Bend Arch–Fort Worth Basin
|Bend Arch–Fort Worth Basin Province|
|Operators||Devon Energy, Chesapeake Energy, EOG Resources, XTO Energy, EnCana, Range, ConocoPhillips, Quicksilver, Denbury|
|Start of production||1917|
|Peak of production||1960s|
|Current production of gas||200,000×106 cu ft/d (5,700×106 m3/d) (2002)|
|Producing formations||Barnett Shale, Ordovician, Permian|
The Bend Arch–Fort Worth Basin Province is a major petroleum producing geological system which is primarily located in north central Texas and southwestern Oklahoma. It is officially designated by the United States Geological Survey (USGS) as Province 045 and classified as the Barnett-Paleozoic Total Petroleum System (TPS).
- 1 Introduction
- 2 Boundary
- 3 Structural elements
- 4 Tectonic history
- 5 General stratigraphy
- 6 Petroleum production history
- 7 Source rock
- 8 Thermal maturity
- 9 Hydrocarbon generation
- 10 Reservoir rocks
- 11 Fractured Barnett Shale
- 12 See also
- 13 Notes
- 14 References
Oil and gas in Province 045 are produced from carbonate and clastic rock reservoirs ranging in age from the Ordovician to the Permian. The 1995 USGS Assessment of undiscovered, technically recoverable oil and gas identified six conventional plays in Province 045, which are listed below in Table 1: One continuous unconventional play, hypothetical "Mississippian Barnett Shale" (4503), was also considered. The cumulative mean of undiscovered resource for conventional plays was: 381 million barrels (60.6×106 m3) of oil, 103.6 million barrels (16.47×106 m3) of natural gas liquids, 479 billion cubic feet (13.6×109 m3) associated gas, and 1,029 billion cubic feet (29.1×109 m3) non-associated gas.
|1995 Play No.||1995 Play Designation||2003 AU||2003 Proposed AU Designation|
|4502||Mississippian Carbonate||2||Mississippian Pinnacle Reef|
|4504||Low-Pennsylvanian Sandstone & Conglomerate||3||Pennsylvanian Fluvial-Deltaic Sandstone & Conglomerate|
|4505||Strawn (Desmoinesian)||4||Pennsylvanian Fluvial-Deltaic Sandstone & Conglomerate|
|4505||Post Desmoinesian||5||Upper Pennsylvanian/Permian Clastic|
|4503||Mississippian Barnett Shale (Hyp)||6||Greater Newark East Fractured Siliceous Shale|
|4503||Mississippian Barnett Shale (Hyp)||7||Ellenburger Subcrop Fractured Barnett Shale|
|4503||Mississippian Barnett Shale (Hyp)||8||North Basin and Arch Fractured Shale|
1. Assessment unit number also indicates time span of stratigraphic units.
The USGS assessment of undiscovered conventional oil and gas and undiscovered continuous (unconventional) gas within Province 045 resulted in estimated means of 26.7 trillion cubic feet (760×109 m3) (Tcf) of undiscovered natural gas, 98.5 million barrels (15.66×106 m3) of undiscovered oil, and a mean of 1.1 billion barrels (170×106 m3) of undiscovered natural gas liquids. Nearly all of the undiscovered gas resource (98%, 2.62 × 1013 cu ft or 7.4 × 1011 m3) is considered to be in continuous accumulations of nonassociated gas trapped in strata of two of the three Mississippian-age Barnett Shale Assessment Units (AUs) - the Greater Newark East Frac-Barrier Continuous Barnett Shale Gas AU and the Extended Continuous Barnett Shale Gas AU (2.62 × 1013 cu ft combined). The remaining 467 billion cubic feet (13.2×109 m3) of undiscovered gas resource in the Province is in conventional nonassociated gas accumulations (3.586 × 1011 cu ft or 1.015 × 1010 m3) and associated/dissolved gas in conventional oil accumulations (1.084 × 1011 cu ft or 3.07 × 109 m3). The Barnett-Paleozoic TPS is estimated to contain a mean of 409.2 billion cubic feet (11.59×109 m3) of conventional gas, or about 88% of all undiscovered conventional gas, and about 64.6 million barrels (10.27×106 m3) of conventional oil, or about 65% of all undiscovered oil in Province 045.
