Development of World-Class Oil Production and Water Injection Rate and High Ultimate-Recovery Wells in Deepwater Turbidites--Bonga Example
- Solomon O. Inikori (Shell E&P Technology) | Bert Coxe (Shell E&P Technology) | Ebenezer Ageh (Shell Nigeria E&P) | Jaap W. Van der Bok (Shell Nigeria E&P)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- May 2009
- Document Type
- Journal Paper
- 293 - 302
- 2009. Society of Petroleum Engineers
- 2 Well Completion, 4.2.3 Materials and Corrosion, 5.6.1 Open hole/cased hole log analysis, 1.6 Drilling Operations, 3.3 Well & Reservoir Surveillance and Monitoring, 5.5.3 Scaling Methods, 5.6.9 Production Forecasting, 1.2.1 Wellbore integrity, 5.1.1 Exploration, Development, Structural Geology, 5.2.1 Phase Behavior and PVT Measurements, 2.4.5 Gravel pack design & evaluation, 5.7.2 Recovery Factors, 5.5 Reservoir Simulation, 1.7 Pressure Management, 6.5.2 Water use, produced water discharge and disposal, 2.5.1 Fracture design and containment, 1.8 Formation Damage, 1.4.3 Fines Migration, 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 3 Production and Well Operations, 2.3 Completion Monitoring Systems/Intelligent Wells, 5.6.4 Drillstem/Well Testing, 5.4.1 Waterflooding, 5.1.2 Faults and Fracture Characterisation, 5.1 Reservoir Characterisation, 2.4.3 Sand/Solids Control
- deepwater Nigeria, high rate oil production, fractured water injection, development of turbidites, deepwater West Africa, deepwater turbidites, high rate wells
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Bonga field in deepwater Nigeria produces hydrocarbons from classic deepwater turbidite reservoirs deposited in channel settings. The reservoirs consist of a series of amalgamated channel complexes with varying degrees of compartmentalization. The depostional configuration presented significant uncertainties in connected volumes, well placements, and sweep efficiency between water injector/producer well pairs. However, because of the high costs of deepwater developments, well count needs to be as low as practical, and production rates must be sustainably high to ensure economic robustness of the project. High rates and high ultimate recoveries are the foundations of successful deepwater projects. At Bonga, constant pressure maintenance is a key component to achieving high-rate, high-ultimate-recovery wells. Several research studies concluded that the required water-injection wells be designed for fracture injection (i.e., above sandface-fracture pressure) to sustain the required high rates, as opposed to reservoir matrix injection. This paper presents the results of these research efforts leading to this conclusion and the implications on reservoir management. Also presented is an overview of the challenges of developing these complex channel deposits and the new approach to modeling high-rate wells in deepwater turbidites.
Key to successful understanding of reservoir behavior (connectivity) and early indications of future reservoir performance is a systematic undertaking of interference tests at production startup.
After approximately 2 years of production, the results from the Bonga wells demonstrate that sustained high oil rates could be achieved with adequate pressure maintenance. Average oil production rates of vertical/deviated wells range from 15,-00 to 22,000 BOPD and that of horizontal wells range from 25,000 to 35,000 BOPD. Estimated ultimate recovery (EUR) per well ranges from 20 to 100 million STB for Phase 1 wells and from 10 to 30 million STB for Phase 2 development wells, with several additional opportunities for infill drilling of lower-EUR wells. Nameplate capacity of 225,000 BOPD was achieved and sustained with just nine producers and six injectors. To maintain these high production well rates, world-class water-injection well rates (of between 40,000 and 70,000 B/D per well) have been sustained since first oil.
The fracture-injection approach is applicable both for onshore and offshore reservoir development but, more significantly, for deepwater reservoir development in which sustained high rates and economic considerations are paramount.
The Bonga development is targeted at four major Lower-to-Upper Miocene channelized turbidite reservoirs (A, B, C, and D), each with varying degrees of amalgamation. The Bonga reservoirs lie on the western flank of the shale-cored Bonga anticline and are trapped stratigraphically and structurally in mud-rich, unconfined turbidite systems in a mid-lower slope setting. The reservoirs consist of unconsolidated fine-to-medium-grained turbidite sand deposits with reservoir permeabilities ranging from 200 to more than 5,000 md. Pre-first-oil production-test interpretation results suggested permeabilities in the 2,000-7,000-md range, and production indices (PIs) in the 70-140-(B/D)/psi drawdown range for vertical/deviated wells and over 350 (B/D)/psi drawdown for horizontal wells. The reservoirs are mainly hydrostatically pressured to mildly geopressured, and reservoir fluids are undersaturated in gas with undersaturation spreads (reservoir to bubblepoint pressure) of 500 to 2,000 psi. To keep production rates high and to keep the reservoirs from going below bubblepoint, water injection for pressure maintenance was required from Day 1 of productions.
Table 1 summarizes the typical rock and fluid properties of the various reservoirs. With such a combination of excellent reservoir and production-fluid properties, achieving high initial oil-production rates was not a challenge in this field. In contrast, the main challenges were
- Sustaining high oil rates over time with adequate injection
- Maintaining sand-control integrity in the well completions
- Demonstrating that reservoir discontinuities associated with fault compartmentalization and stratigraphic compartmentalization associated with turbidite channel complexes would not exceed predicted levels
Item 2 was addressed by the application of various sand-control measures, including fracture and pack (F&P) for vertical/deviated wells and openhole gravel pack (OHGP) for high-angle/horizontal wells with adequate wellbore-integrity modeling. Item 3 was addressed through careful well-placement strategy with injector/producer pairs located in the same fault block, limiting the injector-to-producer spacing as much as was possible to 1.5 to 2.5 km.
Item 1 in the list is the primary subject of this paper and is discussed later in detail. This paper presents strategies adopted to ensure sustained injection of treated seawater to maintain reservoir pressure greater than the bubblepoint.
|File Size||2 MB||Number of Pages||10|
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