Abstract

The Typhoon Field development required 9,000 psi MAWP flowlines from the four subsea wells to the TLP. An overview is presented of the design, manufacturing and installation of these four flexible flowlines. The flowline design required the use of insulation for flow assurance, start-up fluid considerations in the carcass metallurgy, and tensile and armor wire design for the testing and operation conditions. Because the design temperature caused aging concern for the Polyamide-11 (PA-11) pressure sheath, additional manufacturing requirements were placed on this flexible pipe component. Additional testing and inspection was also performed due to the high-pressure application. A flowline and associated umbilical installation overview highlights the use of diverless bend restrictor to I-tube connectors, brine filled flowlines for start-up hydrate inhibition, wellhead Staband-Hinge-Over connections, subsea heat exchanger installation, and installation sequence considerations. Lessons learned from this project scope are presented.

Overview

The Typhoon Field is in Green Canyon Block 236 and 237 in approximately 2,100-ft water depth. Equity is fixed at 50% Chevron and 50% BHP Billiton, with Chevron the designated operator. The discovery well was drilled in April 1998. The Typhoon Project was sanctioned in January 2000 for the development of 4 subsea wells produced to a centrally located TLP. First oil was achieved from the field on July 29, 2001. All four wells were on production at full rate by August 16, 2001, which was 54 days after the installation of the TLP.

Design
Design Basis.

The flowline design was based on a well shut in tubing pressure (SITP) of 9,000 psi. The flowlines for the field connect 4 subsea wells offset from 3,000 ft. to 9,800 ft. to a TLP centrally located in the field. Design maximum flowrates were up to 22,000 BOPD for the most productive well in the field. The wax appearance temperature was 82 °F. Because the wells were centrally located with relatively short offsets and wax plugging was not thought to be a major concern, a single flowline for each well was determined to be adequate. Flowline routing was required to avoid a methane gas vent area and possible chemosynthetic community area(Figs. 1, 2 & 3).

Of concern in the design requirements were the well head temperatures. The temperature forecast for the hottest well in the field, the GC237 No. 2 well, was for an initial wellhead temperature of 184 °F. For flow assurance reasons the overall heat transfer coefficient for the pipe was required to be 1.7 BTU/hr-ftÂ2-°F.

The flowline design was specifically engineered for the Typhoon field conditions. Although the well lives were expected to be less than 7 years, the fatigue and corrosion design was based on a 20 year design life requirement. The design life for the pressure sheath layer in the flexible pipe was allowed to be 10 years based on the maximum expected heat content from the flow stream.

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