This paper describes challenges, test equipment, test program and results in the development of a screen product and contingency fluid-loss control (FLC) pill formulation to withstand 4,600-psi burst resistance pressure. In maturing deepwater fields, such as Shell Ursa/Princess where depleted reservoir pressures are significantly below the hydrostatic pressure of a seawater column, a modified screen design was required since screen products currently available were limited to <3,500 psi. FLC pill formulations also required modification because they were only validated to 1,000 psi in the current laboratory test apparatus. A series of burst tests were conducted on a wire-wrap screen design direct wrapped to 4-in. base pipe. The objective was to determine if the screen could withstand at least 4,600 psi without damage. The wire-wrap design selected to improve the pressure rating was substantially heavier than what has been used in traditional sand-control completions. Initial burst tests with available 316L material averaged 4,600 psi. Two sets of additional burst tests were conducted with Alloy 625 screens on 25 Chrome base pipe to meet injector material requirements. The FLC formulation was modified from conventional design to enhance the pressure response. The last test results averaged over 5,100 psi. Comprehensive before and after measurements and slot inspections were done; the data were used in Finite Element Analysis to finalize the detailed screen design. No traditional mechanical burst of the screen occurred. Most influential factors were slot size/geometry and pill formulation. Introduction Ursa-Princess Waterflood Development Overview The Ursa and Princess Fields, brought online in 1999 and 2003 respectively, are part of the Mars basin located in the Mississippi Canyon area, offshore Louisiana, Gulf of Mexico, in 3,850 ft of water (Figure 1). The primary producing interval in both fields consists of an unconsolidated, turbidite amalgamated sheet sand with evidence of pressure communication through the hydrocarbon leg. Aquifer support does not exist within this sand; instead the primary recovery mechanisms are depletion drive and compaction. This lack of pressure support led the operator to develop plans for four high-rate subsea water injection wells (two in the Princess field and two in the Ursa field) to enhance production in the main producing sand. Eight direct vertical access wells from the Ursa TLP and three subsea Princess Wells will directly benefit from the planned water flood. The current lack of pressure support in the reservoir sand results in relatively low recovery efficiencies. Under the proposed development plan, the four injectors are expected to maintain higher pressures and improve sweep efficiency, ultimately resulting in significant incremental recovery.

Summary The Ursa-Princess Waterflood (UPWF) targets the Lower Yellow sand, the main reservoir in the Mars-Ursa basin in Mississippi Canyon, approximately 60 miles south of the mouth of the Mississippi River in the Gulf of Mexico (GOM). The Lower Yellow sand, a world-class Upper Miocene turbidite reservoir, has been on production in the Ursa and Princess fields since 1999, and has been drawn down nearly to the bubblepoint. The waterflood is intended to increase and stabilize reservoir pressure, and to improve sweep efficiency. To accomplish this, four subsea injectors were designed and constructed to inject treated seawater at 40,000 B/D each for a target life of 30 years. Because the Lower Yellow reservoir was already highly depleted, unique risks were identified in the planned subsea completion operations, to be conducted from a mobile offshore drilling unit (MODU). Seawater, used as a completion fluid, was expected to be up to 4,000 psi overbalanced to the reservoir, depending on the well location. This created the risk of either an uncontrollable fluid-level drop in the marine riser or an extreme impairment to the sandface completion. In order to maintain well control with a fluid level at the surface and still deliver low-skin completions, multiple design and procedural issues needed to be addressed, including the following: Control systems on the rig and riser system to prevent uncontrollable fluid-level drop. Perforating systems to minimize impairment in a highly overbalanced environment without adding undue risk to well control. Pill designs that could both control fluid loss at the sandface and clean up effectively. Downhole completion systems capable of functioning either under very high pressure differentials or against very high loss rates. Development of high-burst screens suited to the use of fluid-loss-control pills as a contingency provision in the event that mechanical fluid-loss devices failed. As more deepwater reservoirs approach depletion, specialized tools and procedures will be required to continue to deliver safe and effective sandface completions from floating rigs. This paper details many of these considerations and summarizes the execution experience and results for one such reservoir.

