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Isochore map of the West Texas Super Basin, T bosa Basin Woodford (contour interval = 100 ft; modified from Fairhurst, 2015; Fairhurst and Rogers, 2018) overlain by Permian Basin tectonic features from Ruppel (2019a).
Source publication
The West Texas (Permian) Super Basin is the prototype super
basin. The basin has produced 28.9 billion bbl of oil and 203 TCF
of gas (63 billion BOE, 1920–2019). The US Geological Survey
and Bureau of Economic Geology estimate this super basin has
remaining reserves of 120–137 billion BOE, twice the volume
produced during the first 100 yr of hydroc...
Contexts in source publication
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... erosion was followed by a Late Devonian transgression that deposited the organic-rich Woodford Shale in Oklahoma, Texas, and New Mexico. Figure 7 is an isochore map of the Woodford in the West Texas Super Basin. The Woodford extends over a larger area than the Simpson Group isochore forming the more oval shape of the T bosa Basin defined by Galley (1958) and most typically represented (shape and areal extent). ...
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... Simpson Group isochore outline ( Figure 6) is reasonably equivalent to the 100-ft Woodford isochore value. Figure 7 includes an overlay of the Permian Basin tectonic elements for comparison and later discussion. The thickest Woodford at the Tobosa Basin center is roughly spatially equivalent to the later developed (Permian) Malaga subbasin (Figure 4). ...
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... margin of the Delaware Basin (Figure 7). The relationship between the Guadalupian (Queen, Seven Rivers, and Yates) conventional fields ( Figure 21) on the western margin of the central basin platform and steeply dipping petroleum systems below and into those reservoirs (Figures 7, 19) is perhaps the most significant petroleum system relationship of the entire West Texas Super Basin conventional reservoir reserves and production. ...
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... erosion was followed by a Late Devonian transgression that deposited the organic-rich Woodford Shale in Oklahoma, Texas, and New Mexico. Figure 7 is an isochore map of the Woodford in the West Texas Super Basin. The Woodford extends over a larger area than the Simpson Group isochore forming the more oval shape of the T bosa Basin defined by Galley (1958) and most typically represented (shape and areal extent). ...
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... Simpson Group isochore outline ( Figure 6) is reasonably equivalent to the 100-ft Woodford isochore value. Figure 7 includes an overlay of the Permian Basin tectonic elements for comparison and later discussion. The thickest Woodford at the Tobosa Basin center is roughly spatially equivalent to the later developed (Permian) Malaga subbasin (Figure 4). ...
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... margin of the Delaware Basin (Figure 7). The relationship between the Guadalupian (Queen, Seven Rivers, and Yates) conventional fields ( Figure 21) on the western margin of the central basin platform and steeply dipping petroleum systems below and into those reservoirs (Figures 7, 19) is perhaps the most significant petroleum system relationship of the entire West Texas Super Basin conventional reservoir reserves and production. ...
Citations
... The Permian Basin is a complex Paleozoic sedimentary basin spanning an area of 11,583 squared miles (300,000 km 2 ) covering west Texas and southeastern New Mexico of the United States (Galley, 1958;Ward et al., 1986). The basin is found in the foreland of the Marathon-Ouachita orogenic belt (Fairhurst et al., 2021). The Permian Basin is filled with Phanerozoic carbonates, evaporites, and siliciclastics to a maximum depth of 33,136.5 ft (10,100 m) (Frenzel et al., 1988). ...
The Lower Clear Fork from Tex-Mex, S.E. Field on the Central Basin Platform is a typical complex reservoir that displays high heterogeneity in lithological and petrophysical properties. The unit represents a producing reservoir succession of Leonardian platform carbonates deposited in shallow marine water during the Early Permian. The sediment of the Lower Clear Fork is composed of a mixed succession of dolomite interbedded with anhydrite, minor clay minerals, and siliciclastics. The high heterolithic nature of the reservoir makes efficient recovery of hydrocarbons difficult. This situation requires an understanding of the variability in depositional facies in terms of mineralogy, depositional textures and structures, and an assessment of its petrophysical properties. As of December 2023, cumulative production of hydrocarbon from the Tex-Mex, S.E. Field reached about 88,308 barrels of oil equivalent.
