Analysis of Hydrofracture Geometry and Matrix/Fracture Interactions during Steam Injection

by A. R. Kovscek, R. M. Johnston, Tadeusz W. Patzek
Year: 1996


Kovscek, A. R., R. M. Johnston, and T. W. Patzek. "Analysis of hydrofracture geometry and matrix/fracture interactions during steam injection." In SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers, 1996.


​This is the second part of our analysis of a steam drive pilot in the South Belridge Diatomite, Kern County, California. In this pilot, steam is injected through two noncommunicating, vertical hydrofractures (IN2U and IN2L) that nearly span the entire 1000 ft tall diatomite column. In the first part, we summarized pilot results for the initial 1200 days of steam injection and examined steam convection and heating resulting from injection into the lower hydrofracture.
Here we update the pilot response from 10/90 to 11/95. We conclude that the cumulative oil production in the far (543N) and close (543P) producer was 106,000 and 55,000 BO, respectively. and the incremental oil production above primary was 60,000 and 37,000 BO, respectively. This translates to the total oil recovery of 9% OOIP and the incremental oil recovery over primary of 6% OOIP after 5 years of steam injection. From our simulations of steam injection in IN2U and IN2L, we estimate that 246,000 BS CWE was injected to the west towards S43N and 102,000 BS was injected to the east toward 543P. The cumulative oil steam ratio (COSR) for the pilot was, therefore, 0.45, and the incremental COSR was 0.28.
We also apply a high resolution numerical model developed in the first paper to interpret the results of steam injection through the upper hydrofracture of the pilot. Results of this analysis indicate that the upper injection hydrofracture was highly dynamic and asymmetrical while undergoing steam injection. Steam flowed preferentially into the northern wing of the hydrofracture which reached a final winglength of 250 ft. To the south, hydrofracture winglength reached roughly 75 ft and diatomite heating was weak. A dramatic temperature response above the perforated interval of the upper injection well suggests that a horizontal fracture, or network of natural fractures, opened within the formation and linked to the injection hydrofracture. Our analysis indicates that roughly 43 percent of the total injected steam migrated above the perforations of the injection well, but remained within the Diatomite, and flowed rapidly away from the fracture face due to a large increase of hydraulic diffusivity of the formation.