Showing papers in "AAPG Bulletin in 2012"
TL;DR: In this paper, a pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix related pore and relate them to pore networks.
Abstract: Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.
1,895 citations
TL;DR: In this article, the nanometer-scaled pore systems of gas shale reservoirs were investigated from the Barnett, Marcellus, Woodford, and Haynesville gas shales in the United States and the Doig Formation of northeastern British Columbia, Canada.
Abstract: The nanometer-scaled pore systems of gas shale reservoirs were investigated from the Barnett, Marcellus, Woodford, and Haynesville gas shales in the United States and the Doig Formation of northeastern British Columbia, Canada. The purpose of this article is to provide awareness of the nature and variability in pore structures within gas shales and not to provide a representative evaluation on the previously mentioned North American reservoirs. To understand the pore system of these rocks, the total porosity, pore-size distribution, surface area, organic geochemistry, mineralogy, and image analyses by electron microscopy were performed. Total porosity from helium pycnometry ranges between 2.5 and 6.6%. Total organic carbon content ranges between 0.7 and 6.8 wt. %, and vitrinite reflectance measured between 1.45 and 2.37%. The gas shales in the United States are clay and quartz rich, with the Doig Formation samples being quartz and carbonate rich and clay poor. Higher porosity samples have higher values because of a greater abundance of mesopores compared with lower porosity samples. With decreasing total porosity, micropore volumes relatively increase whereas the sum of mesopores and macropore volumes decrease. Focused ion beam milling, field emission scanning electron microscopy, and transmission electron microscopy provide high-resolution (∼5 nm) images of pore distribution and geometries. Image analysis provides a visual appreciation of pore systems in gas shale reservoirs but is not a statistically valid method to evaluate gas shale reservoirs. Macropores and mesopores are observed as either intergranular porosity or are confined to kerogen-rich aggregates and show no preferred orientation or align parallel with the laminae of the shale. Networks of mesopores are observed to connect with the larger macropores within the kerogen-rich aggregates.
1,251 citations
TL;DR: The microstructure of gas shale samples from nine different formations has been investigated using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM) as discussed by the authors.
Abstract: The microstructure of gas shale samples from nine different formations has been investigated using a combination of focused ion beam (FIB) milling and scanning electron microscopy (SEM). Backscattered electron (BSE) images of FIB cross sectioned shale surfaces show a complex microstructure with variations observed among the formations. Energy dispersive spectroscopy of the shale cross sections indicates that clay, carbonate, quartz, pyrite, and kerogen are the most prevalent components. In the BSE images, areas of kerogen are observed interspersed with the inorganic grains. Pores are observed in both the kerogen and inorganic matrix with the size, shape, and number of pores varying among the shale samples. By using FIB milling and SEM imaging sequentially and repetitively, three-dimensional (3-D) data sets of SEM images have been generated for each of the shale samples. Three-dimensional volumes of the shales are reconstructed from these images. By setting thresholds on the gray scale, the kerogen and pore networks are segmented out and visualized in the reconstructed shale volumes. Estimates of kerogen and pore volume percentages of the reconstructed shale volumes have been made and range from 0 to 90.0% for the kerogen and 0.2 to 2.3% for pores. Estimates of pore-size distributions suggest that although pores with radii of approximately 3 nm dominate in number, they do not necessarily dominate in total volumetric contribution. Scanning electron microscopy images and 3-D reconstructions reinforce the facts that shales are quite different and that their microstructures are highly variable and complex.
590 citations
TL;DR: In this article, the bulk chemical composition of the sediments below the reach of high pore-water flow rates of meteoric water or hydrothermal convection should remain nearly constant during progressive burial because of limited porewater flow.
Abstract: Descriptions of mineralogy and textural relationships in sandstones and limestones have been used to establish a sequence of diagenetic events (epigenesis), involving mineral dissolution and precipitation, which have been interpreted to have occurred during the burial history. Published epigenetic sequences commonly imply a geochemically open system with very significant changes in the bulk chemical composition of the sediments during burial. Near-surface diagenetic reactions may be open, involving significant changes in the sediment composition and formation of secondary porosity caused by high pore-water flow rates of meteoric water or reactions with sea water near the sea floor. Calculations show that the bulk chemical composition of the sediments below the reach of high pore-water flow rates of meteoric water or hydrothermal convection should remain nearly constant during progressive burial because of limited pore-water flow. Mass transport between shales and sandstones is also limited because the pore water is, in most cases, buffered by the same minerals so that the concentration gradients are low. Recent studies show that silica released from clay-mineral reactions in mudstones has been precipitated locally as small quartz crystals and not exported to adjacent sandstones. If the geochemical constraints for mass transfer during burial diagenetic reactions are accepted, the chemical reactions involved in diagenesis can be written as balanced equations. This offers the possibility to make predictions about reservoir quality based on assumptions about primary sediment composition related to facies and provenance. Large-scale changes in the bulk composition of sandstones and mudstones during burial diagenesis have been suggested, but because such changes cannot be explained chemically and physically, no predictions can be made. Burial diagenetic processes are, in most cases, not episodic but occur as slow adjustments to increased stress and temperature, driving the sediments toward increased mechanical and thermodynamic stability. As a result, the porosity of a single lithology must decrease during progressive burial, but each lithology has a different porosity curve. This article discusses quantitative calculations and estimates that show clearly that burial diagenesis must represent geochemically nearly closed systems where mineral dissolution and precipitation must be balanced. This provides a theoretical basis for the modeling and prediction of reservoir quality.
332 citations
TL;DR: In this paper, a relatively simple kinetic model that describes porosity development within kerogen as a function of thermal maturation is proposed. But the model is limited to nonmatrix pore systems.
