Coal mine methane: A review of capture and utilization practices with benefits to

mining safety and to greenhouse gas reduction

C. Özgen Karacan a,⁎,

a NIOSH, Office of Mine Safety and Health Research, Pittsburgh, PA, USA

⁎ Corresponding author. Tel.: +1 412 3864008.

E-mail address: cok6@cdc.gov (C.Ö. Karacan).

Felicia A. Ruiz b,

b US EPA, Coalbed Methane Outreach Program, Washington, DC, USA

Michael Cotè c, Sally Phipps c

c Ruby Canyon Engineering, Grand Junction, CO, USA

abstract

Coal mine methane (CMM) is a term given to the methane gas produced or emitted in association with coal

mining activities either from the coal seam itself or from other gassy formations underground. The amount of

CMM generated at a specific operation depends on the productivity of the coal mine, the gassiness of the coal

seam and any underlying and overlying formations, operational variables, and geological conditions. CMM can

be captured by engineered boreholes that augment the mine's ventilation system or it can be emitted into the

mine environment and exhausted from the mine shafts along with ventilation air. The large amounts of

methane released during mining present concerns about adequate mine ventilation to ensure worker safety,

but they also can create opportunities to generate energy if this gas is captured and utilized properly.

This article reviews the technical aspects of CMM capture in and from coal mines, the main factors affecting

CMM accumulations in underground coal mines, methods for capturing methane using boreholes, specific

borehole designs for effective methane capture, aspects of removing methane from abandoned mines and

from sealed/active gobs of operating mines, benefits of capturing and controlling CMM for mine safety, and

benefits for energy production and greenhouse gas (GHG) reduction.

Contents

1. Introduction ............................................................. 122 
 

2. Factors affecting specific emissions in underground coal mines and estimation methods .......................... 123 
 

2.1. Analyses of contributors for CMM emissions for longwall mines ...... ............................ 123 
 

2.2. Empirical CMM emissions prediction methods .......................................... 124 
 

2.3. Modular CMM emission prediction methods ........................................... 125 
 

3. Degasification of coal seam and capture of coal mine methane ...................................... 126 
 

3.1. Degasification of coal beds using horizontal boreholes for reducing emissions ........................... 127 
 

3.2. Capturing methane from longwall gobs using vertical (gob gas venthole) and cross-measure boreholes for reducing emissions .... 128 
 

3.2.1. Longwall gob gas ventholes ............................................... 129 
 

3.2.2. Cross-measure boreholes ................................................ 132 
 

3.3. Degasification borehole stimulation, stability, and completion issues .... ............................ 133 
 

4. Geological features and heterogeneities that affect gas emissions and removal from mines ........................ 135 
 

4.1. Effects of faults in coal bed on mining, mining gas emissions, and degasification efficiency ..................... 136 
 

4.2. Effects of partings in the coal seam for coal mine methane emissions and degasification ...................... 139 
 

4.3. Effects of permeability facies and spatial changes in coal types and coal microlithotypes on emissions into mines .......... 140 
 

