Browsing by Subject "Fort Worth Basin"

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Controls on Mudrock Pore System Development in the Upper Mississippian Barnett Shale, Fort Worth Basin, Wise County, Texas
(American Association of Petroleum Geologists (AAPG) Annual Convention, 2019-05-19) Reed, R.M.; Loucks, R.G.; Rowe, H.D.
An investigation of the nanopore systems in the Barnett Shale found that the controls on pore development are in part related to lithofacies, but are also related to organic- matter properties. Sixteen Ar-ion milled samples from core in the Devon Adams No. 7 well in the Newark East Field were analyzed using scanning electron microcopy. This core begins in the upper Barnett and provides a complete section of the lower Barnett. Samples were selected based on core lithofacies descriptions and XRF chemostratigraphic analysis to ensure a complete range of lithofacies was analyzed. Quartz content averages 42% with a high of 73%. Clay-mineral content is generally low, averaging 15%. Four of the samples are relatively calcareous including two from the Forestburg limestone member. TOC averages 3.66% with a range from 0.54% to 7.42%. Siliceous lithofacies have higher TOC values than the carbonate-rich lithofacies. Calculated Ro averages 1.04% (but low-T shoulders on S2 peaks). Pore types consist of interparticle, intraparticle, and organic-matter (OM) pores. Pore type and development varies between lithofacies and to a lesser extent between spots on the same sample surface. Based on visual estimates, OM pores are commonly the dominant pore type in siliceous and argillaceous mudstones. OM pore morphology varies between kerogen and solid bitumen. Kerogen pores are generally larger, some greater than 1 µm in length, and more elongate. Bitumen pores are generally smaller and more equant. Organic matter in association with phosphatic grains appears espe- cially porous. The calcareous lithofacies, which contain less organic matter, have fewer OM pores. Intraparticle pores are present in all lithofacies, but are not common. Interparticle pores are rare and are generally less than 1 µm in size. The lack of interparticle pores in most lithofacies is interpreted to be the result of spread of ductile kerogen and occlusion by solid bitumen. Two organic-rich siliceous mudstone samples, one from the lower Barnett and one from the basal Mo-enriched mudstone, show few pores in their OM. These samples suggest that OM properties rather than simple TOC content controls pore development. Even using XRF, one nonporous siliceous mudstone sample was not di erentiated as a separate lithofacies in the initial core analysis. The conclusion that both lithofacies and organic-matter properties have an in uence on the generation of mudrock pores is important for trying to predict pore development and distribution in mudrock plays.
Geologic setting and reservoir characterization of Barnett Formation in southeast Fort Worth Basin, central Texas
(2014-08) Liu, Xufeng; Fisher, W. L. (William Lawrence), 1932-; Loucks, R. G.
The Mississippian Barnett Formation is a prolific shale-gas reservoir that was deposited in the Fort Worth Basin, Texas. Many previous studies of the Barnett Formation have been conducted in the main production area; few studies have been made of the Barnett Formation in the southern part of the basin, which is a less productive area. In the present research, several cores from the Barnett Formation in Hamilton County, southeast Fort Worth Basin, are studied in detail. Two vertical, continuous cores from Hamilton County, Texas, were studied to delineate the depositional setting, lithofacies, pore types, and reservoir quality of the Barnett Formation in the area. Five lithofacies were defined by analysis of the two cores: (1) laminated clay-rich silty and skeletal peloidal siliceous mudstone; 2) laminated skeletal silty peloidal siliceous mudstone; 3) nonlaminated silty peloidal calcareous mudstone; 4) laminated and nonlaminated skeletal calcareous mudstone; and 5) skeletal phosphatic packstone to grainstone. As indicated from this study, the dominant organic matter type is a mixture of Type II (major) and Type III (minor) kerogen having a mean TOC content of approximately 4%. Analysis of Rock Eval data shows that most of the interval is within the oil window; calculated Ro is approximately 0.9%. Organic geochemistry shows that the hydrocarbon generation potential of the abundant oil-prone kerogen was excellent. Mineralogical analysis reveals that the two types of siliceous mudstone, which are similar in composition to the siliceous mudstone in the main producing area in the northern Fort Worth Basin, are good for hydraulic fracturing and production, but they are also limited by their marginal thickness. Organic matter pores, which are the dominant pore types in these two cores, are consistent with pore types found in currently producing wells in the Newark East Field. This research also suggests that the deposition of Barnett Formation was controlled largely by basinal geometry, suspension settling, and slope-originated gravity-flow events. Skeletal deposits and carbonate-silt starved ripples suggest gravity-flow deposits and bottom-current reworking during deposition. Redox-sensitive elements and degree of pyritization both indicate anoxic/euxinic conditions during the deposition of the Barnett Formation.
