Bighorn Basin Geology
The Bighorn Basin is an elongate, northwest-trending structural basin in north-central Wyoming. It is approximately 193 km (120 mi) long and up to 145 km (90 mi) wide. Along the axis of the basin, the total thickness of Paleozoic, Mesozoic, and Cenozoic rocks exceeds 7,620 m (25,000 ft). The basin is bounded on the north and east by the Pryor and Bighorn mountains, and on the south and west by the Owl Creek, Absaroka, and Beartooth mountains.
The present structural configuration of the Bighorn Basin resulted from the Late Cretaceous through Early Eocene Laramide orogeny (Blackstone, 1963), during which the peripheral mountain uplifts experienced their major growth. The folding and faulting that formed oil-producing anticlines in the Bighorn Basin occurred during pulses of compressional stress, mainly oriented northeast-southwest.
The source of the oil and gas found in the basin’s Paleozoic reservoirs is the dark, phosphatic fine-grained, marine facies of the Phosphoria Formation (Stone, 1967). Primary hydrocarbon migration began immediately after deposition of Triassic sediments and was completed by Early Jurassic time.
Both structural and stratigraphic traps occur in Paleozoic and Cretaceous source-rock/reservoir systems in the Bighorn Basin. Structural plays include basin margin subthrusts, basin margin anticlines, deep basin structures, and sub-Absaroka-volcanics (Fox and Dolton, 1996). Later Laramide folding may have been superimposed on or near the primary structural traps. Although most of the basin’s production comes from anticlinal or other structural traps, Lawson and Smith (1966) suggest that many of the structurally-controlled traps are influenced by stratigraphic effects, including intraformational variations in permeability and, as in the Bonzanza and Nowood fields, incised channels in the Tensleep surface that were filled with impervious Goose Egg sediments.
Pure stratigraphic traps are also productive within the Bighorn Basin, including Phosphoria Formation pinchouts (up-dip facies change), Tensleep Sandstone paleogeography (dune fields versus interdune regions), and irregular truncation of thick Tensleep Sandstone beds prior to deposition of the Phosphoria/Goose Egg Formation (Stone, 1967; Fox and Dolton, 1996).
The largest of these is the Cottonwood Creek field in the southeast corner of the basin, a trap resulting from an eastward, updip facies change from Phosphoria carbonate to the impermeable red shale and anhydrite facies of the Goose Egg Formation. Oil and gas in some of these stratigraphic traps were later released by fracturing and faulting associated with Laramide folding. During the Laramide orogeny, these hydrocarbons moved into older Paleozoic reservoir rocks and older structures where they were trapped in pools. The occurrence of a common oil-water contact is attributed to fractures joining the reservoirs. The oil-water contact is also often tilted as a result of hydrodynamic flow (Stone, 1967).
Mesozoic formations produce a much lower percentage of the Bighorn Basin’s oil and gas, with most production coming from the Upper Cretaceous Frontier Formation. Source rocks in the Mesozoic include the Cody, Frontier, Mowry, and Thermopolis black shale units (Stone, 1967).
Production
The Bighorn Basin is primarily an oil-producing basin (WSGS oil and gas map). Oil was first discovered in the basin in the 1880s seeping from a spring on the Bonanza anticline. Oil has since been produced from more than 125 fields in the basin and from more than 30 reservoirs and/or co-mingled reservoirs ranging in age from Cambrian to Paleocene. Seven of these fields are in the top 10 cumulative oil-producing fields in Wyoming (WOGCC, 2024).
Future Development
Despite the decreasing production levels, most fields in the Bighorn Basin still contain a significant quantity of recoverable oil. In response, operators are utilizing secondary and tertiary recovery techniques to revitalize old fields and to activate fields that were not economically feasible in years past. Future oil production in the Bighorn Basin will rely on the success of these recovery techniques.
Unconventional reservoir plays could also improve oil and gas production in the Bighorn Basin. Fox and Dolton’s (1996) resource assessment identified basin center/deep gas and coalbed natural gas as significant potential future plays within the basin. Many of the same Cretaceous formations currently being exploited as unconventional reservoirs in other Wyoming basins also exist in the Bighorn Basin. Future exploration for similar unconventional plays, horizontal drilling, and hydraulic fracturing could again make the Bighorn Basin a major player in state oil and gas production.
References
Blackstone, D.L., Jr., 1963, Development of geologic structures in central Rocky Mountains, in Childs, O.E., and Beebe, B.W., eds., Backbone of the Americas—Tectonic history from pole to pole: Tulsa, Okla., American Association of Petroleum Geologists Memoir, p. 160–179.
Fox, J.E., and Dolton, G.L., 1996, Petroleum geology of the Bighorn Basin, north-central Wyoming and south-central Montana, in Bowen, C.E., Kirkwood, S.C., and Miller, T.S., eds., Resources of the Bighorn Basin: Casper, Wyo. , Wyoming Geological Association, 47th annual field conference, Guidebook, p. 19–39.
Lawson, D.E., and Smith, J.R., 1966, Pennsylvanian and Permian influence on Tensleep oil accumulation, Bighorn Basin, Wyoming: American Association of Petroleum Geologists Bulletin, v. 50, no. 10, p. 2,197–2,220.
Stone, D.S., 1967, Theory of Paleozoic oil and gas accumulation in Bighorn Basin, Wyoming: American Association of Petroleum Geologists Bulletin, v. 51, no. 10, p. 2,056–2,114.
WOGCC, 2024, Wyoming Oil and Gas Conservation Commission website, accessed March 2024, at http://pipeline.wyo.gov/legacywogcce.cfm.