Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch Fort Worth Basin, Texas

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1 Geologic framework of the Mississippian Barnett Shale, Barnett-Paleozoic total petroleum system, Bend arch Fort Worth Basin, Texas Richard M. Pollastro, Daniel M. Jarvie, Ronald J. Hill, and Craig W. Adams ABSTRACT This article describes the primary geologic characteristics and criteria of the Barnett Shale and Barnett-Paleozoic total petroleum system (TPS) of the Fort Worth Basin used to define two geographic areas of the Barnett Shale for petroleum resource assessment. From these two areas, referred to as assessment units, the U.S. Geological Survey estimated a mean volume of about 26 tcf of undiscovered, technically recoverable hydrocarbon gas in the Barnett Shale. The Mississippian Barnett Shale is the primary source rock for oil and gas produced from Paleozoic reservoir rocks in the Bend arch Fort Worth Basin area and is also one of the most significant gasproducing formations in Texas. Subsurface mapping from well logs and commercial databases and petroleum geochemistry demonstrate that the Barnett Shale is organic rich and thermally mature for hydrocarbon generation over most of the Bend arch Fort Worth Basin area. In the northeastern and structurally deepest part of the Fort Worth Basin adjacent to the Muenster arch, the formation is more than 1000 ft (305 m) thick and interbedded with thick limestone units; westward, it thins rapidly over the Mississippian Chappel shelf to only a few tens of feet. The Barnett-Paleozoic TPS is identified where thermally mature Barnett Shale has generated large volumes of hydrocarbons and is (1) contained within the Barnett Shale unconventional continuous accumulation and (2) expelled and distributed among numerous conventional clastic- and carbonate-rock reservoirs of Paleozoic age. Vitrinite reflectance (R o ) measurements show little correlation with present-day burial depth. Contours of equal R o values measured from Barnett Shale and typing of produced hydrocarbons indicate Copyright #2007. The American Association of Petroleum Geologists. All rights reserved. Manuscript received January 25, 2006; provisional acceptance March 15, 2006; revised manuscript received August 2, 2006; final acceptance October 30, DOI: / AUTHORS Richard M. Pollastro Central Energy Resources Team, U.S. Geological Survey, Box 25046, MS 939, Denver, Colorado 80225; pollastro@usgs.gov Rich Pollastro received an M.A. degree in geology from the State University of New York at Buffalo in Rich joined the U.S. Geological Survey in 1978 and serves as a province geologist on the national and world energy assessment projects. His recent accomplishments include petroleum system assessments of the Fort Worth, Permian, and South Florida basins and the Arabian Peninsula. Daniel M. Jarvie Humble Instruments and Services, Inc., Humble Geochemical Services Division, P.O. Box 789, Humble, Texas 77347; danjarvie@humble-inc.com Dan Jarvie is an organic geochemist and president of Humble Geochemical Services. Dan earned his B.S. degree from the University of Notre Dame and was mentored in geochemistry by Don Baker and Wallace Dow. He has studied unconventional oil and gas systems extensively since Dan s work on the Barnett Shale spans much of the last decade, which has resulted in several AAPG awards. Ronald J. Hill Central Energy Resources Team, U.S. Geological Survey, Box 25046, MS 939, Denver, Colorado 80225; ronhill@usgs.gov Ronald Hill specializes in petroleum geochemistry and has more than 12 years of oil industry experience. Currently, he is a research geologist for the U.S. Geological Survey. His research interests include shale-gas resources and processes that control petroleum generation. Ron holds geology degrees from the Michigan State University (B.S. degree) and the University of California, Los Angeles (Ph.D.), and a geochemistry degree from the Colorado School of Mines (M.S. degree). Craig W. Adams ADEXCO Production Company, 309 West 7th Street, Ste. 400, Fort Worth, Texas 7610; craig@adexco.net Craig Adams worked as an exploration geologist with Amoco Production Company for 13 years before becoming an independent in As president and co-owner of Adexco AAPG Bulletin, v. 91, no. 4 (April 2007), pp

2 Production Company, his primary focus is conventional and unconventional oil and gas in Texas and the mid-continent. Craig has worked the Barnett Shale for 6 years, where his company was one of the first to expand beyond the core area of the Newark East field. ACKNOWLEDGEMENTS This study benefited from contributions of several individuals and independent exploration companies. We especially thank Republic Energy, particularly Brad Curtis and Dan Steward, for discussing the Barnett Shale play and for permissions and arrangements to sample oil and gas from Republic Energy wells. We thank Kent Bowker, David Martineau, Tony Carvalho, and Robert Cluff for their helpful discussions that resulted in a more comprehensive understanding of the geologic framework, production characteristics, and historical evolution of the Barnett Shale play. We are especially grateful to the reviews of the manuscript in its early stages made by Tom Ahlbrandt, Neil Fishman, and Dick Keefer at the U.S. Geological Survey, and the especially thorough and critical reviews from an anonymous AAPG reviewer and AAPG reviewers Ken Peters and Barry Katz, all of which have greatly improved the manuscript. significant uplift and erosion. Furthermore, the thermal history of the formation was enhanced by hydrothermal events along the Ouachita thrust front and Mineral Wells Newark East fault system. Stratigraphy and thermal maturity define two gas-producing assessment units for the Barnett Shale: (1) a greater Newark East fracture-barrier continuous Barnett Shale gas assessment unit, encompassing an area of optimal gas production where dense impermeable limestones enclose thick (300 ft; 91 m) Barnett Shale that is within the gas-generation window (R o 1.1%); and (2) an extended continuous Barnett Shale gas assessment unit covering an area where the Barnett Shale is within the gas-generation window, but is less than 300 ft (91 m) thick, and either one or both of the overlying and underlying limestone barriers are absent. INTRODUCTION The Bend arch Fort Worth Basin area of north-central Texas is a mature petroleum province (Figure 1) where exploration and production of oil and gas has been ongoing since the early 1900s. Prior to about 1998, production was mostly from conventional reservoirs ranging in age from Ordovician to Permian (Ball and Perry, 1996). Of recent importance, however, is the recognition that a giant continuous (unconventional), nonassociated gas accumulation exists within the Mississippian Barnett Shale. Since 2000, annual gas production from the Barnett Shale has established the greater Newark East field (Figure 1) as the largest gas-producing field in Texas (EIA, 2002; Rach, 2004). Subsequently, Barnett Shale Newark East field now ranks second in the United States in terms of annual gas production (EIA, 2005). Cumulative gas production from January 1993 to January 2006 from the Barnett Shale Newark East field was about 1.8 tcf; in 2005, gas production was about 480 bcf compared to less than 11 bcf in 1993 (Texas Railroad Commission, 2006). Proven gas reserves for Newark East field are estimated to be between 2.5 and 3.0 tcf (Bowker, 2003). In addition, the U.S. Geological Survey recently estimated a total mean volume of undiscovered, technically recoverable gas of about 26 tcf in two Barnett Shale gas assessment units within the Fort Worth Basin (Pollastro et al., 2004b; Pollastro, 2007). A geologic framework was constructed jointly by the U.S. Geological Survey and Adexco Production Company (Fort Worth, Texas) for the Barnett Shale within the Bend arch Fort Worth Basin area from well logs, commercial well databases, and scientific literature to (1) determine the geographic extent and stratigraphic relations of the Barnett Shale with underlying and overlying formations and (2) define favorable areas for undiscovered recoverable gas and oil resources in the Barnett Shale. A joint petroleum geochemistry study of the Barnett Shale was also established between the U.S. Geological Survey and Humble Geochemical Services (Humble, Texas) to identify total petroleum systems (TPS) within the area by (1) identifying major source rocks, (2) characterizing oil and gas 406 Barnett Shale, Bend Arch Fort Worth Basin, Texas

