American Oil and Gas Reporter - January 2019 - 93

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Tech Trends
The plots in Figures 4A and 4B show
the injection activity relative to the pressure
surges in the S-10H and 11H wells. More
often than not, injection actually was initiated late in the pressure event and often
was not higher than 0.5 bbl/minute.
Toward the end of the project, transducers
on the flowmeters failed, resulting in
some lost data.
The fact that the onset of these stronger
hits came later in the time sequence and
was delayed in the S-11H by 52 hours
compared with the S10-H may be explained by decreasing system compressibility with time as re-pressurization of
semi-depleted areas progressed from
west to east in the legacy well group.
Determining the causative well for each
hit proved difficult because of the nearcontinuous nature of the zipper frac operations in the zipper frac and the complexity of the pressure data in this regard.
Pressure events also were detected between wells on the zipper pad. Causative
correspondence for these hits was easier to
determine. The S-8H and 9-H zipper wells

are an example of frac-to-frac communication. Fracturing the 8H was estimated to
have caused four frac hits on the 9H, while
fracturing the 9H caused five hits on the
8H. All of these hits were of a lower magnitude, no doubt because of the fact that
the regions around the wells were pressured
up by the ongoing frac activity.
In all, 21 frac-to-frac events of this
type occurred during the zipper process
on the four new infill wells. Once again, it
was observed that pressure communication
frequently occurred across the Lower
Bakken Shale, with Three Forks wells hit
by Middle Bakken wells and vice versa.
Figure 5 plots the combined production for the six defended legacy wells
both before and after the four-well pad
was zipper fractured in May 2017. The
total oil rate increased after the zipper
frac operations, which could be part a
stimulation effect and part makeup production from the down period. More
obvious was the increase in post-frac
water production, which doubled compared with prefrac rates. However, at

the 120-day post-frac mark, the group
of wells was trending back in the direction of prefrac water levels.
The most important result in terms of
project goals is the fact that all of the
legacy wells were returned to production
without the need for remediation. None of
the wells showed signs of wellbore fill or
required a post-frac clean-out. In this regard,
the trial was 100 percent successful.
Estimated cost of the defense project,
including water, chemicals and all related
services was $262,273, which was less
than the cost of one CT well clean-out.
The per-well average cost was $43,700,
which represents a bargain compared
with remediation. On a per-well basis,
the most expensive cost component was
the pumping horsepower ($20,041), followed by pressure monitoring ($12,556),
water and chemicals ($8,497) and returning
wells to production ($2,618). The cost to
return wells to production was relatively
low because all six wells were configured
for gas lift and did not require pre- or
post-frac rig work.
r

PETER
BOMMER

Peter Bommer is vice president of engineering for San Antonio-based Abraxas Petroleum
Corporation. Prior to joining Abraxas in 2007, he owned and ran the day-to-day operations of
Bommer Engineering, a privately held engineering firm, for more than 25 years. Bommer
began his oil field career in 1974 as a well service floor hand in Texas, and later worked for
Chevron USA in California. He holds a B.S. in petroleum engineering from the University of
Texas at Austin and a master's in biblical studies from the Dallas Theological Seminary.

MARCUS
BAYNE

Marcus Bayne is engineering analytics manager and frac supervisor with Abraxas Petroleum
Corporation. He handles day-to-day data management and analytics for the company's
engineering department and supervises its hydraulic fracturing operations. Bayne began his
career as a production foreman with Abraxas, serving in that capacity for six years.
JANUARY 2019 93

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