5. Methane emission and recovery from abandoned underground coal mines .... ............................ 141 
 

5.1. Detecting mine voids ...................................................... 141 
 

5.2. Methane emissions evaluation .................................................. 142 
 

6. World coal mine methane (CMM) overview .............................................. 144 
 

6.1. China ............................................................. 144 
 

6.2. United States .......................................................... 145 
 

6.3. India .............................................................. 145 
 
7. Benefits of capturing and utilizing CMM and mitigating CMM emissions ...... ........................... 146 
 

8. CMM utilization technologies ...................................................... 147 
 

8.1. Pipeline injection ........................................................ 147 
 

8.2. Gas processing ......................................................... 148 
 

8.2.1. Nitrogen rejection unit (NRU) technologies ....................................... 148 
 

8.2.2. Other impurity and water vapor removal technologies .................................. 148 
 

8.2.3. Other CMM upgrading options ............................................. 149 
 

8.3. Power generation ........................................................ 149 
 

8.3.1. Ventilation air methane (VAM) use technologies ..................................... 149 
 

8.3.2. Onsite use options of CMM by coal mines ........................................ 150 
 

8.4. Emerging technologies ..................................................... 151 
 

8.4.1. Concentrators ..................................................... 151 
 

8.4.2. Lean fuel gas turbines .................................................. 151 
 

8.4.3. Carbureted gas turbine (CGT) .............................................. 151 
 

8.4.4. Lean-fueled turbine with catalytic combustor (CCGT) ................................... 151 
 

8.4.5. Lean-fueled catalytic microturbine ............................................ 151 
 

8.4.6. Hybrid coal and VAM-fueled gas turbine ......................................... 151 
 

8.5. Benefits and disadvantages of end-use technologies ........................................ 151 
 

9. CMM project barriers and a global overview of projects ......................................... 152 
 

9.1. Barriers to the recovery and use of CMM ............................................. 152 
 

9.2. CMM capture and utilization projects .............................................. 152 
 

10. Summary and conclusions ....................................................... 153 
 

Disclaimer .................................................................. 154 
 

References ................................................................. 154 
 

1. Introduction

Coalmine methane (CMM) is a generalterm for all methane released

mainly during and aftermining operations.Although,methane captured

prior to mining can also be considered associated to mining and thus can

be considered as coal mine methane, it can also be termed as coalbed

methane (CBM). CMM shows great variability in flow rate and

composition. At a typical gassy coal mine, ventilation air may contain

0.1–1% methane, whereas gas drained from the seam before mining can

contain 60% to more than 95% methane depending on the presence of

other gasses in the coal seam. Gas drained from fractured formations

above mined seams (gobs), on the other hand, may contain 30–95%

methane depending on the locations of the boreholes and other

operation and completion parameters (Karacan, 2009a). Although

ventilation air methane (VAM) from shafts of active mines contributes

approximately 64% of worldwidemethane emissions from underground

coal mines, methane concentrations in the ventilation air are different

for each mine (S. Su et al., 2005; Su et al., 2008; X. Su et al., 2005). These

varying concentrations impact the choice of potential capture and

utilization technologies for VAM.

There are three primary incentives for recovering CMM (Bibler

et al., 1998). The first and foremost reason is to improve the safety of

the mines. In recent years, there have been many fatalities in underground coal mine explosions in which methane was a contributing

factor. Table 1 shows some of the major mine explosions (United

Nations, 2010) after 2000.

Table 1

Some of the major coal mine explosions that occurred after 2000 (modified from United

Nations, 2010).

Country Date Coal mine Fatalities

China 14 Feb., 2005 Sunjlawan, Haizhou shaft, Fuxin 214

USA 2 Jan., 2006 Sago, West Virginia 12

Kazakhstan 20 Sept., 2006 Lenina, Karaganda 43

Russia 19 March, 2007 Ulyanovskaya, Kemerovo 108

Ukraine 19 Nov., 2007 Zasyadko, Donetzk 80

USA 5 April, 2010 Upper Big Branch, West Virginia 29

Turkey 17 May, 2010 Karadon, Zonguldak 30

Removing methane from mines can reduce

the methane in working areas, thereby improving safety. The second

benefit of recovering CMM is to improve mine economics by allowing

the mines to produce coal with minimum downtimes due to high

methane levels. The third incentive is to reduce greenhouse gas

emissions involving methane, which is about 21 times more potent

than CO2 (Warmuzinski, 2008).

Coal mine methane has always been considered as a danger for

underground coal mining as it can create a serious threat to mining

safety and productivity due to its explosion risk. One of the most

important duties of ventilation in underground coal mines is to keep

methane levels well below the explosive limit by diluting methane

emissions that occur during mining. Methane entering a mine can create

a localized zone of high concentration in an area of low air velocities and

quantities. The concentration of methane in these zones may pass

through a range between 5% and 15%, known as the explosive range. In

this range, methane can be ignited easily with the presence of an ignition source to create a violent methane explosion that may propagate in

the presence of combustible coal dust. Fig. 1 shows the explosibility

diagram for methane (Coward and Jones, 1952).

Fig. 1. Methane explosibility diagram.

Modified from Coward and Jones (1952).

In addition to proper ventilation practices, removal of coal mine

methane from the mining environment prior to, during, and after coal
production by using various in-seam and surface-to-mine borehole

designs, has been the key componentto alleviate the explosion threat in

mining operations. However, application of these techniques requires

knowledge of those operational factors that control gas emissions

during mining and the geological factors that may lead to excessive

emissions that can affect the performance of degasification techniques.

Also important is knowledge on the accumulation of methane in sealed

and active gobs, and the size of the gas emission zone that may put

abandoned workings in physical connection with the active mine.