3 Figure 1. Map shows the area of U.S. Geological Survey (USGS) Bend arch Fort Worth Basin province 45, major structural features, location of Newark East and Boonsville fields, extent of Mississippian Barnett Shale and Barnett-Paleozoic TPS, and relation to historical production in north-central Texas and southwest Oklahoma. Oil cells contain only oil wells; gas cells contain only gas wells; and mixed oil and gas cells contain both oil and gas wells. Cell data were derived from IHS Energy (2003). Cell size is equal to 0.25 mi 2 (0.64 km 2 ). Pollastro et al. 407

4 produced from both Paleozoic-age conventional reservoirs and from continuous accumulations within the Barnett Shale, and (3) identifying areas where the Barnett Shale is within the oil and thermogenic gasgeneration windows. Total organic carbon (TOC) and mean vitrinite reflectance (R o ) analyses were performed by Humble Geochemical Services. Sample location, descriptions, and details and interpretations of organic geochemistry and R o ofthebarnettshalearefoundincompanion articles by Jarvie et al. (2007) and Hill et al. (2007). The purpose of this article is to present an overview of the geologic framework and thermal history of the Barnett Shale in the context of the TPS. Using the interpretations of organic geochemistry from companion articles by Jarvie et al. (2007) and Hill et al. (2007), the geologic framework is combined to define the Barnett-Paleozoic TPS of the Bend arch Fort Worth Basin to further determine the geographic extent and stratigraphic relations of the Barnett Shale and favorable areas for undiscovered, technically recoverable gas in the Barnett Shale for resource assessment. Finally, these relations and interpretation are used for the assessment of undiscovered gas in the Barnett Shale discussed in a companion article by Pollastro (2007). TOTAL PETROLEUM SYSTEM, RESOURCE ASSESSMENT, AND THE BARNETT SHALE CONTINUOUS ACCUMULATION Current U.S. Geological Survey assessments to estimate undiscovered oil and gas resources are based on the TPS assessment unit methodology (Klett et al., 2000; Magoon and Schmoker, 2000; Pollastro, 2007). Similar to the petroleum system, principal geologic elements of a TPS include source, reservoir, and seal rocks and hydrocarbon traps. The TPS is different from the more conventional petroleum system definition. The conventional definition of a petroleum system by Magoon and Dow (1994) includes an area of all known accumulations linked to a specific pod (or pods) of mature source rock. The TPS, however, is better suitable for resource assessment because it also incorporates areas of petroleum potential related to the pod(s) of mature source rock where undiscovered accumulations may exist because of hydrocarbon migration. In general, the assessment unit is categorized into one of two primary end-member types of accumulations (conventional and continuous) that are identified for assessment purposes, although some accumulations may contain characteristics of both, indicating that a transitional-type accumulation may also exist (Schenk and Pollastro, 2002; Pollastro, 2007). Because the methodology used to assess continuous-type accumulations is much different from that for conventional accumulations (Schmoker, 1999, 2002), the characterization of reservoirs within a TPS is critical to assess undiscovered resources. The Barnett Shale of the Fort Worth Basin, Texas, is the foremost example of a continuous-type, shale-gas accumulation. Samples of (1) oil and gas from numerous Paleozoic reservoirs, and (2) cuttings and cores of the Barnett Shale, as well as other potential source rocks, were collected from wells throughout the Bend arch Forth Worth Basin area and analyzed in a joint study by Humble Geochemical Services and the U.S. Geological Survey (Figure 2A). The study concluded that the organic-rich, Mississippian Barnett Shale is the primary source rock for oil and gas produced from reservoirs of Paleozoic age in the Bend arch Fort Worth Basin area (Jarvie et al., 2001; 2004a, b; 2005; 2007; Pollastro et al., 2003; Hill et al., 2007). Although other stratigraphic units show limited source potential, including organic-rich facies of Pennsylvanian age, correlation of oils to both oil produced from the Barnett Shale and rock extracts of the Barnett Shale indicates that the Barnett is the source of most of the oil and gas in the basin (Jarvie et al., 2001, 2004). For example, fingerprinting of oil produced from lowmaturity Barnett Shale in Brown County, Texas, using gas chromatography, biomarkers, and carbon isotopes correlates with other oils from reservoirs in the western part of the basin in Shackelford, Callahan, and Throckmorton counties, and that most of the oils are low in sulfur and originated from a marine shale source rock. Similarly, light hydrocarbons, biomarkers, and carbon isotopes of the same oils correlate with condensates in the central Barnett Shale, producing horizons of Newark East field. Barnett Shale derived oil and gas are found in all reservoirs of Ordovician (Ellenburger Group) to Lower Permian age (Jarvie et al., 2004a, b; 2005; 2007; Hill et al., 2007), thus defining the stratigraphic distribution of the Barnett-Paleozoic TPS. Ordovician, Mississippian, and lower Pennsylvanian reservoirs are mostly carbonate rocks, whereas clastic rocks dominate the middle Pennsylvanian to Lower Permian reservoirs (Figure 3). Although new data are available because of recent gas drilling and production in the Barnett Shale play, the distribution of oil and gas within the Bend arch Fort Worth Basin is generally shown in the 0.25-mi 2 (0.64-km 2 ) cell map of Figure 1 compiled in Here, if a cell contains only oil cells, it is designated as an oil cell. Similarly, if only gas wells fall within the cell, it is 408 Barnett Shale, Bend Arch Fort Worth Basin, Texas

