Summary
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.
Introduction
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.
© 2009. Society of Petroleum Engineers
View full textPDF
(
2,623 KB
)
History
- Original manuscript received:
9 August 2007
- Meeting paper published:
11 November 2007
- Revised manuscript received:
17 October 2008
- Manuscript approved:
20 December 2008
- Published online:
1 May 2009
- Version of record:
1 May 2009
View Cart