In addition to safety concerns, methane that is emitted from

domestic and international coal mines represents approximately 8%

of the world's anthropogenic methane emissions contributing 17%

to the total anthropogenic greenhouse gas emissions (U.S. EPA, 2003,

2010a). By 2020, CMM emissions are projected to increase, with

estimates as high as 793 MtCO2e (×1000 tons CO2 equivalent).

Underground coal mining is the most important source of fugitive

methane emissions, and nearly 70% of this methane is emitted

through mine ventilation air at low concentrations. Thus, CMM is an

important issue from an environmental point of view. Further,

capturing and utilizing this gas will not only decrease greenhouse

gas emissions, but will provide an additional energy source that

otherwise will be lost.

Capturing high concentrations of methane using boreholes,

upgrading it to pipeline quality gas if needed, and utilizing this gas

are fairly well-developed techniques. Since methane emissions

from VAM represent most of the methane emissions from coal

mines, much attention has been given to explore ways to capture and

utilize low concentrations of methane under variable flow conditions. In addition, the quality of ventilation air and methane concentration varies in relation to dust loading, particle size distribution,

and the presence of other gasses that may make a particular VAM

capture and utilization technology unfeasible for a given mine.

Therefore, the characteristics of ventilation air from a particular

mine wanting to utilize these techniques should be well-understood

(Su et al., 2008).

This article reviews the technical and geological aspects of CMM

capture from active and sealed coal mines, the main factors affecting

CMM accumulations in mines, and the benefits of capturing and

controlling CMM for mine safety, energy production, and greenhouse

gas (GHG) reduction.

2. Factors affecting specific emissions in underground coal mines

and estimation methods

There are various geological and operational factors affecting a

mine's methane emissions while coal is being extracted. The

individual contributions of each of these factors to the total amount

of emissions vary and, in most cases, may be difficult to distinguish

from each other. Therefore, a relative term called “specific emissions”

is used, quantified as a lumped parameter to designate the gassiness

of a mine.

Specific emissions is the amount of methane generated per unit

amount of coal that is mined (United Nations, 2010), and this quantity

is generally used to determine the degasification and ventilation

needs of a particular mine. One should be aware that this is not the gas

content of the mined coal, but rather the gas amount generated as a

consequence of coal extraction.

Fig. 2 shows the relationship between mine emissions and gas

content of mined coal for Australian mines (Saghafi et al., 1997).

Fig. 2. Mine emissions versus gas content of mined coal.

Modified from Saghafi et al. (1997).

As

shown, the amount of mine emissions exceeded gas content of coal by

a factor of 4. Kissell et al. (1973) observed similar trends for the U.S.

coal mines and suggested that the mine emissions greatly exceeded

(approximately 7 times) the amount expected from an analysis of coal

gas content alone. The difference may be related to the differences in

Australian and U.S. mining conditions and the differences in geology.

However, methane that leads to specific emissions of a mine may be

generated from the mined coal itself and also may originate from

overlying and underlying strata. In addition, the quantity may change

based on the changes in operational parameters. Therefore, mine

emissions are difficult to predict and may depend on many factors

besides gassiness of the mined coal.

2.1. Analyses of contributors for CMM emissions for longwall mines

Karacan (2008a,b) compiled data on mine operational parameters,

seam depths, locations, coal gas contents, and methane emissions

from U.S. longwall operations that spanned a period of 20 years. The

data were analyzed using multiple regression and neural networks. In

order to reduce model complexity, principal component analysis

(PCA) was performed to determine the weight of each parameter on

methane emissions. Below is a brief discussion on the influence of

individual parameters on methane emissions in coal mines and the

results of PCA to determine the most influential parameters.

Gas content is one of the key data included in coalbed methane

resource estimations (Boyer and Qingzhao, 1998). The gas content

data, when combined with geologic and engineering data, can be used

as a basis for an initial estimate of methane emissions and ventilation

requirements (Diamond et al., 1986; Karacan and Diamond, 2006;

Noack, 1998). During mining, all three components of coal gas content

(lost, desorbed, and residual) can potentially contribute to methane

emissions into the mine atmosphere.

Rank represents the level of maturation reached in a coal seam and

usually increases with increasing depth. Most longwalls, as well as

most commercial coalbed methane projects, operate in bituminous

coal beds. The coals of sub-bituminous to low-volatile bituminous

range usually provide high gas content and natural permeability

(Steidl, 1996). Mining coals of this rank, particularly medium- to lowvolatile bituminous coals, potentially liberates high amounts of gas

into the ventilation system.

