American Oil and Gas Reporter - September 2015 - 69

Horizontal Refractures Likely To Grow
HOUSTON-By 2020, refracturing will
account for as much as 11 percent of horizontal well fracturing in the United States,
says a new IHS Energy Insight report, although it adds that horizontal well refracturing technologies likely will remain a
niche market until significant technical
and financial risks can be reduced.
In its report, To Frac or Refrac:
Prospects for Refracturing in the United
States, IHS predicts this trend will continue
despite significant interest from both oil
and gas operators and oil field service
companies hoping the technology will
reinvigorate drilling activity in the U.S.
onshore.
IHS says its report reviews horizontal
refracturing technologies and approaches,
as well as economics and effectiveness,
then establishes base-line criteria and assesses the potential of the technology
using primary intelligence, rigorous research and proprietary data. The report
draws from two IHS databases for its
analysis, the firm says: its U.S. well and
production database, which contains in
excess of 1 million wells, and its proprietary database of fractured wells.
"In response to lower oil prices, operators and service companies have shown
increasing interest in horizontal well refracturing," observes Christopher Robart,
managing director, unconventional resources, at IHS Energy and the report's
lead author. "However, while refracturing
has potential to leverage improved completion techniques to increase production
while avoiding drilling and facility costs
associated with a new well, IHS research
indicates there is a great deal of uncertainty
about the viability of large-scale refracturing that must be overcome first."
Refracturing History
IHS says its researchers examined the
entire population of U.S. onshore horizontal wells fractured since 2000 to identify all refracturing operations. Through
a robust search and filter methodology,
IHS says, its researchers were able to
identify nearly 600 horizontal well refractures.
According to IHS, the Bakken play
has the greatest number of refractured
wells among U.S. plays, followed by the
Barnett and Marcellus shales. Unsurprisingly, the firm remarks, the largest number
of refractured wells is located in the plays
with the oldest wells.
Refracturing success, as measured by
comparing initial production rates of refractured wells to original IP rates, IHS
reports, is mixed. With the exception of

the Bakken wells studied, IHS says most
refractured wells have IP rates lower than
the original IP rates. The Bakken anomaly,
IHS reasons, likely is the result of suboptimal well specifications chosen for
the original completion, which the firm
suggests is not surprising, since the Bakken
play was one of the early testing grounds
for the initial horizontal drilling and fracturing technologies that have since been
improved significantly.
However, because of the Bakken's
refracturing results, and some overperformers in the Eagle Ford, IHS says, the
overall average refractured well IP is
equivalent to 98 percent of the original
well IP.
As for decline rates, IHS's report finds
refractured wells had slightly better 12month decline rates than the original well
completions (refractured wells declined
at a rate of 56 percent compared with 64
percent for original well completions).
According to its analysis, IHS says,
three refracturing techniques-diversion,
coiled tubing or mechanical isolation-
were employed most often in the wells
studied. However, it says each method
has benefits and limitations, and it is unclear which technique will dominate in
the future.
Refracturing costs vary widely by
method and job size, IHS continues,
saying the diversion method offers the
lowest cost, but also limited control. Conversely, mechanical isolation is the most
costly of the three approaches, in part
because of increases in surface and downhole costs, the firm adds.

Looking Forward
As for applying the refracturing technologies, Robart says the popularity of
refracturing will grow if operating companies gain more confidence in one or
more techniques, and costs recede.
Because of the technical challenges,
uncertainties and costs associated with
today's refracturing methods, Robart says
operators who have better portfolios of
new well prospects likely will pursue
those opportunities first, and save older
assets for later, when improved technologies make those wells a more attractive
investment for refracturing.
"The companies with superior acreage
for new well development are not the
prime candidates for refracturing," Robart
comments. "Operators with less attractive
assets likely will be more interested in
advancing this technology in the near
term."
He continues, "Refracturing technology
is in its infancy, and a large-scale refracturing program is the most important step
that can be taken to advance it. However,
most operators are cautious about investing
significant capital before they see more
positive results from others first.
"To get better at something, you have
to repeat it and refine processes-you have
to experiment," Robart avers. "What refracturing needs now is a new innovator
to step up, invest capital, and take risks
to refine the technologies and lower costs.
For refracturing to advance significantly,
we need the next George Mitchell to
come forward."
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Contango Tests Its First Muddy Sandstone Well
HOUSTON-Contango Oil & Gas
Company has announced its successful
completion of the Elliott No. 1H well in
the Muddy Sandstone formation in Weston
County, Wy.
According to Contango, the well tested
at a maximum 24-hour rate of 907 barrels
of oil equivalent from a 6,601-foot lateral
section completed using 25 stages of
fracture stimulation. Total measured depth
was 13,116 feet at a true vertical depth
of 6,235 feet.
Contango says the Elliott 1H is its
initial well in the North Cheyenne prospect.
It is between two legacy vertical Muddy
Sandstone oil fields: the Fiddler Creek
Field to the north and the Clareton Field
to the south. The company notes that both
fields were discovered in the 1940s, and
have a combined cumulative production

in excess of 50 million barrels of oil.
Although additional production data
were needed to confirm the estimated ultimate recovery and type curve profile,
the company says the well's maximum
24-hour initial production rate exceeded
its predrill model of 500 boe/d. "We are
still early in the initial production stage
and continue to develop the best combination of surface and subsurface production facilities," comments President and
Chief Executive Officer Allan Keel.
According to Keel, Contango has approximately 49,000 gross acres in the
North Cheyenne prospect area, and expected to begin full scale development
in early 2016 with a commitment of one
to two rigs after spudding one or two
more wells yet this year to further delineate
the discovery.
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SEPTEMBER 2015 69

American Oil and Gas Reporter - September 2015

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