TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProduction from the deepwater Bonga turbidite reservoirs was started in November 2005. As with all waterflood and Enhanced Oil Recovery schemes, 'world-class' Well and Reservoir Management (WRM) is the foundation of a successful project. A comprehensive WRM plan was defined for Bonga very early in the project, and its implementation from start-up has demonstrated tremendous value.More than 220 MMstb have been produced as of March 2009 from 13 subsea producers, and reservoir pressures have been maintained by water injection from the start of production in 13 subsea high rate water injectors, allowing high field production rates to be sustained. Well and reservoir performance data obtained during the first three years of production, and information from 4 D seismic shot in early 2008 are now used to optimize the planning and drilling of additional wells as part of the Phase 2 development drilling project. Bonga is a 'brownfield' that is not immune to normal well and asset integrity issues, and declines in well injectivity and productivity. Ability to respond swiftly to these issues is part of the Bonga WRM Plan. This paper presents key elements of successful WRM in Bonga. These include people factor and cross discipline integration, Smart Fields ® capability, 'live' WRM Plan and monitoring, good understanding of subsurface, application of integrated production modelling, intervention readiness and effective well integrity management. The paper concludes on key learnings applicable to future deepwater waterflood projects.

The Bonga field located offshore Nigeria in OML 118, has produced more than 275 MMstb in the last 4 years. Production rates from 16 subsea high rate oil producer wells from 5 different manifolds are being sustained by waterflooding that was implemented from the onset of production. Currently, mostly single zone oil producer wells drain 5 different deepwater turbidite reservoirs in the field. Fully treated seawater is injected from 13 subsea high rate water injector wells daisy chained onto 2 separate injection lines. Oil offtake on reservoir level is highly dependable on successful voidage replacement and pressure maintenance. In addition, constraints and operating envelopes in both the production and injection system make day-to-day optimizations extremely challenging. As with all waterflood and Enhanced Oil Recovery schemes, 'world-class' Well and Reservoir Management (WRM) is the foundation of a successful project.One key element of effective WRM is the application of Integrated Production System Modelling (IPSM).Advanced and robust tools that model complex integrated systems from the reservoir to the topsides have been developed and applied extensively in the industry. An IPSM was built for Bonga allowing detailed dynamic reservoir simulation models to be linked with well, flowline / subsea and topside models. Both the injection and production network models were incorporated to simulate the actual field situation. In addition, an optimization script was built to manage offtake and distribution of injection water aligned to the field pressure policy. This enables the model to duplicate as closely as possible actions taken in the field. An integrated-discipline workflow was developed and applied on a monthly basis to maintain the Bonga IPSM 'live' through calibration with well test data and update with the latest field information.The 2 key benefits of the IPSM are:• Integration of multi-disciplines (from subsurface to topside) in model update and calibration, and to ensure all aspects are considered for a robust forecast • Testing new optimization opportunities or ideas for improving oil offtake and water injection prior to implementation in the field Examples of successful application of IPSM in WRM are described in this paper, which also highlights future applications of IPSM for the Bonga asset.

The economics of deepwater oil field developments rely heavily on the availability of high oil production rate wells that can generate early income to pay for the high CAPEX invested in such field developments. In addition to the cash flow is the uncertainty that surround such high CAPEX developments. For example the influence of governments and policy changes leaves the investor no choice than to ensure early recovery of investment. To support the required high oil production rates, the reservoir pressures must be maintained to minimize the chances of breakout of gas in the reservoir in an under saturated system or production of gas cap gas in a saturated system. Often times, the question is not whether to apply a reservoir maintenance scheme or doubts about the strength of the aquifer but when is the appropriate time to implement the water injection scheme and thus optimize the development for stakeholders both in terms of economics and ultimate recovery. The choice of scheme to employ follows the decision to provide reservoir pressure support as part of reservoir management strategy. Water injection in the deepwater setting appear to be a preferable choice over gas given the ready availability of sea water and less complications in the operation of the injection system when compared to gas injection. Further to the decision on the use of water injection for reservoir maintenance is the question of sizing of the injection facility to deliver the required amount of water for the field development. Subsurface and Project engineering teams most often depend on global industry knowledge especially the golf of Mexico to design the injection facilities. However occasions arise where the development plans and aspirations defer. For example, the sizing of the injection system may not have considered the complexity of the reservoirs nor the future development plans for nearby fields. Such occasions may result in ad hoc operational philosophy to optimize oil production. This paper aims to put the shortcomings of water injection limitations in deepwater Nigeria in perspective, identify best practices in such instances and make recommendations for future development planning.