Depth of the mined coal seam, or its overburden impacts methane

emissions in two ways. First, for coals of the same rank, gas content

generally increases with increasing depth (Kim, 1977). Second,

overburden impacts the disturbance created in the overlying strata.

This effect is related to the width of the extracted panel. If panel width

is greater than overburden depth, the panel is referred to as a

“supercritical” panel, where the caving will be more complete after

mining compared to a situation where the panel width is less that the

overburden depth. Complete caving in the case of a supercritical panel

creates a larger volume of fractured strata in overlying formations.

Panel dimensions influence methane emissions by impacting the

dimensions of the subsided strata overlying the extracted panel and

the emissions from the longwall face. The increasing size of longwall

panels, while helping to increase coal production, may also increase
methane emissions due to the exposure of the mining environment to

a larger area of fractured, gas-bearing strata.

Cut depth is the slice of coalbed that is mined by the shearer during

each pass. In general, the greater the cutting depth, the more coal is

produced per rotation ofthe cutting drums and the greater the emissions.

However, emissions may also be affected by the rotational speed of the

cutting drums and the loading rate of the shearer. If the drums are

rotating fast compared to haulage speed, then a finer coal fraction is

produced (Peng, 2006), which potentially increases emissions.

Face conveyer and stage loader speed should be at high capacity

and should be as fast as is practical to ensure continued coal production. These speeds are important so that the coal is moved from the

face area as quickly as possible to minimize emissions from the broken

coal on the conveyor.

Coal production is affected by most of the operational parameters

contributing to gas emissions, too. Practical experience has shown that

gas emissions are directly related to coal production, and the more coal

that is mined, the higher the emissions rates. This is one of the reasons

why coal production is used as one of the major parameters, or the sole

one, in most empirical models studying methane gas emissions.

Mining height is usually equal to or related to the seam height. In

some thin-seam mines, the roof is also extracted to make room for

equipment and personnel. Seam and mining height impact coal mine

emissions because thick, permeable, and gassy coal beds potentially

generate more gas from the longwall face compared to their thinner

counterparts. In addition, caving height is proportional to mining

height (Peng, 2006). Thus, the greater the mining height, the higher

the caving will be and the greater the potential for more gas to flow

into the gob from the overlying strata and into the mine.

The number of gate roads used varies based on the needs of the

operation. In the U.S., some of the early longwalls used five-entry

gateroads. Today, three-entries are preferred since they require less

development footage compared to four- or five-entry systems. A fourentry system is used in coal seams of low height or high gas content

where additional gateroads are needed to minimize airflow resistances or to improve methane dilution by increasing ventilation

quantities. Two-entry gateroads require a special variance and are

used in deep mines with a thick layer of strong overlying strata, such

as operations in Colorado and Utah (Peng, 2006).

Degasification can be used for controlling methane emissions prior

to and during mining. An effective degasification process can reduce

emissions into the ventilation system (Diamond, 1994; Thakur and

Poundstone, 1980). Depending on the gassiness of the coal seam and

the fractured strata, horizontal boreholes, vertical boreholes, or gob

gas ventholes can be used. The number of boreholes, their locations,

and their degasification durations may change based on site-specific

factors (Diamond, 1994).

A strong relationship exists between gas emissions rates and

geological factors, such as stratigraphy, and the gas contents and

strengths of the overlying and underlying strata. There is not a simple

solid mathematical expression to uncover this relation. Geomechanical models coupled with fluid-flow models are usually used to

investigate this relationship. However, it is known that when the

overlying formations are thin and weak, and when are they gassy and

in close proximity to the mined seams the emissions increase. Also,

coal beds are strongly affected by regional sedimentology and

tectonics. Pashin (1998) reported, based on investigations in the

Black Warrior Basin and in the San Juan Basin, that regional variations

in sequence stratigraphy were useful for characterization of coalbed

methane reservoirs. Although geographical location is not directly

related to methane emissions, it can be used indirectly to identify the

differences in underground stratigraphy between different locations.

The discussions in this section show that complex relations exist

between different factors and the resultant emissions rates from

longwall operations. In fact, these relations are too complex to be explained by simple equations. Table 2 gives the PCA factor loadings

and the most influential variables for mine methane emissions.

