Recent reservoir studies have shown great strides in capturing complex multi-tank reservoir systems using Material balance (MBAL®) model especially when these tanks are hydraulically connected. The preference of a simple and quick material balance method over numerical simulation is justified when time and budget constraints may hamper full field simulation modelling. The subject reservoir for this study is a mature hydraulically connected tank under waterflood. This paper compares reserves estimation using predictive material balance and dynamic simulation after history matching both models.Results from this paper shows that for multi-tank modeling using of hydraulically connected reservoirs using MBAL, transmissibility modeling & aquifer modelling are key factors in achieving reasonably reliable MBAL models. A good understanding of the reservoir fault frame work and connectivity, adequate & reliable BHP, injection and production data are very important for attaining a good history match & model calibration. Results of this study show a good comparison between the Reserves estimate from both MBAL and that from dynamic simulation. Under the appropriate conditions, Predictive Material Balance is a quick alternative tool to reservoir simulation in reservoir performance prediction especially when time & resources are limited. Also, predictive material balance analysis should be applied in reservoir where the existing wells have adequate data to build reliable inflow & out flow models.

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.

Reservoir E is an offshore saturated black-oil reservoir with three lobes, initially thought of as independent reservoirs, but later seen as lobes of same reservoir with acquisition of more pressure data. It started production in 1968, but was shut-in in 1985 due to declining pressure. After the onset of waterflood in 1992, pressure data showed the reservoir behaving like two pressure tanks aerially (Main and Horn Area).The main area showed good pressure response from water-flooding but limited response was observed in the horn area. The challenge has been how to improve the current reservoir performance given the availability of reserves especially in the horn area which is pressure challenged.This paper describes a three-dimensional, three-phase, black-oil simulation of Reservoir E. The purpose of this study was to investigate and identify the optimal operating scheme for maximizing recovery in this reservoir.

A stacked series of fault juxtaposed reservoirs across four fault blocks in an offshore field were being considered for further development, but communication across fault blocks remained an uncertainty even after 40 years of production from these reservoirs. Providing a reliable forecast associated with a development plan required understanding of the impact of these faults to the reservoirs' historical production and how it may impact future development opportunities. A full field simulation model containing all the reservoirs in the field, which can capture the impact of the communication across the fault blocks was built but due to the large number and coarse scale of grid blocks as well as mulyiple reservoirs, it was decided to use the results from the pressure-match work done on the full-field model and work with smaller, but finer scale, full-field simulation models with less number of reservoirs which were more likely to be communicating to produce a model which could answer these questions and provide a reliable forecast associated with the development opportunities.This paper describes a full field, three-dimensional, three-phase, black-oil simulation model of several reservoirs in Bayelsa field (not real name) which was used to investigate across fault block communication and identify further development opportunities in these reservoirs.