Continuous-type accumulations include fractured shale and fractured chalk oil and gas, basin-centered gas, coal bed gas, and tight reservoir gas. They typically cover large areas, have source rocks in close association with these unconventional reservoir rocks, and are mostly gas (and in some cases oil) charged throughout their extent. Continuous accumulations commonly have transition zones that grade into more conventional accumulations.
The Fort Worth Basin and Bend Arch lie entirely within north central Texas covering an area of 54,000 square miles (140,000 km2). The southern and eastern boundaries are defined by county lines that generally follow the Ouachita structural front, although a substantial portion of this structural feature is included near Dallas. The north boundary follows the Texas-Oklahoma State line in the east, where the province includes parts of the Sherman Basin and Muenster Arch. In the west, the north boundary follows the north-east county lines of Oklahoma's three southwestern counties (Harmon, Jackson and Tillman Counties), which include the south flank of the Wichita Mountains and the Hollis Basin. The western boundary trends north-south along county lines defining the junction with the Permian Basin where part of the eastern shelf of the Permian Basin lies in Province 045.
Major structural features include the Muenster and Red River Arches to the north, and the Bend and Lampasas Arches along the central part of Province 045. Along the east portion is an area that includes the Eastern Shelf and Concho Arch, collectively known as the Concho Platform. The Mineral Wells fault runs northeast-southwest through Palo Pinto, Parker, Wise, Denton Counties and joins with the Newark East fault system. The fault system bisects the Newark East Field (NE-F) creating a zone of poor production in Barnett Shale gas reservoirs. Several faults that cut basement and lower Paleozoic rocks in the southern part of the province are identified at the Ordovician Ellenburger Group stratigraphic level. These faults and associated structures formed during development of the Llano Uplift and Fort Worth Basin with faulting ending by the early Missourian.
Fort Worth Basin
Evolution of the Fort Worth Basin and Bend Arch structures are critical to understanding burial histories and hydrocarbon generation. The asymmetrical, wedge-shaped Fort Worth Basin is a peripheral Paleozoic foreland basin with about 12,000 feet (3,700 m) of strata preserved in its deepest northeast portion and adjacent to the Muenster Arch and Ouachita structural belt. The basin resembles other basins of the Ouachita structural belt, such as the Black Warrior, Arkoma, Val Verde, and Marfa Basins that formed in front of the advancing Ouachita structural belt as it was thrust onto the margin of North America. Thrusting occurred during a late Paleozoic episode of plate convergence.
The Bend Arch extends north from the Llano Uplift. It is a broad subsurface, north-plunging, positive structure. The arch formed as a hingeline by down-warping of its eastern flank due to subsidence of the Fort Worth Basin during early stages of development of the Ouachita structural belt in the Late Mississippian and west tilting in the late Paleozoic which formed the Midland Basin. There is disagreement on the structural history of the Bend Arch. Flippen (1982) suggested it acted as a fulcrum and is a flexure and structural high and that only minor uplift occurred in the area to form an erosional surface on the Chester-age limestones that were deposited directly on top of the Barnett. In contrast, Cloud and Barnes (1942) suggested periodic upwarp of the Bend flexure from mid-Ordovician through Early Pennsylvanian time resulted in several unconformities. The Red River Arch and the Muenster Arch also became dominant structural features during the Late Mississippian and Early Pennsylvanian.
Hydrocarbon production from Ordovician, Mississippian, and Early Pennsylvanian rocks is mostly from carbonate rock reservoirs, whereas production in the Mid-Pennsylvanian through Low-Permian is mostly from clastic rock reservoirs. The sedimentary section in the Fort Worth Basin is underlain by Precambrian granite and diorite. Cambrian rocks include granite conglomerate, sandstones, and shale that are overlain by marine carbonate rocks and shale. No production has been reported from Cambrian rocks. The Silurian, Devonian, Jurassic, and Triassic are absent in the Fort Worth Basin.
From Cambrian to Mississippian time, the Fort Worth Basin area was part of a stable cratonic shelf with deposition dominated by carbonates. Ellenburger Group carbonate rocks represent a broad epeiric carbonate platform covering most of Texas during the Early Ordovician. A pronounced drop in sea level sometime between Late Ordovician and Mississippian time resulted in prolonged platform exposure. This erosional event removed any Silurian and Devonian rocks (post Viola Limestone unconformity) that may have been present. Barnett Shale was deposited over the resulting unconformity. Provenance of the terrigenous material that constitutes the Barnett Shale was from Ouachita thrust sheets and the reactivation of older structures such as the Muenster Arch. Post-Barnett deposition continued without interruption as a sequenced of extremely hard and dense limestones were laid down. These limestones have often been confused with the lower part of the overlying Marble Falls Formation, and they have never been formally named in the literature. Since the underlying Barnett is generally assumed to be Late Mississippian Chester in age, the superposed carbonates are often referred to informally as "the Chester Limestones."
