American Oil and Gas Reporter - May 2017 - 70

For instance, if a well was able to
sustain a flat rate of 20 million cubic feet
a day under managed pressure drawdown
for one year, it would equate to 7.3 billion
cubic feet of production. The high productivities and ability to recover large
reserves per foot of stimulated horizontal
lateral are the biggest drivers behind the
industry's excitement over the Utica/Point
Pleasant's potential.
The most important challenges associated with Utica deep, dry gas wells
have been proppant design (specifically
proppant type), flowback, and long-term
production strategies. When the first wells

were flowed back, the common practice
was to produce at the highest rate the
production facility would allow regardless
of pressure drawdown. The initial performance of these early wells was very
encouraging, but after reaching line pressure, the effective annual decline percentage dropped significantly. It became
clear that some type of managed pressure
drawdown strategy was crucial to both
short- and long-term well productivity.
Managed Pressure Drawdown
Managed pressure drawdown is commonly defined as maintaining a daily

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70 THE AMERICAN OIL & GAS REPORTER

tubing or casing pressure drop of 15-25
psi. The tubing and casing pressure drop
per day, therefore, becomes the controlling
factor of the production rate. In the Utica
study, eight wells in a very similar geologic
area were selected that had been completed
successfully. Diagnostic fracture injection
tests determined a pressure-dependent
leakoff (PDL) signature, followed by a
closure pressure of approximately 10,000
psi. The PDL signature signified complexity, and possibly, a naturally fractured
formation. Pore pressure was estimated
at 0.88 psi/foot.
Pressure drawdown was not managed
in two of the wells (A and B), while the
other six (C, D, E, F, G and H) used
some form of pressure management. Wells
G and H were added later, since they had
higher production histories and actually
reached the line pressure. The other four
managed pressure wells were still producing at pressures higher than line pressure at the time the study was conducted.
Various diagnostic plots were performed
to determine each well's flow capacity
(normalized by lateral length). As shown
in Table 1, the wells with managed
pressure drawdown (15-25 psi/d tubing
and casing pressure drop) have significantly higher flow capacity and EURs
compared with the wells with unmanaged
pressure drawdown.
Figure 1 shows that the managed pressure wells are able to sustain similar or
higher cumulative production while maintaining higher flowing bottom-hole pressures. In general, the Utica/Point Pleasant
exits the transient flow period much faster
than the Marcellus because of its higher
reservoir permeability. The wells with
unmanaged drawdown appear to exit transient flow into transitional or boundarydominated flow much faster than the
other six wells.
Looking at production versus calculated
sand-face pressure, gas production from
the two unmanaged drawdown wells
clearly drops with sand-face pressure at a
critical pressure much higher than line
pressure. Interestingly, this behavior occurs
almost at the same critical pressure in
both wells. This behavior could be the
result of the pressure dependency of matrix
permeability or stimulated reservoir volume
(SRV) permeability, but is most likely associated with the pressure dependency of
hydraulic fracture conductivity.
To investigate this idea, the two wells'
completions designs were compared. Both
were completed with very similar designs.
Therefore, one would expect the hydraulic
fractures to behave similarly with respect
to effective stress. However, as the PDL
studies show, effective stress is likely to
be impacted by complexity and the pres-


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Table of Contents for the Digital Edition of American Oil and Gas Reporter - May 2017

Contents
American Oil and Gas Reporter - May 2017 - 1
American Oil and Gas Reporter - May 2017 - 2
American Oil and Gas Reporter - May 2017 - Contents
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