TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractShell Malaysia Exploration & Production (SM-EP) is planning for secondary recovery via water injection in the Barton field by using the novel concept of raw seawater injection. Raw seawater injection is essentially injection of minimally treated, fully aerated seawater. The seawater having undergone limited solids interception only by coarse filtration. The concept of raw seawater injection has not received much interest from operators due to lack of understanding on issues such as reservoir souring and impact of oxygen on the reservoir. However, raw seawater injection has proven to be the most cost effective secondary recovery design for mature fields like Barton, which do not boast huge reserves. This paper will focus on work carried out to identify and mitigate additional risks from raw seawater injection, principally on issues of reservoir souring, increased corrosion on production system, increased levels of suspended solids and impact of oxygen on the reservoir scale. Raw seawater injection in Barton will be the first of its type in the Shell Group and only the second known attempt in the industry.

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.

Fractured injection is not new to the oil and gas industry, and occurs unintentionally in most water injection schemes. However, deliberate fractured water injection is usually not evaluated upfront in order to derive optimal cost and recovery, and open-up opportunities for further optimization. The initial design for water flooding in Barton was based on a full-blown conventional water treatment plant on a new platform for seawater injection under matrix conditions. Fracture simulation work revealed that in the case of Barton, by relaxing water quality induced fractures are not expected to be excessively large and cause any concerns on integrity of the reservoir and nearby wells. Owing to a lower required injection tubing head pressure than previously believed to achieve fractured injection only relatively low pressure and cheap injection pumps are required. Additionally, fractured water injection has allowed for the introduction of raw-seawater injection, whereby the significantly smaller water treatment facility than previously required for matrix injection is placed on a deck extension from an existing platform. Introduction Barton Field Shell Malaysia Exploration & Production (SM-EP) operates the Barton field, which is located about 220 kms northeast of Labuan island, offshore Sabah, in Malaysia (refer to Fig. 1). The field is part of the North Sabah 96 Production Sharing Contract (PSC) with 50% SM-EP and 50% Petronas Carigali (PCSB) equity interest. Development of the field started in 1981. Oil production is primary depletion assisted by continuous gas lifting. Reservoir drive mechanism is gravity drainage with weak aquifer support. Current oil production is about 6.0 kbpd, from 11 wells (13 producing strings) at two separate platforms (BTJT-A and BTMP-B). Gas production, totaling some 3 MMscfd, is re-injected for disposal or used for gas lifting, with the excess flared at location. Geologically Barton reservoir is an asymmetrical anticlinal structure bounded by major reverse faults, and compartmentalized into 4 separate blocks. The field is situated in a structural province characterized by intense compressional wrench tectonics and clay diapirism. The reservoir is believed to be of lower coastal plain origin. Reservoir sands comprise of channels, crevasses, and shallow marine and delta front complexes with shale deposition in flood plain environment, which now form seals and flow barriers between sand units. Barton sandstones comprise predominantly of quartz, with minor content of feldspars, carbonate minerals and clays (mainly non-swelling type - kaolinite, chlorite and illite). Average porosity of the main sand package is about 20%, with rock permeability ranging from 50–3000 mD. The H sand unit has the highest rock permeability in the field. There are 3 sand packages in Barton:shallow D sands at 1000 ft tvdss charged with 16° API medium viscous oil,F, G, H and I sands at 2000 ft tvdss charged with 32° API oil, anddeeper M, P and Q sands at 3300 ft tvdss charged with 32° API oil. The current field STOIIP is about 165 MMstb, out of which some 50 MMstb has been produced. Production is almost exclusively from the G, H and I sands (main package). Fig. 2 shows the top structure map of H sand and cross sectional view of the field (along the North-South plane). Barton Water Injection (BTWI) Project Primary depletion alone addresses some 35% of oil recovery. Secondary recovery via water injection is expected to add another 15 MMstb of reserves, improving recovery to more than 45% and prolong field life. Field reservoir pressure will be progressively increased to near initial condition (c.1000 psia). Reservoir simulation work revealed that the maximum amount of seawater required is approximately 40 kb/d for optimum recovery under water injection through 4 injector wells. Each injector well is designed to handle 10 kb/d of treated seawater.

This study explains the large injectivity changes observed in the field, how to remedy it, and how to ensure fracture containment in channel sand reservoirs. The case study field is located offshore Ghana and is a channel sand reservoir. Water injection was initiated for pressure maintenance and waterflooding under fracturing conditions. The injection wells are designed to ensure high and sustainable injection rates while maintaining the integrity of the cap rock. The injection bottom-hole pressure (BHP) was history-matched to investigate the impact of stress profiles, reservoir shapes, injection water quality, poroelastic and thermally induced stress changes. The injectivity decline was found to be a result of changes in stresses caused by the channel boundaries and, to a lesser extent, near-wellbore formation damage. The rapid increase in pore pressure and the resulting decrease in injectivity is unique to these kinds of channel sands. Once the origin of the decreasing injectivity was identified, remedial actions were recommended and predictions for future injectivity were made ensuring containment of fractures.

The Bonga field has produced more than 275 MMstb in the last 4 years, a major contributor to deepwater oil produced offshore Nigeria to date. High production rates are being sustained as a result of the pressure maintenance scheme based on waterflooding that was implemented from the onset of production. Fully treated seawater is injected from 13 subsea high rate water injector wells daisy-chained on two separate water injection lines. To date more than 370 MMbbls of treated seawater has been injected in the field.High rates in water injector wells can only be achieved through fractured injection. Industry experience so far shows that matrix injection mode leads to declining well injectivity. However, for effective reservoir management, it is required that fractures created are not excessively large to cause integrity concerns on nearby seals, reservoirs and wells. Hence, it is necessary to predict the fracture dimensions for corresponding injection rates and pressures for effective waterflood management. The size (length and height) of an induced fracture depends on several parameters. This paper describes the use of an in-house fractured injection tool for estimating lateral and vertical extension of waterflood-induced fractures in Bonga wells. History matching of field data is performed to calibrate the model. Information from Pressure Transient Analysis and well interventions is used to improve model prediction.The analysis shows that with continuous high rate injection, long contained fractures are created in these high Darcy sands. Prediction results are used to define operating envelopes for these high rate water injector wells, with rates constrained in some wells to prevent induced fractures breaching the top shale layer. Reservoir Management PhilosophyBonga's reservoir management plan was developed with the intention to maximize and sustain oil production whilst ensuring optimum reserves development. Bonga's reservoir management philosophy is based on pressure maintenance from onset of production due to the relatively low-pressured environment and excellent reservoir and fluid properties for early