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Shell Exploration & Production Company continues to execute redevelopment slim hole sidetracks using Managed Pressure Drilling (MPD) on the Auger TLP in Deepwater Gulf of Mexico. Four sidetracks have been successfully drilled utilizing a Dynamic Annular Pressure Control (DAPC) system to eliminate lost circulation and borehole instability events.Execution of MPD continues to improve, resulting in operational efficiency gains and allowing access to previously unattainable reservoir targets. Intervals previously considered impossible to drill due to depletion induced frac gradient reduction are being drilled and cased trouble free with MPD.Recent MPD well designs have incorporated reduced static mud weights below pore pressure to manage the available drilling margin. Bottom hole pressure variation from the defined set point has been reduced and excursions outside of the target pressure window are being eliminated during subsequent MPD well operations.Auger's field redevelopment history, well designs and Managed Pressure Drilling designs will be reviewed. Execution of MPD operations will be addressed in detail focusing on engineering and operational improvements throughout the four MPD sidetrack campaign.

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.

TX 75083-3836 U.S.A., fax 1.972.952.9435. AbstractAccess to previously unattainable offshore drilling targets continues to expand through advancements in Managed Pressure Drilling (MPD) and Dynamic Annular Pressure Control (DAPC) technologies since their first application on the Mars TLP in 2005. Shell Exploration & Production Company successfully executed a second MPD operation, eliminating lost circulation and hole instability risks by utilizing a DAPC system on the Auger TLP.Redevelopment drilling in maturing deepwater fields is challenged by high circulating density (ECD) and depletion induced fracture gradient (FG) reduction for intervals that still require original mud weights (MW) for borehole stability.The DAPC system provides automated control of surface applied annular backpressure to the wellbore to a specified bottom hole pressure (BHP) set point. This allowed drilling on the Auger TLP with a surface mud weight lower than required by conventional drilling, effectively reducing the ECD magnitude on the open hole.The well design will be discussed, along with the equipment, methods, planning, preparation and training to successfully execute MPD offshore. Execution results and key learnings will be summarized.