Clastic rocks of provenance similar to the Barnett dominate the Pennsylvanian part of the stratigraphic section in the Bend Arch–Fort Worth Basin. With progressive subsidence of the basin during the Pennsylvanian, the western basin hinge line and carbonate shelf, continued migrating west. Deposition of thick basinal clastic rocks of the Atoka, Strawn, and Canyon Formations occurred at this time. These Mid- and Late Pennsylvanian rocks consist mostly of sandstones and conglomerates with fewer and thinner limestone beds.
Petroleum production history
Hydrocarbon shows were first encountered in Province 045 during the mid-nineteenth century while drilling water wells. Sporadic exploration began following the Civil War, and the first commercial oil discoveries occurred in the early 1900s. In 1917, discovery of Ranger field stimulated one of the largest exploration and development "booms" in Texas. Ranger field produces from the Atoka-Bend formation, a sandstone-conglomerate reservoir that directly overlies the Barnett formation. Operators drilled more than 1,000 wildcats in and around the Fort Worth basin attempting to duplicate the success of Ranger. These wildcat efforts resulted in the discovery of more fields and production from numerous other reservoirs including Strawn fluvial/deltaic sandstone, Atoka-Bend fluvial/deltaic sandstone and conglomerate, Marble Falls carbonate bank limestone, Barnett siliceous shale, and Ellenburger dolomitic limestone. By 1960, the Province reached a mature stage of exploration and development, as demonstrated by the high density and distribution of well penetrations and production wells. Oil and lesser amounts of gas are found throughout the Paleozoic section, but most hydrocarbons consist of oil in Pennsylvanian reservoirs.
Province 045 is among the more active drilling areas during the resurgence of U.S. drilling, which began after the OPEC oil embargo. It has consistently appeared on the list of the 10 most active provinces in terms of wells completed and footage drilled. 9,177 oil wells and 4,520 gas wells were drilled and completed in this area from 1974 to 1980.
Cumulative production in Province 045 from conventional reservoirs prior to the 1995 USGS Assessment was 2 billion barrels (320×106 m3) of oil, 7.8 trillion cubic feet (220×109 m3) of gas, and 500 million barrels (79×106 m3) of natural gas liquids. Cumulative gas production through 2001 from the continuous Barnett fractured shale play in Wise and Denton counties was about 440 billion cubic feet (12×109 m3). Cumulative gas production from the Barnett Shale for the first half of 2002 was 94 billion cubic feet (2.7×109 m3); annual production for 2002 was estimated at 200 billion cubic feet (5.7×109 m3). Currently, over 2.5 trillion cubic feet (71×109 m3) of proven gas reserves are assessed for NE-F. These production and proven reserve figures for the Barnett play, combined with estimates of underdeveloped Barnett resources indicate that technically recoverable continuous gas, and to a lesser extent oil, from fractured Barnett Shale will provide the greatest additions to near-future reserves in Province 045.
Petroleum data: selected fields
|Field||County||Cumulative oil production||Cumulative gas production||Reserves||Discovery|
|million barrels||million cubic meters||billion cubic feet||million cubic meters|
|Newark East||Wise, Denton||200||5,700||2.5 trillion cubic feet (71×109 m3) of gas||1981|
|Shackelford||Shackelford||10 million barrels (1.6×106 m3) of oil||1954|
|Lake Abilene||Taylor||-||Note: GOF = giant oil fields (>500 million barrels of oil equivalent)|
The primary source rock of the Bend Arch–Fort Worth Basin is Mississippian Chester-age Barnett Shale. The Barnett commonly exhibits high gamma-ray log response at the base of the unit. Other potential source rocks of secondary importance are Early Pennsylvanian and include dark fine-grained carbonate rock and shale units within the Marble Falls Limestone and the black shale facies of the Smithwick/Atoka Shale. The Barnett Shale was deposited over much of North-Central Texas; however, because of post-depositional erosion, the present distribution of Barnett is limited to Province 045. The Barnett Shale is over 1,000 feet (300 m) thick along the southwest flank of the Muenster Arch. It is eroded in areas along the Red River-Electra and Muenster Arches to the north, the Llano uplift to the south where it outcrops, and the easternmost portion of the province where the Barnett laps onto the Eastern Shelf-Concho Platform.
