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

A significant problem confronting Operators in modern field development and production is that created by loss of functionality of the surface controlled subsurface safety valve (SCSSV) due to blockage of, or damage to, the hydraulic control line. The consequent loss of hydraulic pressure to the valve means its closure, the resultant loss of production and the need to provide an alternative safety system in order to continue exploiting the wells reserves Currently two alternatives are available:○A full scale workover to pull tubing, replace the inoperable control line and restore functionality to the SCSSV.○Installation of a velocity or dome charged subsurface controlled subsurface safety valve (SSCSSV). The former approach requires a major expense, which may not be justifiable in a mature well, while the reliability offered by the latter approach typically does not meet well integrity requirements and can sometimes lead to reduced production. Nederlandse Aardolie Maatschappij (NAM) has been faced with this problem in many onshore and offshore wells and was determined to find an alternative solution. Based on the successful completion of a previous development project, NAM asked Weatherford to jointly develop a solution to this problem, which would allow the installation of an alternative control line without the expense of a workover. In this paper the authors will review the problems associated with loss of control line functionality and consequent SCSSV malfunction. They will go on to describe in detail the joint project which led to the development, testing, and eventual field deployment of the Weatherford Damaged Control Line (WDCL) Safety Valve featuring surface control, which can be installed using wireline and capillary string techniques. Introduction In any and all field developments which incorporate surface controlled subsurface safety valves a significant potential problem exists with the hydraulic access conduit. When a control line is used to provide hydraulic power to the safety valve, the danger is ever present that it could become blocked or damaged thus rendering the safety valve inoperable. When such a situation occurs there are normally two possible alternatives to be considered in order to restore safety valve control to the well and thereby facilitate continued safe production:○The well can be worked over to pull the tubing, replace the damaged control line and recomplete the well with a functioning safety system. This approach involves major expenditure which, in more mature wells, can often be financially unjustifiable because the remaining reserves may be insufficient. In the case of NAM operations the approximate cost of such a workover is in the range 6 - 8 million Euros which makes it a fiscally unattractive approach.

The GA-03 well on the Gannet platform in the UK sector of the North Sea developed a blockage in the safety valve control line that rendered the existing tubing retrievable safety inoperable. In addition, the seal bores inside the valve were scarred and damaged badly enough that a conventional wireline safety valve would not seal. These were the problems confronting the operator as they planned remediation work to return the well to production. Initially a major rig workover had been anticipated to pull the tubing and replace the safety valve and control line. This operation required the use of a Hydraulic Workover Unit (HWU) to perform the work which would carry a multimillion dollar cost. An alternative method was examined that would allow replacement of the safety valve and control line without pulling the production tubing or making changes to the wellhead configuration. This alternative method was a new concept not previously attempted by any operator in the North Sea. This innovative approach would involve the installation four elements: A new safety valve landing nipple in the production tubing using a specially modified seal bore production packer. A new wireline safety valve that would be landed in the new landing nipple A new control line and special control line connector installed inside the production tubing. A modified lower master valve to allow wellhead penetration for the injection of hydraulic power fluid to the new control line. This particular combination of tools had never been run together and their installation would have to be accomplished under a severe deadline, as the HWU job had been planned for execution in September 2009. To accomplish this, the entire operation had to be planned, designed, manufactured, tested, qualified and installed in the GA-03 well before the end of the year. It is a great credit to the project team that from initial proposal for use of the new system in July, they were able to achieve the target date of returning the well to production by the end of 2009. This showed the high level of cooperation and collaboration between the operator and the completion tool and wellhead providers. This paper will describe in detail the system components and the decision processes and evaluations that led to the selection of this alternative repair method. The collaborative efforts between the operator and two major service providers will be examined and discussed and the installation procedure described in detail. The paper will describe why the successful completion of this project marks a significant milestone in the remediation of older producing wells.

