UPPER MISSISSIPPIAN SANDSTONE PLAY

The Upper Mississippian Sandstone Play is defined by gas and local oil trapped in Upper Mississippian deltaic and shallow-marine sandstone reservoirs by a variety of basement-involved fault blocks, combination traps, and stratigraphic traps. Stratigraphically, the play involves informally named sandstone units of the Upper Mississippian Parkwood Formation such as the Carter, Sanders, Lewis, Evans, Millerella, Abernathy, and Rea sandstones. The play is confirmed and extends across the entire Black Warrior Basin except for the northern margin where Mississippian rocks either crop out or subcrop beneath Cretaceous strata of the Mississippi Embayment. The sandstone reservoirs in the play are classified as conventional.

Reservoirs:

Primary reservoirs in the play are sandstone of deltaic and distributary channel origin. The thickness of these sandstone reservoirs generally range from 30 to 50 ft, but, locally, individual reservoir units may be as thick as 150 ft. Commonly, sandstone reservoirs exhibit continuity for 2–5 mi along depositional strike and for 10–15 mi along depositional dip. The source of the sandstone is controversial. One group of geologists suggests a cratonic source area to the northwest in the vicinity of the Ozark Uplift, whereas another group suggests an orogenic source area to the southwest in the vicinity of the Ouachita Fold and Thrust Belt. The sandstone reservoirs consist of quartzarenite containing 1–2 percent rock fragments and feldspar. Primary and secondary intergranular porosity are the dominant porosity types. Porosity values range from 5 to 20 percent, and permeability values range from 0.4 to 250 Md. The lowest porosity and permeability values cited here are from a depth of 8,500 ft in the Siloam field (Clay County, Miss.), and they indicate a marked decrease in reservoir quality toward the southern end of the basin. Tectonic fractures of extensional and transpressional origin may improve the reservoir quality of the sandstone. Extensional fractures are caused by widespread block-faulting episodes of Pennsylvanian age that broke the Alabama-Mississippi foreland into northwest-trending basement-involved blocks bounded predominantly by down-to-the-south normal faults. Transpressional fractures may have resulted from limited strike-slip motion between adjoining fault blocks.

Source rocks:

Dark-gray to black shale of the Upper Mississippian Parkwood Formation, Floyd Shale, and Neal shale (slope to basin facies of the Bangor Limestone) are the likely sources of gas and oil in the play. The Floyd Shale and Neal shale are as thick as 500 ft and 200 ft, respectively. Published total organic carbon values from undefined Upper Mississippian shale in Alabama, probably the Parkwood Formation and Floyd Shale, range from 0.07 to 2.36 (avg 0.58). The organic matter consists of type II and type III kerogen. Although no analyses are available, the Neal shale is expected to have total organic carbon values between 1 and 5 and organic matter that consists of type II kerogen. Based on CAI, TAI, and vitrinite reflectance values, the Parkwood Formation, Floyd Shale, and Neal shale are in the zone of oil generation and the beginning of the zone of gas generation. Oil and wet thermal gas are the expected hydrocarbon types.

Timing and migration:

Oil and gas probably were generated from the Parkwood Formation, Floyd Shale, and Neal shale in Late Pennsylvanian time when these rocks were deeply buried beneath a southward-thickening wedge of orogenic sediments derived from an Ouachita and (or) Appalachian source. Hydrocarbons were first generated at the southern end of the basin and migrated northward across the block-faulted foreland, along fractures and carrier beds, into anticlines and fault traps. As the zones of oil and gas generation expanded northward with increasing burial, the traps in the block-faulted foreland became charged with locally derived hydrocarbons.

Traps:

Structural traps and combination traps account for about 75 percent of the known gas and oil trapped in this play. The remainder of the gas and oil is trapped in facies-change stratigraphic traps. Faulted anticlines controlled by basement-involved fault blocks characterize the majority of the structural traps, whereas facies changes on an anticlinal nose or juxtaposed against a normal fault characterize the majority of the combination traps. Closure on prospective structural, combination, and stratigraphic traps covers an area between 1,000 and 9,000 acres. Probable seals for the structural, combination, and facies-change traps are shale and argillaceous siltstone of the Upper Mississippian Floyd Shale and Parkwood Formation. The drilling depth to the reservoirs in the majority of the Upper Mississippian sandstone fields ranges between 1,000 and 5,000 ft. Several fields produce from Upper Mississippian sandstone reservoirs between 8,500 and 10,000 ft. Potential structural, combination, and stratigraphic traps may be present as deep as 16,000 ft.

