reservoirs, in marginal platform and intraplatform shoals, and another is fracture–vug reservoirs in the karstic weathering crust of the formation-capping unconformity. Three hydrocarbon accumulation models were established for the Leikoupo Formation based on the spatial and temporal relationship among the source, reservoir, and cap rocks. Two types of exploration plays are present in the Leikoupo Formation, that is, shoal (including intraplatform shoal and marginal platform shoal) dolomite plays and karstic dolomite weathering crust plays (including intraplatform shoal karst and marginal platform shoal karst). The western Sichuan depression in the karstic slope belt presents immense exploration potential because of a proximal hydrocarbon supply, charging via an extensive fracture network, shoals and karstic reservoir, a good seal rock of terrestrial mudstone, and potential composite hydrocarbon accumulations in stratigraphic traps, making it a promising area for future exploration.〈/span〉

Description: 〈span〉〈div〉ABSTRACT〈/div〉Carbonaceous debris (CD) within uranium-bearing strata has been studied in the Daying uranium deposit of the northern Ordos Basin, northern China. The influence of radiogenic heat from uranium on organic matter maturation was investigated through a series of tests including measurements of vitrinite reflectance (〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉), fission-track (FT) analysis in quartz grains, and the calculation of the radiogenic heat production rate of the samples. The results show that 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 in uranium-bearing strata generally increases as the burial depth increases, indicating that CD experienced normal burial coalification. However, 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 values of the samples rich in uranium are 0.062% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 higher than those without uranium mineralization. Vitrinite reflectance bears a positive relationship with uranium content, and an inverse relationship with distance to the closest sandstone rich in uranium, indicating that uranium enrichment enhances organic matter maturation. The production of uranium decay makes FT observable in quartz grains, and the intensity of decay increases with proximity to the uranium ore body. The calculated radioactive heat production rate from the uranium ore body is 6.857 × 10〈sup〉−5〈/sup〉 W/m〈sup〉3〈/sup〉. During the long-term stable decay, as the uranium ore body theoretically results in an abnormal increase in temperature of 52°C without consideration of the loss of heat conduction, heat convection, and thermal radiation, this would yield a theoretical 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉 increase of 0.209% 〈span〉R〈/span〉〈sub〉〈span〉o〈/span〉〈/sub〉, reasonably greater than the observed. Therefore, the long-term stable radiogenic heat produced by uranium ore body can slightly enhance organic matter maturation, which is instructive in uranium prospecting.〈/span〉

Description: An extensive seismic database covering an area of 100,000 km 2 (38,610 mi 2 ) and 16 wells are integrated to define a sequence-stratigraphic framework for the Lower Cretaceous succession in the southwestern Barents Sea. Seven sequences (S0–S6) are defined, and the geometry, trajectory, and lateral variability of decompacted seismic clinoforms are described to elucidate the depositional history of the basin and to better understand coarse-grained sediment transport from the shelf to basin. Three different clinoform scales are recognized: (1) clinoform sets with 35–60 m (115–197 ft) height, interpreted as deltaic or shoreline clinoforms; (2) clinoform sets with 60–110 m (197–361 ft) height, interpreted as sediments prograding on a continental shelf; and (3) clinoforms with greater than 150 m (〉492 ft) height, which represent shelf-margin clinoforms. Furthermore, clinoforms are grouped into two main progradation directions: (1) clinoforms prograded to the southeast in sequences 2–3, in the Fingerdjupet Subbasin and the western Bjarmeland platform, indicating a source of sediments located in the west-northwestern Barents Sea, and (2) clinoforms prograded to the southwest in sequences 1–6, in the eastern part of the Bjarmeland platform, Nordkapp Basin, and Finnmark platform, indicating a second source of sediments located in the east-northeast. Additionally, in the Hammerfest Basin, clinoforms prograded to the southeast off the Loppa high in sequences 5–6. Low-relief (35–60 m [115–197 ft]), high-gradient, and oblique clinoforms are observed within sequence 2 in the western Bjarmeland platform. The high-gradient foresets are interpreted as potential coarse-grained deposits or as a result of clinoforms prograding to progressive deeper waters, resulting in steeper foresets. Clinoforms located in the eastern part of the study area are interpreted as sourced by a mud-rich system, reflecting a long transportation distance. However, thin, heterolithic patterns in the gamma-ray log possibly reflect thin, sheetlike sands. The height of the clinoforms seems to be a factor controlling the sediment bypass to deep water in the study area. When the height is more than 200 m (656 ft), bottomset deposits are common. This study contributes to a better understanding of the paleogeography and the evolution of the frontier southwestern Barents Sea during the Early Cretaceous and to comprehending the variables increasing the bypass of coarse-grained sediments to deep-water settings.

Description: Variations in environmental and biological origins contributing to the heterogeneity of lacustrine source rocks can be illustrated in their diverse genetic facies. The Zhu 1 depression, eastern Pearl River Mouth Basin, South China Sea, is characterized by two thick, Paleogene, organic-rich synrift units, the Wenchang and Enping Formations. The integration of bulk geochemical and biomarker data with tectonic and sedimentary information provides the basis for a comprehensive assessment of the environmental and ecological changes through geologic time and their impact on the heterogeneity of these lacustrine source rocks. Both the Wenchang and Enping Formations display wide variations in total organic carbon content and hydrogen index values as well as biomarker composition, suggesting lateral and chronological changes in organic facies. Using gas chromatography–mass spectrometry and hierarchical cluster analysis, five genetic facies were identified within these two source horizons. These facies represent different organic-matter inputs and sedimentary and early diagenetic environments based on their distinctly different assemblages of 11 source-dependent biomarker ratios. Four facies were distinguished in the Wenchang Formation, and two facies were distinguished in the Enping Formation, with one being common to both formations. During the middle Eocene, the Wenchang Formation was deposited in a series of small, deep lakes of laterally variable salinity, acidity, and biofacies. During the deposition of the Enping Formation in the late Eocene and early Oligocene, the previous lakes merged into fewer lakes with shallower depth and larger areal coverage, with the biota becoming more uniform across the whole depression. The coevolution of these lacustrine settings and their biota is closely associated with the development of the Zhu 1 depression, within which multiple separate sags produced by rapid mid-Eocene subsidence finally merged into a single depositional unit during slow subsidence in the late Eocene and early Oligocene. Accordingly, an integrated model was established to provide an overview of the contrasting origins of lacustrine source rocks during the two Paleogene epochs. This model may have important implications for source-rock prediction in the undrilled parts of the basins or for reference to source-rock heterogeneity in other rift basins.

