Research Journal of Applied Sciences, Engineering and Technology 4(21): 4265-4274, 2012
ISSN: 2040-7467
© Maxwell Scientific Organization, 2012
Submitted: January 12, 2012
Accepted: March 06, 2012
Published: November 01, 2012
Forecasting CBM Production of Mukah Balingian Coalfield, Sarawak, Malaysia
Sonny Irawan, Prashanth Nair and Saleem Qadir Tunio
Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia
Abstract: Coal-Bed Methane (CBM) or coal-bed gas is a form of natural gas extracted from coal beds. The
term refers to methane adsorbed into the solid matrix of the coal. In order to understand the performance of a
CBM reservoir, we need to know the Original Gas in Place, Production Rates and also Recovery Factor. This
is mainly on creating a Microsoft Excel ® 2007 with the help of Visual Basic for Application (VBA) based
CBM forecast tool. Field data from Mukah-Balingian Coalfield Sarawak is analyzed and forecasted. Original
Gas in Place is calculated by multiplying the mass of the coal with the initial gas content of the coal bed.
Following from the generated Relative Permeability data, production rates for both water and gas calculated
over a specific time range. During the whole production, an abandonment condition which is mainly the
pressure will be set by the engineers. Using this abandonment pressure, we can calculate the recovery factor.
Using constant values of Langmuir Volume of 714.29 scf/ton, Langmuir Pressure of 1024.5 psia and reference
initial pressure of 2000 psia; flowing pressure of 100 psia which is also the abandonment pressure, various
range of skin, permeability, initial gas content as well as porosity tested to predict the field performance. Using
the range of initial gas content of 86.286-173.36 scf/ton; range of permeability of 1.01e-6 mD to 1010 mD;
porosity, with a range of 0.0001 to 0.5%; Skin ranged from-5 to 4, CBM production is forecasted for the range
of 5 years.
Keywords: Coal-Bed Methane (CBM), forecasting, mukah balingian coalfield
INTRODUCTION
Coal-bed methane (CBM) or coal-bed gas is a form
of natural gas extracted from coal beds. The term refers to
methane adsorbed into the solid matrix of the coal.
Production from Coal-bed Methane, which is the gas
desorption from coal, using Langmuir Isotherm ,Gas
content vs. Pressure plot, as shown Fig. 1, from the initial
pressure, reservoir will constantly be depressurized due to
the water production. During this period, process called as
“Dewatering” occurs. Once desorption point has been
passed, gas will start to desorbs from the surface of the
coal in matrix into the cleats and will be produced from
the well in the form of mixture with water. Since two
phases of fluid are flowing following initially initial single
phase flow, relative permeability will change with time to
each of the phase.
In order to understand the performance of a CBM
reservoir, we need to know the Original Gas in Place
which helps the Reservoir Engineer to estimate the
deliverability of a known reservoir. It is the amount of gas
in the reservoir before any production begins. Production
Rates is in need in order to keep track of the production of
the reservoir. Based on the abandonment condition,
recovery factor can be calculated. Recovery factor of
CBM reservoir is the percentage of gas that can be
produced from the reservoir. A numerical reservoir
simulator is the best to predict a CBM reservoir’s
production by integrating various conditions and
parameters of the CBM reservoir (Aminian et al.,
2004).Therefore, the study is mainly on creating a
Microsoft Excel ® 2007 based CBM forecast tool. For the
user interface, Visual Basic for Application (VBA) is
used. Using this software, field data from MukahBalingian Coalfield, Sarawak Malaysia is used to forecast
its production. Due to direct measurements and low-well
density, there will always be scarcities in data such as
production rate (Clarkson et al., 2007). Since the field is
still new and has not produce, general data from coal
properties is recorded and used for forecasting.
