American Oil and Gas Reporter - May 2017 - 72

SpecialReport: Gas Compression Technology
FIGURE 2B
Gas Production Rate versus Calculated Sand-Face Pressure
(Wells G and H)
25

Gas Production Rate (MMcf/d)

20
Well G
Well H

15

10

5

0
0

1,000

2,000

3,000
4,000
5,000
6,000
Calculated Sand-Face Pressure (psi)

development, a wide variety of γ values
obtained from Eagle Ford and Haynesville
shales were applied for a range of sensitivities. The respective EUR and production forecasts associated with each design
are listed in Table 2. As γ increases, the
EUR from the well can be reduced by 36
percent. This is obviously significant to
well economics.
The effect of pressure-dependent permeability can be described using inflow
performance relationship (IPR) curve reversal behavior. The conventional assumption for constant fracture permeability
models (i.e., the pressure dependency of
permeability is not significant) is that as
flowing wellbore pressure decays, the
production rate increases. However, this
behavior can change if hydraulic fracture
permeability is impaired by significant
pressure change (effective stress). In this
case, a decrease in flowing wellbore pressure will result in a reduced flow rate.
The effect of modulus of permeability
on well performance was also investigated
using a dual-porosity/dual-permeability
model with a single hydraulically fractured
horizontal well and a compositional numerical simulator. Two reservoir models
were developed in which the matrix and
fracture permeability change as a function
of pressure related to modulus of permeability. Increasing the modulus of permeability resulted in higher matrix and
fracture compaction and permeability
72 THE AMERICAN OIL & GAS REPORTER

7,000

8,000

9,000

loss in the matrix.
Note that in this model, hydraulic
fracture conductivity was kept constant.
However, because of very low matrix
and fracture permeability (0.0001 md)
and the diffusive nature of gas transport
in the matrix, cumulative gas production
was not reduced by increasing the modulus
of permeability. This also implies that
permeability variation as a function of
reservoir pressure might not result in IPR
curve reversal.
Economic Analysis
The final step was performing economic
sensitivity analysis to understand the
impact of various flowing rates on net
present value and internal rate of return.
This required understanding the impact

of flowing at flat daily rates of 30 MMcf,
25 MMcf, 20 MMcf, and 15 MMcf, with
30 MMcf/d chosen as the maximum rate
because of equipment and facility limitations (the wells under managed pressured
drawdown are typically flowed back between 13 MMcf/d and 20 MMcf/d). The
base-case type curve was developed based
on all of the producing wells in the area
using managed pressure drawdown.
The modified hyperbolic decline curve
parameters for a base case well with a
10,000-foot lateral included a flat period
of 10.5 months at 17.143 MMcf/d and
cumulative production of 5.475 billion
cubic feet. Following that flat period, the
annual effective decline was estimated
to be 56 percent with a terminal decline
of 6 percent and an EUR of 2.8 Bcf per
1,000 foot of completed lateral.
As the initial flat rate increases from
the base case assumptions, the flat period
gets shortened to yield the same cumulative
production volume as the base case and
the same EUR of 2.8 Bcf/1,000 feet, assuming no reservoir damage caused by
flowing at higher rates. Obviously, the
higher the production rate, the higher the
NPV and IRR. In fact, when there is no
damage to the reservoir, the analysis
shows that producing at an IP of 15
MMcf/d would result in $640,000 of lost
NPV compared with the 30 MMcf/d maximum rate. This illustrates the importance
of understanding possible reservoir damage
when attempting to calculate optimal production rates.
Producing the well at a flat rate of 30
MMcf/d for six months (again, assuming
no damage to the reservoir) and yielding
the same EUR as all of the other cases
results in an NPV of $3.5 million and
IRR of 36 percent. The next task was
performing sensitivity analyses to find
out the percentage uplift in the type curve

TABLE 2
Pressure-Dependent Permeability Modulus and EUR
Pressure-dependent
perm modulus
No pressure-dependent perm
(Base case)
2.00E-04

EUR
(MMcf)

EUR
(Bcf/1,000')

EUR % reduction
from base case

21,076

3.01

0%

19,740

2.82

6.34%

2.50E-04

18,921

2.70

10.22%

3.00E-04

17,942

2.56

14.87%

3.50E-04

16,856

2.41

20.02%

4.00E-04

15,720

2.25

25.41%

4.50E-04

14,583

2.08

30.81%

5.00E-04

13,484

1.93

36.02%



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