SPE Members Abstract A major obstacle to the successful implementation of an enhanced oil recovery project is the proper completion of the injection wells to prevent fluid loss. The injectants are often expensive and highly corrosive. Further, economics dictate in many cases that the wells to be completed and used as the input wells for the injectant be existing wells; the economics simply do not allow for the drilling of new injection wells. These wells were originally designed without this purpose in mind and are very often old, at least thirty years. Most of these wells suffer from poor casing integrity and small casing sizes. Again, economics do not allow for the use of corrosion resistant high nickel chrome alloy liners. To solve these problems, a unique completion method was designed using fiberglass casing and a drillable permanent packer as the liner hanger. The permanent packer was also used as the injection packer. This system allows the use of corrosion resistant fiberglass for control of the corrosive injection fluids and imparts the ability to drill out the permanent packer and the fiberglass liner to prevent the loss of the well bore in the future, if mechanical problems do arise. problems do arise. This paper will describe in detail the development of the injection system, and the remedial procedures required. Case histories from an procedures required. Case histories from an operator in southeastern New Mexico will demonstrate the successful recompletion of existing well bores into injection wells, supported by injection profite data that demonstrates injected fluid control. Economics demonstrating cost effectiveness of the unique completion design are also presented. Introduction The slimline fiberglass liner system was developed to allow an operator to successfully and economically implement a tertiary CO2 miscible flood. A pilot CO2 injection project had demonstrated the potential revenue to be realized by tertiary oil recovery. There were, however, major economic and operational concerns to be addressed before a field-wide CO2 injection program could be undertaken. The existing injection wells were all over 30 years old. Originally drilled as producing wells, these wells had been converted to water injection wells during the implementation of a field-wide water flood program in the early 1960's. These injection wells all had two common problems; poor casing integrity and small casing sizes. Injection profiles indicated a significant amount of injected water-as much as 90% in some cases-was lost to non-pay intervals and the majority of the injection wells had four and one half inch (4 1/2") casing, with the balance having five and one half inch (5 1/2") casing. Since the loss of only a small amount of CO2 into a non-pay interval could significantly reduce the profitability of the project, the injection wells profitability of the project, the injection wells would have to be repaired. If the wells could not be repaired, replacement injection wells would have to be drilled and the old wells plugged and abandoned. The estimated 14 million dollars this would require, would severely effect the economics of the project. The CO2 pilot project had also shown the injectant to be extremely corrosive. Standard carbon steel liners would not, in all probability, survive the life of the CO2 injection flood. Corrosion of the liners would lead to the loss of CO2 into non-pay intervals. In addition, the small casing sizes were a handicap. If a carbon steel alloy liner was run and corrosion caused a loss of casing integrity, it would mean the loss of the well bore. There was not enough room to run another liner, and it was not economically feasible to attempt fishing and milling operations to recover the steel liner and recomplete the well. P. 321

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