In order to handle any risk due to a CBM Project, one
must know the inter-dependence of each parameters
involved and their importance in CBM production
(Roadifer et al., 2003). To achieve this goal, one has to
analyze (Saulsberry et al., 1996):
C
Relative permeability relationship is used to measure
the flow in the cleats as gas and water are produced
at the same time. Two main relative permeability
relationships can be used:
B
Fekete (2012) represents Corey:
k rg
k rgo
 S g  S gc 

 
 1  S wc  S gc 
ng
, S g  S gc
(1)
Corresponding Author: Saleem Qadir Tunio, Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia
4265
650
600 Initial pressure
550
500
450
400
350
300
250
200
150
100
50
0
Under-saturation
Initial gas content
Critical desorption pressure
[saturated]
Dewatering (single-phase)
3000
2600
2200
1800
1400
1000
600
Gas production (tow-phrase)
200
Gas content, scf/ton
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Reservoir pressure, psi (a)
Fig. 1: Langmuir isotherm
 S  S wc 
k rw

 w
k rwo  1  S wc 
B
nw
, S g  1  S wc 
Gci 
(2)
C
Fekete (2012) represents Honarpour:
S  S 
 S
k  0.035388
 0.010874 
1  S 
1 S
 0.56556S  S  S 
w
wc
w
rw
wc


wc 
C
2 ,9
(3)
3, 6
w
w
wc
 S g  S gc 


k rg  11072
.
 1  S wc 
2
Sg  Sg
(4)
S wi [1  cw ( Pi  P)] 
Sw 
1  c ( P  P)
f
C
(5)
i
Bulk density of coal is measured from the lab core
analysis. Bulk density is usually measured in gram
per cubic centimeter. It will be used to calculate the
Original Gas In Place of the Coalbed. In order to
calculate Original Gas-In-Place (OGIP), following is
the calculation used in the forecasting tool using
initial gas content (Gci) and Initial Reservoir Pressure
(Pi):
OGIP  Ahb Gci
(6)
VL P
PL  P
(8)
Using the Langmuir Isotherm, with the known
aband onment pressure and gas content according
to it:
5,615We  BwWp
i Ah
(7)
Porosity of the coal is also measured during the core
analysis. It ranges from 0.1 to 10%. Porosity is
important to calculate the production rates.
In order to understand the methane gas production
from a coalbed methane reservoir, one has to analyze
the Langmuir Isotherm Curve. Langmuir Isotherm
assumes that gas adsorbs to the coal surface and
covers the as a single layer of gas (King, 1990).
Nearly all of the gas stored by adsorption coal exists
in a condensed, near liquid state. At low pressures,
this dense state allows greater volumes to be stored
by sorption than is possible by compression.
Langmuir Isotherm adsorption derives as:
V ( P) 
Water saturation for the coalbed methane equation is
defined as:
VL * Pi
PL  PI
 Gci  GC @abd 
Recov eryFactor , RF (%)  
 *100% (9)
Gci


A few assumptions are taken into consideration when
preparing the simulator for convenient calculations (Xiao
et al., 2003):
C
C
C
4266
Coalbed contains two-phase (gas and water)
Temperature remains constant
Gas volume desorbed from the coal surface is
estimated from the available Sorption Isotherm
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Fig. 2: Flow chart of basic calculation
Fig. 3: Pressure drop calculation
C
C
C
Gas is not soluble in water
Gas transport through the coal matrix system is a
diffusion process, while gas and water flow to the
wellbore via the cleat network obey Darcy’s Law
Porosity in coal micropore and macropore systems is
unchanged with pressure
METHODOLOGY
In order to create the forecast tool, the equations is
been set into the visual basic for application. There are
few work-flows that the forecasting tool adheres to. There
are three main calculations involved in creating CBM
4267
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Fig. 4: Flow chart to calculate based on gas/water constraint
Forecast Tool. They are the Basic calculations, Pressure
drop calculation and Gas/Water Constraint. All of these
calculations are related to each other in predicting the
performance of a known gas reservoir
Core calculation flow chart (Fig. 2): CBM Forecast
Tool controls the pressure during calculation. As pressure
drops from Pn-1 to Pn, fluid properties is calculated using
Pn. These properties are such as Gas Formation Volume
Factor (Bg), Gas compressibility factor (Z) and also Gas
density (:g). We also can calculate the current cleat
volume using its compressibility. Using the properties
calculated, we can calculate the volume of water in cleats
using the Water Initially in Place (WIIP) together with gas
volume in cleats. Both of these add up to give total fluid
volume in cleats and they are compared to available pore
volume to evaluate production. These properties also will
be used to calculate ratio of gas to water and water to gas.
