Design and Operation of the WorldTs Highest Pressure Gas Injection Centrifugal Compressors

ABSTRACT This paper discusses the design features and operational case histories of high pressure, centrifugal gas-injection compressors. These compressors are currently being operated in the Phillips Group-Ekofisk, North Sea Project. High density gas compression can involve a problem called "subsynchronous rotor whirl" in centrifugal compressors. The methods - of attacking and solving this problem are discussed. It is concluded that centrifugal compressors will satisfy any known gas injection requirements. INTRODUCTION Energy conservation mandates that natural gas (which is entrained in high pressure crude oil) be recovered through injection. Injection not only retains the gas for future marketing but also maintains the field pressure at peak production. Crude oil production, which at Phillips Group Ekofisk North Sea Platform (see Fig. I) has exceeded 300, 000 bbls/day, requires that large amounts of gas be reinjected into the geological reservoir. The conservation minded Norwegian government allows flaring of only a limited amount of gas each day. Unless the remainder of the gas (in excess of 480 ECFD) can be reinjected, oil production must be curtailed. In order to meet gas injection requirements, it is necessary to use high flow, high pressure compressors. Previously, most companies used positive-displacement reciprocating injection compressors. Phillips Group decision to use centrifugal compressors for injection was unique because these units had never before been required to perform in such high flow, high pressure situations. Subsequently, the Ekofisk operation established the centrifugal compressor as the most practical means of gas injection. The natural gas used-for injection is recovered from crude oil in three separation stages. The high pressure crude is progressively flashed to 1000 psia, 265 psia and finally to 20 psia. At the low pressure level, the gas may be flared to the atmosphere or compressed to 265 psia by an Elliott 46M centrifugal compressor. From this pressure level, the gas is compressed to 1000 psia by an Elliott 38MB centrifugal compressor and then transported by pipeline to the injection platform where it is compressed by two identical trains of high pressure centrifugal compressors, each driven by a General Electric Frame 5 gas turbine. The gas is compressed to the injection pressure level in two compression stages. The first stage is an Elliott 25MBH centrifugal compressor which receives the gas at 975 psia and increases the pressure to 3500 psia. The gas is then intercooled and sent to the second stage 25MBHH centrifugal compressor which increases the pressure to the required injection pressure level. This pressure which is a function of gas flow and the number of injection wells can vary from 6000 to 8700 psia. The actual "bottom-hole" pressure, which is a function of the reservoir geological structure, will vary over long periods of time. The design and development of this centrifugal compressor were a major, state of- the-art breakthrough; the problems confronted and their solution have greatly advanced engineering design technology.