Description: Three-dimensional (3-D) printing provides an opportunity to build lab-testable models of reservoir rocks from tomographic data. This study combines tomography and 3-D printing to reproduce a sample of the Fontainebleau sandstone at different magnifications to test how this workflow can help characterization of transport properties at multiple scales. For this sandstone, literature analysis has given a porosity of 11%, permeability of 455 md, mean pore throat radius of 15 μm, and a mean grain size of 250 μm. Digital rock analysis of tomographic data from the same sample yielded a porosity of 13%, a permeability of 251 md, and a mean pore throat radius of 15.2 μm. The 3-D printer available for this study was not able to reproduce the sample’s pore system at its original scale. Instead, models were 3-D printed at 5-fold, 10-fold, and 15-fold magnifications. Mercury porosimetry performed on these 3-D models revealed differences in porosity (28%–37%) compared to the literature (11%) and to digital calculations (12.7%). Mercury may have intruded the smallest matrix pores of the printing powder and led to a greater than 50% increase in measured porosity. However, the 3-D printed models’ pore throat size distribution (15 μm) and permeability (350–443 md) match both literature data and digital rock analysis. The powder-based 3-D printing method was only able to replicate parts of the pore system (permeability and pore throats) but not the pore bodies. Other 3-D printing methods, such as resin-based stereolithography and photopolymerization, may have the potential to reproduce reservoir rock porosity more accurately.

Description: The Upper Ordovician Red River Formation has been a prolific producer of oil and gas in the Williston Basin, where it has cumulatively produced more than 750 million bbl of oil equivalent over the past half century. Previous studies have recognized petroleum source beds, referred to as kukersites, in the Red River Formation but have not determined their complete extent or hydrocarbon generation significance. Examination and analysis of 28 cores and greater than 300 wireline logs have revealed 10 distinct kukersites in the Red River D zone that can be correlated individually for tens to hundreds of miles (tens to hundreds of kilometers) across the western quarter of North Dakota. Although each Red River kukersite is typically thin (1–2 ft [0.3–0.7 m] thick), they combine to reach net thicknesses of greater than 12 ft (3.7 m) with average present day total organic carbon (TOC) values of typically 3–6 wt. %. Hydrogen index (HI) values from kukersite samples range from primarily greater than 800 mg hydrocarbons (HC)/g TOC within the northern flank of the basin to systematically decreasing to less than 100 mg HC/g TOC within the basin center. This systematic decrease in HI is interpreted to be a function of increased thermal maturity, where hydrocarbon generation has depleted kukersite organic richness. Preliminary calculations of hydrocarbon volumes generated from Red River kukersites, based on a previously developed method that calculates the volumetric decrease in original to present-day kerogen content, total approximately 66 billion bbl (1.05 x 10 10 m 3 ) of oil equivalent. This approximate generation total is more than enough to account for cumulative Red River production and supports the idea that the Red River is a self-sourced petroleum system with potentially significant remaining exploration potential.

Description: Event-based risk management (EBRM) is an improved way of describing subsurface uncertainties and their possible business impacts in a manner that facilitates specific actions to improve business performance. In EBRM, uncertainties are viewed as potential causes of risk events that could in turn lead to consequences that affect the attainment of objectives. This "causes–event–consequences" syntax aids the design of prevention measures to inhibit the causes turning into the event and mitigation measures to reduce the potential consequences should the risk event occur, and it also facilitates construction of a risk taxonomy scheme based on risk consequences, events, and causes. Using a data set of 1456 subsurface risks, each risk was described in this manner and placed in the taxonomy, and the proportion of risks in each taxonomic group was analyzed. This revealed clear trends in the relative frequency of risk groups with type of field: for example, risks related to hydrocarbon-in-place volumes are more frequently identified in deep-water oil fields and gas fields feeding liquefied natural gas plants, situations in which resource volumes are critical to support the large project capital costs. Trends were also evident with field maturity: for example, risks related to hydrocarbon-in-place volumes are more frequently identified before the field sanction decision than afterward. Several benefits have yielded from EBRM: the risk description syntax encourages the creation of meaningful risk-management actions, the taxonomy and associated risk identification frequencies assist the identification of relevant risks so that key risk areas are not overlooked and also help to anticipate future risks, and the focus on risks (rather than uncertainties) helps to focus resources (data acquisition, technical studies) onto those aspects of the subsurface that are likely to impact business outcomes.

Description: A comprehensive study of seep carbonates at the top of the organic-rich Maastrichtian to Danian Moreno Formation in the Panoche Hills (California) reveals the mechanisms of generation, expulsion, and migration of biogenic methane that fed the seeps. Two selected outcrops show that seep carbonates developed at the tip of sand dykes intrude up into the Moreno Formation from deeper sandbodies. Precipitation of methane-derived cements occurred in a succession of up to 10 repeated elementary sequences, each starting with a corrosion surface followed by dendritic carbonates, botryoidal aragonite, aragonite fans, and finally laminated micrite. Each element of the sequence reflects three stages. First, a sudden methane pulse extended up into the oxic zone of the sediments, leading to aerobic oxidation of methane and carbonate dissolution. Second, after consumption of the oxygen, anaerobic oxidation of methane coupled with sulfate reduction triggered carbonate precipitation. Third, progressive diminishment of the methane seepage led to the deepening of the reaction front in the sediment and the lowering of precipitation rates. Carbonate isotopes, with 13 C as low as –51 Peedee belemnite, indicate a biogenic origin for the methane, whereas a one-dimensional basin model suggests that the Moreno Formation was in optimal thermal conditions for bacterial methane generation at the time of seep carbonate precipitation. Methane pulses are interpreted to reflect drainage by successive episodes of sand injection into the gas-generating shale of the Moreno Formation. The seep carbonates of the Panoche Hills can thus be viewed as a record of methane production from a biogenic source rock by multiphase hydraulic fracturing.

Description: Production decline prediction is important to understand the performance and life span of oil and gas wells. The most common prediction method is decline curve fitting based on available production rate data. Such data are fit with different equations that extrapolate to future time. However, the parameters are commonly poorly constrained, especially when the production rate data are limited. In this study, we establish a novel gas isotope interpretation tool to better predict the resource quantity and life span of producing gas wells. This tool is based on the evolution of methane carbon isotope ratios ( 13 C1) caused by different gas-releasing processes during production. It requires (1) real-time methane carbon isotope ratio data, (2) continuous gas production rate data for a certain period of time, and (3) basic geological and engineering conditions. We successfully applied the production decline prediction tool to a producing shale gas well in the Barnett Shale. We obtained real-time 13 C1 data for approximately 1 yr using our proprietary, field-deployable gas chromatography–infrared isotope ratio analyzer. The prediction in this well from the isotope method showed a total reserve of up to 7.34–7.75 BCF (2.07–2.19 x 10 8 m 3 ), which was used to constrain the production decline trend of the study well. The measured production rate data were first fit using the Arps equation, which then joined to an exponential decline curve smoothly at approximately 10 yr, such that the cumulative production calculation from integration of the product rate curve equaled to the total reserve predicted by the isotope method. The novel production decline prediction method thus provided important constraint on the future well production and expected ultimate recoverable reserves.