Abstract: Evaluations of porosity relevant to hydrocarbon storage capacity in kerogen-rich mudrocks (i.e., source rocks) have thus far been plagued with ambiguity, in large part because conventional core and petrophysical techniques were not designed for this rock type. The growing recognition of an intraparticle organic nanopore system that is related to thermal maturity is beginning to clarify this ambiguity. This mode of porosity likely evolved with the thermal transformation of labile kerogen and probably neither depends nor interacts (except perhaps chemically) with previously assumed matrix or mineral porosity that is dominated by bound water, and that may be largely irrelevant to hydrocarbon storage capacity in these rocks. To address this newly recognized and important nonmatrix kerogen pore system, that is arguably the dominant hydrocarbon storage and mobility network in these rocks, we introduce a relatively simple kinetic model that describes porosity development within kerogen as a function of thermal maturation. Kerogen porosity development is estimated within the upper Albian Mowry Shale in the Powder River Basin of Wyoming to illustrate the approach. Relevant storage capacity is considered to have evolved with thermal decomposition of organic matter during catagenesis, where we estimate that kerogen porosity does not typically exceed 3% of bulk rock volume. Modeled oil-in-place estimates are comparable to residual oil estimates from pyrolysis data (S1) at lower maturities, but exceed pyrolytic S1 yields at higher maturities. We hypothesize, therefore, that a subsurface kinetic porosity model might represent a means to account for S1 losses at surface conditions and to circumvent difficulties surrounding estimations of expulsion efficiencies that are inherent to more traditional mass balance calculations.
271 citations
TL;DR: Porosity, permeability, and total organic carbon (TOC) in a heterogeneous suite of 21 high-maturity samples (vitrinite reflectance 1.52-2.15%) from the Barnett Shale in the eastern Fort Worth Basin display few correlations with parameters of rock texture, fabric, and composition, these factors being mostly obscured by the effects of a protracted history of diagenesis.
Abstract: Porosity, permeability, and total organic carbon (TOC) in a heterogeneous suite of 21 high-maturity samples (vitrinite reflectance 1.52–2.15%) from the Barnett Shale in the eastern Fort Worth Basin display few correlations with parameters of rock texture, fabric, and composition, these factors being mostly obscured by the effects of a protracted history of diagenesis. Diagenesis in these rocks includes mechanical and chemical modifications that occurred across a wide range of burial conditions. Compaction and cementation have mostly destroyed primary intergranular porosity. The porosity (average 5 vol. % by Gas Research Institute helium porosimetry) and pore size (8 nm median pore-throat diameter) are reduced to a degree such that pores are difficult to detect even by imaging Ar ion–milled surfaces with a field-emission scanning electron microscope. The existing porosity that can be imaged is mostly secondary and is localized dominantly within organic particulate debris and solid bitumen. The grain assemblage is highly modified by replacement. A weak pattern of correlation survives between bulk rock properties and the ratio of extrabasinal to intrabasinal sources of siliciclastic debris. Higher porosity, permeability, and TOC are observed in samples representing the extreme end members of mixing between extrabasinal siliciclastic sediment and intrabasinal-derived biosiliceous debris. Reservoir quality in these rocks is neither more strongly nor more simply related to variations in primary texture and composition because the interrelationships between texture and composition are complex and, importantly, the diagenetic overprint is too strong.
242 citations
TL;DR: A 223-ft (68-m) long core from Johnson County, Texas was used for the identification of ten Barnett Shale lithofacies, including spiculitic mudstone and lag deposits, which are indicative of a relatively higher energy environment and downslope resedimentation of shallower water deposits as discussed by the authors.
Abstract: Ten Barnett Shale lithofacies have been recognized in a 223-ft (68-m)-long core from Johnson County, Texas. Eight of these lithofacies match those previously identified in the main producing area of the Newark East (Barnett Shale) field in the northern part of the Fort Worth Basin, but two new lithofacies have been identified in this core, resedimented spiculitic mudstone lithofacies and lag deposits, both of which are indicative of a relatively higher energy environment and downslope resedimentation of shallower water deposits. The recognition of cyclical stacking patterns of the lithofacies, condensed sections (CSs), and transgressive surfaces of erosion were the keys to establishing the sequence-stratigraphic framework in these fine-grained rocks, which consists of seven stratigraphic intervals in the lower Barnett Shale and nine stratigraphic intervals in the upper Barnett Shale. Spectral gamma-ray uranium and thorium logs aided in this objective and are recommended for future sequence-stratigraphic studies of these and other shales. The sequence-stratigraphic framework reveals that the lower Barnett Shale in this area was deposited mainly in a low-energy, relatively deep-water environment, somewhat far from a terrigenous source area, which probably lies to the northwest. By contrast, the upper Barnett Shale was deposited in an oxygenated shallower water environment, which had a source area from the west and southwest sides of the basin. The higher frequency of sea level fluctuation during development of the upper Barnett Shale most probably indicates periodic tectonic activity, perhaps associated with a structural high that was susceptible to sea level fluctuations. Alternatively, it could have resulted from the onset of glaciations in Gondwanaland during this time. This higher frequency may indicate that the upper Barnett is Chesterian in age, because cyclicity was higher than during the Osagean and Meramecian stages. If so, there may be more high-frequency cycles than recognized in this core. Siliceous sponge spicules are more common in this core than in more northerly cores, so more brittle facies might prevail in the southern part of the Fort Worth Basin. High gamma-ray log responses, which are caused by a high total organic carbon, and/or in-situ phosphate minerals are commonly found in CSs and can be used for regional correlations. However, high gamma-ray phosphatic deposits that have been resedimented to downslope positions by sediment gravity flows are an exception to the previous statement. Correlation of the Barnett stratigraphic intervals now provides a north-to-southeast stratigraphic framework along the Fort Worth Basin. Relative hydrocarbon potential (RHP) is an organic geochemical parameter applied to this core and found to provide an indicator of marine transgressions and regressions. We recommend continued testing and use of the RHP parameter for high-frequency sequence-stratigraphic analysis of unconventional gas shales.
