forecasting cbm production of mukah balingian coalfield.pdf

8/10/2019 Forecasting CBM Production of Mukah Balingian Coalfield.pdf

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Research Journal of Applied Sciences, Engineering and Technology 4(21): 4265-4274, 2012ISSN: 2040-7467 Maxwell Scientific Organization, 2012Submitted: January 12, 2012 Accepted: March 06, 2012 Published: November 01, 2012

Corresponding Author: Saleem Qadir Tunio, Petroleum Engineering Department, Universiti Teknologi PETRONAS, Malaysia

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Forecasting CBM Production of Mukah Balingian Coalfield, Sarawak, Malaysia

Sonny Irawan, Prashanth Nair and Saleem Qadir TunioPetroleum 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. Theterm refers to methane adsorbed into the solid matrix of the coal. In order to understand the performance of aCBM reservoir, we need to know the Original Gas in Place, Production Rates and also Recovery Factor. Thisis 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. OriginalGas 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 referenceinitial pressure of 2000 psia; flowing pressure of 100 psia which is also the abandonment pressure, variousrange of skin, permeability, initial gas content as well as porosity tested to predict the field performance. Usingthe 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 rangeof 5 years.

Keywords: Coal-Bed Methane (CBM), forecasting, mukah balingian coalfield

INTRODUCTION

Coal-bed methane (CBM) or coal-bed gas is a formof natural gas extracted from coal beds. The term refers tomethane adsorbed into the solid matrix of the coal.Production from Coal-bed Methane, which is the gasdesorption from coal, using Langmuir Isotherm ,Gascontent vs. Pressure plot, as shown Fig. 1, from the initial

pressure, reservoir will constantly be depressurized due tothe water production. During this period, process called asDewatering occurs. Once desorption point has been

passed, gas will start to desorbs from the surface of thecoal in matrix into the cleats and will be produced fromthe 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 toeach of the phase.

In order to understand the performance of a CBMreservoir, we need to know the Original Gas in Placewhich helps the Reservoir Engineer to estimate thedeliverability of a known reservoir. It is the amount of gasin the reservoir before any production begins. ProductionRates 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 reservoirs production by integrating various conditions and parameters of the CBM reservoir (Aminian et al .,2004).Therefore, the study is mainly on creating aMicrosoft Excel 2007 based CBM forecast tool. For theuser interface, Visual Basic for Application (VBA) isused. Using this software, field data from Mukah-Balingian Coalfield, Sarawak Malaysia is used to forecastits production. Due to direct measurements and low-welldensity, there will always be scarcities in data such as

production rate (Clarkson et al ., 2007). Since the field isstill 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 parametersinvolved and their importance in CBM production(Roadifer et al ., 2003). To achieve this goal, one has toanalyze (Saulsberry et al ., 1996):

C Relative permeability relationship is used to measurethe flow in the cleats as gas and water are produced at the same time. Two main relative permeabilityrelationships can be used:

B Fekete (2012) represents Corey:

(1)k

k

S S

S S S S

rg

rgo

g gc

wc gc

ng

g gc

1,


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Res. J. Appl. Sci. Eng. Technol., 4(21): 4265-4274, 2012

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050

100150200250300350400

450500550600650

G a s c o n

t e n

t , s c

f / t o n

2 0 0

6 0 0

2 2 0 0

2 6 0 0

1 0 0 0

1 4 0 0

1 8 0 0

3 0 0 0

Reservoir pressure, psi (a)

Critical desorption pressure[saturated]

Under-saturation

Initial gas content

Dewatering (single-phase)

Gas production (tow-phrase)

Initial pressure

Fig. 1: Langmuir isotherm

, (2)k k

S S S

rw

rwo

w wc

wc

nw

1 S S g wc 1

B Fekete (2012) represents Honarpour:

(3)

k S S

S

S

S

S S S

rw

w wc

wc

w

wc

w w wc

0 0353881

0 0108741

056556

2 9

3 6

. .

.

,

,

(4)k S S

S rgg gc

wcS g Sg

11072 1

2

.

Water saturation for the coalbed methane equation isdefined as:

(5)

S

S c P PW B Wp

Ah

c P Pw

wi w ie w

i

f i

[ ( )],

( )

15 615

1

C Bulk density of coal is measured from the lab coreanalysis. Bulk density is usually measured in gram

per cubic centimeter. It will be used to calculate theOriginal Gas In Place of the Coalbed. In order tocalculate Original Gas-In-Place (OGIP), following isthe calculation used in the forecasting tool usinginitial gas content (G ci) and Initial Reservoir Pressure(P i):

(6)OGIP Ah Gb ci

(7)G V P

P Pci L i

L I

*

C Porosity of the coal is also measured during the coreanalysis. It ranges from 0.1 to 10%. Porosity isimportant to calculate the production rates.

