Twenty-Three Years of Gas Injection into A Highly Undersaturated Crude Reservoir

Abstract

Abstract Gas injection, as a means of pressure maintenance, has been employed in the Bahrain field Second Pay Limestone reservoir for the last 23 years. The crude contained in this reservoir is highly undersaturated. This paper describes the methods used to calculate the quantity of gas entering into solution in the reservoir crude and the indicated recovery of oil by gas, which has been found to be much greater than that by water drive. The paper also relates the history of the gas-cap expansion and its final shape as defined by neutron logging. Introduction and History The Bahrain field is situated in an anticlinal feature of middle Cretaceous period, containing a number of separated conformable pay zones. The most important of these, both from the standpoint of size and commercial reserves, is the one which has been named the "Second Pay Limestone". This paper deals with the performance of this reservoir, first when it was solely under natural water drive and later when pressure maintenance by gas injection was utilized. The Second Pay Limestone reservoir is about 6 1/2-miles long X 2 1/2-miles wide. It is a continuous zone with numerous small faults, none of which appears to affect the pressure-production performance. The contained rock is a soft, porous, sugary limestone with limited fractures and vugs, and its average thickness is 110 ft. The original water-oil contact was placed at a depth of –2,175-ft subsea. Core analyses indicate the porosity of the rock to be between 20 to 30 per cent and the average permeability as 40 md. However, the permeability of the reservoir determined by pressure build-up curve analyses or from steady-state radial- flow formula is much higher, being of the order of 1 darcy. The original reservoir pressure was 1,236 psig at the chosen datum of –1,900-ft subsea. There was no original gas cap in the reservoir because the crude oil in place is highly undersaturated, having a bubble point of 278 psig at a reservoir temperature of 140F and a solution gas-oil ratio of 142 cu ft/bbl. The viscosity of the crude under reservoir conditions is between 2.2 and 2.3 cp. Early production from the reservoir was taken from wells situated on the crest of the structure, since the mechanism of production was thought to be water drive. From the pressure-production history, however, it was soon evident that water influx was not keeping pace with the rate of oil withdrawal and that a considerable proportion of the oil was being produced by expansion of the reservoir crude, as shown by the pressure decline curve of Fig. 1. The utimate recovery from the natural depletion mechanism was calculated to be low and, after an engineering study had been made, it was decided that pressure maintenance by gas injection should be attempted to improve recovery. Accordingly, gas injection to the crest of the reservoir was commenced in April, 1938. The gas for injection was obtained from a deeper and higher-pressured Arab zone gas reservoir, and the cost of expensive compressor plants thus was eliminated. After 23 years, gas for injection is still being acquired in this way. JPT P. 361^