5 Pollastro et al. 409 Figure 2. (A) Maps shows area of U.S. Geological Survey (USGS) province 45 (termed the Bend arch Fort Worth Basin province ), geographic extent of the Mississippian Barnett Shale, major structural features, Newark East and Boonsville fields, and general locations of wells sampled for oil and gas and total organic carbon analyses. (B) Map shows boundary of Barnett-Paleozoic TPS and major structural elements in the Bend arch Fort Worth Basin province. Modified from Pollastro (2003).

6 designated as a gas cell. If the cell contains both oil and gas wells, it is designated as a mixed oil and gas cell. The distribution of oil, gas, and mixed oil and gas produced in the Bend arch Fort Worth Basin on the basis of the cell map reveals some significant trends that can be attributed to the thermal maturity of the Barnett Shale source rock. Most gas cells are found along the northeastern part of the basin or along the Ouachita thrust front. These areas are the deeper and more thermally mature parts of the basin. Oil cells are concentrated to the north and west, where thermal-maturity levels are lower. Mixed oil and gas cells occur mostly in transition zones between oil and gas cell concentrations. The lack of productive cells in the eastern part of the basin and along the Ouachita thrust front is mostly caused by (1) the lack of quality conventional reservoirs in the area and (2) historical well production data for Figure 1, which was limited to early 2003 because it was generated at the time of the 2003 U.S. Geological Survey assessment (Pollastro et al., 2004b). Since early 2003, about 3000 additional gas wells have been completed in the Barnett Shale, with several hundred of these wells completed in counties along the eastern part of the basin. The approximate geographic boundary of the Barnett-Paleozoic TPS is shown in the oil and gas cell map of Figure 1 and in Figure 2B; petroleum system elements and events for the Barnett-Paleozoic TPS are summarized in Figure 4. Combining the petroleum geochemistry studies of Jarvie et al. (2004b, 2005, 2007) and Hill et al. (2007) with framework geology and vitrinite reflectance (R o ) thermal-maturity data, we define a Barnett-Paleozoic TPS (Pollastro, 2003; Pollastro et al., 2003, 2004a) for the purpose of understanding petroleum systems and assessing undiscovered resources in this area, with emphasis on the unconventional, nonassociated gas accumulation in the Barnett Shale. STRUCTURAL EVOLUTION AND GENERAL STRATIGRAPHY OF THE BEND ARCH FORT WORTH BASIN Figure 3. Generalized subsurface stratigraphic section of the Bend arch Fort Worth Basin province showing the distribution of source rocks, reservoir rocks, and seal rocks of the Barnett- Paleozoic TPS. Modified from Pollastro (2003). The Fort Worth Basin is a shallow, north-south elongated trough encompassing roughly 15,000 mi 2 (38,100 km 2 ) in north-central Texas (Figure 1). It is one of several foreland basins formed during the late Paleozoic Ouachita orogeny, a major tectonic event of thrust-fold deformation resulting from collision tectonics ( Walper, 1982; Thompson, 1988). The Ouachita thrust front forms the eastern boundary of the Fort Worth Basin (Figures 1, 2). Other basins in this trend include the Black Warrior, 410 Barnett Shale, Bend Arch Fort Worth Basin, Texas

7 Pollastro et al. 411 Figure 4. Petroleum system events chart for Barnett-Paleozoic TPS of the Fort Worth Basin, Texas. Abbreviations: E = early; M = Middle; L = late; Cam = Cambrian; Ord = Ordovician; Sil = Silurian; Dev = Devonian; Mis = Mississippian; Pen = Pennsylvanian; Per = Permian; Tr = Triassic; Jur = Jurassic; Cret = Cretaceous; Ter = Tertiary; Cen = Cenozoic; O = Oligocene; Mi = Miocene.