Exploration status:

Several thousand holes have been drilled through all or part of the Upper Mississippian sequence in the Black Warrior Basin. Between 1926 and January 1992, approximately 145 gas fields and 20 oil fields were discovered in the Upper Mississippian sandstone play. Most of the fields are in a 10-country area (Fayette, Lamar, Marion, Pickens, and Walker Cos., Ala.; Chickasaw, Clay, Lee, Lowndes, and Monroe Cos., Miss.) in the central part of the basin. The Carter sandstone is the primary gas reservoir. Through 1991, approximately 1 TCFG (85 percent of basin total) and 10 MMBO (95 percent of basin total) have been produced from Upper Mississippian sandstone reservoirs. The five largest fields discovered in the play are: Corinne, Monroe Co., Miss., discovery date 1972, depth 5,000–5,700 ft, ultimate recovery (Upper Miss. sandstone part) 378.6 BCFG; Blooming Grove, Fayette Co., Ala., discovery date 1975, depth 2,100 ft, ultimate recovery 169.6 BCFG; Musgrove Creek, Fayette Co., Ala., discovery date 1974, depth 2,500 ft, ultimate recovery 111.0 BCFG; McGee Lake, Lamar Co., Ala., discovery date 1979, depth 4,200– 4,700 ft, ultimate recovery 105.9 BCFG; and 5) Splunge, Monroe Co., Miss., discovery date 1973, depth 1,700 ft, ultimate recovery 101.2 BCFG. Most of the oil fields in the play have an ultimate recovery of less than 1 MMBO. Two exceptions are the Blowhorn Creek North field (Lamar Co., Ala., 2,000 ft-depth) which has an ultimate recovery of 14.5 MMBO, and the Maple Branch field (Monroe Co., Miss., 5,300 ft depth) which has an ultimate recovery of 2.0 MMBO.

Resource potential:

This play has potential for numerous undiscovered gas fields greater than 6 BCFG of gas and several undiscovered oil fields greater than 1 MMBO. Because 6 of the 39 largest gas fields in this play have been discovered since 1985, more gas (and probably oil) fields may remain to be found in the existing exploration area; however, the majority of the undiscovered gas in the play probably is in the deeper part of the basin at drilling depths between 8,000 and 16,000 ft. At these depths, reservoirs are expected to be distal-bar sandstone and possibly sandstone in previously unrecognized deltaic complexes. A major limiting factor to the play may be the paucity of sandstone reservoirs in the deeper parts of the basin. A second limiting factor is that sandstone reservoirs are expected to be thinner and of lower quality than reservoirs in the existing trend.

From: U.S.G.S. Assessment of Undiscovered Oil and Gas Resources of the Black Warrior Basin Province, 2002

Using a geology-based assessment methodology, the U.S. Geological Survey estimated a mean of 8.5 trillion cubic feet of undiscovered natural gas, a mean of 5.9 million barrels of undiscovered oil, and a mean of 7.6 million barrels of undiscovered natural gas liquids in the Black Warrior Basin Province.

Assessment Units

The total petroleum systems within the Black Warrior Basin Province are the Pottsville Coal TPS and the Chattanooga Shale/Floyd Shale- Paleozoic TPS (fi g. 2). The Black Warrior Basin AU of the Pottsville Coal TPS defi nes potential coal-bed gas found primarily in the Alabama portion of the basin. The Carboniferous Sandstones AU of the Chattanooga Shale/Floyd Shale-Paleozoic TPS is defined by gas and oil trapped in Upper Mississippian deltaic and shallow-marine sandstone reservoirs by a variety of basement-involved fault blocks, combination traps, and stratigraphic traps. The Pre-Mississippian Carbonates AU of the Chattanooga Shale/Floyd Shale-Paleozoic TPS is defined by gas

trapped primarily in Cambrian and Ordovician platform-carbonate reservoirs by basement-controlled fault blocks.