In order to comply with local regulation, production volumes from each reservoir in the Okowri field offshore Nigeria, must be identifiable. Addax Petroleum's strategy for their Okwori subsea field development project was to produce a number of stacked reservoirs in each of the wells, using selective completions to facilitate testing and fingerprinting of individual zones. Due to the unconsolidated nature of the reservoir, downhole sand control was required for all wells. A technical study of all available technology at the time of design showed that expandable sand screen deployed inside the casedhole could deliver the combination of reservoir zonal isolation and internal diameter for integration with selective downhole control flow valves and isolation packer. This combination of expandable and intelligent completion technologies was an industry first. The initial completion design was based on casing and cementing the entire productive interval prior to perforating each of the target reservoir sands. Expandable sand screens [ESS®] were then placed across each interval spaced out with blank pipe. Isolation packers were set within the string to provide zonal isolation. Following installation of the sandface completion, downhole flow control valves were run through the expanded sand screens and the producing interval isolated, with packers set in the blank pipe run between the sections of expandable sand screen. This completion configuration delivered zonal isolation and surface control over each zone, facilitating selective production and fingerprinting. This paper describes the initial casedhole completion design, systems installation and subsequent performance as well as the engineering and project management that are required in order to deliver this combination new technology system. Further, the paper will also discuss how the original completion design has evolved with the introduction of the latest openhole zonal isolation devices to deliver a true openhole sandface completion with intelligent selectivity. Introduction The Okwori oil field [today OML 126] was discovered offshore Nigeria in 1972, approximately 50 miles southwest of the city of Port Harcourt [Fig. 1]. Average water depth in this region is 440 ft. Field appraisal revealed a complicated geological structure with fragmented hydrocarbon pools of limited extension that discouraged further development The Okwori field was acquired in 1998 by Addax Petroleum Exploration [Nigeria] Ltd. who presented a development plan that received Nigerian Petroleum Authorities approval. Okwori field development drilling started in July 2004; first oil was delivered in March 2005. The initial Okwori development phase included 8 producers and was completed by October 2006. Okwori Project Overview A challenging subsurface Away from the traditional image of an anticlinal oil trap, Okwori field is a chaotic ensemble of superimposed hydrocarbon and water bearing pools separated by faults. This structural complexity was explained through the development of a collapsed crest anticline along two intersecting sets of syn- and post-sedimentary fault planes. The convergence of multiple faults in the core of the collapsed crest and the presence of shallow gas accumulations added to the natural complexity the challenge of difficult seismic data interpretation. Today, more than 250 fault-dip closures have been identified, 59 of them with proved hydrocarbon content. Appraising while developing Given the subsurface complexity, the information available from the initial discovery and appraisal wells was very limited. The presence of hydrocarbon had been established; a well test had shown good permeabilities and pools of limited size. Side wall sample analysis established the unconsolidated nature of the reservoir sands. Development wells would have to access scattered reserves, by penetrating sand compartments of largely unknown fluid content and production potential, since even hhydrocarbon content [oil or gas] and fluid contacts differed between compartments of the same reservoir level.

fax 01-972-952-9435. AbstractIn order to comply with local regulation, production volumes from each reservoir in the Okowri field offshore Nigeria, must be identifiable. Addax Petroleum's strategy for their Okwori subsea field development project was to produce a number of stacked reservoirs in each of the wells, using selective completions to facilitate testing and fingerprinting of individual zones.Due to the unconsolidated nature of the reservoir, downhole sand control was required for all wells. A technical study of all available technology at the time of design showed that expandable sand screen deployed inside the casedhole could deliver the combination of reservoir zonal isolation and internal diameter for integration with selective downhole control flow valves and isolation packer. This combination of expandable and intelligent completion technologies was an industry first.The initial completion design was based on casing and cementing the entire productive interval prior to perforating each of the target reservoir sands. Expandable sand screens [ESS®] were then placed across each interval spaced out with blank pipe. Isolation packers were set within the string to provide zonal isolation. Following installation of the sandface completion, downhole flow control valves were run through the expanded sand screens and the producing interval isolated, with packers set in the blank pipe run between the sections of expandable sand screen. This completion configuration delivered zonal isolation and surface control over each zone, facilitating selective production and fingerprinting.This paper describes the initial casedhole completion design, systems installation and subsequent performance as well as the engineering and project management that are required in order to deliver this combination new technology system. Further, the paper will also discuss how the original completion design has evolved with the introduction of the latest openhole zonal isolation devices to deliver a true openhole sandface completion with intelligent selectivity.