Summary
Developing the Okwori field (offshore Nigeria) required the combination of
several recent technological advances. The subsea development targeted multiple
oil-bearing zones in all wells with the requirement that each zone could be
operated independently. Expandable sand-screen (ESS) strings were deployed
within casing for up to four zones to prevent sand production from
unconsolidated-sandstone reservoirs. Independent control of all zones was made
possible by use of remotely operated surface-controlled sliding-sleeve units
[(ROSS)trademark of Weatherford U.K.]
Losses experienced after perforating required the use of loss-control
material (LCM) for well control. Initial LCM formulation appeared to yield
formation damage. A special effort ensued to design optimal LCM pills to meet
project requirements. This paper presents the completion issues associated with
the project, the optimization of the LCM pills, and the design and placement
aspect of the remedial treatment associated with this type of completion. The
evolution of the completion efficiency for each zone throughout the learning
curve is presented and discussed.
Introduction
After discovering the Okwori field (offshore Nigeria) in 1972 (Fig. 1),
several operators studied field development options but, none felt in a
position to ensure sufficient economic returns. The inherent subsurface
difficulties, coupled with the status of offshore technology and economic
constraints, would not permit the development of such a complex project at that
time. In 1998, Addax Petroleum Development (Nigeria) acquired this asset and
subsequently engaged actively in studying its own development plan, which the
Nigerian Petroleum Authorities sanctioned in 2002.
The highly faulted and compartmentalized nature of the Okwori reservoirs
required dispersed well surface locations, hence, a subsea development with
each well being tied back individually to a central floating production,
storage, and offloading vessel (FPSO) (Fig. 2). To make the Okwori development
economical, each well needed to intersect several oil-bearing reservoirs. The
well trajectories were carefully planned to target these successive horizons.
The wells were cased and cemented to isolate all reservoir sands. Local
regulation stipulates that each reservoir must be able to be tested and
produced individually. Therefore, an inner-completion string had to be designed
to allow complete independent control of all the producing zones from
surface.
In the Niger delta region, oil is produced from weak-to-unconsolidated
sandstones. Because of the “interventionless” nature of the subsea wells, a
sand-exclusion system compatible with the required full selectivity was chosen
for the Okwori development. ESS™ were installed inside the
95/8-in. casing. An inner completion with packers and
ROSSTM was then installed before the well was tested and hooked up
to the FPSO.
The Okwori development required highly productive wells to meet the set
financial goals. The integrity of the wells was also an important concern
because any well intervention would take place at a huge expense as a result of
semisubmersible rig mobilization costs. Under these conditions, the different
steps taken to minimize formation damage were key to the project success.
Curing the losses after perforating without damaging the formations and
restoring the original near wellbore permeability of each zone were major
sandface-completion issues.
Subsurface Description
The complexity of the Okwori field can be best summarized by the large
number of reservoir layers and fault-delimited compartments (Fig. 3). resulting
in numerous potentially hydrocarbon-bearing pools. More than 100 of these
fault-dip closures were mapped from two vintages of 3D-seismic surveys while
approximately 30 pools were penetrated by six wells drilled before the start of
field development
The structural complexity was explained through the development of a
collapsed-crest anticline along two intersecting sets of syn- and
post-sedimentary fault planes (Fig. 4). Well trajectories were designed to
intersect reservoir closures parallel to fault planes. Hydrocarbon content (oil
or gas) and fluid contacts were also found to be highly variable among
reservoirs as well as among compartments of the same reservoir, adding to the
overall field complexity. Risked oil-in-place volumes were calculated to rank
reservoir targets and guide field development.
© 2007. Society of Petroleum Engineers
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History
- Original manuscript received:
17 February 2006
- Revised manuscript received:
6 March 2007
- Manuscript approved:
25 May 2007
- Version of record:
20 September 2007
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