Resource Summary

The USGS assessed undiscovered conventional oil and gas and undiscovered continuous (unconventional) gas. For the Black Warrior Basin Province, the USGS estimated a mean of 8.5 trillion cubic feet of gas (TCFG), a mean of 5.9 million barrels of oil (MMBO), and a mean of 7.6 million barrels of total natural gas liquids (MMBNGL). Most (83 percent, or 7 TCFG) of the potential undiscovered gas resource is continuous (unconventional) coal-bed gas in the Pottsville Coal TPS (table 1). Undiscovered conventional gas resources, estimated to be about 1.5 TCFG at the mean, are in the Chattanooga Shale/ Floyd Shale-Paleozoic TPS, and undiscovered conventional oil resources, estimated to be about 5.9 million barrels (MMB) at the mean, are also within the Chattanooga Shale/Floyd Shale- Paleozoic TPS (table 1).

AAPG Annual Convention 2007, EMD Divison

Unconventional Shale Gas Potential of the Floyd Shale in the Black Warrior Basin, Northwestern Alabama . http://aapg.confex.com/aapg/2007am/techprogram/A110400.htm

Matthew W. Totten and Albert S. Oko. Department of Geology, Kansas State University, 108 Thompson Hall, Manhattan, KS 66506, phone: 785-341-0821, fax: 785-532-5159, mtotten@ksu.edu

The commercial success of Barnett Shale gas production in the Fort Worth basin has drawn abundant attention to other potential unconventional shale gas formations. The Mississippian-aged Floyd Shale in northwestern Alabama has been previously identified as the probable source rock for conventional oil production in the Black Warrior basin. The results of this study suggest that it also represents a potential unconventional shale gas resource. Twenty-five samples from seven wells were analyzed for their clay-mineralogy, total organic carbon (TOC), thermal maturity, kerogen type, formation thickness and stratigraphic position based upon well logs.

Two distinct areas of prospective production were delineated. The first is in the shallower, northern portion of the basin where the Floyd Shale is encased by two dense limestone units, comparable to the stratigraphic relationship needed to contain induced fractures necessary to achieve production in the Barnett Shale. It is relatively thick (>200 ft), organic rich (>3.0% TOC), but thermally immature (<1.0% vitrinite reflectance). A second area within the deeper part of the basin has thicker, organic-rich shale (~300 ft; >3.0% TOC), which is also thermally mature (vitrinite reflectance >1.0%), but lacks the upper limestone-bounding unit.

Patterns of maturation and burial-history data indicate secondary cracking of original oil to gas in the deeper parts of the basin. Like the analogous Barnett Shale, potential production will require artificial stimulation. Production from the deeper portion of the basin could be challenging due to the absence of the upper limestone fracture barrier.

South-Central Section–40th Annual Meeting (6–7 March 2006)

Oko, Albert S. Hydrocarbon Potential Of The Floyd Shale In The Black Warrior Basin, Northwestern Alabama

http://gsa.confex.com/gsa/2006SC/finalprogram/abstract_99765.htm

An unconventional shale gas play is considered a fully self-contained petroleum system, whereby critical petroleum system elements, source, reservoir, and seal coincide in the same formation. This study investigated the Mississippian Floyd Shale in Northwestern Alabama which represents a potential unconventional shale gas resource in the Black Warrior basin. Although the Floyd has been previously identified as the possible source rock for conventional Mississippian oil production in the Black Warrior basin, evidence from geochemical measurements suggests that it has a potential for unconventional thermogenic gas production. Mineralogy consists of illite clays and predominantly silica and calcite. Production will require artificial stimulation as indicated by low permeability measurements. Two distinct areas of prospectivity were delineated based on straigraphic position and thermal maturity. First is the shallow northern portion of the basin where the Floyd Shale is enclosed by dense limestone units, relatively thick (>200 ft; >61 m) and organic rich (>3.0% total organic carbon), but thermally immature (<1.0% vitrinite reflectance). A second area corresponds to the deep part of the basin where the formation is thicker (~300 ft; 92 m), organic rich (>3.0 total organic carbon), thermally mature (vitrinite reflectance >1.0%), but lacks the top limestone bounding unit. Patterns of maturation and burial-history data indicate secondary cracking of original oil to gas in the deep parts of the basin. Production from the deep portion could be challenging due to absence of the top fracture barrier, but good engineering of completion techniques can aid the Floyd Shale play economics.

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