Investigation of the Davis Sandstone (Ft. Worth Basin, Texas) as a Suitable Formation for the GRI Hydraulic Fracture Test Site
(1992) Collins, Edward W.; Laubach, Stephen E. (Stephen Ernest), 1955-; Dutton, Shirley P.
The concept of the GRI Hydraulic Fracture Test Site (HFTS) was to provide a field laboratory to (1) validate three-dimensional hydraulic fracture models in tight gas sandstone and (2) develop technology in fracture diagnostics and stimulation. The Davis sandstone in the Fort Worth Basin, north-central Texas, was initially selected as a viable candidate formation for HFTS research based on the results of a cooperative well program initiated with Dallas Production. To gather comprehensive data on a specific site for HFTS research, the S.A. Holditch & Associates Data Well No. 1 was drilled in June 1991. The results of geological, petrophysical, and engineering analyses of the co-ops and data well are the basis of this report. These analyses indicate that in northern Parker and southern Wise Counties, Texas, the Davis sediments range from 250 to 350 feet thick. A broadly continuous, 100-foot thick interval in the upper part of the gross interval comprises the Davis Reservoir. The average permeability of the Davis Reservoir was found to be 0.08 millidarcies with an average closure stress of 0.45 pounds per square inch per foot. The shale barriers above and below the Davis had average closure stress of 0.63 to 0.73 pounds per square inch per foot and 0.88 to 0.98 pounds per square inch per foot, respectively. Hydraulic fracture azimuth was found to range from N10Â°E to N20Â°E. Drainage area from production analyses was calculated to be 48.7 acres in northwest Parker County. Natural fractures were encountered in the Davis, causing severe drilling problems in Data Well No. 1. Davis was therefore suspended.
Lithofacies, depositional systems, and depositional models of the Mississippian Barnett Formation in the southern Fort Worth Basin
(2016-08) Redmond, Lauren Patricia; Loucks, R. G.; Rowe, Harry; Kerans, Charles; Fisher, William
The Barnett Formation in the Llano Uplift region of the southern Fort Worth Basin of north-central Texas is an Osagean-Chesterian age siliciclastic mudrock whose deposition was influenced by the structurally stable Llano Uplift, topographic variabilities, and a long-term, second-order sea-level rise. Pervious work has mostly focused on the producing northern portion of the basin. The present study uses a group of 29 cores to: (1) characterize the Barnett lithofacies, (2) define the depositional setting of each lithofacies and develop a coherent depositional model, (3) identify stacking patterns and correlative surfaces, and (4) establish a viable sequence stratigraphic framework for the succession. On the basis of core data, the Barnett strata are interpreted to have been deposited in a basinal setting, below storm-weather wave-base, under predominantly anoxic bottom waters. The analysis of core and thin sections revealed four dominant lithofacies: (1) laminated siliceous mudstone, (2) laminated calcareous siliceous mudstone, (3) skeletal packstone, and (4) phosphatic packstone and grainstone. Facies stacking patterns were correlated using phosphatic packstone facies as regional marker beds. These beds coincide with changes in clay-mineral abundances, revealed by chemostratigraphic data, and their occurrences were used to subdivide the Barnett strata into lower, middle, and upper units. The lower Barnett is characterized by cyclic sedimentation of extrabasinal clays and has the greatest thickness variability related to accumulation of the calcareous siliceous mudstone facies in graben structures. The middle Barnett is characterized by an increase in extrabasinal clay abundance compared to the lower Barnett, and the upper Barnett is characterized by a decrease in the extrabasinal clay abundance compared to the lower and middle Barnett. The phosphatic packstone facies is sourced from the outer shelf/upper slope of the adjacent Chappel Shelf and is interpreted to represent cycle tops within the aggradational stacking pattern that characterized sediment accumulation style during the second-order sea-level rise that occurred throughout Barnett deposition. The findings contribute to the understanding of the stratal architecture and depositional history of the Barnett deep-water mudrocks and are used to refine the lithofacies variability of the Barnett Formation.
Revisiting Mississippian Barnett Shale: Lithological and Geochemical Control on Varied Reservoir Heterogeneity and Fluid Saturation from Late Oil to Dry Gas Window, Fort Worth Basin, Texas
(American Association of Petroleum Geologists Southwest Section (AAPG SWS), 2023-05-06) Ko, L.T.; Peng, S.; Fu, Q.; Periwal, P.; Sivil, E.