219 citations
TL;DR: In this article, the authors investigated the use of non-routine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification.
Abstract: Tight gas reservoirs are notoriously difficult to characterize; routine methods developed for conventional reservoirs are not appropriate for tight gas reservoirs. In this article, we investigate the use of nonroutine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification. Profile permeability is used to characterize fine-scale (1 in. [2.5 cm]) vertical heterogeneity in a tight gas core; more than 500 measurements were made. Profile permeability, although useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; furthermore, the scale of measurement is much smaller than log scale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ stress conditions, and 13-point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, N2 adsorption, a new method for tight gas was used to estimate the pore-size distribution of several tight gas samples. A unimodal or bimodal distribution was observed for the samples, with the larger peak corresponding to the dominant pore-throat size, as confirmed by independent methods. Furthermore, the adsorption-desorption hysteresis loop shape was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides rapid analysis and does not suffer from some of the same limitations of Hg injection. In the future, we hope that the N2 adsorption method may prove useful for flow-unit characterization (based on dominant pore size) of fine-grained (siltstone-shale) tight gas reservoirs.
212 citations
TL;DR: In this paper, the authors investigated how clay grain coats inhibit quartz cement and preserve porosity in deeply buried sandstones and found that the fraction of grain surface coverage is the primary control on cement inhibition by coats, but at high temperatures, many coats permit quartz nucleation and preserves porosity by limiting cement growth.
Abstract: Observations and hydrothermal experiments were used to derive new information about how clay grain coats inhibit quartz cement and preserve porosity in deeply buried sandstones. Samples of deeply buried, porous sandstones with different types of clay coats were split in two, coats removed from one of each pair of splits, and grain surfaces inspected with scanning electron microscopy. Quartz grains in a fluvial-deltaic sandstone buried to 115C had no visible authigenic quartz on grain surfaces cleaned of diagenetic chlorite coats, though well-developed overgrowths occurred on nearby, naturally uncoated grains. However, in similar sandstones buried to 164C, quartz-grain surfaces exposed by chlorite-coat removal were covered with small (5 m), mainly anhedral, syntaxial quartz overgrowths. Similar overgrowths were observed under various detrital and diagenetic clay coats in porous eolian sandstones buried to temperatures up to 215C. We conclude that clay coats may retard quartz nucleation at moderate temperatures, but at high temperatures, many coats permit quartz nucleation and preserve porosity by limiting cement growth. To investigate cement growth-limitation mechanisms, samples with coats removed were subjected to quartz-cementing conditions in a hydrothermal reactor. During experiments, the naturally occurring small overgrowths on clay-cleaned grains coalesced and grew, suggesting that clay particles in coats inhibit cement growth by forming barriers to early-overgrowth coalescence. Although the fraction of grain-surface coverage is the primary control on cement inhibition by coats, cement growth–interference textures vary with coat type, providing a mechanism by which coat composition may be a secondary control on inhibitory effectiveness. In deeply buried sandstones, quartz cement can fill significant microporosity within diagenetic chlorite coats, potentially affecting mechanical and petrophysical rock properties.
136 citations
136 citations
TL;DR: In this article, the authors argue that the assumption of mesogenetic dissolution producing a net increase in secondary porosity should not be used in the prediction of carbonate reservoir quality, and they also present a review of the literature where this model has been advanced and reveal a consistent lack of quantitative treatment.
Abstract: Many authors have proposed that significant volumes of porosity are created by deep-burial dissolution in carbonate reservoirs. We argue, however, that this model is unsupported by empirical data and violates important chemical constraints on mass transport. Because of the ubiquitous presence and rapid kinetics of dissolution of carbonate minerals, the mesogenetic pore waters in sedimentary basins can be expected to be always saturated and buffered by carbonates, providing little opportunity for the preservation of significantly undersaturated water chemistry during upward flow, even if the initial generation of such undersaturated pore water could occur. A review of the literature where this model has been advanced reveals a consistent lack of quantitative treatment. In consequence, the presumption of mesogenetic dissolution producing a net increase in secondary porosity should not be used in the prediction of carbonate reservoir quality.
TL;DR: In this paper, an analysis of the South Sumatra Suban gas field, developed mainly in fractured carbonate and crystalline basement, where active deformation has partitioned the reservoir into distinct structural and stress domains.
Abstract: It is becoming widely recognized that a relationship exists between stress, stress heterogeneity, and the permeability of subsurface fractures and faults. We present an analysis of the South Sumatra Suban gas field, developed mainly in fractured carbonate and crystalline basement, where active deformation has partitioned the reservoir into distinct structural and stress domains. These domains have differing geomechanical and structural attributes that control the permeability architecture of the field. The field is a composite of Paleogene extensional elements that have been modified by Neogene contraction to produce basement-rooted forced folds and neoformed thrusts. Reservoir-scale faults were interpreted in detail along the western flank of the field and reveal a classic oblique-compressional geometry. Bulk reservoir performance is governed by the local stress architecture that acts on existing faults and their fracture damage zones to alter their permeability and, hence, their access to distributed gas. Reservoir potential is most enhanced in areas that have large numbers of fractures with high ratios of shear to normal stress. This occurs in areas of the field that are in a strike-slip stress style. Comparatively, reservoir potential is lower in areas of the field that are in a thrust-fault stress style where fewer fractures with high shear-to-normal stress ratios exist. Achieving the highest well productivity relies on tapping into critically stressed faults and their associated fracture damage zones. Two wellbores have been drilled based on this concept, and each shows a three- to seven-fold improvement in flow potential.
TL;DR: In this paper, the Woodford Shale samples, obtained from a cored outcrop in southeastern Oklahoma, were geochemically analyzed to determine vertical variations of organic facies, thermal maturity, and an evaluation of their depositional environments.