Average total organic carbon (TOC) content in the Barnett Shale is about 4% and TOC is as high as 12% in samples from outcrops along the Llano uplift on the south flank of the Fort Worth Basin. It has geochemical characteristics similar to other Devonian-Mississippian black shales found elsewhere in the US (e.g., Woodford, Bakken, New Albany, and Chattanooga Formations). These black shales all contain oil-prone organic matter (Type II kerogen) based on hydrogen indices above 350 milligrams of hydrocarbons per gram of TOC and generate a similar type of high quality oil (low sulfur, >30 API gravity). Although kerogen cracking decomposition is a source of oil and gas from the Barnett Shale, the principal source of gas in the Newark East Field is from cracking of oil and bitumen.
Low maturation levels in the Barnett Shale at vitrinite reflectance (Ro), estimated at 0.6-0.7%, yield oils of 38° API gravity in Brown County. Oils found in Shackelford, Throckmorton, and Callahan Counties as well, as in Montague County, are derived from Barnett Shale at the middle of the zone of oil generation (oil window) thermal maturities levels (≈0.9% Ro). Although condensate is associated with gas production in Wise County, Barnett source rock maturity is generally 1.1% Ro or greater. The zone of wet gas generation is in the 1.1-1.4% Ro range, whereas the primary zone of dry gas generation (main gas window) begins at a Ro of 1.4%.
Thermal maturity of Barnett Shale can also be derived from TOC and Rock-Eval (Tmax) measurements. Although Tmax is not very reliable for high maturity kerogens due to poor pyrolysis peak yields and peak shape, the extent of kerogen transformation can be utilized. For example, Barnett Shale having a 4.5% TOC and a hydrogen index of less than 100 is in the wet or dry gas windows with equivalent Ro values greater than 1.1% TOC. In contrast, low maturity Barnett Shale from Lampasas County outcrops have initial TOC values averaging about 12% with hydrocarbon potentials averaging 9.85% by volume. A good average value for Barnett Shale is derived from the Mitcham #1 well in Brown County where TOC is 4.2% and hydrocarbon potential is 3.37% by volume. Using these data we can determine TOC values will decrease 36% during maturation from the immature stage to the gas-generation window. Samples from the T. P. Simms well in the Newark East gas-producing area have average TOC values of 4.5%, but greater than 90% of the organic matter is converted to hydrocarbons. Thus, its original TOC was about 7.0% with an initial estimated potential of 5.64% by volume. Any oil generated would be expelled into shallow (or deeper) horizons as in the west and north, or cracked to gas where measured vitrinite reflectance is above 1.1% Ro.
The Barnett Shale is thermally mature for hydrocarbon generation over most of its area. Barnett source rock is presently in the oil-generation window along the north and west parts of the province, and in the gas window on the east half of the Barnett-Paleozoic TPS. Expulsion of high-quality oil from the Barnett was episodic and began at low (Ro = 0.6%) thermal maturity. Thirty-two oils from Wise and Jack Counties were analyzed to determine the characteristics of the generating source rock. API gravity and sulfur content were integrated with high-resolution gas chromatography (GC) and Gas chromatography-mass spectrometry (GCMS) analyses. The API gravity of the oils ranges from 35° to 62° and sulfur contents are low (<0.2%), which is characteristic of high thermal maturity oils. Biomarkers from GCMS analyses show oils were sourced from marine shale, based on sterane distribution and the presence of diasteranes. Carbon isotopic analyses of saturated and aromatic hydrocarbon fractions support hydrocarbon generation from a single-source unit. In the main gas-producing area of fractured Barnett Shale, the gas generation window is along a trend sub-parallel to the Ouachita thrust front. Jarvie (2001) reported the British Thermal Unit (BTU) content of Barnett gas is directly proportional to Ro levels.
Reservoir rocks include clastic and carbonate rocks ranging in age from Ordovician to Early Permian. Most production from conventional reservoirs is from Pennsylvanian rocks, whereas the only recognized production from unconventional accumulations is from Mississippian fractured Barnett Shale and early Pennsylvanian (Atokan?) fractured Marble Falls Limestone. Conglomerate of the Pennsylvanian Bend Group is the main producing reservoir in the Boonsville Bend Field with cumulative production through 2001 exceeding 3 trillion cubic feet (85×109 m3) of gas. Oil sourced from Barnett Shale is produced from numerous reservoir rocks in the Bend Arch–Fort Worth Basin, including Barnett Shale, Caddo Formation, Canyon Group, Chappel Limestone, Bend Group, and Ellenburger Group.