8 Arkoma, Kerr, Val Verde, and Marfa basins (Flawn et al., 1961). The Fort Worth Basin is a wedge-shaped, northwarddeepening depression; the general structure is shown by the Ellenburger Group structure contour map in Figure 5. The axis roughly parallels the Muenster arch, which bounds the basin to the north-northeast, then bends southward to parallel the Ouachita structural front (Figure 5). The opposing hinge line and consequent limits of the Fort Worth Basin shifted west and northwest throughout the early and middle Pennsylvanian in response to the rising Ouachita fold belt to the east (Tai, 1979). The north margin of the basin is formed by fault-bounded basement uplifts of the Red River and Muenster arches (Figure 5). These features are part of the northwest-striking Amarillo-Wichita uplift trend and were formed by reactivation of basement faults associated with the Oklahoma aulocogen during Ouachita compression (Walper, 1977, 1982). The Fort Worth Basin shallows to the west against a series of gentle positive features including the Bend arch, Eastern shelf, and Concho arch (Figure 2B). The Bend arch is a large, north-plunging positive subsurface structure extending north from the Llano uplift of central Texas (Figures 1, 2). The arch is postulated to have formed by subsidence of the Fort Worth Basin beginning in the late Mississippian, combined with westward tilting in the late Paleozoic, which created the Midland Basin to the west (Walper, 1977, 1982; Tai, 1979). Thus, the Bend arch is a flexure and structural high that formed without being actively uplifted; it represents the major and final westernmost hinge line of the presentday Fort Worth Basin. The Llano uplift, a domal feature that exposes Precambrian and Paleozoic (Cambrian Pennsylvanian) rocks, forms part of the southern boundary of the Fort Worth Basin (Figures 2, 5). The Llano uplift had intermittent positive movements beginning in the Precambrian (Flawn et al., 1961). Sections of the Barnett Shale are exposed along the uplift in Lampasas and San Saba counties (Grayson et al., 1991). A secondary structural feature in the southern part of the basin is the Lampasas arch, which extends northeastward from the Llano uplift and closely parallels the Ouachita structural front (Figure 2B). Other structures in the Fort Worth Basin include (1) major and minor faults, (2) local folds, (3) fractures, (4) karst-related collapse features of the Ellenburger Group, and (5) thrust-fold structures. Major basement reverse faults, possibly strike-slip displacements, define the south margin of the Red River and Muenster arches (Flawn et al., 1961; Henry, 1982). Isopach maps of the Mississippian rocks (mainly Barnett Shale) in Montague County indicate the presence of local fault blocks in the northern part of the Fort Worth Basin (Henry, 1982). Thrust-fold structures are interpreted to exist in the easternmost parts of the basin (Walper, 1982) and involve, or override, Mississippian and older rocks. An important structural feature in the main area of the Barnett Shale gas production is the Mineral Wells fault (Figures 1, 2B), a prominent northeast-southwest trending structure that has been mapped in the subsurface in Palo Pinto, Parker, Wise, and Denton counties. The fault cuts across Newark East field in its northeastern part; the fault system is also informally referred to as the Mineral Wells Newark East fault system (Pollastro et al., 2003, 2004a). The origin of the Mineral Wells fault is not completely understood because it does not appear to be directly related to either the fault blocks of the Muenster and Red River arches or Ouachita thrusting. However, proprietary seismic data indicate that it is a basement fault that underwent periodic reactivation, particularly during the late Paleozoic (Montgomery et al., 2005), with possibly some recurrent movement during the Mississippian (Pollastro, 2003). Studies have shown that the Mineral Wells fault was a significant factorin(1)thedepositionofbendgroupconglomerates (Thompson, 1982); (2) influencing depositional patterns and thermal history of the Barnett Shale (Bowker, 2003; Pollastro, 2003; Pollastro et al., 2004a; Montgomery et al., 2006); (3) controlling migration and distribution of oil-associated gas at Boonsville field in the northern Fort Worth Basin (Figure 2A) (Jarvie et al., 2003, 2004b, 2005; Pollastro et al., 2004a); and (4) inhibiting gas production from Barnett Shale where the Mineral Wells fault zone and associated fractures intersect Newark East field (Bowker, 2003; Pollastro, 2003). Minor high-angle normal faults and graben-type features are present in many parts of the basin (Reily, 1982; Williams, 1982). The changing orientation of these structures argues for their being related to several major tectonic elements. For example, at Boonsville and Newark East fields, high-density stratigraphic well control shows many normal faults that trend northeast to southwest, parallel or subparallel to the Mineral Wells Newark East fault. In the central basin, faults have a north-south trend and appear to be related to the Ouachita structural front to the east (Adams, 2003; Montgomery et al., 2005, 2006). Natural fractures associated with fault trends occur in conventional cores taken from wells that penetrate the Barnett Shale, particularly at the Newark East field. Such fractures are commonly filled with carbonate cement (Bowker, 2003). A recent 3-D seismic study at 412 Barnett Shale, Bend Arch Fort Worth Basin, Texas

9 Figure 5. Generalized structure contour map, top of Ellenburger Group, Fort Worth Basin Bend arch area of north-central Texas. Data interpreted from subsurface log and IHS well-history database (IHS Energy, 2003). Pollastro et al. 413

10 Boonsville field shows small-scale faulting and local subsidence in Mississippian to middle Pennsylvanian (Strawn Formation) strata that are related to karst development and solution collapse in the underlying Ordovician Ellenburger Group (Hardage et al., 1996). Sedimentary rocks in the Fort Worth Basin reach a maximum thickness of about 12,000 ft (3660 m) adjacent to the Muenster arch. The subsurface stratigraphic section consists of ft ( m) of Ordovician Mississippian carbonates and shales, ft ( m) of Pennsylvanian clastics and carbonates, and, in the eastern parts of the basin, a thin veneer of Cretaceous rocks (Flawn et al., 1961; Henry, 1982; Lahti and Huber, 1982; Thompson, 1988). Stratigraphic relations and burial-history reconstructions indicate that a thick (>4000 ft; >1220 m) section of upper Pennsylvanian and possibly Permian strata was eroded prior to the incursion of Early Cretaceous seas (Henry, 1982; Walper, 1982). Sedimentary rocks are underlain by Precambrian granite and diorite basement (Figure 3). From the Cambrian to the Mississippian, the area that is now the Fort Worth Basin was part of a stable cratonic shelf, with deposition dominated by carbonates (Turner, 1957; Burgess, 1976). Ellenburger Group carbonate rocks represent a broad epeiric carbonate platform that covered virtually all of Texas during the Early Ordovician. A pronounced drop in sea level at the end of Ellenburger deposition resulted in prolonged platform exposure and extensive karst features in the upper part of the carbonate sequence (Sloss, 1976; Kerans, 1988). Moreover, a later major erosional event removed any Silurian and Devonian rocks that may have been present in that area (Henry, 1982). The Barnett Shale was deposited over the resulting unconformity over most of the Fort Worth Basin. In the area of the Chappel shelf (Figures 6, 7A), pinnacle reefs and mounds of the Chappel Limestone were deposited on the Ellenburger unconformity. In this area, the upper part of the lower Barnett Shale thins over the shelf and drapes these pinnacle reefs and mounds to form the seal for Chappel Limestone reservoirs. Mississippian rocks consist of alternating shallowmarine limestones and black, organic-rich shales; however, the Mississippian section is not well defined because of lack of sufficient diagnostic fossils. The Pennsylvanian (Morrowan) Marble Falls Limestone overlies the Barnett Shale (Figures 3, 8) and includes an upper limestone interval and a lower unit of interbedded dark limestone and gray-black shale, sometimes referred to as the Comyn Formation. The lower shale part of the lower Marble Falls is commonly used as a marker unit, but is also commonly mistaken on subsurface well logs for the Barnett Shale (informally referred to by the industry as false Barnett ). This shale marker unit or false Barnett in the lower Marble Falls is shown on the log section of Figure 8 and on the cross sections in Figures 9 and 10. Uppermost Mississippian and lowermost Pennsylvanian rocks appear conformable but may include disconformities in some areas (e.g., proximal to the Muenster arch) (Flippin, 1982; Henry, 1982). Pennsylvanian rocks above the Marble Falls generally consist of clastic and mixed carbonate deposits that represent a range of westward-prograding fluvialdeltaic environments, and transgressive carbonate bank deposits (Cleaves, 1982; Thompson, 1988). Terrigenous clastics originated mainly from uplifts of the Muenster arch and the Ouachita fold and thrust belt to the north and east and represent the main phase of subsidence and basin infilling during major advancement of the Ouachita structural front. Sediment loading and basin formation by the westward-advancing thrust front caused a progressive westward shift of depocenters (Thompson, 1988). Lower Pennsylvanian deposits consist of Atokan conglomerates, sandstones, shales, and thin limestones deposited in settings ranging from marine to marginal marine to continental (Thompson, 1982). Depositional patterns in lower Pennsylvanian (Atokan) rocks indicate that the Muenster arch was an active sediment source prior to major uplift (Lovick et al., 1982). Tectonism along the Muenster arch probably involved the rejuvenation of older, deep-seated basement faults, associated in part with the Oklahoma aulacogen (Flawn et al., 1961; Walper, 1977, 1982). Permian rocks occur in parts of the Fort Worth Basin, but no Triassic or Jurassic rocks have been identified, probably because of pre-cretaceous erosion. Cretaceous rocks of the Comanche series overlie the tilted and eroded Paleozoic sequence along the eastern part of the basin (Walper, 1982). Cretaceous rocks are not productive of hydrocarbons, but are major groundwater aquifers where present (Herkommer and Denke, 1982). RESULTS, INTERPRETATION, AND APPLICATION Barnett Shale Deposition, Geographic Distribution, and Stratigraphic Framework The Barnett Shale was deposited over a large part of north-central Texas during the late Mississippian in a remnant of the southern part of an early Paleozoic aulacogen during the early formation of the Fort Worth 414 Barnett Shale, Bend Arch Fort Worth Basin, Texas

