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.

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).

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.