American Oil and Gas Reporter - January 2015 - 121

TECH TRENDS
mental cost associated with each test and
the total plan may require significant
capital investment. However, the capital
invested in the testing program ultimately
will improve performance across the
entire play.
Some of the aspects that make completion optimization challenging are:
* Deciding the number of wells in
which to test each completion parameter
(repeatability);
* Identifying test wells with identical
offsets with benchmark completions in
areas with similar geology, hydrocarbon
type, yield, etc. (an "apple-to-apple" comparison with a significant change only in
a completion parameter is desired);
* Selecting test wells from areas producing different hydrocarbon types (oil,
gas and condensate) based on drilling and
completion activity in the test period;
* Developing an acceptable budget
for implementing the plan; and
* Quantifying the expected production
uplift and economic benefit from an optimized completion design.
A detailed performance analysis of
offset-operator wells with different completion designs was performed using traded well data and available public domain
data. The offset-operator wells were compared with the analogous standard benchmark completion wells. A detailed technical evaluation of the Eagle Ford benchmark completion design was performed.
A completion optimization test matrix
of the candidate wells was created with
close coordination among area geologists,
reservoir engineers, completion engineers
and production engineers.
The test wells were selected so they
had offset wells with the benchmark completion. Each test well had exactly the
same completion design as its offset well(s),
except for the completion parameter to be
tested. The net cost of testing each completion parameter and the capital budget
required for the entire optimization plan
was quantified. The completion optimization plan involved testing:
* Higher proppant volumes per lateral
length for greater stimulated reservoir
volume (SRV);
* Reduced cluster spacing for improved near-wellbore stimulation;
* Higher proppant volume (pound/foot)
combined with reduced cluster spacing
for improved SRV and near-wellbore stimulation ("combo" wells);

* Higher rates per cluster for improved
fracture half-lengths;
* Optimized fluid system for improved proppant transport; and
* Optimized proppant size for improved conductivity.
Reservoir Performance Analysis
To avoid ambiguity in test results caused
by interference between wells on the same
pad, each pad was completed with a single
completion type. If test wells conclusively
outperformed standard benchmark wells
within the first four months, then the
analysis was accelerated. If results were
inconclusive, analysis was performed again
periodically with additional production
data for the test wells. Wells for the "higher
rate per cluster" test were the first to have
six months of production data. The diagnostic and economic evaluation was performed, and a design change was implemented.
The higher proppant-volume test
pumped 50 percent more proppant per
foot. Cluster spacing and all other parameters of the benchmark completion
were kept constant. The additional proppant volumes associated with this optimization test added net incremental cost
to the standard completion design. Both
single "one-off" wells and multiwell pads
were chosen to test this variable, and results were compared with single standalone and pad offset benchmark wells.
The aim of the combo wells was to
combine higher proppant volumes and reduced cluster spacing to achieve a larger
SRV and better near-wellbore stimulation.
Because this completion added more stages
to stimulate the lateral, it was the highest
net incremental cost test case in the completion optimization plan. The combo test
wells were chosen similarly to the test
wells for higher proppant volumes.
For both completion designs, the test
wells and corresponding offset wells are
located in the Eagle Ford's condensate
(retrograde gas) window with yields ranging from 150 to 350 barrels per million
cubic feet of gas. During test well selection, it was extremely important to choose
wells in similar geologic environments
as the offset benchmarks to limit the
effects of other variables (i.e., reservoir
pressure, effective porosity, water saturation, net pay, brittle mineral content,
etc.). It also was important for the test
wells to be operated in a similar manner.

Choke sizes were kept the same on all
test wells to better evaluate short-term
production performance.
The first part of the analysis looked at
normalized short-term and cumulative
production, followed by EUR estimates
using decline curve analysis (DCA). The
second part included straight-line analysis
on rate/pressure/time data and history
matching with reservoir simulation. To
avoid ambiguity in the results caused by
intrapad well communication, each pad
was treated as a unit. Comparisons were
then performed between the standard and
optimized completion pads.
The step-by-step procedure used in
the study began with creating diagnostic
plots such as gas-to-oil ratio (CGR or
yield) versus time and bottom-hole pressure versus time. Normalized rate versus
time and normalized cumulative production versus time were created to compare
short-term production and economics
(when wells with a similar yield band
are compared, individual gas and oil rates
can be replaced with energy equivalent
rates using a 6-to-1 ratio).
A normalized productivity index versus
time plot was built to evaluate the producibility level of each well. Wells completed from the same pad with similar designs were averaged to create a pad type
curve. Oil/condensate and gas EURs were
forecast for each pad using DCA. When
limited production data were available, the
hyperbolic decline "b" factor was limited
to ranges derived from production of older
wells in the area. This is extremely important
for wells flowing at smaller choke sizes
where the initial decline rate is less than
65-70 percent.
The next steps were creating pressure
normalized rate versus material balance
time plot to identify the flow regime, as
well as a flowing material balance (FMB)
plots to estimate the volume corresponding
to SRV depletion. The volumes estimated
from the end of linear flow should be the
same as volumes estimated from the
FMB plot. The final steps involved building the reservoir model using an enhanced
fracture region model and history matching, and forecasting oil/condensate and
gas EURs.
Higher Proppant Volume
Wells with higher proppant volume
were tested in Dewitt County, Tx., and
based on the uplift in well performance
JANUARY 2015 121



American Oil and Gas Reporter - January 2015

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2015

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American Oil and Gas Reporter - January 2015 - Cover3
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