Table 2

Factor loadings of the variables after rotating the principal component (PCR) matrix

using Kaiser's varimax rotation. Boldfaced entries show the most influential variables in

each PCR.

Variables PCR1 PCR 2 PCR 3 PCR 4 PCR 5

Presence or absence of degasification 0.472 0.221 0.163 0.245 0.538

Basin −0.287 −0.007 0.917 −0.136 −0.145

State 0.002 0.049 0.951 −0.196 0.002

Seam height 0.064 0.113 −0.093 0.925 −0.063

Cut height 0.048 −0.027 −0.225 0.911 −0.043

Panel width 0.036 0.798 −0.006 0.004 −0.029

Panel length −0.248 0.701 0.093 −0.202 0.052

Overburden thickness 0.808 −0.075 −0.129 0.108 0.121

Number of entries 0.271 −0.178 −0.045 −0.224 0.805

Cut depth 0.125 0.745 0.056 0.142 −0.076

Face conveyor speed 0.145 0.834 0.116 0.056 −0.167

Stage loader speed 0.147 0.811 −0.048 0.070 0.105

Lost+desorbed gas contents 0.954 0.024 −0.187 0.065 −0.011

Residual gas content −0.244 0.237 0.748 0.032 0.372

Total gas content 0.960 0.077 −0.036 0.076 0.068

Rank 0.907 0.031 −0.174 −0.091 0.186

Coal production −0.221 0.688 0.251 0.114 0.036

In this

table, the higher numbers (factor loadings) associated with different

variables show the importance of that variable in each of the principal

components. In addition, positive numbers indicate a positive effect on

principal components, whereas negative numbers indicate negative

correlation. Principal component analysis helps select the most

influential parameters for model development and thus is an effective

technique for simplifying the predictive models.

2.2. Empirical CMM emissions prediction methods

Accurate estimation of the rate of methane emissions from mines,

i.e., specific emissions, can be challenging due to the large number of

variables involved with mining operation. On the premise that gas

emissions in underground mine environments can be linked to different stages in the life of a coal mine, the following empirical model

was suggested (Lunarzewski, 1998):

 ∑

y+ 1

0

C

 !m

+ 1−

m

∑ +

y

0

C

 

ð1Þ Q yð Þ = g

CA 1

 !

where Q(y) is the average methane emissions in a year y of the mine's

existence (m3

), CA is the coal production in the most recent year only

(tons), C is the coal production for the life of the mine up to year y

(tons), and g and m are the site-specific coefficients dependent upon

geological and mining conditions. In other words, this approach

summarizes methane emissions as a function of coal production only

and lumps other variables into empirical constants.

In a separate study, Kirchgessner et al. (1993) presented an equation

based on the multi-linear regression technique between coalbed

methane contents, coal productions, and mine emissions (with

R2=0.59). The relationship that the authors generated is presented in

Eq. (2). The form of the equation that they developed is a standard

multi-linear function with a slope and intercept. The reason there is a

non-zero intercept in this functional relationship is that methane

emissions can occur at underground coal mines even at very low or at

zero production rates.

Q y = 1 08 × 107 ð Þ : ðCP × GCÞ + 31:44−26:76ðDVÞ ð2Þ

In this equation, Q(y) is the average methane emissions in a year,

CP is the annual coal production (tons), GC is the gas content of the
coal (m3

/ton), and DV is a dummy variable that takes the value “1” if

(CP ×GC) is less than 7.6 × 105

, and “0” if (CP ×GC) is greater than or

equal to 7.6×105

.

Creedy (1993) used historical methane emissions to atmosphere

from deep mines in Britain. He summed the contributions from the

non-draining mines, the mines with methane drainage, and the coal in

transit or storage on the surface, obtaining the following relationship:

ED = LPw + 1ð :857DÞ + F + RPt−	 ð3Þ

where ED is the emission, Pw is the annual coal production from mines

without methane drainage, Pt is the total annual deep mine coal

production, D is the total annual methane drained from all mines, F is

the difference between drained and utilized methane, L is the specific

emission for mines without drainage (assumed to be 6 m3

/ton), and R

is the residual gas content of coal arriving at the surface (assumed to

be 2 m3

/ton).