Abstract: Woodford Shale samples, obtained from a cored outcrop in southeastern Oklahoma, were geochemically analyzed to determine vertical variations of organic facies, thermal maturity, and an evaluation of their depositional environments. Total organic carbon values ranged from 5.01 to 14.81%, indicating a good source rock potential. In this area, the Woodford Shale is marginally mature, as indicated by vitrinite reflectance values. Rock-Eval data revealed that the samples are dominated by type II kerogen. Biomarker ratios, based on pristane, phytane, steranes, and hopanes, show a mix of marine and terrigenous organic matter. High-salinity conditions and water density stratification also prevailed during deposition of this formation, as indicated by the presence of gammacerane. The Woodford Shale was subdivided into lower, middle, and upper members based on the integration of geochemical and geologic data. Moreover, the presence and extent of photic zone anoxia (PZA) were determined by the presence of aryl isoprenoids. The lower and upper Woodford Shale members were deposited under dysoxic to suboxic conditions and episodic periods of PZA. The middle member was deposited under anoxic conditions and persistent PZA. In addition, aryl isoprenoids helped infer the position of the chemocline during deposition of the different members. The relative hydrocarbon potential parameter was used in determining transgressive and regressive cycles within the Woodford Shale. This study undoubtedly demonstrates the significant lithologic and chemical variability that occurs within shales. The application of this workflow to regional studies can have a direct influence on exploration and production activities in shale-gas systems.
TL;DR: In this article, a new thermal history of the Tarim Basin was reconstructed using the integrated thermal indicators of apatite and zircon (uranium-thorium/helium)/helium ages and fission tracks, and equivalent vitrinite reflectance data.
Abstract: The Tarim Basin is one of the richest basins in oil and gas resources in China. The Cambrian and Middle–Upper Ordovician strata are the most important source rocks. Previous early Paleozoic thermal histories have led to varied hypotheses on the evolution of the lower Paleozoic source rocks, causing a significant impact on petroleum exploration in the basin. A new Paleozoic thermal history of the Tarim Basin was reconstructed in this article using the integrated thermal indicators of apatite and zircon (uranium-thorium)/helium ages, apatite fission tracks, and equivalent vitrinite reflectance data. The modeled results indicate that different parts of the basin experienced widely differing early Paleozoic thermal gradient evolution. The eastern and central regions of the basin experienced a decreasing thermal gradient evolution from 37 to 39C/km during the Cambrian and Ordovician to 35 to 36C/km in the Silurian, whereas the northwestern region of the basin had an increasing early Paleozoic thermal gradient evolution from 28 to 32C/km in the Cambrian to 30 to 34C/km in the Ordovician and Silurian. The Lower Cambrian thermal gradient resulted from the higher thermal conductivity of the 800- to 1000-m (2625- to 3280-ft) thickness of gypsum and salt in the Cambrian strata. The basin experienced an intracratonic phase during the late Paleozoic and a foreland basin phase during the Mesozoic and Cenozoic, with the thermal gradient decreasing to the present-day value of 20 to 25C/km. The sensitivity of thermal modeling by the best-fit method is less than 5% in our study, and the differences of the early Paleozoic thermal gradient evolution in different regions of the basin may result in differential maturation of lower Paleozoic source rocks. The maturity histories of the source rocks, modeled based on the new thermal histories, indicate that the lower Paleozoic source rocks in most areas of the basin matured rapidly and reached the late mature to dry-gas stage during the Paleozoic but experienced slower maturation during the Mesozoic and Cenozoic. These new data on the Paleozoic thermal history and lower Paleozoic source rock maturity histories of the Tarim Basin provide new insights to guide oil and gas exploration of the basin.
TL;DR: The basin-centered gas accumulation model was applied to the Piceance Basin by determining the timing of fracturegrowth and associated temperature, pressure, and fluid-composition conditions using microthermometry and Raman microspectrometry of fluid inclusions trapped in fracture cement that formed during fracture growth as discussed by the authors.
Abstract: The Upper Cretaceous Mesaverde Group in the Piceance Basin, Colorado, is considered a continuous basin-centered gas accumulation in which gas charge of the low-permeability sandstone occurs under high pore-fluid pressure in response to gas generation. High gas pressure favors formation of pervasive systems of opening-mode fractures. This view contrasts with thatofothermodelsoflow-permeabilitygasreservoirsinwhich gas migrates by buoyant drive and accumulates in conventional traps, with fractures an incidental attribute of these reservoirs. We tested the aspects of the basin-centered gas accumulation model as it applies to the Piceance Basin by determining the timing of fracturegrowth and associated temperature,pressure, and fluid-composition conditions using microthermometry and Raman microspectrometry of fluid inclusions trapped in fracture cement that formed during fracture growth. Trapping temperatures of methane-saturated aqueous fluid inclusions record systematic temperature trends that increase from approximately 140 to 185°C and then decrease to approximately 158°C over time, which indicates fracture growth during maximum burial conditions. Calculated pore-fluid pressures for methanerich aqueous inclusions of 55 to 110 MPa (7977–15,954 psi) indicate fracture growth under near-lithostatic pressure conditions consistent with fracture growth during active gas maturation and charge. Lack of systematic pore-fluid–pressure trends
TL;DR: In this article, a hybrid approach combines inverse and forward models of mantle convection and accounts for the principal contributors to long-term sea level change: the evolving distribution of ocean floor age, dynamic topography in oceanic and continental regions, and the geoid.
Abstract: Dynamic earth models are used to better understand the impact of mantle dynamics on the vertical motion of continents and regional and global sea level change since the Late Cretaceous. A hybrid approach combines inverse and forward models of mantle convection and accounts for the principal contributors to long-term sea level change: the evolving distribution of ocean floor age, dynamic topography in oceanic and continental regions, and the geoid. We infer the relative importance of dynamic versus other factors of sea level change, determine time-dependent patterns of dynamic subsidence and uplift of continents, and derive a sea level curve.