C In order to understand the methane gas productionfrom a coalbed methane reservoir, one has to analyzethe Langmuir Isotherm Curve. Langmuir Isothermassumes 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 existsin 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:

(8)V PV P

P P L

L

( )

Using the Langmuir Isotherm, with the knownaband onment pressure and gas content accordingto it:

*100% (9)Recov , (%) @eryFactor RF G G

Gci C abd

ci

A few assumptions are taken into consideration when preparing the simulator for convenient calculations (Xiaoet al ., 2003):

C Coalbed contains two-phase (gas and water)C Temperature remains constantC Gas volume desorbed from the coal surface is

estimated from the available Sorption Isotherm


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Fig. 4: Flow chart to calculate based on gas/water constraint

Forecast Tool. They are the Basic calculations, Pressuredrop calculation and Gas/Water Constraint. All of thesecalculations are related to each other in predicting the

performance of a known gas reservoir

Core calculation flow chart (Fig. 2): CBM ForecastTool controls the pressure during calculation. As pressuredrops from P n-1 to P n, fluid properties is calculated usingPn. These properties are such as Gas Formation VolumeFactor (Bg), Gas compressibility factor (Z) and also Gasdensity ( : g). We also can calculate the current cleatvolume using its compressibility. Using the propertiescalculated, we can calculate the volume of water in cleatsusing the Water Initially in Place (WIIP) together with gasvolume in cleats. Both of these add up to give total fluid volume in cleats and they are compared to available porevolume 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 thereservoir. If these are present, permeability and porosityare influenced and a new permeability and porosity needsto be calculated. Using permeability, with or without thematrix shrinkage, gas and water rates are calculated withthe help of relative permeability. These rates used areused to find rate ratios to check calculations. Totalvolume time with the ratio will give the volume of gasand water need to be produced at given pressuredifference. 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 dividingthe cumulative production by the rates subsequently. If the calculation steps were followed accurately, timeobtained from gas and water is the same. This is another test of analytical solutions. Once this achieved, CBMForecaster proceeds to next pressure step.

Pressure drop calculation (Fig. 3): Before beginning arun, user has to key in a value for pressure difference.This is due to the fact that our core calculation controls

pressure. From P n-1 to P n, pressure drop will be the one set by the user. This will be the same until the pressurereaches the desorption pressure. Once desorption pressureis reached, pressure need to be controlled. Anuncontrolled pressure drop, will give a big amount of gasdesorbed into the cleats of the CBM. The will cause

pressure rebound as the gas desorbed may be more thanthe cleat size. This is mainly because the excessive gascreates pressure and the reduced pressure initially will re-

bounce high again.To achieve the goal of controlling the pressure, CBM

Forecaster controls the gas desorbs into the cleat to bemaximum of 1% of the cleat volume. Using the Langmuir isotherm curve, we calculate the pressure differenceneeded to get the value of 1% of cleat volume to producethe same amount of gas desorbed. The step will repeat inevery subsequent pressure step.


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700

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0 0 500 1000 1500 2000 2500 3000

O g

( M s c /

d a y )

Days on streem

Commercial toolCBM fore caste tool

600

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100

0 0 500 1000 1500 2000 2500 3000

O w

( b b l / d a y

)

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5000000

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( s c f

)

Days on streem


1000000015000000

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0 0 500 1000 1500 2000 2500 3000

C u m w a t e r p r o d

( b b l s )

Days on streem


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15000 20000

25000

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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 gasrate constraint. For gas rate constraint, it is impossible to

back-calculate as easy as water rate. As we can see fromthe equation of gas rate (Q g), there is the need to calculatem (p) which stands for a known pressure divides with thegas properties related which is gas viscosity ( : ) and gascompressibility 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 thegas rate equation. For a given range of Pwf, iterationwithin the range of uncertainty is becoming smaller. Pwf within the range will be tested to calculate gas rate. Thisrange is between the current reservoir pressure and initialPwf. Using iterations, a new Pwf will be tested until gasrate 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 therelated properties.

Tools and equipment: In this project, computers are themajor tool used. Simulation is done using MicrosoftExcel 2007 and with the help of VBA for the interface.Commercial software is used for comparison purposewhich is the Fekete (2010) CBM by FEKETE Softwares.