Before calculation, user also specifies whether there
is matrix shrinkage and cleat expansion effect in the
reservoir. If these are present, permeability and porosity
are influenced and a new permeability and porosity needs
to be calculated. Using permeability, with or without the
matrix shrinkage, gas and water rates are calculated with
the help of relative permeability. These rates used are
used to find rate ratios to check calculations. Total
volume time with the ratio will give the volume of gas
and water need to be produced at given pressure
difference. With this, we get cumulative gas and water
production.
Using cumulative water production, relative
permeability for the next pressure step is calculated using
the water saturation remaining in the cleat after
production. This continues with the rates ratio for the next
pressure step. With the current water and gas production,
time for both gas and water can be calculated by dividing
the cumulative production by the rates subsequently. If
the calculation steps were followed accurately, time
obtained from gas and water is the same. This is another
test of analytical solutions. Once this achieved, CBM
Forecaster proceeds to next pressure step.
Pressure drop calculation (Fig. 3): Before beginning a
run, user has to key in a value for pressure difference.
This is due to the fact that our core calculation controls
pressure. From Pn-1 to Pn, pressure drop will be the one set
by the user. This will be the same until the pressure
reaches the desorption pressure. Once desorption pressure
is reached, pressure need to be controlled. An
uncontrolled pressure drop, will give a big amount of gas
desorbed into the cleats of the CBM. The will cause
pressure rebound as the gas desorbed may be more than
the cleat size. This is mainly because the excessive gas
creates pressure and the reduced pressure initially will rebounce high again.
To achieve the goal of controlling the pressure, CBM
Forecaster controls the gas desorbs into the cleat to be
maximum of 1% of the cleat volume. Using the Langmuir
isotherm curve, we calculate the pressure difference
needed to get the value of 1% of cleat volume to produce
the same amount of gas desorbed. The step will repeat in
every subsequent pressure step.
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Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Tools and equipment: In this project, computers are the
major tool used. Simulation is done using Microsoft
Excel® 2007 and with the help of VBA for the interface.
Commercial software is used for comparison purpose
which is the Fekete (2010) CBM by FEKETE Softwares.
Og (Msc/day)
600
Recovery Factor
Peak Water Rate
Ultimate Recovery of Water
Initial Gas Rate
Peak Gas Rate
Time to Peak
Original Gas In Place (OGIP)
Ultimate Recovery of Gas
500
400
300
200
100
0
0
500
1000
1500
2000
Days on streem
2500
3000
Fig. 5: Gas rate comparison
600
Commercial tool
CBM fore caste tool
500
400
300
200
100
0
0
500
1000
1500
2000
Days on streem
2500
3000
Fig. 6: Water rate comparison
Commercial tool
CBM fore caste tool
45000000
40000000
Cum Gas prod (scf)
CBM forecast tool: Based on the equations, a Microsoft
Excel 2007® and Visual Basic for Application (VBA)
based Coal Bed Methane production forecasting tool is
created. This forecasting tool is able to generate data for
the user such as:
35000000
30000000
25000000
20000000
15000000
10000000
5000000
0
0
500
1000
1500
2000
Days on streem
2500
3000
Fig. 7: Cumulative gas production comparison
Commercial tool
CBM fore caste tool
35000
Cum water prod (bbls)
C
C
C
C
C
C
C
C
Commercial tool
CBM fore caste tool
700
Ow (bbl/day)
Gas/water constraint (Fig. 4): For water rate constraint,
in order to calculate the required Well-flow Pressure
(Pwf) we need to back calculate the water rate equation
(Qw) using the constraint values. This is simpler than gas
rate constraint. For gas rate constraint, it is impossible to
back-calculate as easy as water rate. As we can see from
the equation of gas rate (Qg), there is the need to calculate
m (p) which stands for a known pressure divides with the
gas properties related which is gas viscosity (:) and gas
compressibility factor (Z). It is hard to calculate the
properties when Pwf is not known initially. Therefore,
iteration is needed. A range of Pwf will be tested in the
gas rate equation. For a given range of Pwf, iteration
within the range of uncertainty is becoming smaller. Pwf
within the range will be tested to calculate gas rate. This
range is between the current reservoir pressure and initial
Pwf. Using iterations, a new Pwf will be tested until gas
rate difference to the constraint is about 0.001%. Once
both Pwf obtained, it will be compared. Highest Pwf will
be used to recalculate gas rate and water rate and the
related properties.
