Optimization of Well Performance in a Selective Subsea Sand-Control Completion, Offshore Nigeria
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDeveloping the Okwori field (offshore Nigeria) required the combination of several recent technological advances. The subsea development targeted multiple oil-bearing zones in all wells with the requirement that each zone could be operated independently. Expandable sand screen (ESS) strings were deployed within casing for up to four zones in order to prevent sand production from unconsolidated sandstone reservoirs. Independent control of all zones was made po… Show more
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Cited by 3 publications
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Efficient Cost Saving through an Appropriate Completion Design
Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. Considering the fact that completion takes a substantial stake in the whole CAPEX for a new well, the cost and the impact of the well completion is too significant to be ignored. Two field case studies will be discussed in the present paper to demonstrate the possibility of cost saving through efficient completion designs. The first case study is focused on a deviated gas producer, and the second on a horizontal oil producer. The most popular completion options, including openhole gravel pack, cased-hole gravel pack, openhole, standalone screen, cased-hole frac pack, expandable sand screen, inflow control devices (ICD), intelligent well completions (DIACS), etc, will be considered in the completion selection. Other completion options such as alternating standalone screen and blank pipe that may slash completion cost without sacrifice of well performance will also be proposed and evaluated. Well performance will then be evaluated in details by assessing total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Cost recovery, water and/or gas shut-off, formation damage, casing collapse, sand prevention issues associated with different completion options will be addressed. A work flow aiming at optimizing well performance while maintaining completion cost at the minimum will be proposed. Introduction Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. With more and more advanced well completion options deployed in new wells, especially in the deep and ultra-deepwater environment, the cost and the impact of the well completion is too significant to be ignored. The major motivation for the study is to illustrate the strategy and workflow that should aid to achieve an efficient completion design in regard to both cost saving and production efficiency. The procedure will be applied to two filed examples to demonstrate its application. Literature Review As anticipated, a wide range of well completion aspects, including completion performance review, completion design, completion selection, sand control, gas and water shut-off, best practices and lessons learned, etc., have been discussed in a significant number of SPE papers. A selection of the most recent studies is briefly introduced here for reference. Powers et al[1] reviewed the completion evolution in the Chirag field, compared the relative performance of completion types over a range of indicators, and discussed measures to take to improve open-hole gravel pack performance from a reservoir damage perspective. Ouyang & Huang[2] compared the performance of horizontal and multilateral wells under different completion options. Total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner have been evaluated.
Efficient Cost Saving through an Appropriate Completion Design
Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. Considering the fact that completion takes a substantial stake in the whole CAPEX for a new well, the cost and the impact of the well completion is too significant to be ignored. Two field case studies will be discussed in the present paper to demonstrate the possibility of cost saving through efficient completion designs. The first case study is focused on a deviated gas producer, and the second on a horizontal oil producer. The most popular completion options, including openhole gravel pack, cased-hole gravel pack, openhole, standalone screen, cased-hole frac pack, expandable sand screen, inflow control devices (ICD), intelligent well completions (DIACS), etc, will be considered in the completion selection. Other completion options such as alternating standalone screen and blank pipe that may slash completion cost without sacrifice of well performance will also be proposed and evaluated. Well performance will then be evaluated in details by assessing total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Cost recovery, water and/or gas shut-off, formation damage, casing collapse, sand prevention issues associated with different completion options will be addressed. A work flow aiming at optimizing well performance while maintaining completion cost at the minimum will be proposed. Introduction Well completion plays a critical role in well design, and more importantly, the performance of the well in its entire life. With more and more advanced well completion options deployed in new wells, especially in the deep and ultra-deepwater environment, the cost and the impact of the well completion is too significant to be ignored. The major motivation for the study is to illustrate the strategy and workflow that should aid to achieve an efficient completion design in regard to both cost saving and production efficiency. The procedure will be applied to two filed examples to demonstrate its application. Literature Review As anticipated, a wide range of well completion aspects, including completion performance review, completion design, completion selection, sand control, gas and water shut-off, best practices and lessons learned, etc., have been discussed in a significant number of SPE papers. A selection of the most recent studies is briefly introduced here for reference. Powers et al[1] reviewed the completion evolution in the Chirag field, compared the relative performance of completion types over a range of indicators, and discussed measures to take to improve open-hole gravel pack performance from a reservoir damage perspective. Ouyang & Huang[2] compared the performance of horizontal and multilateral wells under different completion options. Total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner have been evaluated.
