The Agbami field is a Chevron operated deepwater asset located offshore Nigeria, approximately 70 miles off the coast of Nigeria and within about 4,800 feet of water depth. The field was discovered in 1998 and has been on production since July 2008. The field achieved peak production of 250 MBOPD in August 2009 and has produced over 770 MMBO as at year end 2017. The field development plan approved at project sanction adopted a production strategy of mid-flank oil production with pressure support provided through peripheral water injection and crestal gas injection of the produced gas. The field development plan had a phased approach with three phases of development such that learnings are incorporated into the next development phase. The initial three phases of development are almost completed with 37 of the 38 planned wells drilled and supporting production while the next phase of development has recently been approved to drill more wells in two development phases. The field has benefited from the phased development approach and the opportunity to use the rich sets of data acquired to improve performance for the next phase. The newly sanctioned project will also continue to leverage from lessons learned and best practices from previous phases which will be used to refine the development opportunities and improve the performance. The Agbami field is truly a world class asset with 40 existing wells and continues to produce at annual average rates exceeding 230 MBOPD. This paper will highlight the performance of the Agbami field to date, discuss some challenges that have been encountered and share examples of reservoir management best practices such as real-time monitoring and optimization, formation pressure data analysis, 4D seismic acquisition and how the team has utilized these rich data set to optimize production, increase recovery and maintain production plateau nine years after first oil.

This paper reviews and shares lessons on the critical role of subsurface pressure data in the successful management of Agbami Field. Agbami is a Chevron operated deepwater asset located in 4,800 ft of water with a combination of water and gas injection development strategy. Production commenced in 2008 and has remained plateau at over 240 MBOPD. The field hosts intelligent well completions with capability of real time pressure data acquisition. In addition to this suite of pressure data from downhole gauges, wireline and LWD tools have been deployed to acquire valuable pressure data in the field. Several applications of reservoir pressure data in Agbami Field are shared in this paper. First, pressure data was used in establishing connectivity between a water injector and an oil producer in a rather poor seismic amplitude area. This led to significant savings from drilling another injector to support the 20,000 BOPD producer. Second, a reservoir originally interpreted as "virgin", which was later found to be depleted is described. This reservoir re-characterization resulted in over 20% increase in oil recovery. In another case, oil-water contact in a major reservoir was estimated using wireline pressure data, resulting in the booking of additional proved volumes. One key lesson is to always integrate pressure data with other data in the field. This integration often improves the asset team's understanding of the reservoir. A best practice is to ensure that all pressure data is quality checked before use to avoid erroneous interpretation. The availability of subsurface pressure data from different tools, at different gauge depths and at different times, poses a common challenge: RM practitioners who utilize these data need to ensure proper correction is done before field application.

The integrative approach of well log correlation and seismic interpretation was adopted in this study to adequately characterize and evaluate the hydrocarbon potentials of Khume field, offshore Niger Delta, Nigeria. 3-D seismic data and well logs data from ten (10) wells were utilized to delineate the geometry of the reservoirs in Khume field, and as well as to estimate the hydrocarbon reserves. Three hydrocarbon-bearing reservoirs of interest (D-04, D-06, and E-09A) were delineated using an array of gamma-ray logs, resistivity log, and neutron/density log suites. Stratigraphic interpretation of the lithologies in Khume field showed considerable uniform gross thickness across all three sand bodies. Results of petrophysical evaluations conducted on the three reservoirs correlated across the field showed that; shale volume ranged from 7-14%, total and effective porosity ranged from 19-26% and 17-23% respectively, NTG from 42 to 100%, water saturation from 40%-100% and permeability from 1265-2102 mD. Seismic interpretation established the presence of both synthetic and antithetic faults. A total of six synthetic and four antithetic faults were interpreted from the study area. Horizons interpretation was done both in the strike and dip directions. Time and depth structure maps revealed reservoir closures to be anticlinal and fault supported in the field. Hydrocarbon volumes were calculated using the deterministic (map-based) approach. Stock tank oil initially in place (STOIIP) for the proven oil column estimated for the D-04 reservoir was 11.13 MMSTB, 0.54 MMSTB for D-06, and 2.16 MMSTB for E-09A reservoir. For the possible oil reserves, a STOIIP value of 7.28 MMSTB was estimated for D-06 and 6.30 MMSTB for E-09A reservoir, while a hydrocarbon initially in place (HIIP) of 4.13 MMSTB of oil equivalents was derived for the undefined fluid (oil/gas) in D-06 reservoir. A proven gas reserve of 1.07 MMSCF was derived for the D-06 reservoir. This study demonstrated the effectiveness of 3-D seismic and well logs data in delineating reservoir structural architecture and in estimating hydrocarbon volumes