Test is conducted to ensure the validity of the results
obtained from the forecast tool. Data from Table 1 is used
Table 1: Data used to CBM forecast tool with commercial tool
Data type
Value
Data type
Value
Porosity, n
0.65%
VL
14.7 cm3/g
PL
2050 kPa
Ash content, a
20%
Pi
4000 kPa
Moisture content, w
2.74%
Permeability, k
100 mD
Gci
7 cm3/g
Area
12.14 ha
Skin
10
0.09 m
Thickness, h
22 m
Wellbore radius, rw
Abandonment pressure 680 kPa
Bulk density,
1.65 g/cm3
Dbulk,
P abd
Temperature, T
34ºC
Pwf
680 kPa
30000
25000
20000
15000
10000
5000
0
0
500
1000
1500
2000
Days on streem
2500
3000
Fig. 8: Cumulative water production comparison
for comparison purpose to test the results with the
commercially available software. Comparison plot of
4269
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
2000
1800
1600
1200
1000
800
600
400
0
1400
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
50000
45000
40000
35000
30000
25000
20000
15000
10000
5000
0
200
Ow (bbl/day)
714.29
1024.5
2000
227.564
100
2.7
15
129.823
216215
29.69
1.4
98
0.005
2.09E-05
0.000138
0
505
1
1.02
0.364
0.1
Days on streem
Fig. 10: Forecasted water rates for the given range of initial
gas content
forecasted values of production gas rate,production water
rate, cumulative gas production and cumulative water
production are shown in Fig. 5, 6, 7 and 8, respectively.
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
7 E+09
Cum Gas prod (scf)
Table 2: Reference input data for forecasting
Input data (reference values)
Lagmuir volume (VL)
scf/ton
Langmuir pressure (PL)
psia
Initial pressure (Pi)
psia
Desorption pressure
psia
Bottomhole flowing pressure (Pwf)
psia
Ash content (a)
%
Moisture (w)
%
Initial gas content (Gci)
scf/ton
Drainage area (A)
acres
Net pay (h)
ft
Bulk density (rho)
g/cm3
Reservoir temperature (T)
Farenheit
Fracture porosity (ø)
%
Water compressibil ity (Cw)
psia-1
Formation compressibility (Cf)
psia-1
Skin
Permeability (k)
md
Initial water saturation (Swi)
Bw
rbbl/stb
cp
MiuWater (:)
Wellbore radius-rw
ft
6 E+09
5 E+09
4 E+09
3 E+09
2 E+09
1 E+09
3000
2000
1000
2000
1800
1600
1400
1200
1000
800
600
400
0
0
2000
1800
1600
1400
1200
1000
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
12000000
10000000
8000000
6000000
4000000
2000000
2000
1800
1600
1400
1200
1000
800
600
400
0
200
0
Fig. 12: Forecasted cumulative water production for the given
range of initial gas content
4000
200
800
Fig. 11: Forecasted cumulative gas production for the given
range of initial gas content
Days on streem
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
5000
Og (Mscf/day)
600
Days on streem
Range of initial gas content (Table 3): For this, range of
Initial Gas Content from 86.286 to173.36 scf/ton is used
for forecasting. Forecasted results are shown in
6000
400
0
RESULTS AND DISCUSSION
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
200
0
Cum water prod (bbls)
Forecasting mukah-balingian coalfield data (Table 2):
Based on the preliminary studies data of Mukah-Balingian
Coalfield, a reference input data is prepared for
forecasting. Certain values are taken from PERTAMINA
data for the fields in Sumatra. Using this data, a set of
range of Skin, Permeability, Porosity as well Initial Gas
Content is forecasted to get the Peak Gas Rate, Ultimate
Recovery Gas, Ultimate Recovery Water, Recovery
Factor and Water Cut. This forecasting was done for the
duration of 5 years with the abandonment pressure of 100
psia and abandonment gas rate of 0.1 Mscf/day
Days on streem
Fig. 9: Forecasted gas rates for the given range of initial gas
content
Fig. 9 to 12. Data from Mukah-Balingian Coalfield shows
that the range of Initial gas content from the methane
content estimation method is given from 86.286-173.36
scf/ton. Using the Forecast Tool, 10 scenario was
forecasted given the initial gas content was within this
range. The scenario with the highest Initial Gas Content
(Gci = 173.36 scf/ton) gives the highest value of Ultimate
Gas Recovery (6.23 Bscf) and highest Peak Gas Rate
(5714.232 Mscf/day). The scenario with the lowest Initial
Gas content gives the opposite.
