Slaughter Estate Unit CO2 Pilot - Surface and Downhole Equipment Construction and Operation in the Presence of H2S

Abstract

Summary This paper presents the material selection, construction procedures, safety devices, corrosion control and monitoring, and operational procedures necessary for successful compression, transportation, and injection of a gas stream containing 28% hydrogen sulfide. It also discusses various operational problems encountered during the 3-year project life. Introduction As Amoco's West Texas waterfloods in the San Andres formation matured, it became evident that they would reach their peak production levels and begin to decline in the early 1970's. It also became evident that recovery of original oil in place through primary and secondary means would be in the range of 25 to 45%. The large quantities of oil which would remain unrecovered led to considerations of tertiary recovery methods.Although much laboratory work had been done in studying tertiary recovery processes, it was recognized that only field testing in a reservoir environment could prove the economic viability of the various tertiary methods. Screening of possible recovery techniques led to the selection of the miscible displacement process as having the most promise in these reservoirs. A company-wide search was made in late 1970 for possible tertiary project sites, and several pilot sites were selected to test the various miscible agents.A portion of the Slaughter Estate Unit which had not been waterflooded was selected as a site for a pilot test of the CO2 miscible displacement process. Fig. 1 shows the location of the Slaughter field in relationship to the West Texas - eastern New Mexico area. Fig. 2 shows the location of the Slaughter Estate Unit within Slaughter field. Eight pilot wells were drilled from March through June 1972, and waterflood operations began in Nov. 1972. Peak secondary oil production was seen in mid-1973, and by mid-1976 a steady secondary decline rate was discernible.It soon was determined that at projected injection rates a reliable source of pure CO2 in sufficient quantities and a means of delivering it to the pilot site did not exist. There was, however, a feed gas stream to the Claus sulfur unit at the Slaughter gasoline plant, about 7 miles (11.3 km) from the pilot site, which consisted of approximately 72% carbon dioxide and 28% hydrogen sulfide. Investigations ascertained that there were no commercially available processes for completely separating the hydrogen sulfide and carbon dioxide in the Claus plant feed gas (hereafter referred to as acid gas). Further, laboratory tests showed that the displacement process using acid gas as a solvent was the same as when CO2 was used. Preparations were made, therefore, to compress the acid gas stream and to transport it through a transmission line to the pilot wellsite.Of course, there was never any consideration given at any time to the use of the acid gas stream as a miscible agent during full-scale field flooding. In any case it would have provided only a tiny fraction of the required volumes of CO2. JPT P. 1065^