We find that both dynamic factors and the evolving distribution of sea floor age are important in controlling sea level. We track the movement of continents over large-scale dynamic topography by consistently mapping between mantle and plate frames of reference, and we find that this movement results in dynamic subsidence and uplift of continents. The amplitude of dynamic topography in continental regions is larger than global sea level in several regions and periods, so that it has controlled regional sea level in North and South America and Australia since the Late Cretaceous, northern Africa and Arabia since the late Eocene, and Southeast Asia in the Oligocene–Miocene. Eastern and southern Africa have experienced dynamic uplift over the last 20 to 30 m.y., whereas Siberia and Australia have experienced Cenozoic tilting. The dominant factor controlling global sea level is a changing oceanic lithosphere production that has resulted in a large amplitude sea level fall since the Late Cretaceous, with dynamic topography offsetting this fall.
TL;DR: In this paper, a three-dimensional model of the Williston Basin was constructed to integrate and assess the parameters that influence the generation and migration of hydrocarbons in the Bakken Formation.
Abstract: The Bakken Formation of the Williston Basin is a prime example of an unconventionally produced petroleum system, with a low-permeability reservoir that requires application of advanced technologies for commercial production. A three-dimensional model of the Williston Basin was constructed to integrate and assess the parameters that influence the generation and migration of hydrocarbons in the Bakken Formation. This study tests the applicability of available basin and petroleum system modeling technology on an unusually low-permeability petroleum system. The model is based on nine surfaces constructed from log tops of thousands of wells in the study area and additional depth and isopach maps of the Bakken Formation members. These were integrated with the established basin evolution in line with published research. Temperature and thermal maturity were calibrated during model construction from well temperature and geochemistry data. The resulting heat-flow map supports the existence of a heat-flow anomaly along longitude 103W, discussed controversially in the literature. Furthermore, the results indicate that the invasion-percolation migration approach best describes the distribution of petroleum accumulation and the saturated areas in the Bakken members. The volume of generated hydrocarbons was calculated, and the extent of the highly saturated accumulation beyond the area of the high-mature source was mapped. Furthermore, it was demonstrated that petroleum accumulations beyond the high-saturation zones have to be related to stratigraphic pinch-outs, lateral variability in permeability of the Bakken members, or smaller structural influences that were lost because of the resolution applied in the model.
TL;DR: In this paper, the authors analyzed a cataclastic shear-band network developed in uncemented porous sandstone in Provence, France, and found that the shear bands are characterized by a porosity reduction of 10 to 25% and a permeability reduction of three to five orders of magnitude.
Abstract: Determination of the membrane seal capacity of deformation bands is critical for managing geologic reservoirs in porous sandstones. In this study, we have analyzed a cataclastic shear-band network developed in uncemented porous sandstone in Provence, France. Geometrical analyses of the bands show significant differences between three types of bands (single strand, multistrand, and band cluster), sorted by their number of strands, their amount of shear displacement, and their thicknesses. At the microscopic scale, the image-analysis porosities and the grain-size distributions allow definition of three different types of microstructural deformation: damage zone, protocataclastic, and cataclastic. Whereas damage zone and protocataclastic deformations are observed in each type of band, cataclastic strands are observed in clusters and, sometimes, in multistrands. Cataclastic strands are characterized by a porosity reduction of 10 to 25% and a permeability reduction of three to five orders of magnitude compared to the host rock. Field observations of iron hydroxide precipitations around the bands suggest that cataclastic strands were membrane seals to water flow under vadose condition. This study therefore highlights the importance of the degree of cataclasis in shear bands as membrane seals to subsurface fluid flows in sandstone reservoirs.
TL;DR: In this article, the authors introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (13C) data to explore the genesis of thermogenic gases in the Appalachian Basin.
Abstract: Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (13C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature (13C[C1 C2][13C113C2]: –9), isotopically light methane, with low (4He) (average, 1 103 cc/cc) elevated 4He/40Ar and 21Ne/40Ar (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane (13C[C1 – C2] [13C113C2]: 3), with high (4He) (average, 1.85 103 cc/cc) 4He/40Ar and 21Ne/40Ar near crustal production levels and elevated crustal noble gas content (enriched 4He, 21Ne, 40Ar). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.
TL;DR: In this paper, the authors identify two tectonic fracture systems: an older subordinate fully mineralized system and a younger primary mostly open system in the Upper Permian-Carboniferous Unayzah Formation.
Abstract: The Upper Permian–Carboniferous Unayzah Formation in South Haradh, Saudi Arabia, includes two major mechanical and petrophysical layers that are separated by shale-rich zones. Open tectonic fracture clusters are rare and not essential for fluid flow in the Unayzah A zone, which has high porosity and permeability. However, such fracture clusters are essential to, and impact, the production performance in the Unayzah B/C tight-gas reservoir. The occurrence of the tectonic fractures in the Unayzah Formation is linked to the rock mechanical properties, which vary with porosity, shale volume, cement type, and texture. The B/C unit is more fractured than the A unit, but its layers vary in the degree of fracturing. The variation in fracture development within the B/C unit results in differences in fracture-enhanced permeability based on production profiles where flow is restricted to preferentially fractured mechanical layers that lack effective vertical fluid communication with other layers. We identify two tectonic fracture systems: an older subordinate fully mineralized system and a younger primary mostly open system. Early extensional fractures including joints and faults developed parallel to the basement faults during the opening of the Neotethys. These are fully mineralized and have little or no function as fluid conduits. The younger system includes open-fracture clusters that are predominantly parallel or nearly parallel to the regional east-northeast–west-southwest maximum horizontal stress of the Zagros (that has been active since the Late Cretaceous) and is independent of local structures. Therefore, these fractures are controlled by remote stresses instead of the basement-rooted forced folds and faults. In this article, we demonstrate that in the Unayzah B/C, natural fractures are essential to permeability and, in some areas, to porosity, and thence, to reservoir performance. The results of this study are being implemented in well placement and completion design to optimize the intersection of open-fracture clusters with positive preliminary results.
