American Oil and Gas Reporter - January 2015 - 123

TECH TRENDS
and economics, this optimization parameter has become a recommended part of
the design for all wells in this area. Three
wells were drilled and completed with
higher proppant volumes next to three
offset wells completed with the benchmark
design at about the same time. The wells
were flowed using the same choke size.
Figure 4 shows the average normalized
production for each pad. The pad with
the higher proppant volume design had a
shallower decline, and 6.5 and 10.6 percent
greater cumulative production at six and
12 months, respectively. The higher initial
return significantly impacts the wells' net
present value.
EURs were forecast for each phase
and pad using DCA. The "b" factor used
in the analysis was based on local wells
that had been producing for more than
three years. Based on the forecasts, a 21

percent uplift in EUR was observed for
wells completed with the higher proppant
volume. Straight-line analysis was carried
out on rate-pressure-time data based on
recommended workflow. It was concluded
that SRV created by higher proppant volume was 13 percent greater than the
benchmark design.
Finally, a reservoir simulation model
was built and a history match was done
for one representative well from each
pad. Production was forecast for 40 years
with economic limits. Original hydrocarbons in place per well were limited to
well spacing, although a single well simulation model was built. Figure 5 shows
the history match and forecast for each
well. The difference in EURs estimated
by DCA and analytical reservoir simulation modeling was 15 percent, where
DCA values were conservative.

Combo Design
The combo design with both higher
proppant volume and reduced cluster
spacing was tested in Karnes County,
Tx. Three wells were completed with
the combo design next to five wells completed with the conventional design.
Figure 6 shows the diagnostic plots
for the average production of wells in
each pad. For the first four months, the
choke size on these wells was kept the
same, but was later changed for the combo
wells as a part of a drawdown management
program. In addition, four months of production on the combo wells was so strong
(outperforming conventional wells by 37
percent) that there was no need to wait
for more production to draw conclusions
about the success of optimization test.
Production was forecast for each design
using DCA with the recommended "b"

FIGURE 4
Normalized Production Rate (boe/d/1,000 feet) versus Normalized Time (Left)
And Normalized Cumulative Production (Mboe/1,000 feet) versus Normalized Time (Right)
80
Normalized Cumulative Production
(Mboe/1,000')

Normalized Production Rate
(boe/d/1,000')

1,000

100

70
60
50
40
30
20
10
0

10
0

100

200

300

400

500

600

100

200

Normalized Time (d)
Lb/ft Design

300

400

500

600

Normalized Time (d)

Conventional Design

Lb/ft Design

Conventional Design

FIGURE 5
History Match and Forecast Results for Conventional (Left) and Higher Proppant Volume (Right) Designs

3
2
1
0

1,000

10,000

4.50

800

9,000
8,000
7,000
6,000
5,000
3,000
2,000

2012

2013

2014

2015

2016

2017

2018

5.00

11,000

4,000

400
300
200
100
0

5.50

1,000
0

4.00

Cal Condensate Rate (bbl/d)

12,000

3.50
3.00
2.50
2.00

1.50
1.00
0.50
0.00

Legend

History Gas Rate
History Pressure
History Condensate Rate
Match Pressure
Forecast 1 Gas Rate
Forecast 1 Condensate
Forecast 1 Pressure

900
700
600
500
400

10,000
9,000
8,000
7,000
6,000
5,000
4,000

300

3,000

200

2,000

100
0

12,000

11,000

Pressure (psi(a))

Cal Condensate Rate (bbl/d)

Legend

History Gas Rate
History Pressure
History Condensate Rate
Match Pressure
Forecast 1 Gas Rate
Forecast 1 Condensate
Forecast 1 Pressure

Pressure (psi(a))

Cal Gas Rate (MMcf/d)

1,300
1,200
1,100
1,000
900
800
700
600
500

Cal Gas Rate (MMcf/d)

1,000
2012

2013

2014

2015

2016

2017

2018

JANUARY 2015 123

American Oil and Gas Reporter - January 2015

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