Description: Opening-mode veins in cores drilled from the mudrocks overlying and underlying the major Silurian salt décollement in the Appalachian plateau (Tioga and Lawrence Counties, Pennsylvania) have mineralogic and isotopic compositions generally matching those of their host mudrocks, suggesting opening and filling amid little cross-stratal fluid motion. Calcite and most trace minerals probably entered the veins via dissolution–reprecipitation from nearby host rock. Consistent with this interpretation are the observations that (1) trace minerals within the veins, including quartz, pyrite, and dolomite, are invariably also present within the layers hosting the veins, with vein cement minerals generally reflecting the abundance and solubility of minerals in the host rock, and (2) carbon and oxygen isotopic compositions of vein-filling calcite are similar to those of calcite within the host rock, with vein-filling 18 O slightly depleted and 13 C slightly enriched. Modeling the fluid isotopic evolution, assuming vein opening and filling amid immobile connate formation water, accounts for these minor but systematic differences, which are attributable to increasing temperature and hydrocarbon maturation. An exception to the above trend is barite, which, despite its low solubility, is systematically enriched in veins with respect to the host rock. It is unclear whether barite precipitation resulted from the influx of external fluids—perhaps deriving from Silurian salt—or from barium mobilized at depth from local clays or organic material.

Description: Water salinity in the San Joaquin Valley is a function of depth, location, and stratigraphy. This paper presents a reconnaissance study of water salinity within Kern County, California, using chemical analyses from oil field produced water and water wells as well as geophysical logs. Log analysis indicates that the base of underground sources of drinking water (USDWs) (〈10,000 mg/L) slopes from northwest to southeast. Lab analyses show that USDWs extend to depths as great as 1900 m (6233.5 ft) southeast of Bakersfield. This area receives the greatest amount of fresh water recharge from streams flowing westward from the Sierras. The marine Olcese Sand is more saline than the overlying and underlying aquifers and separates the aquifers into an upper and lower USDW. Log analysis also indicates a zone of higher salinity separating zones of lower salinity in this area. Salinities in the west are higher, and depths to base USDW are variable. Although waters in many sands in the western valley are more saline than 3000 ppm total dissolved solids (TDS), numerous wells contain waters between 3000 and 10,000 ppm at depths of less than 600 m (1968.5 ft), particularly in the nonmarine Tulare Formation. At North Belridge field, a salinity reversal is apparent below 2100 m (6890 ft). Waters above this depth are approximately 40,000 mg/L TDS, whereas water salinities below 2200 m (7218 ft) range from 10,000 to 32,000 mg/L. Extremely high salinities are found in several wells less than 30 m (98 ft) deep, primarily in the northwestern area. These may be perched aquifers or lie adjacent to unmapped agricultural drainage sumps and do not reflect salinities in the regional aquifer.

Description: To assess prospective modeling trends for oolitic tidal sand shoals and explore potential patterns of reservoir heterogeneity, this study examines, quantifies, and models the cycle-scale architecture of the Holocene mobile oolitic tidal sand shoal complex at Schooner Cays, Bahamas. Process-based stratigraphic trends are captured in quantitative, geocellular models of the shoal from analyses of satellite imagery; two-dimensional, high-frequency seismic (chirp) data; and sediment cores. Data show that longitudinal tidal sand ridges extend up to 8 km (5 mi) along depositional dip, gradually transforming bankward into channel-bound, compound barforms consisting of linear, parabolic, and shoulder bars. These bars terminate into a laterally extensive (10 km [6 mi]), strike-elongate sand sheet. Each bar type includes distinct internal architecture, grain size, and sorting related to feedbacks among hydrodynamics, geomorphology, and sedimentology. Building on these data and concepts from the Holocene accumulations, this study demonstrates a methodology for quantifying and validating probabilistic stratigraphic trends prior to their inclusion in stochastic-based facies modeling algorithms. Inclusion of statistically robust facies probability volumes during truncated Gaussian simulation generated ordered and geologically accurate facies distributions relative to bar-crest centerlines, water depth, and geomorphic position. Petrophysical models that incorporate facies-specific porosity, permeability, and water saturation functions display pronounced cycle-scale heterogeneity that could provide insights into variable production rates and poor sweep efficiency commonly encountered during development of analogous oolitic reservoirs.

Description: Organic-rich and carbonate-rich Eagle Ford Shale is a self-sourced oil and gas reservoir with little alteration of gas chemistry as might be affected by petroleum expulsion and migration. As such it provides an ideal natural laboratory to quantify the compositional variation of gases generated from oil-prone type II kerogen during thermal maturation. The chemical composition of the gas released from rock crushing was conducted and integrated with Rock-Eval pyrolysis to define the empirical relationship between gas compositional parameters and thermal maturity in this study. From 10 wells in the Eagle Ford Shale in south Texas, we collected 74 core samples having a range of thermal maturity (the measured maximum temperature [ T max ] values of hydrocarbons generated in Rock-Eval pyrolysis range from 427°C to 494°C [800°F to 921°F], and the calculated equivalent vitrinite reflectance ( R oe ) values range from 0.51% to 1.73% based on T max values). Total organic carbon content ranges from 0.3% to 8.53%, with an average of 3.12% (standard deviation of 1.77%). Burial depth is from 2989.6 to 13,827.3 ft (911.2 to 4214.6 m). Our results showed that gas composition in the Eagle Ford Shale is mainly controlled by thermal maturity, and three stages of gas generation are identified based on the C 1 and C 2 concentrations of the gases released by rock crushing from Eagle Ford Shale core samples. The three stages of gas generation correspond to the following processes of organic matter conversion: (1) kerogen and bitumen thermal cracking to crude oil, (2) bitumen and heavy crude oil thermal cracking to light oil, and (3) light oil cracking to gas. Methane-rich gas and an abundance of branched butane and pentane are generated in light oil cracking to gas, resulting in high C 1 /C 2 , C 1 /(C 2 + C 3 ), i-C 4 /n-C 4 , and i-C 5 /n-C 5 ratios. Increased cracking of normal alkanes such as n-butane and n-pentane occurs in the light oil cracking to gas. Empirical equations between gas compositional parameters and thermal maturity ( T max or R oe ) are obtained for oil-prone type II. The C 1 , C 2 , C 1 /C 2 , C 1 /C 2 + C 3 , and i - C 4 /n - C 4 ratios are the five best parameters for determining thermal maturity with an exponentially derived R 2 value of 0.74. The composition of gas produced from the Eagle Ford Shale following hydraulic fracturing is used to validate the empirical equations. Calculated thermal regime for the oil production based on the produced gas is located at the peak of oil generation and the beginning of light oil cracking to gas, corresponding to T max from 454°C to 464°C (849°F to 867°F) or at an R oe ranging from 1.01% to 1.19%. Empirical equations provide a basis for interpretation of mud gas logging data and produced gas composition.

