American Oil and Gas Reporter - January 2015 - 92

Unconventional Resource Science

Field Test Validates Completion Design
Editor's Note: The following article
is the second in a two-part series on optimizing completion design in the Bakken/Three Forks play. Part I focused on
data analysis and completion design, and
was featured in the December issue of
AOGR.
By Jessica Barhaug,
Victoria Martinez King,
Andrew Schmidt,
Angie Southcott,
Lee Steinke
and Harold "Hal" Harper
DENVER-To optimize the completion
effectiveness in Bakken/Three Forks horizontal wells in the Williston Basin, WPX
Energy conducted a two-phase project to
gather and analyze data, integrate the results in a calibrated fracture model, and
then develop and field test a recommended
optimized design.
The recommended design was a cemented plug-and-perf completion in a
9,500-foot lateral with 25 stages spaced
at 380 feet, 73 entry points, 425 pounds
per foot of mostly ceramic proppant, and
a pump rate of 30 barrels a minute. That
compared to the previous design of 16
stages spaced at 594 feet, 31 entry points,
347 pounds/foot of mostly ceramic proppant, and a pump rate of 45 bbl/minute.
The project defined completion optimization as improving well performance

and fracture behavior while also increasing
internal rate of return. Consequently, the
economic impact of the new design had
to be measured to ensure that improvements in target metrics were not in conflict
with improved profitability. This was an
especially important consideration, given
that the completion capital required for
the preferred design was greater than for
the standard design being used at the
time. The economic analysis confirmed
that the preferred design could be considered "optimized" because of an increased internal rate of return.
Economics were run to compare completion designs that had been used by the
company within a two-year period. Swell
packers utilizing plug-and-perf, swell
packers and sleeves, and cemented liners
utilizing plug-and-perf methods were
compared. Risked completion costs were
used in the economics to account for
consistent failures and issues that were
encountered for the respective completion
method.
Table 1 shows that the then-current
design method was outperforming swell
packers and sleeves significantly, but the
important difference to notice is that the
current design was expected to require
$500,000 less in capital investment (when
risk was taken into account) compared
with swell packers using the plug-andperf method.
Economic analysis was run for the

current and recommended completion
designs to analyze associated costs and
expected performance. Expected performance was estimated by using the multivariate tool to forecast cumulative production after 180 days using five key
completion variables: lateral length, proppant volume, stage length, treatment rate,
and proppant type. Entry point type, perforation scheme, and fluid type were not
accounted for in the economic comparison
because of the limitation of available
public data.
Once the 180-day cumulative production was determined, a type curve was
hung to review the well economics. Transitioning to the recommended completion
design had an 8 percent incremental added
cost to optimize the completion design,
but generated a predicted 11 percent to
the rate of return, 16 percent to the PV10,
and 10 percent to the estimated ultimate
oil recovery.
Recommended Design
The recommended design took into
account risk, expected performance and
cost, with the goal of increasing the
internal rate of return while managing
capital investment. The strength of the
recommended design came from having
integrated multiple datasets and analyses
that supported a component of the completion design, which provided a confidence level for each component as well

TABLE 1
Comparison of Past Completion Designs and Correlating Economics
Current Design
Cemented P&P
15 stages (limited entry)
equivalent of 31 stages
3MM lbs of proppant

Swell Packers & Sleeves
30 stages
3MM lbs of proppant

Swell Packers & P&P
30 stages
3MM lbs of proppant

$10,000

$0

$515,000

Incremental Cumulative Production at 180 Days (bbl oil)

18,500 bbl

0 bbl

18,500 bbl

Incremental Risked Completion Cost ($MM)

($297,476)

$0

$208,248

Incremental ROR

16.6%

0.0%

13.3%

Incremental PV10

4,056,000

0

3,687,000

Incremental EUR Mbbl

153

0

153

Percentage of Stuck Plugs

1%

Incremental Completion Cost ($MM)

Percentage of Sleeve Failure

92 THE AMERICAN OIL & GAS REPORTER

1%
18%
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