Tahiti-Project System Qualification
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19859, "Tahiti- Project Subsea System Design/Qualification," by Chris Hey, SPE, and James Rasmussen, Chevron, and Steve Tattersall, SPE, Cameron, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.
The design requirements of the Tahiti subsea facilities, while not dependent on the qualification of new or "enabling" technology, did depend on extending or "enhancing" the limits of existing technology. The full-length paper briefly describes some of the key design requirements, the approach to determine the then current level of equipment qualification relative to these design requirements, the qualification process, and the subsequent lessons learned.

Subsea Overview
The Tahiti project was the first high-pressure subsea development for Chevron. The Tahiti subsea facilities consist of an eight-well production drill center in the south and a six-well production drill center in the north of the field. There is a single-well, mid-flowline tie-in midway between the north drill center and the host facility. The drill centers are approximately 3 miles from the host facility, and each is served by a 2-×9-in.-nominal-outside-diameter (OD) production flowline and a 1-×6-in.-nominal-OD test flowline. Each drill center is served by two electrohydraulic steel-tube umbilicals.
Each manifold has 2-×9.625-in.-nominal-OD production headers and a 1-×6.625-in.-nominal-OD test header. All headers are rated to 12,900-psi operating pressure. Round-trip pigging of the production and test flowlines is achieved by means of removable pigging loops and a Y-spool. The Y-spool allows the smaller test pig to drop into the larger production header where it will be swept back to the host using a production-flowline pig. The manifold configuration enables production from any well to be directed into any header.
Each of the manifolds is supported by a single suction pile, 18 ft in diameter and 77 ft long. The wells are connected to the manifolds by means of rigid production-well jumpers that are as much as 120 ft long and 3.50 in. inside diameter.
Eight production trees were purchased, with the latter two of these configured for smart well completions. The trees are 5 1/8×2 1/16 in. and are rated to 15,000 psi and 0 to 250°F with HH-rated production trim and EE-rated annulus trim.
Each tree has its own subsea control module (SCM) that also controls the manifold branch-isolation valves. The control system is fully redundant, from the master control station to the SCM hydraulic control valves. Each manifold has its own SCM that controls the pigging-loop isolation valves and the methanol-injection isolation valves and monitors the pressure, temperature, and corrosion sensors. The corrosion sensors are located on each of the flowline jumpers connected to the manifold headers.
The development requires equipment to be rated for 5,000-ft water depth, 15,000 psi, and 0 to 250°F, with high-pressure/high-temperature flowlines and steel catenary risers.