11 Figure 6. Map showing regional extent of Barnett Shale, thickness of Barnett Shale in selected wells, generalized regional isopachs of Barnett Shale, and lines of well-log cross sections AA 0 of Figure 9 and BB 0 of Figure 10. Contour intervals are 50 ft (15 m) for thicknesses from 0 to 300 ft (0 to 91 m) and 100 ft (30 m) for thicknesses from 300 to 1000 ft (91 to 305 m). Modified from Pollastro (2003). Pollastro et al. 415

12 416 Barnett Shale, Bend Arch Fort Worth Basin, Texas

13 Figure 8. Typical well-log stratigraphic section showing gamma-ray and resistivity logs through the Barnett Shale and overlying and underlying units. Depth in feet. Basin (Figure 7). The basin formed in response to the collision of the North and South American plates. During convergence and collision, downwarping or subsidence occurred along rejuvenated zones of weakness associated with the aulacogen. Continued collision during the early Pennsylvanian caused overthrusting along the eastern margin of the basin (Figure 11), the formation of the Ouachita geosyncline, and the onset of the orogeny (Henry, 1982; McBee, 1999). Terrigenous material in the Barnett Shale was likely derived from areas of Figure 7. Paleogeographic maps of north Texas and southwestern Oklahoma during the Mississippian. (A) The Osagean showing incipient subduction zone and consequent uplift adjacent to present-day Fort Worth Basin and areas of deposition of the lower part of the Barnett Shale (dark shading), position of Chappel shelf and bioherm deposition. Emergent areas are lightly shaded. (B) The Chesterian showing major structural features and area of upper Barnett Shale, or equivalent, deposition (dark shading). Emergent areas are light shaded. Modified from McBee (1999). Pollastro et al. 417

14 418 Barnett Shale, Bend Arch Fort Worth Basin, Texas Figure 9. Generalized southwest-northeast stratigraphic cross section AA 0 based on well-log correlations; line of section is from Figure 6. Gamma-log profile (red) and resistivitylog profile (yellow) are shown for reference on selected wells. Not to scale horizontally.

15 incipient subduction to the east and from reactivation of older fault block structures such as the Muenster and Red River arches to the northeast and north (Figure 7). Active uplift and nondeposition in the areas later designated as the Ouachita thrust front and Muenster arch (as illustrated in the paleogeographic map in Figure 7B) also explain the absence of Barnett Shale in the Sherman- Marietta Basin to the northeast (Figure 2B). The entire sub-pennsylvanian Paleozoic section, including probably some Barnett Shale, was eroded from these faultblock structures (Flawn et al., 1961; Henry, 1982). The Barnett Shale and equivalent shale units in Texas, Oklahoma, Arkansas, and New Mexico were apparently depositedonashelforinabasinareamarginaltothe Ouachita geosyncline (Figure 7). The eastward thickening of the Barnett Shale (Figure 6) indicates a source to the east or northeast. Black petroliferous mudstone and the local presence of glauconite and phosphatic material indicate rather slow deposition under reducing conditions, particularly in the basal part of the Barnett Shale in the Fort Worth Basin (Mapel et al., 1979). Barnett Shale is absent both north of the Muenster arch in the Sherman-Marietta Basin and east of the Ouachita thrust belt (Figure 2B). The present-day geographic distribution of the formation in the Bend arch Forth Worth Basin area (Pollastro, 2003), as shown in Figures 1, 2, and 6, was determined using subsurface geophysical well logs, the IHS well-history database (IHS Energy, 2003), and the well data of Mapel et al. (1979). Barnett Shale is present in the Hardeman Basin to the north, where an oil-prone Barnett Shale petroleum system, the Barnett-Hardeman TPS (Figure 2B), has been defined (Pollastro et al., 2004a, b); the Barnett Shale is also present in the Midland, Delaware, and Palo Duro basins to the west. Along the Eastern shelf, the Barnett Shale is generally absent because of erosion and a facies change into limestone to the northwest along the Chappel shelf (Figure 7); however, small isolated remnants of the formation have been identified on the karsted surface of the Ordovician Ellenburger Group (Mapel et al., 1979). Several stratigraphic cross sections and isopach maps, including total Barnett Shale and various intervals within,above,andbelowit,weremadefrommorethan 300 subsurface geophysical logs. Figure 6 is a generalized isopach map of the total Barnett Shale in the Bend Figure 10. Generalized northeast-southwest stratigraphic cross section BB 0 based on well-log correlations; line of section is from Figure 6. Gamma-log profile (red) and resistivity-log profile (yellow) are shown for reference on selected wells. Not to scale horizontally. Pollastro et al. 419