A lumped-parameter approach for estimating the instantaneous

volume of gas released from all potential sources is given by

Lunarzewski (1998):

R = a

p

CP + b ð4Þ ffiffiffiffiffi

In this equation, R is the total methane emissions rate (l/s), CP is

the daily coal production rate (tons), and a and b are empirical

constants related to coal production levels and number of working

days per week.

Lunarzewski (1998) has also described gas emission into underground workings as a combination of the quantity of gas released from

both the mined coal seam and adjacent strata. This empirical

relationship is expressed as:

GCf × DCf × TAf GCr × DCr × TA Q yð Þ = Q + ∑ + ∑ r m 5 TM TM ð Þ

where Q(y) is the quantity of gas emission into the mine per ton of

mined coal, Qm is the gas quantity released from the mined coal seam,

GC is the gas content in the floor (f), and roof (r), DC is the degassing

coefficient for (f) and (r), TA is the thickness of the gassy strata in (f)

and (r), and TM is the thickness of the mined coal seam. The difference

between this method and the previous ones is that this relation

includes gas emissions from the floor and roof as well. However, the

inherent difficulty is that the parameters required to include these

emissions are not always easy to define correctly.

One of the methods that can be considered empirical in nature is

based on classification and regression tree (CART) analysis of the

potential contributors for mine emissions and their values. CART

represents a computational-statistical algorithm which predicts in

the form of a decision tree. The CART procedure can be defined as a

partition method of data into terminal nodes (child nodes) by a

sequence of binary splits, starting at a parent node. CART repeats the

partition for each child node, continuing recursively until the

homogeneous level in the generic node required is obtained or a

given stopping criterion is verified. This method has been applied to

predict the range of methane emissions from mines operating with

and without a degasification system to attain certain productivity

goals under ventilation constraints (Karacan and Goodman, submitted

for publication). The models are presented in terms of rules that give

the ranges of parameters to attain for potential emissions for target

productivity values. Table 3 gives a set of example rules for mines using

degasification for achieving coal production between 8.904 Mt/day and

28.219 Mt/day without exceeding a predicted methane emission level.

Table. 3

Example rules for achieving coal production between 8.904 Mt/day and 28.219 Mt/day

without exceeding a predicted methane emissions level (CH: cut height (mm); PW: panel

width (m); SLS: stage loader speed (m/min); LD-GAS: lost+desorbed gas (m3

/ton); HC:

heat content (kcal/kg); OB: overburden (m); SULP: sulfur (%); ENT: number of gateroad

entries; CD: cut depth (m); FCS: face conveyor speed (m/min).

Methane emission

(Mm3

/day)

Rules for daily coal production amount

[8.904, 28.219] Mt/day

50.97	 CH [1.47, 1.93] PW [192, 222.5] SLS [85.3, 116.4] HC [5229,

7120.4] LD-GAS [1.27, 4.12]

110.44	 OB [262.9, 312.4] SLS [155.1, 167.6] ENT [3] SULP [2.185, 3] CD

[0.98, 1.12] HC [7120.4, 7810] LD-GAS [1.27, 4.12]

166.59	 CH [1.94, 1.98] SLS [85.3, 155.1] ENT [3] SULP [2.185, 3] CD

[0.98, 1.12] HC [7120.4, 7810] LD-GAS [1.27, 4.12]

184.01	 CH [1.67, 1.79] ENT [3] SULP [1.7, 2.185] CD [0.98, 1.12] HC

[7120.4, 7810] LD-GAS [1.27, 4.12]

289.48	 CH [1.78, 1.93] PW [297.2, 320.0] FCS [102.1, 121.9] CD [0.76,

0.98] HC [7120.4, 7810] LD-GAS [1.27, 4.12]

For instance, the first rule in this table states that a coal production

between 8.904 and 28.219 Mt/day can be achieved without exceeding

50.97 Mm3

/day methane emission rates only if the variables given for

this rule are within the stated ranges.

2.3. Modular CMM emission prediction methods

Empirical methods of estimating methane emissions in underground coal mines require only a few parameters, but using empirical

methods can sacrifice the accuracy of the results. In order to provide

more accurate results as well as to conduct sensitivity studies, a

modular software suite Methane Control and Prediction (MCP) was

created to predict CMM emissions from longwall mines.