Description: In this paper, a new approach to calculating and restoring the effects of physical compaction in subsalt units is presented. The loading of subsalt units and associated physical compaction is controlled by a combination of suprasalt sedimentation and salt movements. Here it is proposed that the change in load affecting the subsalt units is equivalent to the thickness between paleosurfaces of the basin (regional levels) reconstructed for successive stratigraphic horizons. This is in contrast to suprasalt units, where the changes in load are equivalent to the thickness of the stratigraphic unit. The new approach is integrated into a complete workflow for sequential restoration in a salt basin, which involves (1) removing the effects of physical compaction in suprasalt units, (2) reconstructing the paleosurfaces of the basin (regional level), (3) restoring faults, (4) unfolding to the reconstructed regional level to restore the effects of salt movement in the suprasalt units, (5) reconstructing the change in load affecting subsalt units and restoring the associated physical compaction, and (6) restoring any isostasy and postrift thermal subsidence. Results obtained using this workflow are compared with other methodologies to assess the differences in subsalt sediment thickness and structural configurations. These results suggest that the workflow proposed in this paper will improve the accuracy of sequential restoration of subsalt hydrocarbon plays, allowing their structural configurations through time to be more accurately quantified, and will ultimately reduce the risks in developing subsalt resources.

Description: The Upper Jurassic Norphlet Formation is an eolian sandstone and important hydrocarbon reservoir that overlies the Louann Salt in the Gulf of Mexico (GOM). Because the sand was concentrated into dunes formed by Late Jurassic winds, determining the source areas and paleotransport direction of the sand can improve predictions of the distribution of the dune facies around the GOM. Paleo–wind-blown sediment transport into the proto-GOM was controlled by wind direction and magnitude and the extant topography of the basin and adjacent uplands. Analysis of the Norphlet Formation in the eastern GOM shows that wadis and alluvial fans controlled by the location of highs were the primary route for introducing sediment of varied provenance into the eolian erg. Eolian transport directions interpreted from dip-log analyses are south directed in southern Alabama and west to northwest directed in western Florida. Interpretations of regional, two-dimensional, prestack-depth-migrated seismic data show that erosional incision of the Middle Ground arch occurred prior to and during the time of Norphlet deposition; this as well as preexisting lows in the basement topography may have facilitated basinward sand transport of sediment that fed the Norphlet Formation erg preserved in the deep-water subsurface eastern GOM.

Description: A total of 225 rock samples and 37 oil samples from the Beibuwan Basin, South China Sea, were analyzed with geochemical and organic petrological techniques to evaluate the Eocene lacustrine source rocks and investigate controls on their properties and the distribution of different oil families in the basin. Two types of organic facies are recognized in the Liushagang Formation (LS). The first organic facies is algal-dominated and mainly occurs in the organic-rich, laminated mudstones of the middle member of the LS (LS-2) that were deposited in an anoxic, stratified, medium–deep lake environment. It is geochemically identified by its high abundance of C 30 4-methylsteranes and heavy 13 C values in the range of –22.4 to –27.5. The organic matter in this organic facies comprises type I and II 1 kerogens, with its macerals dominated by fluorescent amorphous organic matter (AOM) and exinites, indicating a highly oil-prone character. The second organic facies is of terrestrial algal origin and is mainly identified in the nonlaminated mudstones of the upper (LS-1) and lower (LS-3) members of the LS that were deposited in shallow, dysoxic, weakly stratified, freshwater environments. Source rocks of the second organic facies mainly contain type II 1 –II 2 kerogens with mixed macerals of AOM, internites, and vitrinites. It is geochemically differentiated from the algal-dominated organic facies by its relatively low abundance of C 30 4-methylsteranes and lighter 13 C values in the range of –27.20 to –28.67. Three oil groups are identified by their biomarkers and stable carbon isotopes. The first two groups (A and B) are probably end-members of two major oil families (A and B) that correspond to the algal-dominated organic facies and algal–terrestrial organic facies, respectively. Most of the discovered oils belong to group A oils that are characterized by a high abundance of C 30 4-methylsteranes and heavy 13 C values and show a good correlation with the algal-dominated organic facies in LS-2. Group B oils are found only within the LS-1 and LS-3 reservoirs, and they are recognized by their relatively low content of C 30 4-methylsteranes and lighter 13 C values, showing a close relation to the algal–terrestrial source facies within the LS-1 and LS-3 members, respectively. Group C oils display intermediate biomarker features and stable carbon isotope values and are interpreted to be a mixture of group A and B oils. The oil–source correlation reveals a strong control of organic facies on the geographic distribution of oil groups or oil fields in the basin.

Description: Two-dimensional seismic refraction tomography was used to map the bedrock topography beneath Hallsands beach in southwest Devon, United Kingdom. Seismic refraction data were acquired from 11 spreads, 4 parallel to the beach and 7 normal to the beach, with either 12 or 24 geophones at 5-m (16-ft) spacing. Eight sediment cores were used to calibrate the velocity model. The bedrock consists of metasedimentary rocks that have a seismic velocity of 2100–2500 m/s (6900–8200 ft/s) and is overlain by variable amounts of gravel, peat, and muddy peat. Wood peat and peaty mud are differentiated within the peat as 700-m/s (2300-ft/s) velocity for wood peat and 1200-m/s (4000-ft/s) velocity for peaty mud. These refraction data were collected and processed in two dimensions, then imported into Petrel, a three-dimensional (3-D) geological modeling software package. The 3-D geologic model was built using the velocity attribute of the seismic refraction data. These selected data points were used to create 3-D horizons, surfaces, and contacts constraining the target bedrock surface from the overlying unconsolidated deposits. The bedrock surface beneath Hallsands beach is marked by two paleochannels. One paleochannel occurs in the north end of the beach beneath the axis of the modern valley. A second paleochannel occurs in the southern section of Hallsands beach centered along the axis of a tributary valley. Bedrock occurs at a depth of approximately –10 m (–33 ft) in the southern and northern sections of the main valley. Bedrock occurs at a depth of approximately –2 m (–6 ft) along the valley wall at the southern end of the beach east of the parking lot. Shore-perpendicular refraction lines differentiate layers within the peat, whereas shore-parallel lines delineate wood-peat, peaty-mud, and bedrock topography.

Description: Drilling for oil/gas and trawling on a continental shelf can cause damage to hard-bottom communities. Moving these activities offshore poses a threat to offshore communities. Habitat complexity is correlated with species diversity. The relationship of bottom relief to benthic species richness is not well understood in deeper communities. Relief may act as a proxy for species richness and disturbance risk. Geographic patterns in relief and richness are also not well understood. We gathered information on bottom relief and species richness of the sessile epibenthic community using a remotely operated vehicle. We surveyed hard bottom on the flanks of 13 banks in the north–central Gulf of Mexico, greater than 27-m (89-ft) depth, on the shelf and at the shelf edge. We found a positive asymptotic relationship between mean relief and species richness at the transect level. Secondary analyses at the drop site level revealed a similar relationship; variance was higher. The relationship was positively linear at the bank level. Analyses using standard deviation of relief yielded even stronger positive results. There was no significant relationship between species richness and latitude or longitude over the study area (215 km [133 mi]). When species richness was plotted in three dimensions, however, peaks in richness emerged in the southeastern study area and the western region, with a trough between them, coinciding with bottom relief. Species richness is positively correlated with bottom relief on banks in the northern Gulf of Mexico. Relief and species richness may be predicted at many spatial scales, up to hundreds of kilometers.