TL;DR: In this paper, the authors evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource and estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 Tcf at the F95 and F5 fractile confidence levels, respectively.
Abstract: As part of an assessment of undiscovered hydrocarbon resources in the northern Gulf of Mexico onshore Mesozoic section, the U.S. Geological Survey (USGS) evaluated the Lower Cretaceous Pearsall Formation of the Maverick Basin, south Texas, as a potential shale gas resource. Wireline logs were used to determine the stratigraphic distribution of the Pearsall Formation and to select available core and cuttings samples for analytical investigation. Samples used for this study spanned updip to downdip environments in the Maverick Basin, including several from the current shale gas-producing area of the Pearsall Formation. The term shale does not adequately describe any of the Pearsall samples evaluated for this study, which included argillaceous lime wackestones from more proximal marine depositional environments in Maverick County and argillaceous lime mudstones from the distal Lower Cretaceous shelf edge in western Bee County. Most facies in the Pearsall Formation were deposited in oxygenated environments as evidenced by the presence of biota preserved as shell fragments and the near absence of sediment laminae, which is probably caused by bioturbation. Organic material is poorly preserved and primarily consists of type III kerogen (terrestrial) and type IV kerogen (inert solid bitumen), with a minor contribution from type II kerogen (marine) based on petrographic analysis and pyrolysis. Carbonate dominates the mineralogy followed by clays and quartz. The low abundance and broad size distribution of pyrite are consistent with the presence of oxic conditions during sediment deposition. The Pearsall Formation is in the dry gas window of hydrocarbon generation (mean random vitrinite reflectance values, Ro = 1.2–2.2%) and contains moderate levels of total organic carbon (average 0.86 wt. %), which primarily resides in the inert solid bitumen. Solid bitumen is interpreted to result from in-situ thermal cracking of liquid hydrocarbon generated from original type II kerogen that was prevented from expulsion and migration by low permeability. The temperature of maximum pyrolysis output (Tmax) is a poor predictor of thermal maturity because the pyrolysis (S2) peaks from Rock-Eval analysis are ill defined. Vitrinite reflectance values are consistent with the dry gas window and are the preferred thermal maturity parameter. A Maverick Basin Pearsall shale gas assessment unit was defined using political and geologic boundaries to denote its spatial extent and was evaluated following established USGS hydrocarbon assessment methodology. The assessment estimated a mean undiscovered technically recoverable natural gas resource of 8.8 tcf of gas and 3.4 and 17.8 tcf of gas at the F95 and F5 fractile confidence levels, respectively. Significant engineering challenges will likely need to be met in determining the correct stimulation and completion combination for the successful future development of undiscovered natural gas resources in the Pearsall Formation.
TL;DR: The second largest oil and gas field in China, Shengli oil field, located in the Tertiary Dongying graben system in the southern Bohai Basin this paper, provides an excellent example of how three-dimensional petroleum systems modeling allows the assessment of fault behavior and timing to predict the distribution of hydrocarbons in a system.
Abstract: Shengli oil field, the second largest oil and gas field in China, is located in the Tertiary Dongying graben system in the southern Bohai Basin. Three petroleum systems, one for each mapped source rock, and as many as seven reservoir rocks are documented in the Dongying graben system, representing a complex migration and accumulation pattern. In addition, both the source and the reservoir facies are distributed unevenly throughout the system, requiring a complex distribution of possible migration pathways. Stratigraphic conduits, that is, sandy and conglomeratic facies, are mostly present in the northern graben flank area, where coarse sediments provide possible migration pathways. Over most of the basin, however, faults—active at different times throughout basin evolution—add important additional conduits for petroleum migration, as well as acting locally as seals, depending on their surrounding lithology and their respective sealing or leaking properties through time. This article aims to show that the Shengli oil field provides an excellent example of how three-dimensional petroleum systems modeling allows the assessment of fault behavior and timing to predict the distribution of hydrocarbons in a system.
TL;DR: In this article, the Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics.
Abstract: The Middle Jurassic Khatatba Formation in the northern Western Desert of Egypt was evaluated in terms of organic matter abundance, type and thermal maturity, as well as for some organic petrographic characteristics. Depositional environments were interpreted based on organic geochemical (Rock-Eval pyrolysis, extract analysis, and biomarker distributions) and organic petrological methods. Organic carbon contents range between 1.0 and 32.5 wt. %. The Khatatba shale and coaly shale samples have hydrogen index values in the range of 63 to 261 mg hydrocarbon (HC)/g total organic carbon, with mixed types 2–3 and 3 kerogens. Mean vitrinite reflectance (Ro) between 0.77 and 1.07% is in reasonably good agreement with pyrolysis Tmax (temperature at maximum of S2 peak) data (438–459C). Organic-rich sediments of the Middle Jurassic Khatatba Formation have very good source rock generative potential and have obtained thermal maturity levels equivalent to the oil window. The main generation products are gas with very limited liquid HCs (oil or condensate). Seven shale and coaly shale samples from Khatatba Formation were characterized using gas chromatography (GC) and GC–mass spectrometry techniques. The Khatatba samples are characterized by the predominance of C14-C24 alkanes, a pristane/phytane ratio of less than 2, abundant C27 regular steranes, and the presence of tricyclic terpanes. These are consistent with the suboxic marine-environment conditions for the Khatatba source rock. Biomarker parameters for these samples generally indicate a mixture of land- as well as marine-derived organic-matter input. The maturity indicators based on C32 22S/(22S + 22R) homohopane and C29 20S/(20S + 20R) and /( + ) sterane ratios reveal that the Khatatba samples are thermally mature and have reached the peak oil-window maturity supporting the Ro data.
