Subsea Tiebacks Drive Growth in Bonga North Field, Deepwater Nigeria

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35242, “Bonga North Story: Beyond 1 Billion Barrels—Driving Growth With Subsea Tiebacks in Deepwater Nigeria, ” by Areje Adegoke, SPE, Gary Ayenor, and Iyke Nnoaham, SPE, Shell, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The Bonga North (BN) project is a greenfield oil development in the Gulf of Guinea, approximately 130 km offshore in water depths ranging from 900 to 1300 m. The block has an existing floating production, storage, and offloading vessel (FPSO) with a 20-year design life ending in 2025 and an oil capacity of 220, 000 BOPD. The block has descended from the initial production plateau and is producing below capacity. The complete paper discusses the journey of the BN project, highlighting the challenges and resolution strategies in a constantly changing environment. BN Field Bonga is the first deepwater development project in Nigeria, and has produced over 1 billion bbl. The BN field is in the OML 118 block and consists of hydrocarbon accumulations in middle Miocene turbidites (Fig. 1). The five main reservoirs in the field (706, 708, 730, 738, and 742) occur at depths between 1800 and 4800 m true vertical depth subsea. The project has seen three field development plan (FDP) recycles since the field’s discovery in 2003. BN FDP Evolution The initial development plan for the field was based on a subsea tieback of the field to the Bonga Main (BM) FPSO. However, following the reprocessing of Bonga Main seismic in 2010, an increase in the in-place and recoverable volumes of BM was noted. In 2013, a revised development plan was proposed based on a standalone FPSO with 29 wells (16 producers and 13 injectors from the five main reservoirs) targeting 1. 8 billion STB OIIP/542 million STB recoverable volumes over 25 years. The second FDP, however, was not supported by the National Petroleum Investment Management Service because of a misalignment in the allowable number of FPSOs in OML 118. In 2016, the feasibility of a 10-year extension of the design life of the BM FPSO was demonstrated. A decision was made to recycle BN back to the select phase to reevaluate the concept of a subsea tieback of BN to the BM FPSO. The BN concept selection study recommended developing BN in two tranches. BN Tranche 1 development would consist of seven producer/injector well pairs from three of the five reservoirs (708, 738, and 742) and associated subsea infrastructure for a tieback to keep the BM FPSO full and develop approximately 360 million STB ultimate recovery (UR) within the 10-year life extension period. BN Tranche 2 would develop the remaining 706 and 730 reservoirs, including infill targets in the 738 and 742 reservoirs. This two-tranche development strategy proposed by the third FDP allows for optimal development of the field while managing known risks and opportunities. The production forecast showed that the FPSO ullage would be fully used in the first 3 years of production.