Secondary Natural Gas Recovery: Targeted Applications for Infield Reserve Growth in Midcontinent Reservoirs, Boonsville Field, Forth Worth Basin, Texas - Volume I
(1996) Hardage, Bob Adrian, 1939-; Carr, David L.; Finley, Robert J.
This report documents an assessment of Midcontinent sandstone natural gas reservoirs in Boonsville (Bend Conglomerate Gas) field by integrating four key disciplines: geology, geophysics, reservoir engineering, and petrophysics. Pressure and production data confirm the existence of compartmented or poorly drained gas throughout much of the Bend Conglomerate and suggest that additional gas will be found when well spacing is reduced to 80 acres, although multiple stacked completion opportunities will typically be needed to ensure the economic viability of new infill wells. As part of this analysis, the Lower Atoka Group was divided into 13 third-order genetic sequences, and to our knowledge, this is the first public, comprehensive genetic sequence analysis that relates these Pennsylvanian reservoirs to their seismic response and to gas productivity. A 26-miÂ², 3-D seismic survey was done to test methods for reservoir delineation in thin-bed, hard-rock environments and identified a previously unknown structural component of reservoir compartmentalization in the form of low-displacement faulting commonly associated with karst collapse in deeper carbonate rocks. These karst collapse features extend vertically as much as 2,500 ft and may be a widespread influence on the deposition of younger sediments in the Midcontinent. The ability of the 3-D survey to define stratigraphic entrapments was more variable. Some sequences were imaged quite well, and seismic attribute analyses provided excellent agreement with net reservoir distributions generated from sequence stratigraphic interpretations. In other instances, individual systems tracts and reservoir sandstones that were subsets of genetic sequences proved difficult to trace precisely in the 3-D data, especially when those units were associated with a subtle impedance contrast or were extremely thin.
Secondary Natural Gas Recovery: Targeted Applications for Infield Reserve Growth in Midcontinent Reservoirs, Boonsville Field, Forth Worth Basin, Texas - Volume I
(1995) Hardage, Bob Adrian, 1939-; Carr, David L.; Finley, Robert J.
This report documents an assessment of Midcontinent sandstone natural gas reservoirs in Boonsville (Bend Conglomerate Gas) field by integrating four key disciplines: geology, geophysics, reservoir engineering, and petrophysics. Pressure and production data confirm the existence of compartmented or poorly drained gas throughout much of the Bend Conglomerate and suggest that additional gas will be found when well spacing is reduced to 80 acres, although multiple stacked completion opportunities will typically be needed to ensure the economic viability of new infield wells. As part of this analysis, the Lower Atoka Group was divided into 13 third-order genetic sequences, and to our knowledge, this is the first public, comprehensive genetic sequence analysis that relates these Pennsylvanian reservoirs to their seismic response and to gas productivity. A 26-mi², 3-D seismic survey was done to test methods for reservoir delineation in thin-bed, hard-rock environments and identified a previously unknown structural component of reservoir compartmentalization in the form of low-displacement faulting commonly associated with karst collapse in deeper carbonate rocks. These karst collapse features extend vertically as much as 2,500 ft and may be a widespread influence on the deposition of younger sediments in the Midcontinent. The ability of the 3-D survey to define stratigraphic entrapments was more variable. Some sequences were imaged quite well, and seismic attribute analyses provided excellent agreement with net reservoir distributions generated from sequence stratigraphic interpretations. In other instances, individual systems tracts and reservoir sandstones that were subsets of genetic sequences proved difficult to trace precisely in the 3-D data, especially when those units were associated with a subtle impedance contrast or were extremely thin.
Secondary Natural Gas Recovery: Targeted Applications for Infield Reserve Growth in Midcontinent Reservoirs, Boonsville Field, Forth Worth Basin, Texas - Volume II Appendix
(1995) Hardage, Bob Adrian, 1939-; Carr, David L.; Finley, Robert J.
