Analysis of Unusual Performance Indicates High Solution-Gas-Drive Recovery Stateline Ellenburger Field
Authors: Platt C.R. , Lewis W.M. 
Published: December 2007

The primary depletion performance of the Stateline Ellenburger field did not follow the predicted usual performance for a solution-gas-drive reservoir. performance for a solution-gas-drive reservoir. Observed performance and interpretation of reservoir behavior indicate that there is a high equilibrium gas saturation for this dolomite reservoir, and that primary recovery by solution-gas drive may exceed 50 primary recovery by solution-gas drive may exceed 50 percent of the oil in place. percent of the oil in place. The Stateline field is located in Lea County, N.M., and Andrews County, Tex., and produces from the Ellenburger formation at an average depth of about 12,200 ft. The formation is a light tan dolomite with numerous pinpoint vugs and considerable fracturing. Permeabilities determined from core analysis ranged Permeabilities determined from core analysis ranged from less than 0.1 md to more than 1,000 md. Weighted average values for porosity and permeability calculated from the thickness of the net pay core samples were 3.1 percent and 90 md, respectively. The value for average permeability from core analysis is in good agreement with the effective permeabilities of 45 md to 100 md calculated from pressure buildup measurements. The porosities indicated by Sonic logs generally agreed with the core analysis values. Fluid analysis of a subsurface sample indicated a saturation pressure of 1,555 psig. The original reservoir pressure pressure of 1,555 psig. The original reservoir pressure was approximately 4,970 psig. Separation tests of the reservoir fluid sample indicated a separator GOR of 437 cu ft/bbl, with a crude oil gravity of 43.3 API. The initial producing GOR's from the wells under similar separator conditions ranged from 418 to 577 cu ft/bbl. The formation volume factors at the original pressure and at bubble-point pressure were 1.270 and 1.316, respectively. Viscosity of the fluid was 0.53 cp at the saturation pressure and 1.49 at atmospheric pressure. Three field-wide bottom-hole pressure surveys were conducted during the first 9 months of production. Because of reservoir pressure differences noted in the surveys and because of an indicated shear fault, the field was divided into a north area and a south area for purposes of calculating oil in place and estimating purposes of calculating oil in place and estimating performance. The reservoir pressure in the north area performance. The reservoir pressure in the north area had declined from the original pressure of 4,970 to 1,881 psig, only slightly above the bubble-point pressure of 1,555 psig, with the production of only pressure of 1,555 psig, with the production of only 305,000 bbl of oil. The straight-line method for the material balance solution was used to calculate the oil in place from the reservoir pressure and production data in each area. The material-balance calculations were solved on the basis of the laboratory-measured fluid properties and of a rock compressibility value indicated by Hall's correlations between compressibility and porosity. These calculations indicated that the original oil in place was 3,846,000 STB in the north area and 2,180,000 place was 3,846,000 STB in the north area and 2,180,000 STB in the south area. Four pieces of core sample were used by Continental Oil Co. for rock compressibility measurements. The data obtained in the laboratory indicated a value for rock compressibility approximately half that indicated by Hall's correlations.

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