16 Figure 11. Paleogeographic maps of north-central Texas and southwestern Oklahoma. (A) The Pennsylvanian (Morrowan) shows areas of Ouachita thrusting, consequent uplift and basin formation, and areas of deposition of limestone and shale facies of the Marble Falls Formation. (B) Late Ordovician shows areas of Viola Limestone and Sylvan Shale deposition. Emergent areas are light shaded. Modified from McBee (1999). 420 Barnett Shale, Bend Arch Fort Worth Basin, Texas

17 arch Fort Worth Basin area, updated from Pollastro (2003). The geographic extent of the formation in this area is partly controlled by the Red River and Muenster arches to the north and the Ouachita structural front to the south and southeast. In the northern part of the Fort Worth Basin, the Barnett Shale averages about 250 ft (76 m) thick; it is thickest, more than 1000 ft (305 m), in the deepest part of the basin adjacent to the Muenster arch (Figure 6), where it is interbedded with limestone units that have a cumulative thickness of as much as 400 ft (122 m) (Mapel et al., 1979; Henry, 1982; Bowker, 2003; Pollastro, 2003; Texas Railroad Commission, 2003). The Barnett thins rapidly to the west to only a few tens of feet over the Mississippian Chappel shelf and along the Llano uplift (Figures 6, 10). In summary, the Barnett Shale is absent in areas (1) where eroded along the Red River arch and Muenster arch to the north and northeast; (2) along the Llano uplift to the south; and (3) to the west, where there is an erosional limit and a facies change to limestone. The isopach map in Figure 6 also shows three general trends of increased thickness of the Barnett Shale that are unrelated to present-day basin geometry and axis but show some relation to other structural elements within the basin. Two of these thickening trends encircle the Chappel shelf: an east-west trend perpendicular to the Bend arch through Palo Pinto, Shackelford, and Stephens counties, and a northwest-southeast trend in the northern part of the basin through Jack, Clay, and Archer counties (Figure 6). The thickening of Barnett Shale along these trends is not understood; however, the east-west trend is near coincident with elevated thermal maturities of the Barnett Shale (Figure 12), as indicated by mean vitrinite reflectance values (R o = 0.9%), as discussed in the section below. Pollastro (2003) suggested that east-west faulting in the basin may have controlled the deposition of Barnett Shale in this area. The third trend of Barnett Shale thickening is through Hood, Erath, Comanche, and Hamilton counties, north and subparallel to the Ouachita structural front. This trend may represent an ancestral axis during the incipient formation of the Fort Worth foreland basin and Barnett Shale deposition. Based on the well-log interpretations of Figure 8, generalized stratigraphic cross sections were constructed showing the lithology and thickness of the Barnett Shale (Figures 9, 10). It commonly exhibits a high gamma-raylog response at the base (basal hot shale in Figure 8) that can be traced throughout most of the basin. Thick (as much as 1000 ft [305 m]) sections of the Barnett Shale in the deepest part of the Fort Worth Basin adjacent to the Muenster arch contain interbedded thick limestone units that are informally referred to as lime wash in some places (Texas Railroad Commission, 2003). These limestones (not shown in the cross sections of Figures 9, 10, but mapped in Figure 13A) thin rapidly to the south and west away from the Muenster arch. Bowker (2003) suggested that they were deposited as debris flows from a source to the north, probably the Muenster arch. Westward thinning of the Barnett Shale over the Chappel shelf is also shown on the cross section infigure10. In the area of Newark East field, the Barnett Shale is informally divided into lower and upper intervals that are separated by a carbonate rock unit informally known as the Forestburg limestone (Henry, 1982) (Figures 8, 9). The upper Barnett Shale and Forestburg limestone are present over much of the Newark East field area. The Forestburg limestone is absent to the south and west of the field, whereas the upper part of the Barnett Shale (referred to hereafter as the upper Barnett Shale ) can be traced farther westward (Figures 9, 14). Near the Muenster arch, the Forestburg limestone reaches a thickness exceeding 200 ft (61 m), but thins rapidly to the south and west to a feather edge in the southernmost Wise and Denton counties (Figures 9, 13B). This tight limestone unit is not an exploration target, but is important for more successful vertical well completions because it forms an impermeable barrier that helps to limit the zone of induced fractures that are normally required to stimulate production in Barnett Shale gas wells. Where the Forestburg limestone is absent, upper and lower Barnett Shale are undifferentiated on well logs and maps. To the west and southwest of Newark East field, the Barnett Shale thins rapidly, and only the lower part (referred to hereafter as the lower Barnett Shale ) is present. In this area, the upper Barnett Shale changes facies from shale to limestone (Grayson et al., 1991; McBee, 1999) (Figure 7). The Marble Falls Limestone (Pennsylvanian Morrowan), which immediately overlies the Barnett, grades from limestone at the Newark East field into shale in the southeastern part of the basin (Figures 9, 11A). At the Newark East field, the formation, like the Forestburg limestone, is a dense impermeable limestone and forms an effective fracture barrier for containing the induced fracturing of Barnett Shale gas wells. Well data indicate that the Marble Falls Limestone thins rapidly south of the Newark East field, where there is a facies change to shale (Figure 11A) in the east-central part of the Fort Worth Basin (McBee, 1999; Adams, 2003; Bowker, 2003; Pollastro, 2003). Thus, the southern geographic limit Pollastro et al. 421

18 Figure 12. Map shows lines of equal thermal maturity as determined from mean vitrinite reflectance (R o ) of Barnett Shale. Based on data from Humble Geochemical Services, Humble, Texas. Areas of probable high hydrothermal heating and anomalously high R o are also indicated (arrows). 422 Barnett Shale, Bend Arch Fort Worth Basin, Texas

