Winnepegosis Facies and Reservoir Characteristics, Temple Field, North Dakota

James R. Ehrets, Don L. Kissling

Since its discovery in 1982, Temple field has been developed into the largest Winnipegosis oil pool in the Williston basin. Situated on a subordinate limb of the Nesson anticline in northeastern Williams County, the combined structural-stratigraphic trap contains approximately 7.5 million bbl of primary recoverable oil reserves defined by 22 productive wells. Dolomitized upper slope mudstone represents the principal reservoir facies. This facies is overlain by a poorly dolomitized platform-margin reef facies that serves as the reservoir seal.

The Temple Winnipegosis reservoir is envisioned to have developed in response to late Winnipegosis sea level drawdown and widespread exposure of the carbonate platform. Confined between less permeable strata represented by underlying argillaceous slope facies and overlying reef facies, the nonargillaceous slope facies was dolomitized in a mixing zone created by downward and seaward movement of meteoric water into connate marine water. Early cementation of reef facies also served to limit brine invasion and salt plugging of the reservoir upon later transgression of the platform by the hypersaline Prairie sea.

The slope reservoir is generally characterized by 12-20% porosity and 10-70 md permeability. By comparison, reef porosity is typically 2-8%, with less than 3 md permeability. Halite cement is a common constituent in reef facies, having precipitated from hypersaline brine that invaded the reef through a system of fractures and vugs. Halite cement is also responsible for partial reservoir destruction in the underlying slope reservoir, particularly where the reef is poorly developed.

AAPG Search and Discovery Article #91033©1988 AAPG Rocky Mountain Section, Bismarck, North Dakota, 21-24 August 1988