The study at Tex-Mex, S.E. Field utilized 338.9 ft (103.3 m) of Lower Clear Fork cored sample, core data, and wireline data from a key well. Key data utilized included core descriptions, wireline logs, routine core analysis data, petrographic thin sections, and whole rock mineralogical data from X-ray Diffraction. These data helped to (1) determine the paleoenvironments under which the Lower Clear Fork sediments were deposited, (2) build a core-calibrated petrophysical mineral model of the Lower Clear Fork from wireline logs and XRD mineralogy, and (3) assess the petrophysical properties of the Lower Clear Fork reservoir.
The integration of core/log analysis, XRD data, routine core data, and petrographic observations revealed seven (7) facies regrouped into four (4) major facies associations each representing the mineralogy, sedimentary textures, pore characteristics, and paleodepositional environment. The Lower Clear Fork, a second-order Leonardian sequence represents facies transitioning from dolomitized inner to ramp crest facies (skeletal/peloidal wackestone to grain-dominated packstone) in the lower part, to dolomitized restricted lagoon and tidal flats/sabkha facies (dolomudstone/anhydrite) in the upper part. The petrophysical characteristics of the Lower Clear Fork reservoir were dominantly controlled by post-depositional processes that altered the primary carbonate mineralogy and pore development. The principal diagenetic processes included reflux dolomitization, gypsum precipitation (later transformed into anhydrite), and dissolution of anhydrite and dolomite cement.
Mineralogical results revealed the dominance of dolomite, anhydrite with minor amounts of clay, and siliciclastics. Calibrated porosity values within the interval vary from 0.5% to 10%, while Klinkenberg permeability was in the range of 10-4 mD to 17.6 mD. The Lower Clear Fork facies showed dominance of high water saturation values, reaching up to 95.4%, and comparatively low oil saturation levels, peaking at a value of 14.4% in the dolopackstone facies. Overall, the Lower Clear Fork reservoir is of low quality, however, the grain-rich dolopackstone facies offered the most favorable reservoir properties when compared with other facies in the interval.
... However, instead of uplift and erosion, many inverted rift basins worldwide show counterintuitive basin-scale subsidence during inversion. Examples include the Permian Basin in west Texas (Fairhurst et al., 2021), Gulf of Mexico (Roure et al., 2009), South China Sea (Xie et al., 2017), Aquitaine Basin (Angrand et al., 2018;Dielforder et al., 2019), Tyrrhenian Sea (Zitellini et al., 2020), and Pannonian Basin ( Fig. 1A; Horváth and Cloetingh, 1996). In the latter, the change from back-arc rifting to basin inversion occurred within a short (∼2 m.y.) interval, when slab rollback along the Carpathian subduction zone ceased (Horváth et al., 2015), and the slow-rate (1-2 mm/yr) northward convergence of the Adriatic plate became dominant (Fodor et al., 2005;Bada et al., 2007). ...
Structural inversion of rifted basins is generally associated with surface uplift and denu-dation of the sedimentary infill, reflecting the active contractional deformation in the crust. However, worldwide examples of inverted rifts show contrasting basin-scale subsidence and widespread sedimentation patterns during basin inversion. By conducting a series of three-dimensional coupled geodynamic and surface processes models, we investigated the dynamic controls on these subsidence anomalies during the successive stages of rifting and basin inversion , and we propose a new evolutionary model for this process. Our models show that the inherited thermo-rheological properties of the lithosphere influence the initial strain local-ization and subsequent migration of crustal deformation during inversion. The sense of the vertical movements (i.e., uplift or subsidence), however, is not directly linked to the underlying crustal stress patterns; rather, it reflects the balance among contraction-induced tectonic uplift, postrift thermal subsidence of the inherited lithosphere, and sediment redistribution. Based on the interplay among the competing differential vertical movements with different amplitudes and wavelengths, inversion of rifted basins may lead to the growth of intraplate orogens, or the contraction-driven localized uplift may be hindered by the thermal sag effects of the inherited shallow lithosphere-asthenosphere boundary, resulting in basin-scale subsidence. In such basins, dating the first erosional surfaces and other unconformities may not provide accurate timing for the onset of inversion.
