Typhoon, located in the Green Canyon area of the Gulf of Mexico, is a joint deepwater development between ChevronTexaco (operator) and BHP Billiton. First oil was realized in July 2001, just 6 years after acquiring the leases. The Typhoon development consists of a mini-tension-leg platform (TLP) with four subsea wells in approximately 2,100 ft of water. Recently, Boris, a joint project between BHP Billiton (operator), ChevronTexaco, and Noble Energy Partners was discovered in an adjacent block, and two subsea wells were tied back to the TLP. The field consists of several hydrocarbon-bearing sands with 60% of the field's proven reserves located within a single reservoir.
Characteristics typical of many deepwater developments (such as high flow rates, compartmentalization, reservoir compaction, and asphaltene precipitation) are prevalent at Typhoon. As a result, asset management is complex and requires each well to be managed independently. The primary purpose of this paper is to describe how the asset and wells are managed and to heighten the awareness of associated complexities. This will be achieved by providing an overview that includes well and reservoir performances to date, reservoir management processes, and idiosyncrasies associated with operating a deepwater, subsea development in the Gulf of Mexico.
Typhoon is located in the northern Green Canyon area (blocks 236 and 237), 100 miles off the coast of Louisiana in approximately 2,100 ft of water (Fig. 1). Exploration has been very active in this area, with more than 1 billion BOE of recoverable reserves discovered to date. Major fields already on stream in the area include Genesis (ChevronTexaco/Exxon/BHPB),1,2 Troika (BP/Shell/Marathon), and Bullwinkle (Shell).
The existing infrastructure and relatively shallow water depths (where proven production technology could be used) made it feasible to develop a much smaller field such as Typhoon. It also provided an opportunity to deploy and learn from key technologies that could be applied in greater water depths. Subsea technologies such as completions, well intervention, and flow assurance were of particular interest.
The project was fast-tracked, limiting the amount of subsurface data, which resulted in a much larger range in uncertainty. As with most subsea developments, there are well intervention and flow-assurance risks. Well intervention is costly and can pose a major threat to the economics of a subsea project. The primary purpose of this paper is to discuss how the Typhoon asset was developed and managed to mitigate these risks and to bring to light some of the complexities associated with operating a subsea development.
Several development scenarios were evaluated, and the local host option was determined to be the most profitable. It provided the capability of producing incremental reserves in the field and significantly reduced flow assurance and environmental risks relative to a remote subsea development. This option also supported the development of smaller accumulations, as were thought to exist in the Typhoon area.
The best overall structure for this development option was the SeaStar* TLP. The SeaStar is a scaled-down version of the TLP concept, which has been used widely in the Gulf of Mexico and the North Sea. It was considered technically mature because two similar TLPs had been installed and are in operation in the deepwater Gulf of Mexico. The topsides were constructed to support full production facilities with a capacity of 40,000 BOPD, 60 MMcf/D, and 15,000 BWPD from up to six tiebacks.
The field was developed with four of the five appraisal wells completed subsea and tied back to the SeaStar TLP (Fig. 2). The appraisal wells were initially designed, drilled, and temporarily abandoned with this in mind. Upon completion, the wells were equipped with downhole chemical injection to mitigate asphaltene deposition and bottomhole pressure gauges for improved well management. The completions were designed to resist formation compaction caused by the high compressibility of the reservoir rock and frac-packed for sand control. Two of the four wells were initially completed as "smart" wells, which would have provided the flexibility to produce one of two intervals either separately or commingled by means of a single tubing string without subsurface intervention. However, both wells were converted to single-zone completions after flow testing each interval. In the first well, the upper zone frac pack failed, and in the second well, the lower zone proved to be of limited size.
Flowline commissioning and initial startup went smoothly, with first oil being achieved in July 2001, just 6 years after acquiring the leases. As of January 2003, Typhoon had produced 17.6 MMBOE.
The Typhoon field is a combination structural/stratigraphic trap with turbidite sands draped across a southerly structural dip and syndepositional north/south-trending faults. Anomalous seismic amplitudes are present and are interpreted to be indicative of hydrocarbon-filled sands. These sands are inferred to be stacked deepwater turbidites of Late Pliocene age and appear on seismic and well logs to be amalgamated channels and sheet sands. The objective interval is composed of six principal reservoirs with initial reserve estimates ranging from 23 to 81 MMBOE. Sixty percent of the reserves and approximately 75% of the current deliverability are located within a single reservoir known as the B4 sand.
The Typhoon reservoir section is composed of a series of stacked, deepwater turbidite sands deposited in a faulted, intraslope, salt-withdrawal minibasin. The main pay sands in the field are Late Pliocene (2 to 4 million years old) and are divided into the following zones: A0, A1, B2, B3, B4, B4.5, B5, and B6 (Fig. 3). The gross reservoir interval is approximately 2,200 ft thick at depths ranging from 15,000 to 17,500 ft.