Tahoe Subsea Completion A Successful Application of Existing and New Technologies (1995)

ABSTRACT The Tahoe subsea satellite tieback (VK783) demonstrates how existing and new subsea technologies can be combined to achieve a cost effective yet technically significant subsea project. A used Green Canyon 29 subsea Xmas tree was refurbished and modified to implement more recent first-end layaway techniques for both the flowline and umbilical. The diverless completion was made in 1500 ft. of water and tied back approximately 12 miles to a platform in 275 feet of water (Main Pass 252). The flowline system consisted of dual nominal 4-in. lines comprising both flexible and rigid pipes. The control system was multiplexed electro hydraulic with signal-onpower umbilical transmission. Both downhole and Xmas tree temperature and pressure measurements were employed. The techniques used in the Tahoe subsea system can be applied to other projects to help improve reliability of subsea tiebacks. INTRODUCTION The subsea satellite tieback known as Tahoe was completed in November of 1993 and put into production in January 1994. Tahoe is located at Visoca Knoll Block 783 in some 1500 feet of water. It is tied back to the "Bud" Platform (Main Pass 252), approximately 12 miles away and in 275 feet of water, using dual nominal 4-in. flowlines and an electro hydraulic control umbilical. The flowlines are a combination of rigid and flexible pipe. The control system is a multiplexed electro hydraulic design using the signal-on-power umbilical transmission technique. The Xmas tree is a used Green Canyon Block 29 subsea tree which was refurbished and modified to meet the functional requirements of Tahoe. The original workover riser and control system from the Green Canyon Block 29 project were utilized to run the tubing hanger, tree and tree cap. Some new tooling was manufactured for such items as the flowline connection assembly, ROV valve overrides and completion guide base running tool. The Tahoe well was drilled in 1989, and an extended production test was performed in the spring of 1991. The development project officially began in September 1992. Data gathered from the production test aided in the design of completion system. DOWNHOLE COMPLETION The downhole completion system consisted of a gravel pack, production packer, permanent downhole pressure/temperature gauge (PDPG), production tubing, SCSSV, chemical injection mandrel and various tubing plug locking profiles located throughout the completion string, Figure 1. The production packer was a tubing-run, pressure-energized design with a threaded-release stinger. This design allowed the production tubing to be run without making a space out tubing run. The PDPG system consisted of a mandrel, gauge, encapsulated control cable, tubing hanger penetrator with mating connectors and a terminationadapter in the subsea tree. In order to reduce costs and maintain an aggressive schedule, the existing workover system was not modified to allow monitoring of the PDPG during the installation process. Once the tree was landed on the completion guidebase and tested, the PDPG circuit was checked and confirmed to be working properly. The SCSSV was a tubing-retrievable, single control-line, flapper design. Initial pressure testing of the valve as installed in the well required several attempts before the valve successfully held pressure.