CBM forecast tool: Based on the equations, a MicrosoftExcel 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:

C Recovery FactorC Peak Water RateC Ultimate Recovery of WaterC Initial Gas RateC Peak Gas RateC Time to Peak C Original Gas In Place (OGIP)C Ultimate Recovery of Gas

Test is conducted to ensure the validity of the resultsobtained from the forecast tool. Data from Table 1 is used

Table 1: Data used to CBM forecast tool with commercial toolData type Value Data type ValueVL 14.7 cm 3/g Porosity, n 0.65%PL 2050 kPa Ash content, a 20%Pi 4000 kPa Moisture content, w 2.74%Gci 7 cm 3/g Permeability, k 100 mDArea 12.14 ha Skin 10Thickness, h 22 m Wellbore radius, r w 0.09 mBulk density, 1.65 g/cm 3 Abandonment pressure 680 kPaD bulk , P abd Temperature, T 34C P wf 680 kPa

Fig. 5: Gas rate comparison

Fig. 6: Water rate comparison

Fig. 7: Cumulative gas production comparison

Fig. 8: Cumulative water production comparison

for comparison purpose to test the results with thecommercially available software. Comparison plot of


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6000

5000

4000

3000

2000

1000

0

0

2 0 0

O g

( M s c

f / d a y )

Days on streem

Scenario 1Scenario 2Scenario 3Scenario 4Scenario 5


4 0 0

6 0 0

8 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0

0 0

2 0 0

O w

( b b l / d a y

)

Days on streem

4 0 0

8 0 0

6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



5000100001500020000250003000035000400004500050000

0 0 2 0

0

C u

G a s p r o d

( s c f

)

Days on streem

4 0 0

8 0 0

6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



1 E+09

2 E+09

3 E+09

4 E+095 E+09

6 E+09

7 E+09

0 0

2 0 0

C u m w a e r p r o d

( b b l )

Days on streem 4 0 0

8 0 0

6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



2000000

4000000

6000000

8000000

10000000

12000000

Table 2: Reference input data for forecastingInput data (reference values)Lagmuir volume (VL) scf/ton 714.29Langmuir pressure (PL) psia 1024.5Initial pressure (Pi) psia 2000Desorption pressure psia 227.564Bottomhole flowing pressure (Pwf) psia 100Ash content (a) % 2.7Moisture (w) % 15Initial gas content (Gci) scf/ton 129.823Drainage area (A) acres 216215

Net pay (h) ft 29.69Bulk density (rho) g/cm 3 1.4Reservoir temperature (T) Farenheit 98Fracture porosity () % 0.005Water compressibil ity (Cw) psia -1 2.09E-05Formation compressibility (Cf) psia -1 0.000138Skin 0Permeability (k) md 505Initial water saturation (Swi) 1Bw rbbl/stb 1.02MiuWater ( : ) cp 0.364

Wellbore radius-rw ft 0.1

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.

Forecasting mukah-balingian coalfield data (Table 2):Based on the preliminary studies data of Mukah-BalingianCoalfield, a reference input data is prepared for forecasting. Certain values are taken from PERTAMINAdata for the fields in Sumatra. Using this data, a set of range of Skin, Permeability, Porosity as well Initial GasContent is forecasted to get the Peak Gas Rate, UltimateRecovery Gas, Ultimate Recovery Water, RecoveryFactor and Water Cut. This forecasting was done for theduration of 5 years with the abandonment pressure of 100

psia and abandonment gas rate of 0.1 Mscf/day

RESULTS AND DISCUSSION

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

Fig. 9: Forecasted gas rates for the given range of initial gascontent

Fig. 10: Forecasted water rates for the given range of initialgas content

Fig. 11: Forecasted cumulative gas production for the givenrange of initial gas content

Fig. 12: Forecasted cumulative water production for the givenrange of initial gas content

Fig. 9 to 12. Data from Mukah-Balingian Coalfield showsthat the range of Initial gas content from the methanecontent estimation method is given from 86.286-173.36scf/ton. Using the Forecast Tool, 10 scenario wasforecasted given the initial gas content was within thisrange. The scenario with the highest Initial Gas Content(Gci = 173.36 scf/ton) gives the highest value of UltimateGas Recovery (6.23 Bscf) and highest Peak Gas Rate(5714.232 Mscf/day). The scenario with the lowest Init ialGas content gives the opposite.