fax 01-972-952-9435. AbstractThe challenge posed by deep water field development particularly in complex geological architecture necessitates the application of new technologies to improve well performance/ultimate recovery and reduce well construction costs. Therefore, proper evaluation of a variety of new products is imperative so as to ensure selection of a purpose-fit technology. Additionally, a peer review process must challenge the execution plan and identify possible flaws. Then, risks can be assessed and adequate mitigation plans put in place to ensure success. In a first of its kind application in West Africa and probably in the world, Addax Petroleum employed a paradigm shift in zonal isolation in its subsea well construction; in 440ft of water, employing a combination of Elastomeric Packers and compliant Expandable Sand Screen (ESS), two 3-zone single string selective subsea wells in its OML-126 Okwori field have been completed, a feat that will potentially change zonal isolation equation in the industry. The cost savings include elimination of production casing; cementation, wait on cement, cement evaluation, associated loss circulation control, cased hole tubing conveyed perforation, perforation burr removal trip, extensive wellbore cleanup, brine filtration and Acid/Enzyme stimulation to treat post perforation lost control material (LCM). The Implementation included peer Successful Installation of Elastomeric Packers/Expandable Sand Screen in Subsea openhole completions Offshore Nigeria 3 installation, deployment of packers, documentation and back analysis and finally, opportunities for improving future completions.
Subsea Development of Okwori and Nda Oil Fields, Niger Delta
Summary Addax Petroleum's operated Okwori oil field, offshore Nigeria, illustrated the benefits of reviving shelved projects, because of an insufficient return on investment using more traditional approaches, by applying more recent technical and contractual solutions. The Okwori project demonstrated the feasibility of developing small and geologically complex offshore oil fields in medium water depth of 440 ft with subsea technologies traditionally used for large fields. In the subsurface, the Okwori wells combined multiple selective completions hydraulically controlled from the surface with expandable sand screens as the downhole sand exclusion solution. This combination of equipment in subsea wells used to fully develop a small offshore oil field marked another technological first in Nigeria. Far away from pre-existing facilities and with less than 50 million bbl of median technical reserves at the time of project sanction, the Okwori oilfield development went a step further than the more usual subsea tieback to a pre-existing offshore production facility. The Okwori development plan was based on horizontal subsea trees flowing to a leased spread-moored floating production storage and offloading (FPSO) vessel by means of (6-in.) flexible subsea flowlines and risers. The Okwori leased production facilities had a built-in capability for additional tiebacks such as the Nda oil field, whose development was completed in October 2006, or for later redeployment in other parts of the acreage depending on further exploration and appraisal drilling. A review of the field operations to date highlighted a steep learning curve in the formulation of completion design, completion fluids, stimulation, downhole sand exclusion systems, and bean-up/bean-down procedures. Introduction The Okwori oil field (OML 126) was discovered offshore Nigeria in 1972, approximately 50 miles southwest of the city of Port Harcourt (Fig. 1). Despite a prolific initial well test, subsequent field appraisal revealed a complicated geological structure and fluid distribution with fragmented hydrocarbon pools of limited extension. The Okwori field therefore remained dormant until Addax Petroleum Exploration (Nigeria) Ltd. acquired the asset in 1998 and provided a development plan. Okwori field development drilling started in July 2004 after drilling ND-1, the Nda oilfield discovery well located due west of Okwori. Okwori first oil was delivered in March 2005 as planned. Subsurface Critical Success Factors In the subsurface, Okwori's main challenge was the large number of reservoir layers and fault-delimited compartments resulting in numerous potentially hydrocarbon-bearing pools. More than 100 of those pools were mapped from two vintages of 3D seismic surveys; before field development, six wells appraised 30 such pools (Fig. 2). The Okwori structure resulted from a collapsed crest anticline with two intersecting sets of syn- and post-sedimentary fault planes (Fig. 3). It was noted that seismic imaging was of poor quality owing to the convergence of multiple faults in the core of the collapsed crest and the presence of shallow gas accumulations. Appraisal well trajectories were designed to scoop reservoir closures against fault planes. Hydrocarbon content (oil or gas) and fluid contacts differed between compartments of the same reservoir level, adding another level of complexity to the development. Risked oil-in-place volumes were computed to rank reservoir targets and guide the field development. Each development well was considered as an appraisal well for which the decision to complete any reservoir level would be taken after drilling and logging the well. It was also clear that the size of these hydrocarbon pools would seldom justify more than a single producer per pool. Nigeria petroleum law specified a minimum distance of 800 m between two drainage points in the same hydrocarbon pool, which in Okwori meant only a single possible completion per pool. Pressure maintenance through water or gas injection would require additional wells, a situation neither financially attractive nor technically desirable because of the small dimensions and compartmentalization of the oil rims. Finally, the Okwori reservoirs were made of unconsolidated sandstones from the Niger Delta that required some form of sand control.
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