... Several studies have performed petroleum system analysis for the Wolfcamp-sourced HC accumulation in the Delaware Basin Zumberge, 2017, 2018;Jarvie, 2017;Fairhurst et al., 2021). These studies implied that the Wolfcamp unconventional play is self-sourced, and the Wolfcamp SR was responsible for several HC accumulations for the Permian intervals in the Delaware Basin and its surrounding. ...
... The signatures of these two different oil families are documented in Curtis and Zumberge (2018), Pepper et al. (2020), Echegu et al. (2021), and Baskoro et al. (2023). The Wolfcamp marine shale facies is the primary SR for the Wolfcamp unconventional reservoir and the lower Bone Spring interval Zumberge, 2017, 2018;Jarvie, 2017;Pepper et al., 2020;Fairhurst et al., 2021;Baskoro et al., 2023). The marine carbonate-rich SR, which is mainly restricted to the eastern and northern Delaware Basin margins, is primarily responsible for the HC accumulations in the Delaware Basin margins and as far as the Northwest Shelf and Central Basin Platform Zumberge, 2017, 2018;Pepper et al., 2020;Baskoro et al., 2023). ...
... In addition, the Wolfcamp Play is one of the main targets for unconventional production in the Permian Delaware Basin, along with the Leonardian Bone Spring interval (Gaswirth et al., 2018). Among the four intervals, Wolfcamp A is the most drilled interval for unconventional play in the Delaware Basin (Popova, 2019;Fairhurst et al., 2021). Thus, by performing mass balance calculations on the Wolfcamp Fm, an estimate of the remaining recoverable resource and EE in this most targeted unconventional play in the Delaware Basin can be provided. ...
Detailed quantification of basin-wide hydrocarbon (HC) masses from generation to production is necessary for a quantitative petroleum system analysis, and ultimately, for accurate resource estimation. Such quantified HC masses must be balanced following the fundamental laws of mass conservation. Mass balance is particularly important for unconventional-conventional petroleum systems in which expulsion efficiency (EE) is a critical parameter defining HCs in place, within the source rock (SR) interval and outside. This study performs an HC mass balance assessment aiming primarily to obtain insights on the remaining recoverable and EE, applied to the Wolfcamp Formation (Fm) in the Permian Delaware Basin. Calculated generated HC volumes from the Wolfcamp Fm based on the assumed 3D geologic model and p90/50/10 SR properties are 878/2107/4514 billion barrels of oil equivalent (BBOE). The mass balance is performed with three calculation scenarios: (1) inversion of EE (based on the United States Geological Survey [USGS]-estimated remaining recoverable HC in the Wolfcamp Fm), (2) forward calculation with multiple assumed EE, and (3) HC expulsion simulation. The mass balance with the inversion of EE indicates that the p90/50/10 of 58%/62%/69% overall EE is required for the Wolfcamp Fm to achieve the USGS-estimated remaining recoverable HC of 35/78/140 BBOE. Both mass balance with forward calculation and expulsion simulation predict overall lower p90/50/10 EE of 50% and 30%/56%/75%, respectively, thus resulting in higher than the USGS-estimated remaining recoverable HC in the Wolfcamp Fm in most scenarios. All of the mass balance calculations are also consistent with the interpretation of Wolfcamp unconventional play as a self-sourced play. This workflow is an efficient tool for taking a quantitative look at the petroleum system, especially related to the possibilities of generated HC distribution in the system. The calculated mass balance can serve as a reference in modeling unconventional systems and resources.
