Big reservoirs in deepwater Gulf of Mexico (GOM) typically produce at
world-class rates. The scale of investment is likewise world class.
The energy industry's drive to invest in enhanced oil recovery from
deepwater basins is sustainable in a world of volatile oil prices and
increasing demand for energy. However, project economics will continue to
depend on accurate risk assessment, risk-mitigation strategies, and, more
fundamentally, progressive deployment of evolving technologies in brownfield
deepwater secondary-recovery projects.
Details of well geometry and design optimizations may prove to be minor
sensitivities in high-cost deepwater developments; however, rig rate has a
major impact on economics. The assessment required to minimize the number of
injectors and ensure their proper placement logically takes more time than
exotic choices of injection patterns. With such major constraints in mind, an
optimal design for wells and materials has to take precedence. Accepting this
as a given, additional, more common challenges would then follow.
The waterflood-study team for the deepwater Ursa/Princess field in the GOM
has spent appreciable time and effort evaluating various potential challenges
affecting the surface and subsurface aspects of the development plan. The
design for an optimum injection rate was a bottom-up process starting from the
reservoir up to the topsides injection facilities. Reservoir-sweep efficiency
and reservoir-pressure distribution logically dictated injection-well designs
and injection-pump sizing. Subsurface risks, such as reservoir souring and
hydrate formation, dictated materials selection and completions design.
This paper addresses the challenges primarily affecting the design of the
deepwater subsea-injection wells. In addition to the well cost, several other
underlying factors have played an influential role in defining the boundary
conditions for the injectors design.
Industry-wide experience in the execution and the operation of waterflood
projects in deepwater environments is relatively limited. With relatively few
analogs, the Ursa and Princess fields are set to embark on major facilities
expansion and subsea development. The aim is to deliver a high rate of
specific-quality water through four subsea-injection wells into a vast and,
largely thirsty, reservoir.
Ursa and Princess reside 100 miles south/southeast of the Mississippi River
mouth in the Mars basin, GOM. The Ursa field was discovered in 1990 and has
been on production since 1999. The Princess field was discovered in 2000 and
has been producing since December 2003 through a subsea tieback to Ursa. The
fields have their main reservoirs in common and are in pressure communication.
The working interest in the Ursa and Princess fields are Shell (45--operator),
BP (23%), ExxonMobil (16%), and ConocoPhillips (16%).
The Yellow reservoir is the main reservoir at both Ursa/Princess and Mars,
the other major field in the Mars basin. It is a world-class Upper Miocene
turbidite reservoir that stretches across the Mars basin, including the Mars
field. This 12,000-acre reservoir is charged with light-oil type, though with
slight variations in properties, as indicated by the analysis results of the
abundant pressure-volume-temperature measurement samples.
Because of limited TLP well availability, the high cost of subsea wells and
the limitations of the subsea system to handle large water cuts, the waterflood
will use relatively few injectors. The proposed base plan has four water
injectors: two into Princess and two into Ursa.
Producing wells will include three Princess subsea wells and four Ursa TLP
wells. Five TLP wells are to be sidetracked updip or recompleted at a later
High injection rates are required to replace voidage and maintain reservoir
pressure above bubblepoint. Initial injection rates per well (annual average)
of 30 to 40 thousand BWPD are required. This injectivity can only be maintained
by creating fractures. With the wide well spacing relative to fracture length,
this is not expected to negatively impact sweep efficiency. However, because of
the uniqueness of well spacing and reservoir volumes, there is a lack of
analog-data points to calibrate the outcomes.
Parallel evaluation of the viability of artificial lifting has shown that
TLP waterflood producers would benefit from gas lifting. The base plan for
waterflood wells thus includes the requirement for gas-lift completions and
The original Operating Health Safety and Environmental (HSE) case for the
asset did not include the potential threat of reservoir souring after seawater
injection. The well casing and tubular materials, therefore, have limited
resistance to sulfide-stress corrosion cracking. This resulted in the need to
recomplete the Ursa TLP direct-vertical access (DVA) wells with Shell-qualified
tubing. Princess producers already have Shell-qualified C100 sour-resistant
casing, and will not require pre-emptive intervention for tubing change
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
16 January 2007
- Meeting paper published:
30 April 2007
- Revised manuscript received:
4 April 2008
- Manuscript approved:
7 April 2008
- Version of record:
15 August 2008