TL;DR: In this paper, a relational database storing fluvial architecture data has been developed and populated with literature-and field-derived data from modern rivers and ancient successions, which allows the definition of various constraints referring to either genetic units (e.g., architectural elements) or material units (i.e., contiguous volumes of sediment characterized by the same value of a given categorical or discretized variable).
Abstract: Quantitative databases storing analog data describing the geometry of sedimentologic features are commonly used to derive input for geostatistical simulations of reservoir sedimentary architecture; however, geometrical information alone is inadequate for the detailed characterization of sedimentary heterogeneity. A relational database storing fluvial architecture data has been developed and populated with literature- and field-derived data from modern rivers and ancient successions. The database scheme characterizes fluvial architecture at three different scales of observation—recording style of internal organization, geometries, and spatial relationships of genetic units—classifying data sets according to controlling factors (e.g., climate type) and context-descriptive characteristics (e.g., river pattern). The database can therefore be filtered on both architectural features and boundary conditions to yield outputs tailored on the system being modeled to generate input to object- and pixel-based stochastic simulations of reservoir architecture. When modeling heterogeneity with stochastic simulations, the choice of input parameters quantifying spatial variation is problematic because of the paucity of primary data and the partial characterization of supposed analogs. This database-driven approach permits the definition of various constraints referring to either genetic units (e.g., architectural elements) or material units (i.e., contiguous volumes of sediment characterized by the same value of a given categorical or discretized variable; e.g., same lithofacies type, clay and silt content, and others), which permit the realistic description of fluvial architecture heterogeneity. Applications of this database approach include the computation of relative dimensional parameters and the generation of auto- and cross-variograms and transition-probability matrices, which are necessary to effectively model spatial complexity.
TL;DR: In this paper, the Los Cavaos oil field, located in the Malargue fold belt of the Neuquen Basin, Argentina, was analyzed by integrating multiscale fracture data from outcrops and subsurface.
Abstract: Oil-producing sills are commonly considered atypical reservoirs, although they can hold significant exploration potential. The need for a better understanding of fracture properties and petroleum system characteristics for this and similar igneous rock plays is the main motivation of our study. We explore the evolution of this play type by an analysis of the Los Cavaos oil field, located in the Malargue fold belt of the Neuquen Basin, Argentina, integrating multiscale fracture data from outcrops and subsurface. The field was created by a combination of intrusions and mild Miocene-Pliocene inversion. Production stems from thick cavity zones in naturally fractured andesitic sills emplaced in Upper Jurassic shale source rocks. Orientation patterns, fracture spacing, and length of fracture sets in the sill are consistent over several orders of magnitude. Large multiply connected and weakly cemented fractures are responsible for excellent interconnectedness in the reservoir. Fracture density is correlated with fault proximity, indicating a cogenetic evolution during active deformation. Abundant fractures in core with strike-slip to oblique striations support transpressional overprint during and after fracture formation. Although it is challenging to separate cooling from tectonic fractures, we propose two phases of fracturing, marked by a coexistence of subvertical and oblique fractures together with transpressional striae. Petrographic evidence suggests initial local oil expulsion and migration through microfractures, with opening displacements of 0.01 to 1 mm, followed by subsequent charging of the evolving intrasill cavity system as well as the bulk fracture system during cooling and mild deformation. We suggest that the observed patterns may be extrapolated to sills in similar geotectonic settings.
TL;DR: In this paper, the authors compare four approaches to geomechanical modeling of stresses adjacent to salt bodies and compare stresses generated by viscoelastic stress relaxation of a salt sphere.
Abstract: We compare four approaches to geomechanical modeling of stresses adjacent to salt bodies. These approaches are distinguished by their use of elastic or elastoplastic constitutive laws for sediments surrounding the salt, as well as their treatment of fluid pressures in modeling. We simulate total stress in an elastic medium and then subtract an assumed pore pressure after calculations are complete; simulate effective stress in an elastic medium and use assumed pore pressure during calculations; simulate total stress in an elastoplastic medium, either ignoring pore pressure or approximating its effects by decreasing the internal friction angle; and simulate effective stress in an elastoplastic medium and use assumed pore pressure during calculations. To evaluate these approaches, we compare stresses generated by viscoelastic stress relaxation of a salt sphere. In all cases, relaxation causes the salt sphere to shorten vertically and expand laterally, producing extensional strains above and below the sphere and shortening against the sphere flanks. Deviatoric stresses are highest when sediments are assumed to be elastic, whereas plastic yielding in elastoplastic models places an upper limit on deviatoric stresses that the rocks can support, so stress perturbations are smaller. These comparisons provide insights into stresses around salt bodies and give geoscientists a basis for evaluating and comparing stress predictions.
TL;DR: In this paper, the postavulsion evolution of five channel-levee systems, documented from both the shallow subsurface and the sea floor, is marked in the early stages by relatively wide axial channel belts containing sinuous channel elements.
Abstract: Channel avulsion is fundamental in defining submarine fan morphology yet, as a process, is poorly understood. The postavulsion evolution of five channel-levee systems, documented from both the shallow subsurface and the sea floor, is marked in the early stages by relatively wide axial channel belts containing sinuous channel elements. The axial channel belt in each system narrowed through time in association with levee aggradation, which resulted in increased channel confinement. Of the five systems studied, four avulsed from a radial avulsion node at the mouth of the basin feeder-channel complex, which is the entry point to the basin. Only one avulsion occurred at an avulsion node downflow of the mouth of the feeder-channel complex. The degree of channel instability in three of the four systems before an avulsion event was increased by channel-floor aggradation caused by the backfilling of channel-confined turbidity current deposits. Channel-floor aggradation reduced the confinement relief of the systems, thereby increasing the probability of avulsion during an outsized flow event. The backfilled deposits in the channel belts display relatively high seismic-reflection amplitudes inferred to be coarser grained (more sand rich) than their surroundings, that is, out-of-channel deposits. Overbank cyclic steps are exceptionally well preserved on subsurface levees, and their potential function in promoting an avulsion event is discussed. The actual process of avulsion is caused by the flow itself instead of a reduction in confinement relief, and although outsized flows are the likely trigger, depending on the degree of this relief in the channel, multiple small flows could also be responsible for levee breaching, resulting in avulsion. The process of channel-system evolution resulting in avulsion can be applied to other subsurface data where compensating high-amplitude channel belts are recognized. In the context of hydrocarbon exploration, investigating up depositional dip to identify avulsion nodes increases the chance of locating sand-rich deposits, especially where multiple channels converge on one point.
