American Oil and Gas Reporter - June 2016 - 50

SpecialReport: Permian Basin Update

BHP Data Optimize Wolfcamp Wells
By Kyle D. Scott,
Wei-Chun Chu
and Raymond W. Flumerfelt

and operations, Pioneer Natural Resources
Company has run more than 100 BHP
gauges with real-time monitoring in Wolfcamp horizontal wells. Although realtime BHP gauges have not yet been
adopted widely in the onshore U.S. shale
environment, the information has yielded
value far beyond the cost of obtaining
the data, and likely has application in
other onshore shale plays.
Specifically, combining real-time BHP
with other subsurface data is allowing
Pioneer to evaluate interference between
horizontal wells, quantify the variability
of depletion vertically in stacked-pay intervals, develop flowback strategies, optimize artificial lift, and characterize the
fracture system within the reservoir.

IRVING, TX-The Spraberry/Wolfcamp
intervals in the Midland Basin are estimated to hold 75 billion barrels of oilequivalent resource potential, easily making the Spraberry/Wolfcamp the largest
oil field in the United States and the second-largest oil field in the world. However,
the Wolfcamp Shale is still very early in
the horizontal well development phase,
and the play presents unique technical
challenges.
First, the Wolfcamp has the largest
vertical interval of any active U.S. shale
play (thickness can exceed 2,500 feet),
which requires multiple stacked laterals
to fully develop. This presents considerable
challenges in determining an optimal
spacing and stacking development strategy.
Second, multiphase flow complicates
reservoir engineering analyses by limiting
the ability to accurately predict bottomhole pressures from surface pressures
and flow rates.
Finally, many Wolfcamp wells require
artificial lift very early in their producing
lives, and the efficiency of horizontal
well artificial lift techniques to draw
down BHP must be accounted for in well
performance analysis.
To help address these issues and improve the profitability of field development

Real-Time BHP Data
Bottom-hole pressure can be calculated
using surface pressure and flow rates
combined with correlations, mechanistic
models or artificial neural networks, but
these methods lack the necessary accuracy
and data frequency required to effectively
understand well performance and impact
important development decisions in the
Wolfcamp Shale. Multiphase flow effects
are the primary reason for the inadequacy
of the calculated BHP method.
Wolfcamp horizontals produce three
phases (oil, gas and water) from nearly
the first day of production. These everchanging pressures and flow regimes of
the multiphase fluid column in the vertical

ESP Pump Intake Pressure

FIGURE 1A
Diagnosing Well Performance Issue using ESP Pump Intake Pressure

ESP settings adjustments

Time

50 THE AMERICAN OIL & GAS REPORTER

Acid
ﬂush

portion of the wellbore drastically reduce
the operator's ability to calculate BHP
accurately.
The secondary reason for the inadequacy of calculated BHP is lack of data
frequency. Typically, surface pressures
are recorded daily, rounded to the nearest
10 or 50 psi, and are either a 24-hour
average or an instantaneous reading.
That level of accuracy and data frequency
will not suffice for the type of analyses
being performed in the Wolfcamp. Calculated daily BHP averages may be in
the ballpark and suffice for "quick and
dirty" production analyses, but the detailed character seen in measured BHP
data can be almost completely lost in
calculated daily values during phases
that can provide the most insight, such
as during initial drawdown, compressor
downtime, extended pressure buildups,
and offset frac hits.
Obviously, more accurate and higherfrequency surface gauges can resolve
this, but the primary multiphase flow
issue remains. Both of these issues exist
in a naturally flowing well, which is the
most stable flowing condition. But once
artificial lift is introduced, these issues
are amplified. Artificial lift also brings
downtime and periods of lift system optimization, both of which introduce new
rate and pressure fluctuations into the
once-stable flowing well.
For example, gas-lift wells bring new
challenges to calculating BHP as a result
of compressor downtime, variations in
gas injection rates, fluid column changes
in the annulus impacting gas injection
depth, and improperly functioning injection
valves. Gauges set below these continuously changing flowing conditions in the
wellbore have significantly less noise,
leading to better reservoir performance
interpretations.
Application Examples
The examples presented in this article,
which include horizontal wells flowing
naturally as well as utilizing gas lift or
electronic submersible pumps, show improved analysis methods made possible
by using measured BHP. Although only
pressure data are shown, temperature data
from these gauges complement the analysis
by providing another data type to educate
the operator on the likely source and mechanism of observed pressure responses.

American Oil and Gas Reporter - June 2016

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