19 of the dense limestone facies is an important boundary for exploration and exploitation of the main Barnett Shale play area. In the southern part of the Fort Worth Basin and in Brown, Comanche, Mills, and Hamilton counties, the Marble Falls Limestone is a conventional hydrocarbon play. In those areas, the formation consists of a carbonate bank complex that produces gas from mostly conventional stratigraphic traps at depths between 2000 and 3000 ft (610 and 914 m) (Namy, 1982). The Mississippian section in the Fort Worth Basin is thickest just southwest of the Muenster arch, where the Barnett Shale is more than 1000 ft (305 m) thick and contains relatively large amounts of limestone (Figures 9, 13A) (Bowker, 2003; Pollastro, 2003; Texas Railroad Commission, 2003). West of the Newark East field, and along the east flank of the Bend arch, the formation thins over the Chappel shelf carbonate platform (Figures 6, 10). In those areas, the Barnett Shale is underlain by the Mississippian Chappel Limestone, which consists mostly of crinoidal limestone with local pinnacle mounds and reefs up to 300 ft (91 m) thick. Isolated mounds and clusters of these mounds and pinnacle reefs are exploration targets in localized, conventional stratigraphic traps that are sealed by the Barnett Shale (Browning, 1982; Ehlmann, 1982). Generalized structure contour maps drawn on top of the Ellenburger Group and on top of the Barnett Shale in the Bend arch Fort Worth Basin area are shown in Figures 5 and 15, respectively. The top of the Ellenburger Group is generally characterized by solutioncollapse features (karst) that formed by long-term, subaerial weathering. Karsted Ellenburger Group commonly results in localized areas of anomalously thick Barnett Shale that fill cavernous Ellenburger paleotopography. Karst-filled Ellenburger has been identified from well logs in both Johnson and Brown counties (Figure 6). Along the eastern part of the Fort Worth Basin, dense, crystalline limestones and dolomitic limestones of the Upper Ordovician Viola Limestone (Figure 11B) and Simpson Group ( Viola-Simpson) lie between the Ellenburger Group and Barnett Shale. Viola-Simpson rocks dip generally eastward beneath the sub-mississippian unconformity; they are absent to the west along a general northwest-to-southeast trend (Figure 16) through Clay, Montague, Wise, Tarrant, Johnson, and Hill counties (Henry, 1982; Bowker, 2003; Pollastro, 2003). The western geographic limit of the Viola-Simpson subcrop is a critical boundary in the Barnett Shale gas play because to the south and west, where Viola and Simpson rocks are absent (Figure 16B), the Barnett Shale directly overlies Ellenburger Group carbonates. Ellenburger carbonate rocks are commonly dolomitic, karsted, have greater porosities than other underlying formations, and are potentially water bearing. In vertical wells completed where the Barnett Shale stratigraphically rests on low fracture-gradient Ellenburger carbonate rocks, instead of the dense, low-permeability, high fracture-gradient Viola-Simpson limestones, two negative results commonly occur: (1) the energy from hydraulic stimulation is not contained within the gas-saturated Barnett Shale, thus limiting the productivity of a well; and (2) induced fractures tend to move into the underlying porous and water-saturated Ellenburger Group, resulting in multiple production problems related to high-salinity waters that infiltrate the Barnett Shale. Recently, exploration and development of the Barnett Shale in areas where these fracture-barrier limestones (Viola-Simpson below and/or the Marble Falls above) are absent have been exploited by horizontal wells. Petroleum Geochemistry and Thermal History Overview Studies on the geochemistry of oil and gas in the Fort Worth Basin and organic richness and gas generation in the Barnett Shale are ongoing and have been discussed by Jarvie et al. (2001; 2003; 2004a, b; 2005). Refer to articles by Hill et al. (2007) and Jarvie et al. (2007) for details and the most current interpretations on these subjects. These studies demonstrate that oil and gas produced from this area were generated mostly from the Barnett Shale. A brief discussion of the petroleum geochemistry and thermal history of the Fort Worth BasinandBarnettShaleisgivenhereinconjunctionwith the geology to further describe the Barnett-Paleozoic TPS and define and establish geographic areas for oil and gas assessment of the Barnett Shale. Oil and gas samples were taken from producing reservoirs in the following stratigraphic units: Ordovician Ellenburger Group and Viola Limestone, Mississippian Chappel Limestone and Barnett Shale, and Pennsylvanian Bend, Strawn, and Canyon groups (Figure 3). Largescale generation of hydrocarbons mostly from the Barnett Shale source rock in the Bend arch Fort Worth Basin resulted in the migration and accumulation of oil and gas into both conventional and unconventional reservoirs of Paleozoic age. In this area, about 2 billion bbl of oil and 7 TCFG have been produced (Pollastro et al., 2003), most attributed to the Barnett-Paleozoic TPS (Figure 1). Mean TOC values of Barnett Shale shown in Figure 2A are averages mostly from multiple wellcutting samples taken at various depths. Mean TOC ranges between 1 and 5 wt.% and averages between 2.5 Pollastro et al. 423

20 424 Barnett Shale, Bend Arch Fort Worth Basin, Texas

21 Figure 14. Isopach map of the upper Barnett Shale unit, Fort Worth Basin, Texas. Modified from Adams (2003). and 3.5 wt.%. Mean TOC for Barnett Shale in core samples is commonly higher, about 4 5 wt.% (Bowker, 2003; Jarvie et al., 2005). Henk et al. (2000) and Jarvie et al. (2005) reported that samples of Barnett Shale from outcrops in San Saba and Lampasas counties contain as much as 12 wt.% TOC. Jarvie et al. (2007) found that TOC measured in both cuttings and core from a well penetrating the Barnett Shale show that TOCs in core are 2.4 times greater than that from cuttings, thus indicating a dilution effect of TOC measured from cuttings. Moreover, differences in TOC among samples may also reflect a high degree of variability in the source rock or bias caused by sampling. Pollastro et al. (2003, 2004a) suggested that the coincidence between east-west thickening of the Barnett Shale in the trend perpendicular to the Bend arch (Figure 6) and the high isoreflectance contours in Figure 12 may indicate local faulting and hydrothermal heating, possibly reactivation of basement fault blocks contemporaneous with Barnett Shale deposition. Fault or fault-block movement, possibly from an east-west fault system similar to the Mineral Wells fault, may have had some control on local Barnett Shale deposition. Vertical movement along the fault system and any associated high heat flow could have caused thickening or thinning of the Barnett Shale section Figure 13. Isopach maps of limestone units in Barnett Shale. (A) Lime wash units within the Barnett Shale, Fort Worth Basin, Texas. Contour interval equals 25 ft (8 m). Modified from Texas Railroad Commission (2003). (B) Forestburg limestone (informal name) within the Barnett Shale, Fort Worth Basin, Texas. Contour interval equals 25 ft (8 m). Modified from Texas Railroad Commission (2003). Pollastro et al. 425