... In recent years, the petroleum system [88] has been widely adopted as an effective new concept and theory to guide oil and gas exploration, and it has become the frontier and focal point of petroleum geology research [89][90][91][92], which can be used as a method to guide the study of unconventional tight sandstone reservoirs. In light of the limitations of logging data and seismic data, it is possible to quantify the characteristics of different scales of reservoirs through the study of their outcrop in the study area, a deeper understanding of reservoir physical properties and sedimentary structure can thus be obtained, which is helpful in the development of other similar tight sandstone reservoirs. ...
Tight sandstone reservoirs are of interest due to their potentially favorable prospects for hydrocarbon exploration. A better understanding of tight sandstone outcrop reservoir characteristics and their influencing factors is thus needed. By laboratory observation, thin section analysis, and experimental analysis, the current work carried out a detailed investigation of densely sampled tight sandstone outcrops of the Shanxi Formation in the Liujiang River Basin, paving the way for further research on rock types, reservoir spatial distribution, physical properties, and their key controlling factors. The application of the Pressure Pulse Attenuation Method made it possible to determine the porosity and permeability, as well as the analysis of debris composition and filling content. The findings indicate that the main rock type of the tight sandstone outcrop reservoirs in the Shanxi Formation in the Liujiang River Basin is lithic quartz sandstone, some of which contains fine sand-bearing argillaceous siltstone, giving them very low porosity (average porosity of 4.34%) and low permeability (average permeability of 0.023 mD) reservoirs. Secondary pores—mostly dissolved pores among and in grains—are widely developed in the target region. In addition, diagenesis primarily includes mechanical compaction, cementation, and dissolution. The main controlling factors of tight sandstone reservoirs in the target region are sedimentation, diagenesis, and tectonics, whereby sedimentation affects reservoir physical properties that become better as the clast size increases, reservoir properties are negatively impacted by compaction and cementation, and reservoir properties are somewhat improved due to dissolution and the impact of tectonism. In addition, the tilt of the crust will produce faults during the tectonic action, generating reservoir cracks that improve the reservoir’s physical properties. This study tends to be helpful in the prediction of high-quality reservoirs in the Permian Shanxi Formation in North China and can also be used for analogy of high-quality reservoirs in similar areas with complete outcrops.
... Following the Ouachita Orogeny at the end of the Pennsylvanian, a thick section of clastic sediments accumulated in both the Delaware and Midland Basins throughout the Permian period, up to ~5500 m (18,000 ft) and ~3400 m (11,000 ft), respectively. They include the following series of decreasing age (Fairhurst et al., 2021;Ruppel, 2019;Ewing, 2016): Wolfcampian (Wolfcamp Formation -Fm.), Leonardian (Bone Spring Fm. in the DB; Dean, Leonard, and Spraberry Fms. in the MB), Guadalupian (Delaware Mountain Group -DMG-in the DB, San Andres, Grayburg and other formations in the MB), and Ochoan (Castile, Salado, Rustler and Dewey Lake Fms.) (Appendix A). The coeval series on the CBP are mostly dolomitized carbonates. ...
... Due to the development of horizontal well and fracturing technology, shale gas exploration and development in the United States has been successful and energy independence has been realized. At present, the commercially exploited shale in North America is mainly marine shale (mainly Devonian shale, Carboniferous shale, Permian shale and Jurassic shale), such as Devonian Marcellus shale in the Appalachian basin, Devonian Antrim shale in the Michigan basin, Devonian New Albany shale in the Illinois basin, Carboniferous Barnett in the Fort Worth basin, and Jurassic Haynesville shale in the East Texas basin and North Louisiana basin [4][5][6][7][8][9][10][11][12]. Following the United States and Canada, China has also made breakthroughs in shale gas exploration and development. ...
... As one of the few countries in the world to achieve commercial development of shale gas, the shale gas production formations in the United States are mainly Devonian, Carboniferous, Jurassic and Permian-all having a relatively low thermal maturity. For example, the Ro of Mississippi Barnet shale in the Fort Worth basin is between 1% and 1.3%, the Ro of Devonian Marcellus shale in the Appalachian basin is between 1.2% and 3.5%, the Ro of Devonian Woodford shale in the Anadarko basin is between 1.2% and 4%, and the Ro of Devonian Antrim shale in the Michigan basin ranges from 0.4% to 1.6% [4][5][6][7][8][9][10][11][12]123]. Compared with the United States, the four sets of organic-rich shale in southern China have a relatively high thermal maturity. ...
