Agbami Field Development Concept Selection: Evaluating Facility and Field Development Alternatives in an Environment of Significant Subsurface Uncertainty
Authors: Reynolds Kendall C. , Brennan Dave , Spokes John , Seeberg Lars 
Published: October 2008

Planning the development of the Agbami field offshore Nigeria, as with other deepwater projects, required that critical business decisions be made in the absence of extensive subsurface data. Along with other fundamental project components that have a range of possible outcomes-for example, finalized commercial terms, wells and facilities costs, and execution schedule duration-the project team had to effectively understand, communicate, and incorporate all the key subsurface uncertainties in the process of achieving certain field development decisions.

ChevronTexaco uses its gated five-phase ChevronTexaco Project Development and Execution Process (CPDEP) to mature and execute all major projects. In "CPDEP-speak,' Phase Two involves the generation and selection of alternatives. Phase Three is where a "Preferred Alternative" is refined in preparation for project execution in Phase Four. Additional explanation of CPDEP follows in a separate section.

Prior to moving the project into Phase Three, two critical field development options required resolution:facility processing and injection capacities (oil, gas, water); anda dry tree unit (DTU) versus all-subsea development decision. It was required that these development plan options be evaluated over the range of possible subsurface and cost regime outcomes in order to select the optimum development scheme.

Probabilistic estimates for reserves, well count, facility costs, well costs, and schedule were developed. Uncertainties such as a potential reserve differences between dry and wet tree development and management of multiple contracts were included in the options analysis. Other operator's decisions for similar deepwater developments were benchmarked for best practices and lessons learned.

Various project variables were ranked in terms of project impact in order to determine which ones drove each decision and therefore which ones needed to be most fully evaluated in terms of understanding the range of possible outcomes.

Introduction

The Agbami field offshore Nigeria was discovered in late 1998 with the drilling of Agbami No. 1 in Offshore Prospecting Lease (OPL) 216. Fig. 1 shows the location of the Agbami field, which straddles OPL Blocks 216 and 217. Subsequent to Agbami No. 1, an additional four wells were drilled, with one of the wells sidetracked to achieve additional appraisal objectives. The current oil-in-place estimate (mean) is about 1.7 billion bbl.

In the early stages of Phase Two, evaluations of DTUs versus wet trees and facility capacity were performed and decisions made. The early Phase Two field development plan included a 24-slot dry tree unit, 17 additional subsea wells, and a floating production, storage, and offloading (FPSO) vessel with processing capacities of 200,000 stock tank bbl of oil per day (BOPD), 300,000 thousand standard cubic ft per day (Mscf/D) and 220,000 bbl water injected per day) (BWIPD). No gas market currently existsâ??all produced gas, minus fuel requirements, will be re-injected for pressure maintenance. The facility design includes the capability for gas export and has water injection capacity to achieve full reservoir voidage replacement in the event that a gas commercialization opportunity becomes available. The pressure maintenance strategy at that time was downdip water alternating gas (WAG).

As the project moved through Phase Two, additional data analyses was performed that improved subsurface interpretations and provided the basis for refined cost estimates of various project components (wells, facilities).