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0 0

2 0 0

O g

( M c f

/ d a y

)

Days on streem

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0 0

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O w

( b b l / d a y

)

Days on streem 4 0 0

8 0 0

6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



5000100001500020000250003000035000400004500050000

0 0

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C u m

G a s p r o d

( s c f

)

Days on streem

4 0 0

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6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



500000000

1 E+09

1.5 E+09

2.0 E+09

2.5 E+09

3.0 E+09

3.5 E+09

0 0

2 0 0

C u m w a t e r p r o d

( b b l s )

Days on streem

4 0 0

8 0 0

6 0 0

1 0 0 0

1 2 0 0

1 4 0 0

1 6 0 0

1 8 0 0

2 0 0 0



5000000

10000000

15000000

20000000

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30000000

Table 5: Range of porosity values used for forecastingPorosity, Peak gas rate, Mscf/day UR (gas), Bscf UR (water), Bscf Recovery factor (RF), % = 0.0001 4208.91824 1.86348 0.00024 51.07132 = 0.0005 3942.04975 5.71816 0.00120 51.07132 = 0.001 3449.66034 4.58065 0.00231 51.07132 = 0.002 2821.08943 3.32737 0.00436 51.07132 = 0.004 2070.84373 2.08415 0.00803 51.07132 = 0.005 1812.84218 1.71376 0.00971 51.07132 = 0.01 1024.97547 0.75914 0.01702 51.07132 = 0.05 8.01829 0.00045 0.05213 51.07132 = 0.1 0.00000 0.00000 0.08153 51.07132 = 0.5 0.00000 0.00000 0.25329 51.07132

Fig. 17: Forecasted gas rates 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 GasRecovery (5.831 Bscf). This permeability helps themobility of the gas through the fractures and to the well.

High Permeability does not affect the gas in place but itaffects the time of dewatering. Due to that, gas ratereached peak faster and higher but decline faster too.

Range of porosity (Table 5): For this, range of Porosityfrom 0.0001 to 0.5 is used for forecasting. Results of thewhole 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 isvery much needed to be noted that for Scenario 1 with thelowest porosity of 0.0001 gives much lower Ultimate

Fig. 19: Forecasted cumulative gas production for the givenrange of porosity

Fig. 20: Forecasted cumulative water production for the givenrange of porosity

Recovery than porosity of 0.0005. This is due to the factthat the reservoir is still producing but the calculationlimit of the forecasting tool has been achieved. This is oneof the greatest set-back of Microsoft Excel 2007 and Visual Basic of Application (VBA). Porosity does notaffect the gas in place. As in coal, gas is divided to twotypes which are free gas and adsorbed gas. As the porositydecreases, the amount of free gas reduces until itsnegligible. Reduction in porosity also indicates thereduction of cleat volume. Thus, dewatering occurs faster and therefore reaches higher peak gas rate of production.The lowest porosity ( = 0.0001) gives highest Peak gasrate of 4208.918 Mscf/day and ultimate recovery of 5.718Bscf with the recovery factor of 51.07 %.


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( M c s

f / d a y )

Days on streem



500

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( b b l / d a y

)

Days on streem500 1000 1500 2000



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0 0

Days on streem



500 1000 1500 2000

C u m

G a s p r o d

( s c f

)

5000000001 E+09

1.5 E+092.0 E+092.5 E+093.0 E+09

3.5 E+094.0 E+094.5 E+095.0 E+09

0Days on streem



500 1000 1500 2000

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10000000

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Table 6: Range of skin values used for forecastingPeak gas rate, UR (water), Recovery

Skin Mscf/day UR (gas), Bscf Bscf factor (RF), %S = -5 3982.843 4.317823 0.010431 51.071S = -4 3313.013 3.482074 0.010266 51.071S = -3 2800.146 2.858758 0.010112 51.071S = -2 2397.894 2.382875 0.009969 51.071S = -1 2075.742 2.011034 0.009834 51.071S = 0 1812.842 1.713763 0.009706 51.071S = 1 1595.727 1.473982 0.009585 51.071S = 2 1414.121 1.277711 0.009470 51.071S = 3 1260.149 1.114081 0.009359 51.071S = 4 1129.254 0.978410 0.009255 51.071

Fig. 21: Forecasted gas rates for the given range of skin

Fig. 22: Forecasted water rates for the given range of skin

Range of skin (Table 6): For this, range of Porosity from0 to 9 is used for forecasting. This are the common skinvalues 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 gasrate 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 thisstudy:

Fig. 23: Forecasted cumulative gas production for the givenrange of skin

Fig. 24: Forecasted cumulative water production for the givenrange of skin

C Higher permeability, faster dewatering process,

higher peak gas rateC Lower porosity, lesser free gas with higher adsorbed

gas, small cleat volume so faster dewatering process,higher peak gas rate.