The MCP version 2.0 (and its earlier versions) was developed under

the MS AccessTM shell environment using artificial neural networks

and various statistical and mathematical techniques. Dynamic link

libraries (DLLs) written in C++ are used to process data for calculations. This software is available for download from http://www.cdc.

gov/niosh/mining/products/product180.htm (Karacan, 2010). The software suite predicts CMM output from the ventilation systems of

longwall mines using a database of information about these operations,

including basic coal, mining, longwall panel, productivity, and coal bed

characteristics. The software provides deterministic and stochastic

options for CMM prediction and has U.S.-specific and more general siteindependent models. Fig. 3A and B shows the input screens of models

for U.S. and for international conditions, respectively.

MCP users need to enter the input parameters as realistically as

possible for their particular operation. The modules are most accurate

within the given min–max range, but there is some extrapolation

flexibility in the calculation methods, allowing the modules to perform predictions beyond the minimum and maximum limits. When

the entered data are beyond the limits, the program provides a

warning and asks the user whether he/she would like to continue

with the calculations. If the user approves, the program continues

with its calculations. Dougherty and Karacan (2010) present application and sensitivity studies by varying input parameter values in MCP.

Aside from the various methods and their accuracies and adequacies for predicting the CMM emissions in underground coal mines,

from ventilation and mine safety points of view, there are also different numbers speculated as to what level of specific emission is high

or manageable. For instance, Thakur (2006) indicates that mines with

specific emissions of 28.3 m3

/ton (1000 ft3/ton) can be considered

gassy, but that mining can be sustained with the help of a wellplanned ventilation system. However, mining with specific emissions

exceeding 28.3 m3

/ton becomes economically unfeasible due to ventilation costs and also becomes unsafe, as it may be difficult to stay

within statutory methane limits. The author suggests that operations

with specific emissions in excess of 28.3 m3

/ton should use methane

drainage in support of ventilation. He further suggests that mines with

specific emissions exceeding 113.2 m3

/ton (4000 ft3/ton) can be safely

operated with a well-designed degasification system in addition to a

well-designed ventilation system.
Fig. 3. Input screens of CMM prediction models of MCPs version 2.0 for longwall mines in specific states in the U.S. (A), and the stochastic model for longwalls assuming international

settings (B).

3. Degasification of coal seam and capture of coal mine methane

Methane emissions can adversely affect both the safety and the

productivity of underground coal mines. As mining progresses into

gassier coal beds, mine operators have become more interested in

methane control systems to supplement conventional ventilation

methods and keep the specific emissions of the mines at low levels.

Methane emissions from the face, ribs, and conveyor belt are

directly exposed to the mining environment and thus the ventilation

system must have sufficient capacity to handle any unexpected increases in methane emission levels from these sources. As mines

move into deeper and gassier coal beds, and as longwall operation

parameters change, emissions that flow directly into the ventilation

system may increase. To address this issue, the most common supplemental gas management practice is the degasification of the coal

bed prior to mining to reduce the amount and rate of these emissions.

In addition to reducing the in-place gas content of the coal bed, it has

been shown that methane drainage is also effective for reducing the

risk of gas outbursts by decreasing the pressure of the coal bed in the

vicinity of the mine workings (Noack, 1998).

In addition to methane emissions from the face, ribs, and conveyor

belt, the other source of methane is the fractured and caved rock in the

subsided strata (gob) overlying the extracted panel. The subsided

strata are generally made up of a completely caved zone overlain by

strata with extensive fractures. The height of the caved zone is about 3

to 6 times the thickness of the mined coal bed (Palchik, 2003). The

stress relief due to caving causes the overburden strata above the

caved zone to fracture vertically and horizontally, as high as 100 times

the height of the mined coal bed, depending on the size of the panel,

the geology, and geomechanical properties of the layers (Palchik,

2003).

Emissions from the fractured zone are usually controlled by gob

gas ventholes. However, the stress-relief fractures that occur during

longwall mining provide extensive pathways for gas migration from

the surrounding coal beds and other gas-bearing strata into the

active mining environment. The migration of methane into sealed

and active areas depends on the gas contents of the overlying

formations and the presence of methane accumulations, as in

abandoned workings or gobs. These emissions can occur suddenly

with large gas quantities rapidly inundating the ventilation system

and changing the properties of the mine atmosphere in large areas.

Therefore, it is important to be able to know the size of the fractured

zone, or “methane emission zone,” in relation to the design of gob gas

ventholes.
Methane drainage boreholes, whether they are horizontal, vertical,

or gob gas ventholes, directly communicate with methane sources

and gas migration paths, and with both active and sealed mine areas.

