BP announced that it achieved first gas this week from subsea wells in its Greater Tortue Ahmeyim (GTA) liquefied natural gas (LNG) project.
Located offshore Mauritania and Senegal in 2,850 m of water, GTA is one of the deepest and most complex upstream developments launched offshore Africa in years.
The field gas is flowing to BP's floating production storage and offloading (FPSO) vessel for the next stage of commissioning. Once fully commissioned, the multibillion-dollar GTA Phase 1 is expected to produce around 2.3 mtpa of LNG.
After being transferred to the GTA FPSO, the gas will be pipelined to a floating liquefied natural gas (FLNG) vessel located 10 km offshore, where it will be cryogenically cooled, liquefied, and stored before being transferred to LNG carriers for export.
Considered “a project of strategic national importance” by both host countries, some of the gas from GTA will be allocated to help meet growing energy demand in Mauritania and Senegal.
BP operates GTA with a 56% working interest along with partners Kosmos Energy (27%), PETROSEN (10%), and Société Mauritanienne des Hydrocarbures (7%).
BP provided an overview of its drilling and completions campaign for the first four development wells at the GTA field in a 2023 conference paper. In SPE 216392, the supermajor outlined several technical challenges associated with the field’s gas reservoirs, including:
- The multilayered gas reservoir posed a significant risk of perched water and aquifer presence, compounded by limited data from appraisal wells that did not fully penetrate all reservoir zones.
- High flow rates of 220 mmscf/D were anticipated, necessitating a compatible completions design.
- Well cleanup operations were complicated by wellbore pressure differentials during displacement procedures.
- Low-temperature gas wells required operations within the hydrate zone, necessitating a robust hydrate management strategy.
BP noted that while open-hole gravel packs are a preferred completion choice in deepwater operations, they were not suitable for these wells due to erosional concerns associated with the high flow rates. The operator also prioritized mitigating the risk of water breakthrough over sand control, leading to the selection of a cased-and-perforated completion design.
Although no sand production was observed during the initial cleanup phase, BP said in its 2023 paper that long-term production data will be required to assess the success of the cased-and-perforated strategy.
The operator added that future wells might incorporate downhole flow control devices and be drilled with highly deviated trajectories to enhance contact with the multilayer reservoir.
For Further Reading
SPE 216392 Completion Design and Equipment Selection to Facilitate Operations in a New Deepwater Region by C. Giuliani, BP Exploration; T. Tahirov and W. Hou, BP Exploration; Y. Xiao, BP Exploration; M. Eissa, SLB; M. Varghese, SLB; K. McKenzie, Expro; A. Roy, BP Exploration; M. Leng, BP Exploration.
