American Oil and Gas Reporter - April 2015 - 113

SpecialReport: Offshore Tech Trends

Study Analyzes Paleogene Recovery
By Jamie Hartley,
Eric Smedstad,
Ervina Widjaja

HOUSTON-The Gulf of Mexico Paleogene (Wilcox trend) contains large recoverable oil reserves, with the estimated
recoverable reserves of many announced
discoveries in excess of 250 million barrels. However, with drilling depths to
35,000 feet, high reservoir pressures, ultradeep water depths and estimated total
costs on the order of $180 million to
$200 million per well, the Paleogene also
presents operators with unique field development and production challenges.
Given high field development costs,
coupled with low recovery factors, many
operators are looking at various means
of improving the economics of developing
these discoveries. Artificial lift technologies in the form of downhole electric
submersible pumps or subsea mud-line
boosting pumps are being deployed to
improve the recoverable reserves and
overall economics of Paleogene field developments.
According to the Deepwater GOM
study by the Research Partnership to
Secure Energy for America, permeability
values in Paleogene reservoirs can be
more than an order-of-magnitude lower
than in other deepwater Gulf plays. On
top of poor permeability and porosity,
the reservoirs are not expected to have
an appreciable drive mechanism, so recovery factors for natural flow are anticipated to be about 10 percent of the
original oil in place. Even small improvements in the recovery factor can
have a significant impact on the economics, given the large size of the reservoirs. In fact, Wood Mackenzie estimates
that a 2 percent recovery factor improvement translates to an increase of
$1 billion in a Paleogene field's net
present value.
RPSEA's study reveals that both downhole ESPs and mud-line boosting pumps
are anticipated to have the potential to
increase recoverables by 6.4 percent or
more. However, many variables come
into play that can impact the overall economic performance of a field development
using pumps to increase recoverable reserves. Downhole ESPs, when used in
combination with mud-line boosting
pumps, have the potential to deliver the

best recovery factors, but poor reliability
and high intervention costs associated
with ESPs in subsea wells can negate the
value of those recovery gains. Mud-line
boosting pumps, by comparison, have
lower intervention costs and generally
better reliability than downhole ESPs.
The challenge, however, is selecting
the right solution to maximize recovery
in the most cost-effective way. To determine the potential improvement in recovery, a production performance analysis
was performed for a number of ESP and
mud-line pump configurations for Paleogene field developments. The analysis
included an economic performance evaluation to compare the value of the increased recoverable reserves against the
added expenses for the hardware, equipment installation, annual operational costs,
and intervention and maintenance costs
over a 30-year field life.

Field Modeling, Economics
Paleogene reservoir characteristics
were used to develop a model in a dynamic
simulation multiphase software package
to compare the recovery performance of
the base-line natural flow of subsea wells
against the performance of the wells with
one of five secondary recovery
configurations:
* A single six-megawatt subsea multiphase pump (MPP);
* A single three-mw subsea multiphase pump;
* Two three-mw subsea MPPs operating in parallel;
* A single tubing-deployed 1,200horsepower ESP per well; and
* A single tubing-deployed 1,200horsepower ESP per well, supplying a
single three-mw subsea single-phase pump
(SPP).
The reservoir characteristics were coupled with two field development scenarios
and a base-line natural production flow
for the life of the field was established
for each scenario. The ESPs were set at
10,500 feet below the mud line in both
scenarios.
The first secondary recovery field development scenario was based on two
subsea wells, each drilled to 25,000 feet
true vertical depth below mean sea level
(MSL). The flow from the two wells was
comingled and fed into a single 7¾-inch
inside diameter flowline tied back 15

miles to a topsides facility in 10,000 feet
of water.
The hydrocarbon fluid properties used
for the analysis were 25 degrees API
gravity with a gas-to-oil ratio of 350
cubic feet/barrel. The initial reservoir
pressure and temperature were 21,000
psia and 220 degrees Fahrenheit, respectively. The sensitivity of the secondary
recovery configurations to productivity
index (PI) were evaluated, where a lowPI case (1.5 barrels a day/psi) was compared with a high-PI case (3.0 barrels a
day/psi). Maximum drawdown was assumed to be 10,000 psi and the minimum
flowing bottom-hole pressure (FBHP)
was assumed to be 6,000 psi.
The run life used for the ESPs and
mud-line boosting pumps was three and
five years, respectively. For simplicity,
the only deferred production considered
was that which occurred during the actual
intervention operations. The intervention
vessel was assumed to be available on
location immediately following any equipment failure with a spare ESP, MPP or
SPP ready for deployment as needed.
Estimated capital expenditures included
the topsides equipment, subsea power
distribution equipment, incremental initial
installation costs for all secondary recovery
equipment, and spares. Operating expenditures included power generation costs,
topsides maintenance for power distribution equipment, spares storage and
maintenance, equipment refurbishment,
and intervention costs.
The ESP intervention duration was
assumed to be 30 days and require a
mobile offshore drilling unit. MPP or
SPP intervention was assumed to take
14 days and require a Category A or
multiservice vessel. For the economic
evaluation, a discount factor of 12 percent
was used, with a flat inflation rate of 4
percent annually and an $80 a barrel oil
price.
Two-Well Scenario Results
The six-mw pump exhibited the highest
NPV for the low-PI case. Although it
can support more than two wells, it was
not able to take advantage of its full
power capacity because of reservoir constraints and the low number of wells.
Two three-mw pumps operating in parallel
resulted in a lower NPV then a single
six-mw pump, given the slightly higher
APRIL 2015 113



American Oil and Gas Reporter - April 2015

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