Description: Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at T max (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

Description: The deep high-temperature, high-pressure Lower Cretaceous Bashijiqike sandstone (buried to depths as great as 6.5–7.1 km [21,325–23,293 ft]) is an important natural gas reservoir in Keshen gas field, Kuqa depression of the Tarim basin. Reservoir quality is a critical risk factor in the development of these ultradeep reservoirs. Integrated approaches incorporating routine core analyses and mineralogical, petrographic, and geochemical analyses have been used to investigate the diagenetic history of these rocks and their effect on reservoir quality with the aim to unravel the mechanisms for maintaining anomalously high porosities in sandstones that are buried to such a great depth. These sandstones are dominantly fine- to medium-grained, moderately to well-sorted lithic arkoses and feldspathic litharenite. Most primary pores have been lost by mechanical compaction or carbonate cementation, and the reduction of porosity by mechanical compaction was more significant than that by cementation. Dissolution of framework grains contributed to the enhancement of reservoir quality. Eogenetic diagenetic alterations mainly include mechanical compaction, precipitation of calcite cements, and grain-coating clays, and mesogenetic diagenesis is characterized by dissolution of framework grain by organic acids and subsequent precipitation of clay minerals and quartz. Infiltration of meteoric water related to teleodiagenesis would result in dissolution of the framework grains. The meteoric leaching events during teleodiagenesis are of great importance for the Bashijiqike sandstones. Grain-coating clay minerals (mixed-layer illite/smectite clays) help to preserve porosity at depth by retarding quartz cementation and pressure solution. The unique burial regime as early-stage shallow burial with late-stage rapid deep burial contributes to porosity preservation in eodiagenesis. Fluid overpressure caused by intense structural compression in the middle Himalayan movement retarded compaction and helped preserve porosity in the late rapid deep burial stage. Anomalously high porosities are mainly found in medium-grained, well-sorted sandstones with grain-coating clays but with low clay and carbonate cement content, of which the porosity is preserved primarily and enhanced secondarily. The lowest porosities are associated with sandstones that are tightly compacted or cemented with carbonates or rich in detrital matrix. Porosity–depth trends may vary significantly with lithofacies because of their differences in textural and compositional attributes. Five lithofacies are defined in terms of detrital composition and texture and type and degree of diagenesis. The reservoir quality prediction models of various litho-facies are constructed, and the results of this study provide insights into mechanisms for maintaining anomalously high porosity and permeability in high-temperature, high-pressure sandstone reservoirs and may help explain hydrocarbon distribution.

Description: The lower section of the lower Silurian Qusaiba Member, Qalibah Formation, is characterized by regionally developed organic-rich shales that have sourced many of the large Paleozoic petroleum systems of Saudi Arabia. In northern Saudi Arabia, these high–total organic carbon (TOC) horizons are being assessed for their unconventional shale-gas potential. The initial phase of exploration drilling, which resulted in a quadrupling of the number of penetrations in northern Saudi Arabia, had the dual purpose of (1) assessing the high-TOC horizons as an unconventional resource play and (2) acquiring the fundamental data required to understand the geologic development of the zones of interest within the lower Qusaiba. The availability of numerous new cores from across northern Saudi Arabia enabled an extensive refinement of the existing biostratigraphy and enhanced integration between graptolite and palynomorph biozonation systems. In cores from the study area, four distinct sedimentary facies are recognized, (1) pyritic siltstone, (2) black mudstone, (3) black chert, and (4) gray shale, representing distinct paleoenvironmental conditions related to the stepped latest Ordovician and early Silurian Gondwanan deglaciation. The failure of the Gondwanan ice sheet was not a simple, short-lived, consistent melting and associated flooding of a flat continental shelf. This study highlights the complex interplay of sea-floor topography, ocean currents, sediment supply, and variations in the rate of melting of the ice sheet. With the associated rising ambient temperatures there are (1) increasing clay concentrations associated with intensifying chemical weathering of the exposed land mass and (2) progressive lowering of the carbonate compensation depth as water temperatures rise, enabling the preservation of carbonate shell material.

Description: We use finite element modeling to show that upbuilding can be a significant component of salt diapir growth in tectonically stable systems when basin sediments are elastoplastic mudrocks. The ability of such sediments to deform plastically and the dependence of their strength on confining pressure enable structural thinning, which allows salt to pierce through a relatively thick roof. Once pierced, the originally continuous roof uplifts to form a megaflap. We show that the evolution to an upturned megaflap adjacent to a salt stock causes shortening of the bedding layers in the radial and vertical directions and extension in the hoop (circumferential) direction. These deformations lead to significant shear strains within the sediments; as a result, in some areas within the upturned megaflap, mudrocks have reached their maximum level of shear resistance and are failing. Thinning and shear failure of sediments are also significant near salt walls, despite the absence of out-of-plane deformation. We illustrate that cross-sectional area and bedding line lengths are not necessarily preserved. Based on our results, we re-evaluate traditional assumptions of kinematic restoration and show that established workflows may not properly restore salt systems that interact with shallow plastic sediments. Finally, we show that when wall rocks are deformable, salt diapir shapes are not necessarily a simple function of sedimentation and salt flux rates ( q fx / Å ) and that the diapir hourglass shape might result from lateral deformation of the megaflap.

Description: Provenance of Pleistocene–Holocene deepwater sediments in the Gulf of Papua (National Science Foundation Source to Sink Focus Area) has been studied to understand sediment sources and glacioeustatic influences on sedimentary routing and to better understand processes controlling sediment sources and delivery. We show how diverse processes operate in a complex deep-sea environment over time to control sediment routing and accumulation. Quantitative detrital analyses were conducted on 53 turbidite sand and 3 terrestrial samples with scanning electron microscopy and mineral liberation analysis, which yielded a broader and more insightful classification than manual point counts. We determined that (1) multiple terrestrial sediment sources along an approximately 500-km (300-mi) basin margin converged to form one continuous deep-sea system in two major basins (〉30 cal [calibrated] ka); (2) subsequent sea level fall near the last glacial maximum (LGM) (18–22 cal ka) drove repartitioning of sediment sources to create multiple distinct depocenters, presumably caused by migration and incision of individual rivers across the newly exposed coastal plain; and (3) multiple separate deep-sea channels then regained compositional similarity near the end of the LGM. In the subsequent Holocene, deepwater sand transport shut down, except for one locality where delivery continues because of a combination of narrow shelf–slope setting, oceanographic processes, and additional volcanic supply. These findings highlight the diverse processes that must be considered for the development of deepwater petroleum systems, in terms of sediment delivery, deposition, and provenance that may affect the reservoir geometry and quality.

