High Volume Pumping in the Rangely Weber Sand Unit

Abstract

Abstract A review of high volume pumping operations in the Rangely Weber Sand Unit is presented in this paper. The pumping problems encountered and methods used to combat them are discussed. High volume pumping is utilized on both oil producing and water source wells. Pumping problems resulted from free gas interference and pounding, plus corrosive and scale forming well fluids. Submersible as well as large capacity rod pumps are operating at depths of 6,500 ft. High volume pumping is economically successful. Introduction High volume pumping in the Rangely Weber Sand Unit consists of electrically driven submersible pumps and rod pumping units with a stroke length of 100 in. or greater. High volume pumping is utilized in oil producing wells and water source wells.At the end of 1962 there were 73 long-stroke rod pumping units and nine electrically driven submersible pumps in operation in oil producing wells. The water source wells included 10 electrically driven submersible pumps and one shaft driven submersible pump.The Weber wells flowed on initial completion. As the reservoir pressure declined, conventional 64-in. stroke rod pumping units were installed. The wells were pumped through the tubing and flowed on the casing-tubing annulus. When the wells would no longer flow on the annulus they still contained much more potential than could be produced with the conventional units. At this time installation of the 100- to 120-in. units began. Subsequent water flooding increased well potentials, and the 192-in. rod pumping units and electrically driven submersible pumps were installed. Field History The Rangely Weber reservoir was discovered in March, 1933, by the California Oil Co. Development of the field was not started until Oct., 1943, and continued through May, 1949.The reservoir structure is an asymmetrical anticline. The field is approximately 12 miles long and 5 miles wide. The Weber sand contains interbedded shale that increases with depth. The Weber is 1,200 ft thick. Only the upper 700 ft is considered oil productive. There was a small original gas cap. The top of the Weber at the crest is –205 ft subsea. The original gas-oil contract was at –330 ft subsea and the water-oil contact at –1150 ft subsea. Surface elevations range from 5,200 ft to 5,700 ft which result in pumping depths to 6,700 ft.The wells have 7-in. casing set to the top of the Weber or gas-oil contact, and then have an open hole completion to the oil-water contact, or to 700 ft of Weber penetration. Approximately one-half of the wells have been shot. Nearly all the wells have been sand-oil fractured.There is a gas injection program that dates back to Nov., 1950. Gas injection has been dispersed over the field rather than all into the gas cap. The field was unitized on Oct. 1, 1957, with the California Oil Co. its operator. A waterflooding program was initiated in Jan., 1958, utilizing water from the Navajo and Entrada formations. Pumping Conditions in Oil Producing Wells As shown in Fig. 1 the Weber crude has a relatively low gas solubility that varies remarkably with structural elevation. At low pumping bottom-hole pressures, wells with a producing gas-oil ratio of 1,000 cu ft/bbl or less will have a large amount of free gas entering the wellbore. This results in low pump efficiencies and low annular pressure gradients. Fig. 3 shows the calculated per cent by volume of free gas contained in the fluid entering the wellbore for various producing gas-oil ratios and pumping bottom-hole pressures for the - 1,040 ft structural elevation edge wells. These calculations are based on the gas solubilities shown in Fig. 1 and formation volume factors shown in Fig. 2.From the above it is apparent that there must be some gas-oil separation in the wellbore to obtain a respectable pump efficiency. Mechanical bottom-hole separators were installed in eight wells. The gas-oil ratios of these wells ranged from 400 to 2,500 cu ft/bbl with pumping units of 64-in. to 192-in. stroke lengths. These installations used a packer set near the bottom of the 7-in. casing and a bottom-hole separator with a by-pass for the oil and gas that allows the gas to continue up the casing annulus and the oil to fall back to the pump intake. Each installation resulted in decreased pump efficiency and production. To install the bottom-hole separators it was necessary to raise the pumps as much as 560 ft. JPT P. 823^