22 Figure 15. Structure contour map on top of Barnett Shale, Bend arch Fort Worth Basin as interpreted from well logs. Contour interval equals 500 ft (152 m). 426 Barnett Shale, Bend Arch Fort Worth Basin, Texas

23 Pollastro et al. 427 Figure 16. Maps showing Barnett Shale subcrop geology and geographic extent of Ordovician Viola Limestone and Simpson Group in subsurface, Forth Worth Basin as determined from well logs. (A) Area determined from well formation tops where Viola Limestone or Simpson Group is present in subsurface (IHS Energy, 2003). Dotted rectangle represents area shown in (B). (B) Map showing the subcrop geology of the Barnett Shale (modified from presentation given by C. Adams, 2003) (Adams, 2003).

24 and elevated mean R o, respectively, along this east-west trend. Local structural influence on the deposition in this area is supported by the study of Thompson (1982), who showed that deltaic systems of the overlying lower Pennsylvanian Bend Group were partly controlled by movement along the Mineral Wells fault system. In addition, thickening of Barnett Shale perpendicular to the Bend arch indicates that the arch probably had little influence on sedimentation during the Mississippian. Potential source rocks of secondary importance in the Bend arch Fort Worth Basin area are mostly Pennsylvanian in age (Figures 3, 4), including (1) dark, finegrained carbonate and shale units within the Marble Falls Limestone; (2) black shale facies of the Smithwick Shale (Walper, 1982; Grayson et al., 1991); and (3) several thin Pennsylvanian coal beds in Wise, Jack, Young, Parker, Palo Pinto, and McCulloch counties (Mapel, 1967; Evans, 1974; Mapel et al., 1979). Thermally immature Barnett Shale contains mostly oil-prone type II kerogen. Initially, the formation generated oil and associated gas directly from the kerogen (R o < 1.1%), whereas gas produced from within the formation in the Newark East field and surrounding areas probably formed later by secondary cracking of oil and bitumen (Jarvie et al., 2001, 2005, 2007) at higher thermal maturity (R o 1.1%). Gases sampled from conventional accumulations in the Pennsylvanian Bend Group clastics at Boonsville field (Figures 1, 2A) and from the continuous Barnett Shale accumulations at Newark East field both appear to have been generated from the Barnett Shale. Gas in the Bend Group reservoirs is wetter and interpreted as cogenerated from kerogen and oil within the oilgeneration window from the Barnett Shale at thermal maturity R o < 1.1% (Hill et al., 2004, 2007; Jarvie et al., 2004b, 2007). The cogenerated gas subsequently migrated upward into the porous Boonsville field Pennsylvanian reservoirs probably through fractures related to the Mineral Wells Newark East fault system (Pollastro et al., 2004a). In contrast, drier nonassociated gas produced from within the Barnett Shale at Newark East field resulted from the cracking of oil at higher thermal maturity and at R o levels greater than or equal to 1.1% (Jarvie et al., 2005, 2007). Thus, it is known that the Barnett Shale has expelled hydrocarbons both as oil and gas. Burial-history reconstructions by Jarvie et al. (2003, 2005) indicated that significant uplift and erosion occurred across the Fort Worth Basin during the Devonian, Jurassic, and Tertiary. In contrast, Ewing (2006) further discussed burial histories of the Fort Worth Basin and proposed that maximum burial, heating, and mosthydrocarbongenerationoccurredduringthepermian and Triassic. Measurements of thermal maturity (R o, hydrocarbon type, and gas wetness) provide evidence that the Barnett Shale has undergone multiple heating episodes during its burial history, including hydrothermal heating associated with the Ouachita structural front and the Minerals Wells Newark East fault system (Bowker, 2003; Pollastro, 2003; Pollastro et al, 2004a; Montgomery et al., 2005, 2006). As shown in the petroleum system events chart of Figure 4, hydrocarbon generation from the Barnett Shale source rock probably began during the late Pennsylvanian and peaked during the Permian and Triassic and continues to the present day (Jarvie et al., 2001; Montgomery et al., 2005, 2006; Ewing, 2006). Barnett Shale also likely underwent episodic expulsion of gas derived from both primary cracking of bitumen and secondary cracking of oil (Jarvie et al., 2003, 2005, 2007). R o data for the Barnett Shale samples show poor correlation with its present-day burial depth in the Fort Worth Basin. In particular, the formation exhibits relatively high R o in Tarrant and Bosque counties and low R o in Montague County (Figure 17). R o values for surface outcrop samples along the Llano uplift range from about 0.5 to 0.7%. Regional contouring of similar R o data from the Barnett Shale and typing of produced hydrocarbons by Pollastro et al. (2003) and later by Montgomery et al. (2005, 2006) showed patterns of local, anomalously high paleotemperatures, indicating an elevated heating event, probably from hydrothermal fluids along the Ouachita thrust front and Mineral Wells Newark East fault system. In those areas, isoreflectance contours bend westward and are semiparallel to the Mineral Wells Newark East fault system; however, the contours are perpendicular and/or crosscut major structural trends, including the present-day basin axis, the Bend arch, and Ouachita structural trends (Figure 12). As mentioned previously, an area of anomalously high thermal maturity perpendicular to the Bend arch, as evidenced from vitrinite isoreflectance contours with R o = 0.9% (Figure 12), closely corresponds to a trend of west-to-east thickening of the Barnett Shale (Figure 6). Along this trend, anomalously high R o for the Barnett Shale could indicate a westward extension of a fault system similar to the Mineral Wells fault where fault-directed movement and heating by hydrothermal fluids possibly caused increased paleotemperatures. Further evidence for elevated temperatures resulting from hydrothermal fluids is supported 428 Barnett Shale, Bend Arch Fort Worth Basin, Texas