Description: Secondary processes within reservoir sandstones during and after hydrocarbon production are poorly understood. This study looks at the effect of secondary water fill on a sandstone reservoir within a time span of 8 yr. The reservoir rocks consist of medium-grained litharenites with large clasts of shales and carbonates. They originate from a depleted gas reservoir that has been converted into an underground storage field for natural gas. Gas production resulted in a rise of the gas–water contact of approximately 30 m (98 ft). Based on their initial and final gas and water saturations, four zones can be identified. Observed diagenetic changes in all four zones include carbonate cementation, K-feldspar overgrowths, authigenic quartz overgrowths, pyrite formation, and poorly crystallized authigenic clay minerals. However, the authigenic clay mineral fraction differs significantly within the zones. Total clay mineral content and crystallinities of smectite, chlorite, kaolinite, and illite increase from the gas-bearing to the initial water zone. Additionally, expandable clay minerals and kaolinite were not identified in the gas-bearing zone. This is different in the secondary watered zones, where smectites and kaolinites are developing. The study shows that within a maximum of 8 yr from the start of water influx into the gas zone, new clay minerals are forming. The porosity and permeability reduction caused by this artificially induced process might continue and could also be of relevance within producing reservoirs, where water saturation increases during production.

Description: The northern deep-water Gulf of Mexico is one of the most active deep-water petroleum provinces in the world. This paper introduces the regional geologic setting for the northern deep-water Gulf of Mexico and briefly discusses the importance of technology in developing the area’s resources. Exploration has focused on four major geologic provinces: Basins, Subsalt, Fold Belt, and Abyssal Plain. These provinces formed from the complex interactions between Mesozoic–Cenozoic sedimentation and tectonics. Improved understanding of the geology of these provinces has largely been accomplished by improvements in seismic acquisition and processing. In addition, advances in drilling technology have permitted drilling and field development in increasingly greater water depths. The 226 oil and gas fields and discoveries in the northern deep-water Gulf of Mexico are summarized in terms of their exploration and development history, producing facility, ages of reservoirs (Upper Jurassic, upper Paleocene–lower Eocene, Oligocene, lower Miocene–upper Pleistocene), and trap type (structural, combined structural-stratigraphic, and stratigraphic). In addition, the interpreted regional distribution of Upper Jurassic and possible Lower Cretaceous source, source rocks is shown, in part based on the 26 wells that have penetrated these source rocks. The eight papers in this special issue review the geology of the Mississippi Canyon and northern Atwater Valley protraction areas. The first five papers review the subregional structural setting and the evolution of its tectonics and petroleum systems. The final three papers summarize the geologic evolution of two economically important intraslope basins—Thunder Horse and Mensa—in terms of their stratigraphy, structural evolution, and petroleum systems. These two basins contain two of the larger oil and gas fields, respectively, in the northern deep-water Gulf of Mexico.

Description: Thunder Horse and Mensa are two of the largest fields of oil or gas, respectively, in the northern deep-water Gulf of Mexico. The fields are present in adjacent intraslope minibasins, located approximately 12 mi (19 km) apart in Mississippi Canyon. Both fields illustrate important complexities of deep-water sedimentation. Analysis is based on the integration of wire-line logs, biostratigraphy, and a 378-mi 2 (979-km 2 ), three-dimensional seismic data set. Thunder Horse and Mensa reservoirs were deposited during the middle to late Miocene. Changes in paleobathymetry controlled the reservoir deposition, initially as salt withdrawal and later as turtle structures. From 125 to 24 Ma, the lithologies in both intraslope basins are interpreted as dominantly deep-water marls with interbedded shales. From 24 to 14.35 Ma, major input of deep-water siliciclastic sediments began. Sands were deposited in amalgamated sheets and amalgamated channel-fill units within the two major paleobathymetric lows; by contrast, shales were deposited across paleobathymetric highs. Between 14.35 and 13.05 Ma, the Thunder Horse turtle formed, creating a paleobathymetric high. Channelized sands were diverted around and deposited on the flanks of the structure. Meanwhile, to the north at Mensa, thick channel-fill sediments continued to be deposited. From 12.2 to 8.2 Ma, the lithologies throughout the entire area are dominantly overbank shales with thin channel-fill sands, suggesting that large volumes of sand bypassed the study area farther downslope to the south. Finally, at 9.0 Ma, Mensa's sheet-sand reservoir represents a different setting; sands were deposited near the crest of the Mensa turtle, which had subtle bathymetric expression.

Description: The Mensa and Thunder Horse intraslope minibasins in south-central Mississippi Canyon, northern deep-water Gulf of Mexico, had a linked structural evolution from the Early Cretaceous through the late Miocene. Analysis of the two minibasins illustrates the complexities of deep-water sedimentation and salt tectonics in intraslope minibasins. This study is based on the integration of a 378-mi 2 (979-km 2 ) three-dimensional seismic data set, wire-line logs, and biostratigraphic data. These two minibasins comprise several structural features that affected their geologic evolution: basement faults, autochthonous salt, three allochthonous salt systems (top Barremian, top Cretaceous, and Neogene), a growth fault and raft system, three major turtle structures with associated extensive crestal faults, and strike-slip faults. Remnant allochthonous salt pillows are present above the 125 Ma horizon (approximate top Barremian system) and on the 66 Ma horizon (top Cretaceous system) throughout the Mensa minibasin, whereas the top Cretaceous allochthonous salt system is identified regionally by a salt weld in the Thunder Horse area. These allochthonous salt systems formed weld surfaces beneath the Mensa and Thunder Horse turtle structures. Structural features and associated minibasins evolved during several discrete intervals. From the Early Cretaceous through the latest Oligocene (125 to 24 Ma), an extensive allochthonous salt canopy was present within the Mensa and Thunder Horse minibasins. During this interval, sediments loaded the salt, forming thin wedge- and sheet-form deposits in the Mensa area and a thick, northwest-trending trough in the Thunder Horse area. A secondary allochthonous salt system extruded at the Top Cretaceous level, as seen by remnant salt bodies. Salt withdrawal from these allochthonous salt systems provided accommodation for bowl- and trough-shaped external stratigraphic forms to develop during the Miocene. High sedimentation rates produced salt evacuation from these allochthonous salt systems and initiated diapirism that formed the Neogene allochthonous salt level. The prominent turtle structures in the two minibasins, critical to the formation of traps to the two major fields, developed at slightly different times: Thunder Horse at 14.35 and Mensa at 11.4 Ma.

Description: The 86 fields and discoveries in the central Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and Lloyd Ridge protraction areas are summarized with production characteristics and representative seismic profiles and wire-line logs. Three trap styles are recognized: four-way closure, three-way closure, and stratigraphic. The reservoirs in nearly all of the fields are Neogene deep-water sandstones; four are in Upper Jurassic eolian sandstones. Development facilities include a variety of floating platforms and production units and subsea tiebacks.

