Agbami Project Subsea Facilities Design Development
Authors: Knight David J. , Ferrier Brian R. , Holbrook John A. , Norris Peter E. 
Published: October 2008

Agbami is an oil field in 5,000 ft water offshore Nigeria. Following a decision at the end of 2002 to move from using a Dry Tree Unit (DTU) to an all-subsea development, the subsea facilities team was faced with moving from a minimal pressure maintenance scope to a full scale production and injection system consisting of approximately 40 wells. At this time the floating production, storage, and offloading (FPSO) vessel definition was well advanced while the subsurface development plan was undergoing major revision. This paper reviews the design development for the subsea facilities. Also reviewed is the method employed that provided flexibility to accommodate ongoing changes in subsurface requirements while allowing preparation of invitations to tender for lump sum contracts, along with descriptions of the work processes and some key decisions.

Introduction

The Agbami field was discovered in 1998 and plans were put in place to proceed with an initial development scheme comprising an FPSO and limited subsea wells. As reservoir understanding developed, the subsea facilities were replaced with a DTU and a water-alternating-gas (WAG) injection system comprising six subsea wells for pressure maintenance. In October of 2002, the pressure maintenance scheme was revised to a conventional gas injection and water injection scheme due to uncertainties in the performance of WAG. Production capacities for the FPSO were set at 250,000 bbl of oil per day (BOPD), 450,000 bbl of fluid per day (BFPD) and 450,000 thousand standard cubic ft per day (Mscf/D) of gas based on profiles developed using analogue wells and sector models. Revisions to the already well developed engineering for the FPSO commenced.

A full reservoir model was being developed to establish well targets and surface locations but this was not expected to yield results until mid 2003. Nonetheless, studies indicated the need for a significant increase in the number of non-DTU (subsea) development wells. After careful evaluation, the DTU was dropped in favor of an all subsea development. Significant drivers in this decision were:Similar economic performance for reduced initial investment commitment.Increased flexibility to accommodate potential future changes in subsurface requirements. Early in 2003 the subsea team commenced front end engineering for subsea facilities. The development plan consisted of approximately 40 subsea production, gas injection, and water injection wells tied into the FPSO. Although subsea engineering had been undertaken in support of all previous development plans, the scale of these schemes was small, consisting mostly of injection wells for pressure maintenance. It was therefore appropriate to fully review the work to date in relation to the much increased scope and the now-critical role of the subsea facilities to overall project performance.

Subsea Front End Engineering Design Strategy

The developing nature of the subsurface definition, combined with the need to provide a firm basis for FPSO engineering, required a specific approach to subsea system front end engineering design (FEED). The approach would provide long term flexibility to accommodate change in subsurface requirements with minimum future impact on FPSO. The methodology would also support an immediate start to subsea FEED if the project schedule for delivery of trees was to be achieved.