Reservoir Performance Monitoring Techniques Used in the Forties Field

Abstract

Summary This paper describes the techniques used to monitor reservoir performance in the Forties field. Based on the large number of data gathered to date, a detailed numerical model of the reservoir has been compiled, which is used to predict future reservoir performance. Both conventional openhole logs and the Repeat Formation Tester (RFT)TM are run in all wells to define reservoir conditions at the time of completion. Both thermal decay time (TDT) and production combination tool (PCT) surveys are used extensively to describe fluid movement through the reservoir, and the results have been used in planning effective workover operations. Produced water is analyzed regularly to monitor injection water breakthrough and potential barium sulfate scaling problems. During 1981, radioactive tracers were introduced into injection wells to allow more accurate monitoring of the movement of injected water. Introduction The Forties field, discovered by British Petroleum (BP) in Oct. 1970, is located 106 miles [170 km] off the coast of Scotland in License Blocks 21/10 and 22/6a (Fig. 1). Geologically, the reservoir is an anticlinal structure of Paleocene age consisting of interbedded sandstones and shales known as the Forties formation. The internal sedimentary structures and facies relationships of the Forties formation are characteristic of a submarine fan depositional environment. Two oil-producing sand bodies, the Main sand and the Charlie sand, have been identified through data collected from the drilling of 84 development wells. The field covers an area of approximately 35 sq miles [90 km2] and has a maximum oil column of about 460 ft [140 m]. Oil is being displaced by bottomwater drive and, generally speaking, good vertical equilibrium is maintained. A general description of the Forties reservoir is shown in Figs. 2 through 4. Oil production began in Sept. 1975 and reached the plateau offtake rate of 500,000 B/D [79 494 m3/d] in May 1978. This plateau rate was maintained until 1981, and in April 1982 cumulative production reached 1 billion bbl [0.16 × 10(9) m3]. With the good reservoir performance seen to date, the recoverable reserves are estimated to be about 2 billion bbl [0.3 × 10(9) m3] by 1995. Development of the field through June 1983 consisted of 63 producing wells and 19 water injectors drilled from four identical fixed-leg platforms each designed to handle 150,000-B/D [23 848-m3/d] oil production and 150,000-B/D [23 848-m3/d] seawater injection. Well deviations range up to 70 degrees [1.2 rad], allowing peripheral water injection of treated seawater at wellhead injection pressure of 1,200 to 1,300 psig [8.2 to 9 MPa]. Field water injection has reached the planned average rate of 450,000 B/D [71 544 m3/d]; current water production is 57,000 B/D [9062 m3/d], or 11% of the total produced Dubs. To gain a good understanding of reservoir behavior, to identify problem areas, and to take remedial action where needed, it is necessary to monitor field performance with accurate field data. This paper describes the techniques used in Forties to collect such data. Water Movement Monitoring To ensure that maximum oil recovery is achieved from the reservoir, it is vital that the movement of both injected water and aquifer influx be closely observed through the use of openhole logs, cased-hole production logs, and the regular analyses of produced fluids. TDT and production (PCT, PLT) logs have proved very useful as reservoir monitoring tools and for aiding workover decisions. Routine fluid sampling and analysis have proved effective in determining water-cut trends. More detailed analyses of water samples are carried out to determine sulfate concentrations and to detect radioactive tracers, which were added to injection wells during 1981. Further details of water movement monitoring are discussed next. Openhole Logging. Whenever hole conditions permit, the 8 1/2-in. [22-cm] open hole is logged on all newly drilled or sidetracked wells. The routine logging suite consists of a dual laterolog/microspherically focused log/gamma ray, formation density compensated/ compensated neutron/gamma ray, borehole compensated sonic/gamma ray, and the RFT. Data from these logs are combined to produce a computer-processed interpretation (CPI) log. which is used to identify oil zones and to highlight water and hydrocarbon saturation trends. The initial water saturations calculated by the openhole CPI log are later used in conjunction with the cased-hole TDT logs to give a quantitative indication of water saturation changes with time. JPT P. 457^