Gas Injection for Upstructure Drainage
Authors: Combs George D. , Knezek Raymond B. 
Published: December 2007

Here are a theoretical analysis and a summary of field data on the performance of upstructure drainage projects in which gas is injected and performance of upstructure drainage projects in which gas is injected and oil is produced through the same well in a cyclical operation. It has proved to be an economical method of recovering upstructure reserves that proved to be an economical method of recovering upstructure reserves that are too small to justify additional wells.

Introduction
The first application of gas injection for recovery of oil located above the highest well in a reservoir was revealed to the industry in a 1954 publication by Evans and Barry, of Stanolind Oil and Gas Co. They reported that gas injection was started in Aug., 1950, into the Camerina "B" sand of their West Hackberry field in Cameron Parish, La. Limited industry acceptance of this additional recovery process was initially based upon this favorable report. A number of additional articles appeared in industry publications and the process became generally accepted for both one-well and multiwell reservoirs by mid-1960. Humble's experience with one-well gas injection projects started in the offshore and southern projects started in the offshore and southern Louisiana areas in the late 1950's. (In this study 130 of the projects were considered.) These projects have produced 3.4 million bbl of oil not economically recoverable by other means. Average gas injection requirements for all projects at depths from 4,000 to 13,500 ft have amounted to 3.1 Mscf of gas per barrel of oil recovered. Some of this gas has been produced back with the oil, and the net amount of gas left in all reservoirs is 3.1 Mscf/STB. This is expected to decline to about 2.5 Mscf/STB when all projects are depleted. Clearly it is economically attractive and good conservation practice to recover these reserves. Previous publications about one-well projects in which the same well is used for gas injection and oil production have described in detail the reservoir production have described in detail the reservoir characteristics and performance of one or two projects that generally were quite successful. There is, projects that generally were quite successful. There is, however, a notable absence of theoretical methods for estimating production rates from these projects and of field data on the performance of a large number of projects with widely varying reservoir characteristics. Our purpose here is to present theoretical guidelines and field data concerningthe maximum gas-oil segregation rate,the maximum average oil production rate,the minimum and actual gas requirements to recover one barrel of oil, andidentification of the projects that are most likely to succeed.

Theory
Fig. 1 shows an idealized one-well reservoir with gas being injected. The reservoir is bounded on the sides by faults, updip by salt or shale, and downdip by an oil-water contact. Although the geometry is idealized, the general situation is typical of many small, water-drive reservoirs found around piercement salt domes in southern and offshore Louisiana. The updip oil in these reservoirs is recovered by a cyclical operation with three distinct parts. First, gas is injected and migrates updip by gravity segregation. This is followed by a shut-in period in which the gas continues to migrate updip from the well. Then the well is produced until the displaced oil is recovered.
JPT
P. 361