During initial completion operations on a deepwater subsea oil well in the Gulf of Mexico, the 7–3/4 in., 46.1 lb/ft casing failed the pressure test in the production liner. Subsequent operations located the casing leak 1,800 ft above the target completion intervals. The original completion was planned to be a stacked, commingled frac pack with reservoir depths over 23,000 feet and pressures over 14,500 psi. To best address the problem and maintain the original well objectives, a solid expandable tubular system was selected to isolate the casing leak. The first expandable cased-hole liner run in the well failed to initiate expansion and was recovered. Reviews, lab mechanical tests and surface prototype tests were conducted to determine the cause of the unsuccessful start and to plan a second run for casing remediation. The revised design deviated from standard equipment and used a shorter launcher with a smaller outside diameter (OD) and a closed-ended system. In addition to the equipment modifications, lessons learned from the first attempt influenced procedural changes for the second installation. The second cased-hole liner run in the well a few weeks later was successfully installed and expanded. The ~2,300 feet of expandable liner used eight elastomer seal anchor joints specifically located to isolate the leak and allow completion operations to resume essentially as planned. This installation was carried out with straightforward dimensional changes to the expansion system and revised procedures. The post-expansion dimensions of the liner enabled the completion of the well with a 7 in., 38 lb/ft equivalent inside diameter (ID) casing using standard completion equipment. At the time, this application set a record as the deepest cased-hole expandable liner ever run. The financial benefits of the installation included avoiding costs of drilling a risky sidetrack and production deferment. This paper will discuss the problem on the first installation attempt, the operational response, subsequent recovery, lab tests and surface trials. The second installation will be covered in detail with an overview of completion operations and a brief outline of the value added through this expandable liner solution. Introduction During the production casing pressure test at the start of completion operations, a leak was identified and located 1,800 ft above the reservoir intervals. This situation prompted a squeeze job in the casing, after which the casing was drilled out and a cement bond log was obtained. Although the cement held a pressure test after squeezing, engineering risk assessment deemed the squeeze unlikely to hold through multiple high/low pressure cycles required in the planned stacked frac-pack completion operations. To maintain the original stacked frac-pack objective, a robust mechanical barrier was required to provide pressure integrity for completion operations and throughout well life to avoid a costly subsea intervention. Remediation options were assessed based on cost, timing, installation risk and long-term reliability. Because of its technical attributes and economic benefits, a 6 × 7–3/4 in. expandable cased-hole liner was selected. This expandable liner could clad from below the reservoir intervals to above the leak and still maximize post-expansion ID. The system application was designed to provide elastomer seal anchor joints located between the OD of the expandable pipe and the ID of the production liner at each gravel-pack packer depth to avoid possible collapse loads from the micro-annulus during subsequent completion operations. An isolation packer assembly with a tail pipe/seal assembly was placed above and through the expanded liner to the upper zone gravel-pack packer. This packer assembly would completely isolate the expandable liner at the leak depth from collapse loads as production depletion occurs during the well life. This design also addresses concerns about the long-term suitability of expanded connections under production conditions. Figure 1 illustrates the design schematic of the stacked frac-pack completion inside the expandable liner.

fax 01-972-952-9435. AbstractDuring initial completion operations on a deepwater subsea oil well in the Gulf of Mexico, the 7-3/4 in., 46.1 lb/ft casing failed the pressure test in the production liner. Subsequent operations located the casing leak 1,800 ft above the target completion intervals. The original completion was planned to be a stacked, commingled frac pack with reservoir depths over 23,000 feet and pressures over 14,500 psi.To best address the problem and maintain the original well objectives, a solid expandable tubular system was selected to isolate the casing leak. The first expandable cased-hole liner run in the well failed to initiate expansion and was recovered. Reviews, lab mechanical tests and surface prototype tests were conducted to determine the cause of the unsuccessful start and to plan a second run for casing remediation. The revised design deviated from standard equipment and used a shorter launcher with a smaller outside diameter (OD) and a closedended system. In addition to the equipment modifications, lessons learned from the first attempt influenced procedural changes for the second installation.The second cased-hole liner run in the well a few weeks later was successfully installed and expanded. The ~2,300 feet of expandable liner used eight elastomer seal anchor joints specifically located to isolate the leak and allow completion operations to resume essentially as planned. This installation was carried out with straightforward dimensional changes to the expansion system and revised procedures. The postexpansion dimensions of the liner enabled the completion of the well with a 7 in., 38 lb/ft equivalent inside diameter (ID) casing using standard completion equipment. At the time, this application set a record as the deepest cased-hole expandable liner ever run. The financial benefits of the installation included avoiding costs of drilling a risky sidetrack and production deferment. This paper will discuss the problem on the first installation attempt, the operational response, subsequent recovery, lab tests and surface trials. The second installation will be covered in detail with an overview of completion operations and a brief outline of the value added through this expandable liner solution.