This report documents an assessment of Midcontinent sandstone natural gas reservoirs in Boonsville (Bend Conglomerate Gas) field by integrating four key disciplines: geology, geophysics, reservoir engineering, and petrophysics. Pressure and production data confirm the existence of compartmented or poorly drained gas throughout much of the Bend Conglomerate and suggest that additional gas will be found when well spacing is reduced to 80 acres, although multiple stacked completion opportunities will typically be needed to ensure the economic viability of new infield wells. As part of this analysis, the Lower Atoka Group was divided into 13 third-order genetic sequences, and to our knowledge, this is the first public, comprehensive genetic sequence analysis that relates these Pennsylvanian reservoirs to their seismic response and to gas productivity. A 26-miÂ², 3-D seismic survey was done to test methods for reservoir delineation in thin-bed, hard-rock environments and identified a previously unknown structural component of reservoir compartmentalization in the form of low-displacement faulting commonly associated with karst collapse in deeper carbonate rocks. These karst collapse features extend vertically as much as 2,500 ft and may be a widespread influence on the deposition of younger sediments in the Midcontinent. The ability of the 3-D survey to define stratigraphic entrapments was more variable. Some sequences were imaged quite well, and seismic attribute analyses provided excellent agreement with net reservoir distributions generated from sequence stratigraphic interpretations. In other instances, individual systems tracts and reservoir sandstones that were subsets of genetic sequences proved difficult to trace precisely in the 3-D data, especially when those units were associated with a subtle impedance contrast or were extremely thin.
Subsurface gas- and oil-shale samples of Texas shales from the Permian, Fort Worth, and Maverick basins and San Marcos Arch: core sampling for measured vitrintite-reflectance (Ro) determination: final technical summary report (FY 2010–2014)
(2015) Hentz, Tucker F.
Shale samples analyzed for measured vitrinite reflectance during FY 2010–2014 were collected from varying depositional basins in Texas and strata of different ages. They include the Upper Devonian and Lower Mississippian Woodford Shale (Permian Basin), the Lower Pennsylvanian Smithwick Shale (Fort Worth Basin), the Lower Permian shales and Spraberry Formation (Midland Basin), the Lower Cretaceous Pearsall Formation, and the Upper Cretaceous Eagle Ford Shale (Maverick Basin and adjacent area). Although an approximate trend of increasing vitrinite-reflectance values with depth (i.e., increasing thermal maturity, or rank) occurs in the Eagle Ford Shale of the San Marcos Arch, this pattern is not exhibited with the other units sampled. Moreover, when measured vitrinite-reflectance values are compared to calculated-Ro values of Lower Permian shales and the Spraberry Formation, consistently lower values occur with the measured-Ro data set. Sample values from the remaining three successions studied (with the possible exception of the Smithwick Shale) are characterized by similarly lower-than-expected vitrinite-reflectance values. These low values are probably a result of markedly lean successions and not of the presence of low-rank strata. (Lean = either no vitrinite was present in a sample or it was too small to be measured.) Oil- and gas-shale core samples do not appear to be ideal for measuring vitrinite reflectance primarily because of the fine-grained character of the rock, as opposed to coal, in which vitrinite is sufficiently coarse, visible, and abundant to consistently derive Ro values.
Subsurface Pennisylvanian Coal Samples Lower Atoka Group Fort Worth Basin Wise an dAck Counties North Texas Core Sampling for Coal-Rank Determination
(2007) Hentz, Tucker F.; Breton, Caroline L.; Ruppel, Stephen C.
Tasks conducted at the Bureau of Economic Geology (BEG) during Fiscal Year (FY) 2006 for the National Coal Resources Data System State Cooperative Program (NCRDS project) involved sampling of deep (5,400-5,500 ft) subsurface bituminous coal beds from the Fort Worth Basin of North Texas. Identification of their precise stratigraphic position, geographic location, and general depositional setting was a primary objective. This study is one part of a program of sampling and characterization of Texas coals as part of BEG's continuing NCRDS project of coal inventory and investigation of U.S. bituminous coals as a coalbed methane resource. Seven coal samples were collected from the whole cores of two wells in Boonsville field (Wise and Jack Counties), which produces mostly natural gas from the lower Atoka Group (Lower Pennsylvanian). Chronostratigraphic correlations throughout Wise and eastern Jack Counties show that the coal beds correspond to gamma-ray maxima capping retrogradational intervals above thicker progradational sections and are interpreted to represent maximum flooding surfaces within continental deposits of fourth-order transgressive systems tracts. These flooding surfaces can be correlated throughout Wise and eastern Jack Counties. The sampled coal beds in the Oxy Tarrant #A-4 well are inferred to represent peat-swamp deposits that mark the abandonment of a broad braided-river (braidplain) system. The distribution of mapped primary channel and interchannel areas offers an approximation of the total extent of coal beds within this genetic interval. In contrast, the sampled coals in the EP Operating Tarrant WB #3 well were deposited within a fourth-order transgressive succession deposited above proximal delta-front sandstones.