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Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Table 3: Range of initial gas content values used for forecasting
Initial gas content, gci (scf/ton)
Peak gas rate, Mscf/day
Gci = 86.286
147.329
Gci = 90
217.025
Gci = 100
469.082
Gci = 110
817.473
Gci = 120
1266.905
Gci = 130
1823.922
Gci = 140
2496.863
Gci = 150
3294.869
Gci = 160
4230.031
Gci = 173.36
5714.232
UR (gas), Bscf
0.092747
0.147067
0.362642
0.689278
1.139428
1.726104
2.464033
3.367379
4.457539
6.237660
UR (water), Bscf
0.007851
0.008137
0.008720
0.009138
0.009458
0.009710
0.009916
0.010087
0.010232
0.010394
Recovery factor (RF), %
26.384
29.421
36.479
42.254
47.066
51.138
54.628
57.653
60.300
63.359
Table 4: Range of permeability values used for forecasting
Permeability, k (mD)
Peak gas rate, Mscf/day
k = 0.000001013
0
k = 0.0000101
0
k = 0.000101
0
k = 0.00101
0
k = 0.0101
0
k = 0.101
0
k = 1.01
0.00000
k = 10.1
0.00000
k = 101
49.11082
k = 1010
5141.70930
UR (gas), Bscf
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.02036937
5.81345641
UR (water), Bscf
0.00
0.00
0.00
0.00
0.00
0.00007561
0.00077500
0.00327012
0.00666097
0.01065260
Recovery factor (RF), %
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
5000
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
7E+09
Cum gas prod (scf)
4000
3000
2000
6E+09
5E+09
4E+09
2E+09
1000
1E+09
Fig. 13: Forecasted gas rates for the given range of permeability
Cum water prod (bbls)
2000
1800
1600
1400
10000000
8000000
6000000
4000000
2000000
2000
Fig. 14: Forecasted water rates for the given range of
permeability
Range of permeability (Table 4): For this, range of
Permeability from 1.01e-6 to1010 mD is used for
forecasting.
Forecasted results are shown in
Fig. 13 to Fig. 16. Absolute permeability also effects the
production of methane from coal. The range of
2000
1800
1600
1400
1200
1000
800
600
0
400
0
Days on streem
200
1800
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
12000000
1600
1400
1200
1000
800
600
400
200
0
1200
Fig. 15: Forecasted cumulative gas production for the given
range of “k”
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
1000
Days on streem
Days on streem
10000
9000
8000
7000
6000
5000
4000
3000
2000
1000
0
800
600
0
2000
1800
1600
1400
1200
1000
800
600
400
200
0
400
0
0
Ow. (bbl/day)
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
3E+09
200
Og. (Mscf/day)
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
6000
Days on streem
Fig. 16: Forecasted cumulative water production for the given
range of “k”
permeability of coal from a 1.01e-6 to 1010 mD (Shugang
and Derek, 2010) is tested on the forecast tool. The higher
the permeability, the higher the methane gas production
whereby permeability of 1010 mD gives highest Peak Gas
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Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Table 5: Range of porosity values used for forecasting
Porosity, ø
Peak gas rate, Mscf/day
ø = 0.0001
4208.91824
ø = 0.0005
3942.04975
ø = 0.001
3449.66034
ø = 0.002
2821.08943
ø = 0.004
2070.84373
ø = 0.005
1812.84218
ø = 0.01
1024.97547
ø = 0.05
8.01829
ø = 0.1
0.00000
ø = 0.5
0.00000
UR (water), Bscf
0.00024
0.00120
0.00231
0.00436
0.00803
0.00971
0.01702
0.05213
0.08153
0.25329
2500
2000
Recovery factor (RF), %
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
51.07132
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
3.5 E+09
Cum Gas prod (scf)
Og (Mscf/day)
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
3000
UR (gas), Bscf
1.86348
5.71816
4.58065
3.32737
2.08415
1.71376
0.75914
0.00045
0.00000
0.00000
3.0 E+09
2.5 E+09