... (2) There is only one economic shale gas formation. At least 30 sets of economic shale gas formations have been found in 29 basins in the United States [4][5][6][7][8][9][10][11][12]136]. However, China has only found one shale formation (Ordovician-Silurian shale) with commercial exploitation value in one basin (the Sichuan Basin and its surrounding areas) [136]. ...
Many sets of Paleozoic marine organic-rich shale strata have developed in South China. However, the exploration and development results of these shale formations are quite different. Based on the data of core experiment analysis, drilling, fracturing test of typical wells, the reservoir differences and controlling factors of four sets of typical marine organic-rich shale in southern China are investigated. The four sets of shale have obvious differences in reservoir characteristics. Ordovician–Silurian shale mainly develops siliceous shale, mixed shale and argillaceous shale, with large pore diameter, high porosity, moderate thermal maturity, large pore volume and specific surface area. Cambrian shale mainly develops siliceous shale and mixed shale, with small pore diameter, low porosity, high thermal maturity and smaller pore volume and specific surface area than Ordovician–Silurian shale. Devonian–Carboniferous shale has similar mineral composition to Ordovician–Silurian shale, with small pore diameter, low porosity, moderate thermal maturity and similar pore volume and specific surface area to that of Cambrian shale. Permian shale has very complex mineral composition, with large pore diameter, low to medium thermal maturity and small specific surface area. Mineral composition, thermal maturity and tectonic preservation conditions are the main factors controlling shale reservoir development. Siliceous minerals in Cambrian shale and Ordovician–Silurian shale are mainly of biological origin, which make the support capacity better than Devonian–Carboniferous shale and Permian shale (siliceous minerals are mainly of terrigenous origin and biological origin). Thermal maturity of Ordovician–Silurian shale and Devonian–Carboniferous shale is moderate, with a large number of organic pores developed. Thermal maturity of Cambrian shale and Permian shale is respectively too high and too low, the development of organic pores is significantly weaker than the two sets of shale above. There are obvious differences in tectonic preservation conditions inside and outside the Sichuan Basin. Shale reservoirs inside the Sichuan Basin are characterized by overpressure due to stable tectonic activities, while shale reservoirs outside the Sichuan Basin are generally normal–pressure. Four sets of marine shale in South China all have certain resource potentials, but the exploration and development of shale gas is still constrained by complicated geological conditions, single economic shale formation, high exploration and development costs and other aspects. It is necessary for further research on shale gas accumulation theory, exploration and development technology and related policies to promote the development of China’s shale gas industry.
... Alternatively, late syndeformational to post-deformational sedimentation may lead to burial of relict topographic highs generated by formerly active faults; examples include the establishment of late-stage connections among Laramide basins (Lillegraven and Ostresh, 1988;Montagne, 1991;Smith et al., 2014;Lawton, 2019) and the unification of the Midland and Delaware basins within the late Paleozoic Ancestral Rocky Mountain foreland (Ewing, 2019;Fairhurst et al., 2021). Moreover, entirely post-orogenic sedimentation may generate successor basins that fill in preexisting topography at a regional scale (e.g., Dickinson et al., 1988;Graham et al., 1993;Hendrix, 2000;Carroll et al., 2010), thus reducing relief and expanding the cumulative area of a basin system. ...