The Pennsylvanian Lower Strawn Group, Jack and Wise Counties, Fort Worth Basin : facies distribution and stratigraphic architecture
(2020-05-08) Roberts, Andrew Kearny; Steel, R. J.; Ambrose, William A.
The Lower Strawn Group in Jack and Wise counties of the Fort Worth Basin are laterally and vertically heterogeneous deltaic deposits comprising sandstones, siltstones, and shales with thin, discontinuous carbonates and coal seams reflecting variable icehouse condition controls. Given a general lack of differentiation of individual sequences in the Lower Strawn in Jack and Wise counties, this study develops a stratigraphic framework, highlights relationships between component facies of the Lower Strawn, establishes individual sequences, and identifies depositional controls and their effects on reservoir predictability. With an estimated 38 million barrels of oil (MMBO) & 56 billion cubic feet of gas (BCF) of mean total undiscovered resources located in Pennsylvanian/Permian fluvio-deltaic sandstones and conglomerates, analogous to depositional environments in many foreland basins globally, this study provides a key dataset with respect to component depositional facies and reservoir architecture for more informed resource assessment. Based on core description and interpretation, depositional environments of the Lower Strawn Group include prodelta, medial delta front, interdistributary-bay, channel mouth bar, and distributary-channel deposits. These interpreted depositional environments, their well-log pattern, and vertical facies relationships enable an interpretation that fluvio-deltaic depositional systems dominated in the Lower Strawn Group. Wireline log correlations of regionally-extensive maximum flooding surfaces were used to develop a sequence stratigraphic framework that identified eleven regressive-transgressive, fluvio-deltaic sequences averaging 90-240ft thick, collectively spanning a thickness of 1,000-2,700 ft. (305-823 m.) as the interval onlapped the forebulge of the Fort Worth Foreland Basin. A south-southwest overall direction of progradation was identified based on the distribution of net sandstone thickness trends. The depocenters contained within these sequences reflect similar geometries to those described from fluvio-deltaic systems of the Mississippi River and Yukon River Deltas. With elevated porosity trends found to be associated with homogeneous channel-mouth bar and distributary-channel deposits, a better understanding of internal reservoir characteristics and distribution helps improve predictability for operators pursuing complex stratigraphy containing hydrocarbon resources in similar depositional settings.
Update of Oil and Gas Reservoir Data Base, Permian and Fort Worth Basins, Texas
(2000) Dutton, Shirley P.; Zirczy, Helena; Tremblay, Thomas A.
This study updates previous work on oil and gas production in the Permian and Fort Worth Basins by Galloway and others (1983), Kosters and others (1989), and Holtz and others (1993). The original delineation of oil plays in Texas was published by Galloway and others (1983) in the Atlas of Major Texas Oil Reservoirs, which classified into plays all oil fields that had produced more than 10 MMbbl of oil through 1981. Gas reservoirs that had produced more than 10 Bcf of gas through 1986 were grouped into gas plays in the Atlas of Major Texas Gas Reservoirs (Masters and others, 1989). In 1993, Holtz and others updated and expanded the database from the two atlases. The Update of Atlas of Major Texas Oil Reservoirs Database and Atlas of Major Texas Gas Reservoirs Database (Holtz and others, 1993) updated cumulative production data through December 31, 1992, for reservoirs already in the database and added smaller but significant-sized reservoirs (cumulative production > 1 MMbbl of oil equivalent [boe]) to the database. The addition of new reservoirs to the database resulted in the modification of existing plays and the determination of several new oil plays. Play boundaries were also modified to accommodate the additional reservoirs. The goals of this project were (1) to update cumulative production data through December 31, 1998, for all oil and gas reservoirs in the Permian and Fort Worth Basins, Texas, that were included in the database of Holtz and others (1993) and (2) to add additional reservoirs now having cumulative production greater than 1 MMboe to the database. (Reservoirs having production > 1 MMboe are referred to as "significant" reservoirs in this report). Following the U.S. Geological Survey (1995), this report uses a value of 6,000 cf of gas to equal 1 boe; 6 Bcf is therefore the equivalent of 1 MMbbl of oil. The new reservoirs were assigned to plays, and play boundaries from Holtz and others (1993) were modified to include the additional reservoirs. Because one oil reservoir and one gas reservoir did not fall into existing plays, new plays were established for these reservoirs: the Mississippian Platform Carbonate (oil) play in the Permian Basin and Barnett Shale (gas) play in the Fort Worth Basin. Information about the two new plays is provided in this report.