2.0 E+09
1.5 E+09
1 E+09
1500
500000000
1000
2000
1800
1600
1400
1200
1000
800
600
400
0
200
0
500
Days on streem
2000
1800
1600
1400
1200
1000
800
600
400
0
200
0
Fig. 19: Forecasted cumulative gas production for the given
range of porosity
Days on streem
Cum water prod (bbls)
50000
45000
40000
35000
30000
25000
20000
15000
10000
5000
0
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
30000000
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
25000000
20000000
15000000
10000000
5000000
2000
1800
1600
1400
1200
1000
800
600
400
Days on streem
2000
1800
1600
1400
1200
1000
800
600
0
400
0
200
0
200
Ow (bbl/day)
Fig. 17: Forecasted gas rates for the given range of porosity
Days on streem
Fig. 20: Forecasted cumulative water production for the given
range of porosity
Fig. 18: Forecasted water rates for the given range of porosity
rate (5141.71 Mscf/day) and highest Ultimate Gas
Recovery (5.831 Bscf). This permeability helps the
mobility of the gas through the fractures and to the well.
High Permeability does not affect the gas in place but it
affects the time of dewatering. Due to that, gas rate
reached peak faster and higher but decline faster too.
Range of porosity (Table 5): For this, range of Porosity
from 0.0001 to 0.5 is used for forecasting. Results of the
whole production can be seen in Fig. 17 to 20. Higher
porosity does not mean higher production. In CBM,
lowest porosity gives highest Ultimate Recovery. It is
very much needed to be noted that for Scenario 1 with the
lowest porosity of 0.0001 gives much lower Ultimate
Recovery than porosity of 0.0005. This is due to the fact
that the reservoir is still producing but the calculation
limit of the forecasting tool has been achieved. This is one
of the greatest set-back of Microsoft Excel® 2007 and
Visual Basic of Application (VBA). Porosity does not
affect the gas in place. As in coal, gas is divided to two
types which are free gas and adsorbed gas. As the porosity
decreases, the amount of free gas reduces until it’s
negligible. Reduction in porosity also indicates the
reduction of cleat volume. Thus, dewatering occurs faster
and therefore reaches higher peak gas rate of production.
The lowest porosity (ø = 0.0001) gives highest Peak gas
rate of 4208.918 Mscf/day and ultimate recovery of 5.718
Bscf with the recovery factor of 51.07 %.
4272
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
Og (Mcsf/day)
4500
4000
Recovery
factor (RF), %
51.071
51.071
51.071
51.071
51.071
51.071
51.071
51.071
51.071
51.071
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
5.0 E+09
4.5 E+09
4.0 E+09
3.5 E+09
3.0 E+09
2.5 E+09
2.0 E+09
1.5 E+09
1 E+09
500000000
0
Cum Gas prod (scf)
Table 6: Range of skin values used for forecasting
Peak gas rate,
UR (water),
Skin
Mscf/day
UR (gas), Bscf Bscf
S = -5
3982.843
4.317823
0.010431
S = -4
3313.013
3.482074
0.010266
S = -3
2800.146
2.858758
0.010112
S = -2
2397.894
2.382875
0.009969
S = -1
2075.742
2.011034
0.009834
S=0
1812.842
1.713763
0.009706
S=1
1595.727
1.473982
0.009585
S=2
1414.121
1.277711
0.009470
S=3
1260.149
1.114081
0.009359
S=4
1129.254
0.978410
0.009255
0
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
1000
Days on streem
500
1500
2000
Fig. 23: Forecasted cumulative gas production for the given
range of skin
3500
3000
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
12000000
2500
2000
10000000
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
1500
1000
8000000
500
0
6000000
0
500
1000
Days on streem
1500
2000
4000000
2000000
Fig. 21: Forecasted gas rates for the given range of skin
Scenario 1
Scenario 2
Scenario 3
Scenario 4
Scenario 5
80000
Ow (bbl/day)
