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• W2091013307 abstract "Summary Experience at the North West Hutton field has emphasized the importance ofproperly understanding gas-lift valve behavior. In conjunction with regulardownhole pressure and temperature surveys, this has helped maximize productionfrom gas-lifted wells. This paper emphasizes the importance of the downholetemperature survey and of simultaneous well testing with downhole survey work. The paper shows how this kind of performance analysis can reveal such classicproblems as leaking valves and such fundamental problems as mandrel spacingthat does not match well performance. These analysis techniques also canpredict the consequences of increasing available surface injection pressure andhave led naturally to the development of more flexible pressure and have led naturally to the development of more flexible design procedures that optimize production from wells whose performance may be either unpredictable or unlikelyto permit a deep point of injection. Field application of these design procedures also is discussed. Introduction The North West Hutton field is located in the East Shetland basin, in License Block 211/27 of the U.K. North Sea, approximately 300 miles northeastof Aberdeen. The reservoir lies at 12,000 ft subsea in the Middle Jurassic Brent group sandstones. It is characterized by a series of fitted fault blocksand extreme vertical and horizontal heterogeneity in its five major sand units. Field production began in April 1983 following the installation of a 40-slot, twin-rig, fixed steel platform in 475 ft of water and the tieback of seven predrilled wells. By June 1983, the average daily oil production was almost70,000 B/D. Reservoir production was almost 70,000 B/D. Reservoir pressure andproduction initially declined pressure and production initially declined rapidly. To arrest this decline, water injection was started in Feb. 1984. Significant water production began in Sept. 1984, and the first well was placedon gas lift, using recirculated sales gas, in Oct. 1984. By Dec. 1985, allproducing wells were being continuously gas-lifted (Fig. 1). Wells typically are completed with either 5 1/2-or 4 1/2-in. production tubing and a deep-set 95/8-in. production packer located just above the top of the 7-in. liner that penetrates the reservoir. Gas-lift gas circulate penetrates the reservoir. Gas-lift gas circulate down the casing/tubing annulus and enters the tubing through a wireline-retrievable, 1 1/2 -in. gas-lift valve set inside as idepocket mandrel in the tubing string. Wellbore deviation is in some cases ashigh as 70 degrees and measured depth can be as deep as 19,000 ft. With both increasing water cut in several key wells and a general repressurizing of the reservoir occurring as a result of water injection, we found that the originalsales-gas discharge pressure of 1,600 psig was not adequate for pressure of1,600 psig was not adequate for injecting gas-lift gas as deep as desired intothe production tubing. Consequently, in Sept. 1985, a back pressure control valve was installed on the sales-gas line to boost the pressure of gas circulating for gas lift to 2,000 psig (Fig. 2). With all producing wells ongas lift and with water production rates increasing as oil and associated gasproduction declined, a need soon arose for increased gas-lift gas rates. This increase was achieved in Feb. 1987 when the platform gas-impression packages were modified to boost their packages were modified to boost their capacity from the original 40 MMscf/D to more than 70 MMscf/D. By Dec. 1988 this capacity was being fully utilized, continuously lifting 20 producing wells. Well 211/27-A01A Case Study Gas-lift design and performance analysis in the North West Hutton field is best discussed in the context of a case study of one particularly important and interesting well, particularly important and interesting well, Well 211/27-A01, which is referred to here as Well A01. Well A01 was the first well in the North West Hutton field to be, brought on production (April 1983). Initially, it flowed production (April 1983). Initially, it flowed naturally and tested oilat more than 26,000 B/D, with 0% water cut. By Feb. 1985, liquid production hadfallen to less than 8,000 B/D production had fallen to less than 8,000 B/D anda 21% water cut had developed following injection-water breakthrough in Dec.1984. It was predicted that the well would cease to flow once water cut reached30%, and so the well was worked over and a gaslift completion string was run. The valves were designed to unload and lift a well producing 6,000 BLPD with a70% water producing 6,000 BLPD with a 70% water cut. Initial gas-lifted liquidproduction was, in fact, more than 12,000 B/D with a 40% water cut. This result emphasized the need for more flexible gas-lift designs, particularly where production performance particularly where production performance may change rapidly. Increased Casing Pressure Requires Replacement Valves. The increase inavailable gas-lift gas casing pressure in Sept. 1985 was immediately put to use in newly completed wells. All gas-lift designs from that point onward were based on a surface casing point onward were based on a surface casing pressureof 1,850 psig rather than the 1,500 pressure of 1,850 psig rather than the1,500 psig previously available. This meant that psig previously available. This meant that deeper points of injection could be achieved, insulting in either increased production or reduced gas-lift gas-injection rates being required to reach the same production rate. These benefits, however, do not automatically carry over to wells where existing valves have been designed fora lower available casing pressure. JPT P. 96" @default.
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• W2091013307 date "1991-01-01" @default.
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• W2091013307 title "Gas-Lift Design and Performance Analysis in the North West Hutton Field" @default.
• W2091013307 doi "https://doi.org/10.2118/19280-pa" @default.
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