Abstract

The paper describes the results of a multidisciplinary study aimed at optimizing the performance and reducing the gas requirements of a gas injection project in a complex volatile oil reservoir situated in Lake Maracaibo Basin in Western Venezuela. A 3-D reservoir simulation model with corner point geometry and multiple crisscrossing faults were constructed to achieve the objectives. The fluid samples were properly characterized for input to the model. A continuous team interaction between the various geoscience and engineering disciplines facilitated the proper characterization of the reservoir heterogeneities which in turn enabled the history matching of the field performance. The integrated effort culminated in accurate simulation of the reservoir pressure profile and detailed representation of the reservoir heterogeneities.

Sensitivities were carried out with the model to investigate various exploitation schemes for improving the oil recovery. A multidisciplinary team effort followed to evaluate the sand continuity, sedimentological and petrophysical characteristics and to select the appropriate locations of inverted 7-spot patterns for implementation of the Water Alternated Gas Injection process (WAG) in the regions identified by the model as poorly depleted.

The simulation results indicated that a better pressure support and consequently, a more improved oil recovery can be achieved by the WAG process (36 and 430/a of the OOIP for the 20 and 30 years of the predicted cases respectively). Furthermore, the results show that the initial gas requirement can be substantially reduced to 30 MMSCF/D and a gas production of up to 80 MMSCF/D can be obtained by year 2004. This gas production will be sufficient to maintain the injection requirement for the WAG process in the later stages.

Introduction

The Eocene C is a deep, large and geologically complex, volatile oil reservoir, located in Block III, Lake Maracaibo, Venezuela (Fig. 1). The reservoir structure is an elongated flank, 16 by 4 kilometers, with dip ranging from 2 to 5 degrees. The reservoir is composed of low permeability sands (20 – 600 Md.) and a crude whose composition is near to critical point at initial conditions. The estimated OOIP was 1636 MMSTB of 48 degrees API gravity crude, and cumulative production on January 1995 was 289 MMSTB (17.6 %) of OOIP.

From 1960 until 1992, the reservoir has been producing by natural depletion. The. reservoir pressure has declined from its initial value of 5900 psia to the current value of 3450 psia which is well below the bubble point pressure (4200 psia). A gas injection project was initiated in 1972 into the lower C-455 and C-460 sands to arrest the pressure decline in this heterogeneous and geologically complex reservoir whose crude is highly volatile.

During the reservoir exploitation history, several studies have been performed mainly to define and understand the reservoir geology and recovery mechanism (Refs. 1,2,3,4,5). These studies have shown that an appropriate modeling of the complex reservoir sedimentology and compositional effects of the reservoir fluids are key factors for reproducing the reservoir performance.

A 3-dimensional reservoir simulation model (27 × 59 × 10) was developed incorporating all the multidisciplinary information available to date (Refs. 1,5,6) for matching the historical reservoir production and pressure performance, and to determine the actual pressure and fluids saturation distribution in the C-455/60 flow units. This allowed an improved characterization of the reservoir heterogeneity and a better understanding of the fluid flow.

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