Bonga producer (Well-X) became severely impaired during a series of interventions (to address SCSSV failure), with oil potential dropping from 18 to 3 kbod. The Well and Reservoir Management team believed the initial impairment was most likely caused by fines migration and secondly by fluid (MEG and brine) losses to the formation during interventions. A two-fold treatment was recommended –solvent (surfactant) and half stre gth mud acid to target the two impairment mechanisms. Considering the relatively low productivity and remaining reserves, the downside risk was low from a subsurface perspective. The major concerns were related to HSSE and integrity risks pertaining to unspent FPSO. Lessons learnt similar jobs by other acid flow-back to the Bonga from successful executions of Operators enabled the Bonga team to demonstrate the necessary risk management and purs e the concept towards execution. To minimize cost, the recommended deployment method was by bull-heading the treatment from the Field Support Vessel, via a flexible hose connected to the tree, and subsequently to back produce the well fluids to the FPSO with injection of Soda Ash to neutralize any unspent acid on the topsides. The key challenges that needed to be addressed were: Identifying an appropriate stimulation recipe, Ensuring adequate pump rate of stimulation fluid given limited pressure rating of the flexible hose, Managing flowback of unspent acid to topsides, Metallurgy compatibility with the stimulation fluid, ydrate risk and Production of H2S from chemical reaction. Full integration of the various functional aspects was essential for effective planning and execution. The Well-X stimulation led to an increase in production frrom 3 to 22 kkbod, with PI improving from 1.4 to 86 bpd/psi; a PIF of 60. Industry experience shows that gaains from mud acid stimulation to attack fines can typically be sustained for up to 12 months, while the partial gain from surfactant to remove MEG/brine impairment is expected to be sustained permanently. TThhis success paves the way for further acid stimulation in the Bonga field where fines migration is typical among producers, and provides opportunities for production acceleration in the field and other upcoming developments.

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 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

Sand and other solids entrained in reservoir fluids can cause a wide variety of problems in wells and topsides processing facilities 1 . Sand control is required whenever evidence suggests that unmanageable sand production will occur; typically soon after a well is put on stream for unconsolidated sandstones. The main challenge is to select the most suitable sand control method without compromising well productivity. This paper shares experience from 5 years of production from 18 high rate oil producer wells targeting deepwater unconsolidated turbidite reservoirs in the Bonga field. The Bonga field, a subsea type development located in ca. 3500ft water depth, has produced over 330 MMstb to date from deviated and horizontal well types, delivering rates as high as 50,000stb/d per well. Seismic and well data show reservoirs are laterally and vertically heterogeneous with reservoir thicknesses ranging from 25ft to over 140ft and average permeability of 1500mD. Thin section, X-ray diffraction and sieve analysis confirm the Bonga sands are generally high quality; well sorted (UC<5), with average grain size ranging between 198 -260µm, low clay content (< 4 wt %), and limited amount of fines (< 5 wt %). Three types of downhole sand control methods, namely Frac & Packs, Stand-Alone Screens and External Gravel Packs have been deployed in the field. Critical factors including long-term sand control reliability, cost, well performance, ease of installation, operability and field experience guided the sand control design for the Bonga wells. In some cases real life issues at design and execute phase led to a departure from initial completion and sand control design. To date, actual well performances observed in Bonga are largely dependent on the sand quality (kh), completion quality, filtercake removal effectiveness, well type and sand control type. The dependencies on these parameters are analyzed in detail.