Overpressured oil and gas reservoirs in the Rocky Mountain region are more widespread than generally recognized. "Normal" Rocky Mountain

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reservoir pressure gradients are about 0.42 to 0.46 psi/ft (9.5-10.4 kPa/m). Reservoir pressure gradients in excess of 0.5 psi/ft (> 11.3 kPa/m) are considered overpressured. However, most overpressured reservoirs have pressure gradients greater than 0.6 psi/ft (> 13.6 kPa/m). Although a variety of conditions can cause overpressuring, most high pressures in the region are interpreted to be caused by the "active" generation of oil and gas in sequences that still contain organic matter capable of yielding thermally generated hydrocarbons. Several authors have proposed that hydrocarbon generation can cause overpressuring. It is important to note that significantly overpressured water reservoirs are rare in the Rocky Mountain region and, where present, are usually in pressure contin ity with overpressured oil and gas reservoirs. Some slightly overpressured water reservoirs can be explained by local conditions, such as a pressure measurement at a location significantly lower than a topographically high-elevation water recharge area (artesian conditions).

Rocks with above normal pressure in Rocky Mountain basins range in age from Late Devonian to Tertiary and are commonly associated with low-permeability (tight) reservoirs. Most overpressured reservoirs occur in Cretaceous and Tertiary sandstone sequences. Overpressuring is not common in rocks older than Cretaceous except in very organic-rich sequences, probably because lean source beds that have been heated over a long period of time are no longer capable of yielding enough hydrocarbons to maintain abnormal pressure.

Statistically, nearly all overpressured reservoirs and source rocks have temperatures of about 200°F (93°C) or higher. In many basins, the onset of overpressuring occurs rather abruptly at this temperature in organic-rich sequences. In addition, available data indicate that hydrocarbon-related overpressuring does not usually occur if vitrinite reflectance values are < R_o = 0.5% in oil-prone sequences or < R_o = 0.7% in gas-prone sequences. These reflectance values are the lower limit for onset of significant generation of oil and gas, respectively.

Hydrocarbons expelled into widespread, high-permeability reservoirs probably migrate owing to hydrodynamic flow and buoyancy. These reservoirs usually have normal pressures. In contrast, low-permeability (tight) reservoirs retain the overpressuring and have maximum pressures about equal to the natural fracture gradient for rocks in a given area. In a 1978 study, F. F. Meissner proposed that pore pressures in excess of the natural fracture gradient initiate formation fracturing, and the hydrocarbons are expelled laterally and vertically until the pore pressure is reduced and the fractures close. These fracture-initiation pressure gradients range from ^approx 0.7 psi/ft (15.8 kPa/m) to > 0.85 psi/ft (> 19.2 kPa/m). The highest reservoir pressure observed to date in the Rocky Mount ins is in the Merna area (T36N, R112W), Sublette County, Wyoming, where reservoir pressure gradients in Upper Cretaceous sandstones exceed 0.9 psi/ft (> 20.4 kPa/m). Artificial hydraulic-fracturing pressure data indicate that in this area regional fracture gradients also are higher than normal.

Regional pressure analyses indicate overpressured hydrocarbon-bearing reservoirs occur in the following Rocky Mountain basins: Williston, Powder River, Bighorn, Wind River, Hanna, Green River, Washakie, Great Divide, Sand Wash, Piceance, Uinta, and Paradox.

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