Reservoir Simulation of the Planned Miscible Gas Injection Project at Rhourde El Baguel, Algeria
Authors: Clonts Michael , Mazighi Mohamed , Touami Mahiedine 
Published: December 2007

The Rhourde El Baguel (REB) project is an infill drilling and lean gas injection project for enhanced oil recovery. From the initial development plan the estimated total recovery from the REB Field over the next 25 years is over 80 million cubic meters (500 million barrels) of oil, condensate, and liquid petroleum gas (LPG).

Generation of the REB development plan required a highly integrated, multi-disciplinary team of specialists in many areas including sedimentology, fracture analysis, petrographic analysis, reservoir engineering, drilling, facilities, operations and economics. Reservoir simulation was a key component of the integrated effort. This paper briefly describes the project and the reservoir and then details the construction, validation and practical application of various reservoir models used to generate and optimize the REB development plan.

Introduction

The REB Field is one of the largest oil fields in Algeria (Ref. 1 and Fig. 1). The field was discovered and began production in 1962. The peak production rate of approximately 15000 cubic meters (94000 barrels) of oil per day was achieved in 1968 with 17 producing wells. The current rate, after more than 30 years of production, is approximately 4000 cubic meters (25000 barrels) of oil per day, with cumulative production of over 68 million cubic meters (430 million barrels) of oil, or approximately 15 percent of the original oil-in-place.

The REB Field is a thick, elongated, faulted anticline which trends northeast to southwest with an area of roughly 50 square kilometers (12000 acres) (Figs. 2–3). The reservoir was originally filled with a highly undersaturated oil with a specific gravity of 0.806 (440 API). Original reservoir pressure was 397 bars(a) (5750 psia) with a bubble point pressure of 165 bars(a) (2390 psia). The reservoir produced under solution gas drive with an initial solution gas-oil ratio of 167 cubic meters per cubic meter (938 standard cubic feet per barrel). Average reservoir pressure is currently estimated to be approximately 138 bars(a) (2000 psia) at a subsea depth of 2895 meters (9500 feet). A secondary gas cap has formed at the crest of the structure, and at present, is estimated to cover approximately 6 percent of the reservoir hydrocarbon pore volume. There are currently 21 serviceable production wells at an approximate spacing of 1.3 square kilometers (320 acres). Production to date has been mostly by primary depletion; however, a small peripheral water injection pilot, implemented in 1976 and shut-in in 1991, injected a total of 16 million cubic meters (99 million barrels) of water.

Complexities related to forecasting and optimizing the development plan include the effect of natural fractures on sweep efficiency, the floodability of less permeable rock in the lower zone and the uncertainty associated with repressurization of the reservoir fluid back to its minimum miscibility pressure of approximately 275 bars(a) (4000 psia). These complexities were carefully considered in the reservoir simulation approach used to create the initial optimized development plan.

Project Description

Gas injection will initially consist of crestal injection and dispersed injection into 11 nine-spot gas-flood patterns on approximately 0.65 square kilometers (160 acre) well spacing (Fig. 4). The development plan includes drilling new wells for production and injection service (Table 1). Injection of natural gas has already commenced by diverting injection gas from the Mesdar Field (Mesdar Gas in Table 1). The initial phase of the project will begin with drilling of new production wells and with restoration of selected shut-in wells, recompletions, hydraulic fracturing, gas lift, and other facility optimizations, where feasible.

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