Broken foreland basins are caused by crustal-scale contractional basement structures that compartmentalize (or break) a contiguous retroarc or collisional foreland basin into smaller disconnected basins. Broken foreland basins differ from their unbroken counterparts in their deformational, depositional, and geodynamic framework. Whereas contiguous (unbroken) foreland basins are generated mainly by regional flexural loading due to shortening of supracrustal cover strata and uppermost basement in organized ramp-flat thrust systems, broken foreland basins are governed principally by isolated topographic loads and structural tilting associated with widely spaced crustal-scale reverse faults that accommodate intraplate basement shortening. These structural contrasts foster either d´ecollement-style fold-thrust belts (orogenic wedges) with large integrated erosional drainage systems (watersheds) spanning diverse sediment source regions (including thin-skinned fold-thrust belts, elevated hinterland zones, accreted terranes, and magmatic arcs) or independent foreland block uplifts with local drainage systems dominated by basement sources. Although the genesis of broken foreland basins has been uniquely attributed to flat slab subduction, these basins are also sensitive to inherited structural, stratigraphic, thermal, and rheological configurations, as well as synorogenic mass redistribution in relationship to climate, erosion, sediment transport efficiency, and sediment accumulation.
Despite the many modern and ancient examples, questions persist over the underlying geodynamic processes that promote development of a broken or compartmentalized foreland basin instead of a single regionally unified flexural foreland basin. Additional uncertainties and misconceptions surround the criteria used to define broken foreland basins and their linkages to subduction dynamics (chiefly slab geometry), strain magnitude, and structural reactivation. Here we review the tectonic framework of broken foreland basins—with emphasis on South and North America (Pampean and Laramide provinces)—and propose that their genesis can be ascribed to a combination of: (i) underlying conditions in the form of tectonic inheritance, including precursor structural, stratigraphic, thermal, and rheological heterogeneities and anisotropies; and (ii) mechanical triggers, such as increased stress, enhanced horizontal stress transmission, and/or selective crustal strengthening or weakening.
... However, from 2000 to 2015, significant technical innovations took place in the petroleum industry; especially, the utilization of directional drilling and hydraulic fracturing technologies made it possible to develop and utilize unconventional tight oil/gas resources that were previously considered to be uncommercial. The Permian Basin's oil and gas production stopped falling and rebounded in 2010, and grew rapidly since 2016, known as the "Golden Age 2.0" [37] . Fryklund believed that the development model of the Permian Basin can be used for reference by many mature basins worldwide [3] . ...
Based on the contemporary strategy of PetroChina and the “Super Basin Thinking” initiative, we analyze the petroleum system, the remaining oil and gas resource distribution, and the Super Basin development scheme in the Sichuan Basin with the aim of unlocking its full resource potential. We conclude that, (1) The three-stage evolution of the Sichuan Basin has resulted in the stereoscopic distribution of hydrocarbon systems dominated by natural gas. The prospecting Nanhua-rift stage gas system is potentially to be found in the ultra-deep part of the basin. The marine-cratonic stage gas system is distributed in the Sinian to Mid-Triassic formations, mainly conventional gas and shale gas resources. The foreland-basin stage tight sand gas and shale oil resources are found in the Upper Triassic–Jurassic formations. Such resource base provides the foundation for the implementation of Super Basin paradigm in the Sichuan Basin. (2) To ensure larger scale hydrocarbon exploration and production, technologies regarding deep to ultra-deep carbonate reservoirs, tight-sand gas, and shale oil are necessarily to be advanced. (3) In order to achieve the full hydrocarbon potential of the Sichuan Basin, pertinent exploration strategies are expected to be proposed with regard to each hydrocarbon system respectively, government and policy supports ought to be strengthened, and new cooperative pattern should be established. Introducing the “Super Basin Thinking” provides references and guidelines for further deployment of hydrocarbon exploration and production in the Sichuan Basin and other developed basins.
... Early Paleozoic sedimentation consisted of passive-margin carbonates and shales, whereas fluvial-deltaic siliciclastic sediments and deepwater carbonates dominated after the structural differentiation of the basin (e.g., Ruppel, 2019a). Permian-age Wolfcampian and Leonardian age units targeted for horizontal drilling, including the Wolfcamp Formation and the Bone Spring group, consist of mixed carbonate-siliciclastic systems (Ruppel, 2019a;Fu et al., 2020;Fairhurst et al., 2021). The Guadalupian-age DMG overlying the Bone Spring group (Figure 3) is the target of shallow SWD and is dominated by clay-poor sandstones, generally accepted as turbidites deposited in the deepwater basin during relative sea-level lowstands (Silver and Todd, 1969;Gardner, 1992;Nance, 2020). ...
