Lessons Learned from Troika's Flow Assurance Challenges
Authors: Berger Ron K. , McMullen Norman D. 
Published: October 2008

Abstract
BP's Troika subsea field began production in November 1997 with some of the most prolific oil wells completed in the Gulf of Mexico. The facilities feature an eight slot manifold in 2700 ft of water tied back to the host platform with dual, 14 mile flowlines. The system was designed to operate outside the hydrate formation region at all times via inhibitors and extensive insulation. Unfortunately production arrival temperatures at the host were significantly less than expectation and thus challenged the integrity of the original operational strategy for the subsea system. For three years, Troika has managed the added flow assurance risks and problems associated with colder system temperatures. Actual field performance and hydrate mitigation strategies are presented.

Troika Overview
The Troika development is an oil field located 150 miles offshore Louisiana in the Green Canyon area of the Gulf of Mexico. Water depth at the development site is 2700 feet. The primary S-10 reservoir at Troika is located at a depth of approximately 16,000 to 18,000 feet TVD. Initial bottomhole pressure in the primary reservoir is approximately 10,900 psi with bottomhole temperatures ranging from 175 °F to 185 °F. API gravity is approximately 37 °, and the GOR is approximately 2000 scf/bbl. The cloud point for paraffin formation is 105 °F and the produced water salinity is greater than 20%. The wells are frac-pack completions, some capable of production upward of 30,000 bopd.
The Troika subsea production system features an eight slot subsea cluster manifold and an electro-hydraulic control system, Figure 1. The Troika wells have a 10,000 psi pressure rating, tied-in to a manifold and flowline system with an 8,000 psi pressure rating. Methanol may be injected downhole, at the wellhead or directly into the subsea flowline headers.
Production from Troika is processed at the Bullwinkle platform located 14 miles away in 1350 feet of water on Green Canyon block 65. Each flowline flows into dedicated HP separation trains, which are commingled into a common IP and LP train. In the event of a platform process shut-down, the platform is protected by closure of the flowline SDVs, and shut-in of the wells by first closure of the drive close subsea chokes, and then the subsea, production isolation valves. In the unlikely event of an emergency shutdown, the USVs (PWV valve) will also close followed by a delayed closure of the SCSSV's. The valve configuration following a platform generated Emergency Shutdown is shown is Figure 2.
Concern about the potential to form hydrates and paraffin was a key factor in formulating the design and operating plan for the subsea production system. As a result, the trees, jumpers, manifold, and flowlines are all insulated to minimize heat loss during production, as well as to extend reaction time to manage hydrate formation potential following a shut-in. The Troika flowline insulation system was designed to allow 24 hours of cool down time before reaching the hydrate formation conditions. This established a target insulation requirement for the flowline U-value of 0.142 Btu/hour-ft2- °F taken at the internal diameter of the pipe. Theoretically, the resulting U-value was expected to provide arrival temperatures at Bullwinkle ranging from 95 °F to 145 °F, depending on production rate.
Unfortunately, the thermal performance of the production system did not meet expectations. Arrival temperatures were approximately 50 °F cooler than predicted in the original design. The "in-place" U-value of the system was estimated to be approximately 2.3 Btu/hour-ft2- °F. The poor thermal performance negatively impacted the system by causing process foaming and gas breakout problems, par