TL;DR: In this paper, the authors interpret similar seawater chemistry in the aftermath of the end-Permian extinction to explain the genesis of the giant ooids in the Early Triassic.
Abstract: Lower Triassic platforms in the Nanpanjiang Basin contain extensive oolites. Interior oolites are stacked in meter-scale cycles arranged into larger coarsening-upward sequences. Oolites thicken toward margins to include grainstones up to 50 m (164 ft) thick and contain giant ooids (up to 1 cm [0.4 in.]) and composite coated grains. Cross-bedding, ripples, and abraded ooids indicate deposition in high-energy shoals. Apparent layer-cake correlation across interiors indicates amalgamation of shoals. Thinner interior lenses represent spillover lobes. Ooids are interpreted to have originally been bimineralic with cortices of radial or micritic fabrics (high-magnesium calcite), alternating with coarse pseudospar or brickwork (originally aragonite). Distorted ooids formed by brittle compaction of micritic cortices around voids are interpreted to have been dissolved aragonite. Abundant potential nuclei indicate that limited supply was not a factor contributing to the large ooid size. High-energy and abnormally high–seawater CaCO3 saturation are interpreted to be causes of the giant ooids. Most previous reports of giant ooids come from the Neoproterozoic, a period of increasing surface-water oxygenation and high CaCO3 saturation caused by a minimal skeletal carbonate precipitation. We interpret similar seawater chemistry in the aftermath of the end-Permian extinction to explain the genesis of the giant ooids in the Early Triassic. The genesis of bimineralic ooids during an Early Triassic period of rapidly increasing pCO2 and low indicates that an increasing Ca/Mg ratio was the primary mechanism driving the change from aragonite to calcite seas. The architecture, textures, and diagenesis of the Lower Triassic oolites of the Nanpanjiang Basin provide useful analogs for coeval reservoirs in Sichuan and the Middle East.
TL;DR: In this article, a 3D multi-attribute seismic facies (SF) classification was performed on a 3-D cube to discriminate the respective SF related to the breccia deposits compared with other SF and estimate their spatial extent.
Abstract: The recognition of paleokarst in subsurface carbonate reservoirs is not straightforward because conventional seismic interpretation alone is generally not sufficient to discriminate karstified areas from their surroundings. In the Loppa High (Norwegian Barents Sea), a protracted episode of subaerial exposure occurring between the late Paleozoic and mid-Triassic—Late Permian to Anisian—resulted in a significant overprinting of the previously deposited carbonate units. Here, we map the extension of the karstified areas using an integrated approach consisting of (1) a core study of critical paleokarst intervals, (2) a three-dimensional (3-D) seismic stratigraphic analysis, and (3) a 3-D multiattribute seismic facies (SF) classification. A core retrieved in the flat-topped Loppa High revealed breccia deposits at least 50 m (164 ft) thick, which probably resulted from cave collapses following the burial of the karst terrain. The SF classification was tested on a 3-D cube to (1) discriminate the respective SF related to the breccia deposits compared with other SF and (2) to estimate their spatial extent. Seismic-facies analysis suggests that breccias occupied the topmost area of the structural high, extending up to 12 km (7 mi) in width, 46 km (29 mi) in length, and tens of meters in thickness. The inference of such a large amount of breccia suggests that a significant part of this terrain was derived from the amalgamation of successive cave-development events—including periods of subaerial exposure and subsequent burial and collapse—resulting in a coalesced collapsed paleocave system. Previous observations from the Loppa High revealed the presence of karst plains associated with sinkholes, caves, and other dissolution phenomena associated with the breccia facies, further suggesting that a large volume of carbonate rocks in this area was affected by subaerial exposure and karstification. Our integrated approach and proposed karstification model could be applied to similar sedimentary basins that accommodate deeply buried carbonate successions affected by protracted episodes of subaerial exposure, where only few wells as well as 3-D seismic data are available.
TL;DR: In this paper, a coupled poroelastoplastic geomechanical model is used to study how stresses and pore pressures evolve in sediments bounding a spherical salt body.
Abstract: We use a fully coupled poroelastoplastic geomechanical model to study how stresses and pore pressures evolve in sediments bounding a spherical salt body. Drained analyses (pore pressures remain hydrostatic) demonstrate that sediments yield in response to loading by the salt, which leads to a redistribution of stresses and to deformations larger than predicted by poroelastic or solid Coulomb-plastic models. Undrained analyses (overpressures develop while no dissipation occurs) illustrate that salt loading induces pore pressures that extend kilometers away from the salt body. We also model the flow and consequent dissipation that occur in the sediments because of this undrained salt loading. We show that with time, the pressure field dissipates and expands. The dissipation process takes millions of years, which suggests that pore-pressure perturbations caused by salt loading should still be present in mudstones near many salt bodies. Under drained conditions, stress perturbations generate low minimum principal stresses above and below the salt, resulting in convergence of pore pressure and minimum principal stress at these locations. Such conditions are challenging to drill through. In undrained systems, sharp drops in pore pressure may occur above and below the salt, whereas both the pore pressure and the minimum principal stress rise next to the salt. In contrast to previous models that do not couple changes in stress to changes in pore pressure, the coupled approach presented here has the potential to predict in-situ stresses and pore pressures more accurately in a wide variety of geologic settings.