Description: The petroleum systems of two adjacent Miocene intraslope minibasins in the northern deep-water Gulf of Mexico are modeled to investigate why one of them produces primarily gas but the other produces oil. Specifically, the Mensa field produces gas from a faulted four-way closure that overlies a turtle structure, whereas the adjacent Thunder Horse field produces from a turtle structure with four-way structural closure. To resolve this issue, a three-dimensional petroleum-system model was constructed, whose results indicate that the Lower Cretaceous source interval, comprising type II kerogen, matured significantly earlier in the Mensa basin; the oil window was reached between 11.4 and 9.0 Ma, and the thermogenic gas window was reached between 6.2 and 0.0 Ma. By contrast, within the Thunder Horse basin, the source interval reached the oil window by 10.75 to 9.4 Ma and largely remains in the oil window. The Thunder Horse trap had formed by 13.05 Ma, which was before the end of the oil window. The Mensa trap (9.0–8.2 Ma) was not in place when the source rock passed though the oil window. The primary control on the timing of maturation and charge is related to the original thickness of allochthonous salt that created the accommodation for the thick Miocene deep-water sediments. Originally, the Mensa minibasin contained thicker Cretaceous allochthonous salt than the Thunder Horse minibasin. Consequently, as the salt was loaded with sediment and completely evacuated, the turtle structure (trap) formed earlier in Thunder Horse field than in Mensa. By contrast, the source rocks matured earlier in Mensa, prior to the deposition of reservoir sands and the formation of the trap. The results indicate that turtle structures with similar appearances can have subtle differences in the timing of their petroleum systems, which ultimately control whether the feature is charged and with what fluid. These features must be modeled carefully in evaluating their exploration potential.

Description: The structural framework and evolution from the Middle Jurassic to the present of the Mississippi Canyon, Atwater Valley, western DeSoto Canyon, and western Lloyd Ridge protraction areas consist of a complex history influenced by basement fabric, multiple stages of salt movement, and gravitational gliding. A detailed tectono-stratigraphic interpretation of the study area indicates that three main stages of salt movement controlled sediment dispersal patterns and the formation and evolution of intraslope minibasins. These three stages of salt movement occurred during the Cretaceous, the Paleogene, and the Neogene. Basement structures were the primary control on initial salt kinematics, affecting gravity-driven slope deformation and resulting in a wide variety of structural styles. Basement (acoustic basement) structures (horsts, grabens, and half grabens) formed prior to the deposition of the Middle Jurassic autochthonous Louann Salt. These features are interpreted to have controlled the original thickness of the autochthonous salt layer and subsequent salt-withdrawal patterns. Mesozoic structures, such as extensional-compressional gliding systems and expulsion rollovers, formed above the autochthonous salt. Three levels of allochthonous salt systems are identified: (1) approximate top Barremian, (2) top Cretaceous, and (3) intra-Neogene (between 10 and 4 Ma). Early emplacement of two allochthonous salt layers is present in the northeastern part of the study area, whereas the Neogene allochthonous salt system extends throughout the Mississippi Canyon, western DeSoto Canyon, and northern Atwater Valley protraction areas. Salt from the autochthonous and two deep allochthonous salt layers was expelled vertically and basinward during the Neogene, feeding the younger allochthonous salt systems. The autochthonous and deep allochthonous salt layers were detachments for many of the large Neogene extensional (growth faults and turtles) and contractional (anticlines and thrust faults) structures, whereas the Neogene allochthonous salt system accommodated suprasalt minibasins associated with counterregional and roho salt systems. These three allochthonous salt layers were successively loaded by gravity-flow sediments, resulting in deep (above autochthonous or deep allochthonous salt layers) and shallow (supra-Neogene allochthonous salt) minibasin formations and local development of extensive salt welds. Northwest–southeast-oriented strike-slip structures, active during the Neogene, are present in the salt province within the study area. They are related to basinwide heterogeneities in the salt distribution and are controlled by differential basinward movement of adjacent suprasalt minibasins.

Description: Geochemical interactions between shale and hydraulic fracturing fluid may affect produced-water chemistry and rock properties. It is important to investigate the rock–water reactions to understand the impacts. Eight autoclave experiments reacting Marcellus and Eagle Ford Shale samples with synthetic brines and a friction reducer were conducted for more than 21 days. To better determine mineral dissolution and precipitation at the rock–water interface, the shale samples were ion milled to create extremely smooth surfaces that were characterized before and after the autoclave experiments using scanning electron microscopy (SEM). This method provides an unprecedented level of detail and the ability to directly compare the same mineral particles before and after the reaction experiments. Dissolution area was quantified by tracing and measuring the geometry of newly formed pores. Changes in porosity and permeability were also measured by mercury intrusion capillary pressure (MICP) tests. Aqueous chemistry and SEM observations show that dissolution of calcite, dolomite, and feldspar and pyrite oxidation are the primary mineral reactions that control the concentrations of Ca, Mg, Sr, Mn, K, Si, and SO 4 in aqueous solutions. Porosity measured by MICP also increased up to 95%, which would exert significant influence on fluid flow in the matrix along the fractures. Mineral dissolution was enhanced and precipitation was reduced in solutions with higher salinity. The addition of polyacrylamide (a friction reducer) to the reaction solutions had small and mixed effects on mineral reactions, probably by plugging small pores and restricting mineral precipitation. The results suggest that rock–water interactions during hydraulic fracturing likely improve porosity and permeability in the matrix along the fractures by mineral dissolution. The extent of the geochemical reactions is controlled by the salinity of the fluids, with higher salinity enhancing mineral dissolution.

Description: This study evaluates the proportion, length, and effective properties of thin (0.003–0.7 m [0.01–2.3 ft]) shale beds and drapes in tidally influenced channels within a compound valley fill with a focus on estimating geologically based effective rock properties. The Cretaceous Ferron Sandstone is an outcrop analog for fluvial–tidal systems with primary reservoirs being deposited as tidally influenced valley filling point bars. The study outcrops expose three valley systems in Neilson Wash of Utah. Light detection and ranging–derived digital outcrop models have been used to characterize shale length, width, thickness, and frequency of each valley fill succession. Long, uncommon, and anisotropic shales in valley 1 (V1) were deposited in a braided setting with little tidal influence. In contrast, shales in valley 2 (V2) were abundant, short, common, and equidimensional, suggesting deposition by more tidally influenced meandering rivers. Short, frequent, and equidimensional shales in valley 3 (V3) were deposited in single-thread meandering rivers with less tidal influence. A sandstone–shale model was used to estimate the effects of shales on vertical to horizontal permeability ratio ( \[{k}_{v}/{k}_{h} \] ). The unique character of each depositional unit was reflected in resultant \[{k}_{v}/{k}_{h} \] distributions. The valley fill deposits, V1, V2, and V3, had average \[{k}_{v}/{k}_{h} \] ratios of 0.11, 0.09, and 0.17, respectively. More tidally influenced reservoirs such as the studied V2 had short but frequent shales, which resulted in low \[{k}_{v}/{k}_{h} \] estimates. Estimates of \[{k}_{v}/{k}_{h} \] for valleys that predominantly contained fluvial point bar deposits with lesser tidal influence (V1 and V3) were higher. The results of this study highlight the link between shale heterogeneity, reservoir architecture, and inferred flow parameters.