70000
0
0
Scenario 6
Scenario 7
Scenario 8
Scenario 9
Scenario 10
500
1000
Days on streem
1500
2000
Fig. 24: Forecasted cumulative water production for the given
range of skin
60000
50000
C
40000
30000
C
20000
10000
0
0
500
1000
1500
Days on streem
C
2000
Fig. 22: Forecasted water rates for the given range of skin
C
Range of skin (Table 6): For this, range of Porosity from
0 to 9 is used for forecasting. This are the common skin
values expected from the CBM Production. Results are as
per shown in Fig. 21 to 24. Skin is created during the
production. Therefore, during forecasting skin = 0 is used
as the reference value. Positive skin which also damaged
well gives lower rates than the negative ones (enhanced
well). The lowest skin (S = -5) gives the highest peak gas
rate of 3982.843 Mscf/day with the Ultimate recovery of
4.318 Bscf with a recovery factor of 51.07%.
CONCLUSION AND RECOMMENDATIONS
There are certain conclusions can be made from this
study:
C
Higher permeability, faster dewatering process,
higher peak gas rate
Lower porosity, lesser free gas with higher adsorbed
gas, small cleat volume so faster dewatering process,
higher peak gas rate.
Higher initial gas content, higher adsorbed gas; with
the same dewatering process occurring gives higher
peak gas rate and more recovery.
More enhanced the well is (negative skin), the more
faster it dewaters and gives higher peak gas rate.
Using the range given, highest peak gas rate is
5714.232 Mscf/day, highest ultimate recovery value
is 6.23 Bscf and finally highest recovery rate is
63.36%.
This data gained from this study might not be the
exact production as certain parameters can only be gained
through the production of the field. These data can be
eventually used as feasibility studies for the investor in
order to decide on the investment on this particular field.
In order to increase the CBM production, we can
inject Carbon Dioxide (CO2) or Nitrogen (N2) into the
reservoir. This is called the Enhanced CBM Recovery.
Higher affinity gas means, it’s more preferable by coal to
be adsorbed into its surface. Therefore, when CO2 or N2
4273
Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012
is injected into the well, the remaining methane is
released from the coal surface and thus we could get
100% recovery from a known field. This is due to N2 and
CO2 reduces the partial pressure of methane which
encourages the methane to desorped from the surface of
coal (Shi and Durucan, 2008).
NOMENCLATURE
A
Bw
Bw
cw
cf
Gci
Gc@abd
=
=
=
=
=
=
=
GIP
h
krg
krg0
=
=
=
=
krw
krw0
=
=
kg
kw
m()
nw
=
=
=
=
ng
=
P
Pi
PL
Pwf
qg
qw
re
rw
s
Sg
Sgc
Sw
Swc
Swi
T
V (P)
VL
We
Wp
ø
:w
Db
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
=
Area (ft2)
Water formation volume factor (ft3/scf)
Water formation volume factor (bbl/STB)
Water compressibility (/psia)
Formation compressibility (/psia)
Initial gas content (scf/ton)
Gas content at Abandonment Pressure
(scf/ton)
Gas in place (scf)
Net pay (ft)
Relative permeability to gas, (fraction)
Endpoint relative permeability to gas,
(fraction)
Relative permeability to water, (fraction)
Endpoint relative permeability to water,
(fraction)
Gas effective permeability (md)
Water effective permeability (md)
Gas pseudopressure (psi2/cp)
Exponent of the water relative
permeability curve, (fraction)
Exponent of the gas relative permeability
curve, (fraction)
Pressure, (psia)
Initial reservoir pressure (psia)
Langmuir Pressure constant, (psia)
Bottomhole flowing pressure (psia)
Gas rate (MCFd)
Water rate (STB/day)
External radius of reservoir (ft)
Wellbore radius (ft)
Skin
Average gas saturation, (fraction)
Irreducible gas saturation, (fraction)
Average water saturation, (fraction)
Irreducible water saturation, (fraction)
Initial water saturation
Temperature (R)
Amount of gas at pressure P, (scf/ton)
Langmuir Volume constant, (scf)
Water encroached (bbls)
Water produced (STB)
Porosity (dimensionless)
Water viscosity (cp)
Bulk density of the coal (lb/ft3)
ACKNOWLEDGMENT
Author(s) would like to pay thanks to Universiti
Teknologi PETRONAS for supporting this research
project.
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