C Higher initial gas content, higher adsorbed gas; withthe same dewatering process occurring gives higher

peak gas rate and more recovery.C More enhanced the well is (negative skin), the more

faster it dewaters and gives higher peak gas rate.C Using the range given, highest peak gas rate is

5714.232 Mscf/day, highest ultimate recovery valueis 6.23 Bscf and finally highest recovery rate is63.36%.

This data gained from this study might not be theexact production as certain parameters can only be gained through the production of the field. These data can beeventually used as feasibility studies for the investor inorder to decide on the investment on this particular field.

In order to increase the CBM production, we caninject Carbon Dioxide (CO 2) or Nitrogen (N 2) into thereservoir. This is called the Enhanced CBM Recovery.Higher affinity gas means, its more preferable by coal to

be adsorbed into its surface. Therefore, when CO 2 or N 2


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is injected into the well, the remaining methane isreleased from the coal surface and thus we could get100% recovery from a known field. This is due to N 2 and CO 2 reduces the partial pressure of methane which

encourages the methane to desorped from the surface of coal (Shi and Durucan, 2008).

NOMENCLATURE

A = Area (ft2)Bw = Water formation volume factor (ft3/scf)Bw = Water formation volume factor (bbl/STB)cw = Water compressibility (/psia)cf = Formation compressibility (/psia)Gci = Initial gas content (scf/ton)Gc@abd = Gas content at Abandonment Pressure

(scf/ton)

GIP = Gas in place (scf)h = Net pay (ft)krg = Relative permeability to gas, (fraction)krg0 = Endpoint relative permeability to gas,

(fraction)krw = Relative permeability to water, (fraction)krw0 = Endpoint relative permeabili ty to water,

(fraction)kg = Gas effective permeability (md)kw = Water effective permeability (md)m() = Gas pseudopressure (psi2/cp)nw = Exponent of the water relative

permeability curve, (fraction)

ng = Exponent of the gas relative permeabilitycurve, (fraction)P = Pressure, (psia)Pi = Initial reservoir pressure (psia)PL = Langmuir Pressure constant, (psia)Pwf = Bottomhole flowing pressure (psia)qg = Gas rate (MCFd)qw = Water rate (STB/day)re = External radius of reservoir (ft)rw = Wellbore radius (ft)s = SkinSg = Average gas saturation, (fraction)Sgc = Irreducible gas saturation, (fraction)

Sw = Average water saturation, (fraction)Swc = Irreducible water saturation, (fraction)Swi = Initial water saturationT = Temperature (R)V (P) = Amount of gas at pressure P, (scf/ton)VL = Langmuir Volume constant, (scf)We = Water encroached (bbls)Wp = Water produced (STB) = Porosity (dimensionless): w = Water viscosity (cp)D b = Bulk density of the coal (lb/ft3)

ACKNOWLEDGMENT

Author(s) would like to pay thanks to UniversitiTeknologi PETRONAS for supporting this research

project.

REFERENCES

Aminian, K., S. Ameri, A. Bhavsar and M. Sanchez,2004. Curves type for coalbed methane production

prediction. SPE Paper 91482 Presented at the 2004SPE Eastern Regional Meeting, April 16-18,Charleston, West Virginia, USA.

Clarkson, C.R., C.L. Jordan, R.R. Gierhart and J.P.Seidle, 2007. Production data analysis of CBM wells.SPE Paper 107705 Presented at the 2007 SPE RockyMountain Oil and Gas Technology Symposium,April 16-18, Denver, Colorado, USA.

Fekete, F.A.S.T., 2010. RTA Advanced ProductionDecline Analysis Online Help. Retrieved from:http://www.fekete.com/software/rta/media/webhelp/c-te-analysis.htm, (Accessed on: September 17,2010).

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Roadifer, R.D., T.R. Moore, K.T. Raterman, R.A. Farnanand B.J. Crabtree, 2003. Coalbed methane parametricstudy: Whats really important to production and when ? SPE Paper 84425 Presented at the SPEAnnual Technical Conference and Exhibition,October 5-8, Denver, Colorado, USA.

Saulsberry, J.L., P.S. Schafer and R.A. Schraufnagel,1996. A Guide to Coalbed Methane Reservoir Engineering. Gas Research Institute, Illinois,Chicago.

Shi, J.Q. and S. Durucan, 2008. Modeling of mixed-gasadsorption and diffusion in coalbed reservoirs. SPEPaper 114197 Presented at the 2008 SPEUnconventional Reservoirs Conference, February 10-12, Keystone, Colorado, USA.

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