Description: The Permian Khuff-C reservoir in Saudi Arabia is known for its lateral and vertical heterogeneity caused mainly by dolomitization. Detailed petrographic analysis of 600 thin sections, from six cored wells, revealed three main replacive dolomite fabrics: (1) fabric-preserving mimetic (FPM), (2) fabric-preserving nonmimetic (FPNM), and (3) fabric-destructive (FD) dolomites. Crystal sizes are mostly less than or equal to 20 μm for FPM dolomite, less than or equal to 50 μm for FPNM dolomite, and less than or equal to 100 μm for FD dolomite. The FPM dolomite decreases in abundance, and FPNM dolomite increases in abundance, with increasing grain content of the facies. The 18 O values of dolostones (although considered an obsolete term, dolostone is used here to mean rock containing ≥80% dolomite) indicate early dolomitization at low temperatures in Permian seawater or evaporated seawater, with landward facies (mudstone and wackestone) generally dolomitized by more evaporated waters and seaward grainy facies generally dolomitized by less evaporated, more normal marine seawaters. Stratigraphic variations in the dolostones’ 18 O values track with facies variations through fourth-order depositional sequences and indicate that different stratigraphic bodies of dolomite formed from seawaters with different degrees of evaporation. The 13 C values of the dolostones exhibit temporal trends inherited from the precursor limestones. Variations in the lateral and vertical abundance of dolomite and dolomite fabrics, in the propensity for each facies to be dolomitized, and in the dolomites’ oxygen isotopic values all suggest that multiple dolomitization events occurred in the Khuff-C reservoir as depositional cycles accumulated, with some dolostones overprinted by younger events. Average porosities of grain-rich dolostones are greater than those of mud-rich dolostones, indicating that depositional facies preordained porosity distribution within the dolostones. However, the more evaporated the dolomitizing fluid, the more likely dolomitization resulted in lower porosity regardless of facies.

Description: Outcrop studies of fracture development, used as analogs for subsurface fracture patterns, are critical because of the importance of fractures as fluid flow pathways and the fact that most fracture networks exist at a smaller resolution than current seismic data can resolve. Fracture networks in carbonate units are typically controlled by the mechanical properties of the unit, indicating that the mechanical stratigraphy, as well as the fracture stratigraphy, should be considered. This study presents the results of a fracture analysis in the Mississippian carbonates of the Ozark Plateau, considering both mechanical and fracture network characteristics. Mechanical characteristics of the succession were defined using a combination of rebound values and thin section petrography. Fracture characteristics included orientation and intensity, together with abutting relationships. Results indicate that fracture orientations show a distinct evolution throughout the measured succession, including the appearance of early systematic sets, followed by pervasive systematic fracture sets related to existing basement features. Fracture orientation changes do not correspond to changes in mechanical stratigraphy. Fracture intensity, however, is related to the thickness of the mechanical unit instead of the bed thickness and is greatest in less competent units. Mechanical control influences the fracture network on a smaller scale than that of regional tectonic stresses. Thus, evaluations of carbonate reservoirs must account for both the large-scale and the small-scale investigations into fracture characteristic controls. Outcrop evaluations are of critical importance to properly assess characteristics that are challenging to recover from conventional subsurface data sets such as core and seismic reflection volumes.

Description: The results of petroleum system models (PSM) critically depend on the computed evolution of the temperature field. Because PSM typically only resolve the sedimentary basin and not the entire lithosphere, it is necessary to apply a basement–heat-flow boundary condition inferred from well data, surface–heat-flow measurements, and an assumed tectonic scenario. The purpose of this paper is to assess the use of surface–heat-flow measurements to calibrate basin models. We show that a simple relationship between surface and basement heat flow only exists in thermal steady state and that transient processes such as rifting and sediment deposition will lead to a decoupling. We study this relationship in extensional sedimentary basins with a one-dimensional, lithosphere-scale finite element model. The numerical model was built to capture the large-scale dynamic evolution of the lithosphere and simultaneously solve for transient thermal processes in basin evolution, such as sedimentation, compaction-driven fluid flow, and seafloor temperature variations. Our analysis shows that several corrections need to be applied when using surface–heat-flow information for the calibration of basement heat flow in PSM. Not doing so can lead to significant errors of up to 30°C–50°C (86°F–122°F) at typical petroleum-reservoir and source-rock depths. We further show that resolving sediment-blanketing effects in basin modeling is crucial, with the thermal impact of sediment deposition being at least as important as rifting-induced basement–heat-flow variations.

Description: The Lower Mississippian upper shale member of the Bakken Formation in the Williston Basin, North Dakota, consists of organic-rich, black, siliciclastic mudstones deposited offshore on a low-gradient shelf; 12 fine-grained facies are recognized and grouped into 5 facies associations (FAs). Very fine-grained, massive to faintly laminated mudstone (FA1) records deposition in the deepest, calmest parts of the basin, whereas well-laminated mudstones (FA2a); well-laminated, clay-clast–bearing mudstones (FA2b); burrow-mottled mudstone with shells (FA3); and interlaminated siltstone and mudstone (FA4) suggest deposition in the shallower, less calm, and more proximal offshore environment. These proximal-offshore mudstones (FA2a, FA2b, FA3, and FA4) reflect (1) variation in bottom-water oxygen levels and (2) lateral changes in the input of silt and clay clasts. Ubiquitous Phycosiphon fecal strings, patches of shells, burrows, and rare agglutinated foraminifera indicate dysoxic to suboxic basinal deposition and not a persistently anoxic environment. In all FAs, storm-event laminae are sparse to ubiquitous. Repeated stacking of FAs defines up to 10 coarsening-upward parasequences mostly 0.15–0.60 m (0.49–1.97 ft) thick. Individual parasequences can be correlated for 300 km (180 mi) through the basin. The lower half of the succession (interval 1) represents a transgressive systems tract and shows high radiolarian productivity with minor silt input. The upper half of the succession (interval 2) represents the base of a highstand systems tract. In contrast to interval 1, interval 2 mudstones are characterized by high clay content, low radiolarian productivity, and intermittent colonization of the sea floor during higher-order sea-level lowstands.

Description: The Fort Worth basin in northcentral Texas is a major shale-gas producer, yet its subsidence history and relationship to the Ouachita fold-thrust belt have not been well understood. We studied the depositional patterns of the basin during the late Paleozoic by correlating well logs and constructing structure and isopach maps. We then modeled the one-dimensional (1-D) and two-dimensional subsidence history of the basin and constrained its relationship to the Ouachita orogen. Because the super-Middle Pennsylvanian strata were largely eroded in the region, adding uncertainty to the subsidence reconstruction, we used PetroMod 1-D to conduct thermal-maturation modeling to constrain the post-Middle Pennsylvanian burial and exhumation history by matching the modeled vitrinite reflectance with measured vitrinite reflectance along five depth profiles. Our results of depositional patterns show that the tectonic uplift of the Muenster uplift to the northeast of the basin influenced subsidence as early as the Middle Mississippian, and the Ouachita orogen became the primary tectonic load by the late Middle Pennsylvanian when the depocenter shifted to the east. Our results show that the basin experienced 3.7–5.2 km (12,100–17,100 ft) of burial during the Pennsylvanian, and the burial depth deepens toward the east. We attributed the causes of deep Pennsylvanian burial and its spatial variation to flexural subsidence that continued into the Late Pennsylvanian in response to the growth of the Ouachita orogen and southeastward suturing of Laurentia and Gondwana. The modeling results also suggest that the Mississippian Barnett Shale reached the gas maturation window during the Middle–Late Pennsylvanian.