The Delaware Basin of Texas and New Mexico is experiencing elevated levels of seismicity. There have been more than 130 earthquakes with moment magnitudes of at least 3.0 recorded between 2017 and 2021, with earthquakes occurring in spatiotemporally isolated and diffuse clusters. Many of these events have been linked to oilfield operations such as hydraulic fracturing and wastewater disposal at multiple subsurface levels; however, the identification and characterization of earthquake-hosting faults have remained elusive. There are two distinct levels of faulting in the central region of the basin where most earthquakes have been measured. These fault systems include a contractional basement-rooted fault system and a shallow extensional fault system. Shallow faults trend parallel to and rotate along with, the azimuth of SHMAX, are vertically decoupled from the basement-rooted faults, accommodate dominantly dip-slip motion, and are the product of more recent processes including regional exhumation and anthropogenic influences. The shallow fault system is composed of northwest–southeast-striking, high angle, and parallel trending faults which delineate a series of elongate, narrow, and extensional graben. Although most apparent in 3D seismic reflection data, these narrow elongate graben features also are observed from interferometric synthetic aperture radar (InSAR) surface deformation measurements and can be delineated using well-located earthquakes. In contrast to the basin-compartmentalizing basement-rooted fault system, shallow faults do not display any shear movement indicators, and they have small throw displacement given their mapped length, producing an anomalous mean throw-to-length ratio of 1:1000. These characteristics indicate that these features are more segmented than can be mapped with conventional subsurface data. Much of the recent seismicity in the south-central Delaware Basin is associated with these faults and InSAR surface deformation observations find that these faults also may be slipping aseismically.
... Due to the horizontal drilling and hydraulic fracturing, shale gas exploration and development in the United States have been relatively successful and energy independence has been realized. The main gas-producing shales in the United States are Devonian shale, Carboniferous shale, and Permian shale, such as Devonian Marcellus shale in Appalachian Basin, Devonian Woodford shale in Anadarko Basin, Carboniferous Barnett shale in Fort Worth Basin, Carboniferous Fayetteville shale in Arkoma Basin, and Permian Wolfcamp shale in Midland Basin [1][2][3][4][5]. ...
Many sets of Paleozoic marine organic-rich shale strata are developed in southern China. However, the exploration and development degree of these strata are different. Cambrian shale and Ordovician-Silurian shale are two horizons with high degree of exploration, while Devonian shale and Carboniferous shale exploration is deficient. Based on XRD, FE-SEM, and gas adsorption experiment, pore development characteristics and controlling factors of Devonian and Carboniferous shale are investigated. There are mainly four lithofacies in Devonian and Carboniferous shale: mixed shale (M), carbonate/siliceous mixed shale (M-1), argillaceous/siliceous mixed shale (M-2), and argillaceous-rich siliceous shale (S-3). Reservoir characteristics of both two sets of shale strata are quite different. The averages of porosity, pore volume, and specific surface area of Devonian shale are 3.81%,9.7×10−3 cm³/g and 11.8 m²/g, while those of Carboniferous shale are 3.57%, 17.3×10−3 cm³/g and 19.8 m²/g. Thermal evolution (Ro) and tectonic preservation conditions are the main factors affecting the pore development. Carboniferous shale (Ro≈2%) is in the stage of producing a large number of organic pores. Devonian shale (Ro≈3.5%) is having difficulty preserving organic pores due to high thermal evolution. Meanwhile, Devonian shale (well GTD1) is strongly affected by tectonic movement; tectonic fractures and calcite veins are developed. Carboniferous shale (well GRY1) is in relatively stable area; tectonic fractures are not developed. Under the influence of compaction, the pore volume and specific surface area of Carboniferous shale are 78.3% and 67.8% higher than those of Devonian shale, respectively. This research can provide reference for clarifying shale pore development and evolution mechanism and similar shale gas exploration both in study area and around the world.
