American Oil and Gas Reporter - April 2015 - 114

SpecialReport: Offshore Tech Trends
CAPEX cost along with additional field
infrastructure costs to support two pump
modules. A single three-mw pump provided slightly better NPV than two threemw pumps, but was less than the single
six-mw pump. The ESPs with a single
three-mw SPP resulted in the lowest NPV
for the two low-PI well cases (Figure 1).
Given the limits imposed on the maximum drawdown and minimum FBHP,
artificial lift and seabed boosting were
not able to be utilized to any significant
extent until the fourth year of production
for the two-well, low-PI case.
A three-year ESP run life resulted in
significantly higher OPEX for well intervention operations than mud-line pumps
with a five-year run life. The much lower
OPEX is attributable mainly to less frequent
intervention and lower associated intervention costs since mud-line pump recovery and installation can be performed
from a Category A vessel. A mud-line
pump intervention campaign also is shorter
and poses less risk than having to pull the
completion string from each well to perform an ESP intervention with a MODU.
The ESPs supplying the three-mw
mud-line pump for the high-PI case resulted in the highest NPV over the 30year field life, with secondary recovery
configurations evaluated at 16 percent,
followed by the six-mw MPP at 15 percent
and the two three-mw MPPs running in
parallel at 14 percent. However, when
the return on investment for each of the
configurations was calculated, the mudline pumps had considerably better ROI

FIGURE 1
Two-Well Scenario NPV Results
18%
16%
14%
12%
10%
8%
6%
4%
2%
0%

6 mw MPP

3 mw MPP

than the ESP configurations (Figure 2).
For the low-PI case, the three-mw
pump had a higher ROI than the six-mw
pump because of the larger pump's higher
CAPEX, inability to utilize its full power
capacity with only two wells tied to it,
and the drawdown and minimum FBHP
limitations. The high-PI case allows the
mud-line pumps to operate in a less-constrained condition and better utilize their
available capacity.
Looking at the recovery factors for
each of the secondary recovery configurations analyzed, there was not a considerable difference in recovery factor performance in one configuration versus any
other for the low-PI case. For the highPI case, the downhole ESPs feeding the
three-mw SPP showed the greatest recovery factor. However, based on the

FIGURE 2
Two-Well Scenario ROI Results
600%
500%
400%
300%
200%
100%
0%
6 mw MPP

3 mw MPP

2 x 3 mw MPP

High PI (3 bbl/d/psi)

2 x 3 mw MPP

High PI (3 bbl/d/psi)

114 THE AMERICAN OIL & GAS REPORTER

ESP

Low PI (1.5 bbl/d/psi)

ESP + 3 mw
SPP

ESP

Low PI (1.5 bbl/d/psi)

ESP + 3 mw
SPP

ROI performance, it would be ill-advised
to base equipment selection solely on
the recovery factor impact.

Three-Well Scenario Results
Another analysis was conducted using
a field development model with three
wells, but the wells were drilled to a
deeper reservoir depth of 28,000 feet TVD
below MSL. Flow from the wells was
again comingled and fed into either a
single 9¼-inch flowline or equivalent dual
7-inch flowlines tied back 15 miles to a
surface facility in 10,000 feet of water.
Reservoir fluid properties as well as
economic analysis factors/costs remained
the same as in the first scenario, except for
the difference in additional CAPEX and
OPEX to support a third well. A natural
flow base-line was again established over
a 30-year life to evaluate the relative performance of the same secondary recovery
configurations used in the first scenario.
For the low-PI case, all artificial lift
methods were hampered by drawdown
limitations during early field life. Although
the full power capacity of the six-mw
pump was able to be utilized for the threewell, low-PI case, reservoir constraints
limited its use to years four through eight
of the field's life. The six-mw pump in
this scenario exhibited the best NPV of
the artificial lift methods analyzed, followed
closely by the two three-mw MPPs operating in parallel (Figure 3).
The 3,000-foot increase in reservoir
depth taxed the power capacity of the
ESP for the low-PI case as well (the
ESPs are set 10,500 feet below the mud
line in both scenarios). NPV performance
improved for all secondary recovery configurations for the low-PI case, but the
biggest NPV gains were achieved by the

American Oil and Gas Reporter - April 2015

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