Liner Hanger Trapped Annulus Pressure Issues at the Magnolia Deepwater Development

Abstract

ConocoPhillips is developing the Magnolia field with a Tension Leg Platform (TLP) in 4,674 ft of water at Garden Banks block 783 in the Gulf of Mexico. The wells are completed using dry trees from the TLP. The production casing for each well consists of an 8.062 in. liner set near the base of a 10.75 in. liner. The 10.75 in. liner is tied back to the subsea wellhead. The subsea wellhead is tied back to the TLP with an 11.75 in. production riser. To minimize heat loss in the produced fluid above the mudline, the production riser × tubing annulus is filled with low-pressure nitrogen. Completion brine is left in the well below the mudline. Two of the eight wells did not have cement behind the 10.75 in. liner hanger polished bore receptacle (PBR), leaving a trapped annulus. Results from annular pressure build-up programs and finite element analysis (FEA) of the PBR tieback stem configuration, indicated that the combination of increased annular pressure due to temperature heat up during production along with the reduced hydrostatic pressure of the nitrogen in the annulus could cause a collapse failure of the 10.75 in. liner hanger PBR. Since the tieback string had been run and cemented, it was not possible to access the annulus behind the liner hanger PBR by conventional means. A number of potential solutions to address the problem were considered: scab liner, expandable casing, perforate and squeeze annulus, low heat-transfer gel instead of nitrogen, and high-density brine. This paper will discuss the analysis of the potential collapse issue of the liner hanger PBR, the potential solutions, and implementation of the solution on the actual wells. Introduction The wells at the Magnolia field were pre-drilled using a dynamically positioned semi-submersible in 2002- to 20031, 2. After installing the Magnolia TLP in August 2004, a 2,000 horsepower platform rig, the MODS 201, was installed upon the TLP to complete the seven wells that had been pre-drilled. The eighth well required drilling the production interval to total depth (TD) and was scheduled to be the last well to be completed. The wells are dry-tree completions back to the TLP with direct vertical access. Following installation of the platform rig, two 11.75 in. outer diameter (OD) production risers were installed. The first two wells were then completed to begin production from the platform. The remaining six production risers were subsequently run in a batch program followed by completing the remaining pre-drilled wells. First production from the platform occurred on 12 December 2004. Completion designs for the wells had been developed during a two-year planning period from 2002- to 2004. Final detailed planning for the wells was completed in Jan. - Jul. 2004. Prior to installing the MODS 201 aboard the Magnolia TLP, a two-week onshore integration test was conducted. The platform rig, a new build, was commissioned and then the integration test conducted. During the integration test, most of the normal completion operations were simulated to identify any equipment handling issues and familiarize the rig crews with the equipment. It also allowed any potential problems to be identified at a low cost and allowed time to make any potential changes that were identified. During the final completion planning in early 2004, it was identified that two of the intermediate drilling liners did not have cement across the liner lap. There was concern that the two wells might be candidates for potential annular collapse issues under production conditions. Annular pressure problems have been experienced during production at at least one deepwater GOM development3, which led to a more detailed investigation of the potential problem.