Seal rocks in the Barnett-Paleozoic TPS are mostly shale units and dense, low permeability carbonate rock that are distributed on both regional and local scales. Barnett Shale is a major regional seal for older reservoirs, mostly porous carbonate rock reservoirs of the Ellenburger Group. Production from Barnett Shale is largely dependent on the presence or absence of Marble Falls and Viola limestones. Although these formations are not considered seal rocks in areas where they are tight and not water wet, they serve as barriers confining hydraulic-induced fracturing (frac barriers) and help retain formation pressures during well stimulation.
Traps for conventional hydrcocarbon accumulations are mostly stratigraphic for carbonate rock reservoirs and both structural and stratigraphic in clastic-rock reservoirs. Combination structural and stratigraphic traps are also common in Pennsylvanian sandstone reservoirs. Stratigraphic traps in carbonate rocks result from a combination of facies and depositional topography, erosion, updip pinchout of facies, and diagenetically controlled enhanced-permeability and porosity zones. A good example of a carbonate stratigraphic trap is the pinnacle reef traps of the Chappel Limestone, where local porous grainstone and packstone are restricted to isolated buildups or reef clusters on low-relief paleotopography of the eroded Ellenburger Group. Chappel pinnacle reefs are draped and sealed by the overlying Barnett Shale. Stratigraphic traps in Pennsylvanian Atoka sandstones and conglomerates are mainly pinch outs related to facies changes or erosional truncation.
Fractured Barnett Shale
High-quality (35-40° API gravity, low sulfur) oil is produced from Barnett Shale in the province's north and western portions where it exhibits low thermal maturity (Ro ≈ 0.6%). Similar quality oils (40-50° API gravity), and condensates associated with gas are produced in Wise County where the Barnett is of higher thermal maturity. Gas production is from hydraulically fractured black siliceous shale. Calorific values of gases from NE-F commonly range between 1,050-1,300 BTU. The Barnett's main producing facies is a black, organic-rich siliceous shale with a mean composition of about 45% quartz, 27% clay (mostly illite/smectite, and illite), 10% carbonate (calcite, dolomite, and siderite), 5% feldspar, 5% pyrite, and 5% TOC. Average porosity in the productive portions is about 6% and matrix permeability is measured in nanodarcies.
Three assessment units have been proposed for the Barnett Shale continuous accumulations, each with different geologic and production characteristics:
- a NE-F gas "sweet spot" where the Barnett is siliceous, thick, within the gas generation window, slightly overpressured, and enclosed by dense, tight overlying Marble Falls Limestone and underlying Viola Limestone and Simpson Group as frac barriers;
- an outlying area where the Barnett is within the gas-generation window but the subcrop is the porous Ellenburger and the overlying Marble Falls Limestone barrier may be absent; and
- an area of lesser potential where overlying and underlying barriers may be absent and production includes oil and gas from fractured Barnett Shale.
The siliceous nature of the Barnett Shale, and its relation to fracture enhancement in NE-F, was noted by Lancaster. Also, the second assessment unit, where the Barnett Shale subcrop is Ellenburger Group carbonate rocks, is being tested by several operators. The unit's resource potential unit will be guided by the results of current testing with directional wells and various completion methods to determine optimum completion techniques for gas recovery.
Historically, estimated ultimate recoveries (EURs) for Barnett gas wells at NE-F increased with time, as follows:
- 300 to 500 million cubic feet (8.5 × 106 to 1.4 × 107 m3) of gas before 1990;
- 600 to 1000 million cubic feet (1.7 × 107 to 2.8 × 107 m3) of gas between 1990 and 1997; and
- 800 to 1200 million cubic feet (2.3 × 107 to 3.4 × 107 m3) of gas between 1998 and 2000.
In 2002, Devon Energy reported the mean EUR for Newark East Barnett gas wells is 1.25 billion cubic feet (35×106 m3) of gas. The progressive increase in EUR in Barnett wells is the result of improved geologic and engineering concepts that guide development of the Barnett continuous gas play. Moreover, recompletion of wells after about five years of production commonly adds 759 million cubic feet (21.5×106 m3) to its EUR.
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