Therefore, analyses of borehole production and operating pressure

data can provide more information than just the amount of methane

produced. Actually, these analyses can offer insights into the gas

transport properties of the methane sources in question, the

interaction of drainage boreholes with methane sources, the extent

of the borehole-effect radius, the boundaries of the methane source,

and the optimum duration of borehole operation prior to mining.

This information can eventually determine the interactions of the

borehole/methane sources/mine environment trio to evaluate the

observed methane level changes in the mine's ventilation system.

Migration and control of methane gas levels are best accomplished by

measuring in-mine gas levels and by considering the interactions of

sealed and active gobs with a mine's ventilation system, the drainage

radii of boreholes, and the properties of the gas sources.

The selection of an effective methane control system depends on

the sources of the gas emissions. The most commonly applied methane control solution, especially in high in-place gas content coal beds,

is drilling methane drainage boreholes into the panel area prior to

longwall mining to reduce the methane content of the coal bed. These

boreholes can be vertical or horizontal boreholes drilled from the

surface, or in-seam horizontal boreholes drilled from the underground

entries (Diamond, 1994). Although in-mine drilling can be challenging

due to the logistics of working in the restrictive underground environment, one advantage is that virtually the entire drilled lengths of

the boreholes are in the gas-producing horizon of the mined coal bed.

In recent years, a new pinnate-drillingTM technique has been

successfully applied in coal beds in the Appalachian basin and in the

western states of the U.S., including the Arkoma basin (Spafford,

2007). This technique combines the logistically less complicated

process of drilling from the surface with the high productivity of

horizontal methane drainage boreholes. Also, these holes continue

producing even though the single laterals may quit production due to

various reasons.

This section reviews some of the most common borehole techniques

used for degasification of coal seams and the gas emission zones of

longwall panels, as well as some advantages and disadvantages associated with employing them. A good review of engineering and economic evaluation of gas recovery from mines using different boreholes

is also given in Kirchgessner et al. (2002).

3.1. Degasification of coal beds using horizontal boreholes for reducing

emissions

The purpose of and the design considerations for horizontal

degasification boreholes may change depending on the mining conditions and on the coal bed. Generally, in-mine horizontal boreholes

are used to perform two basic mine safety functions: reducing the inplace gas volume within the panel prior to mining and shielding active

workings, especially development sections, from gas migration from

the surrounding virgin gas reservoir. In-seam horizontal methane

drainage boreholes are usually completed open hole, with a short

segment (9–15 m) grouted to seal the end of the borehole near the

mine workings. Long horizontal boreholes drilled parallel to the

gate roads in advance of entry development can be utilized to drain

methane from the panel area, and they also can be used to shield the

advancing development entries from the flow of gas from the

surrounding coal reserves.

In the late 1970s, four long horizontal boreholes were drilled into

the Pittsburgh coal in Pennsylvania from a section of a mine that had

been abandoned for 2.5 years due to high methane emissions. The

lengths of the holes were 299 to 764 m. The average production rate of

the holes was 9.3 m3

/day/m of drilled borehole length and the

cumulative production was 7.2×106 m3

. The production rate decreased

to 3.7 m3

/day/m of borehole after 2.7 years of production. This project

was unique at the time for two reasons. First, in the previous projects,

the primary gas problem was emissions at the active face, and the gas

produced by horizontal boreholes drilled near the face was vented to a

location underground where enough air was present to dilute it. In this

project, the gas was transported to the surface. Second, the transported

gas was utilized to generate electricity from a turbine to power a

ventilation fan. This may have been one of the first applications of

utilizing coal gas for power generation.

Shorter cross-panel horizontal boreholes drilled from the advancing entries can also be used to drain gas in advance of longwall

mining. These boreholes are drilled perpendicular to the rib to a

location close to the opposite side of the panel. Although it has been

reported that this technique successfully removed substantial amounts

of methane from the completion end and the middle of the panel

(Aul and Ray, 1991), gas-related mining delays were encountered at

startup because the cross-panel horizontal boreholes in that area were

in production for a relatively short period of time prior to the start of

mining. Different strategies, such as placing the boreholes at the startup

end closer together or drilling from the tailgate side into the virgin

coal bed beyond the panel as the entries advance, can be considered to

improve their effectiveness.

Continuity and permeability of the coal seam significantly affect

the success of methane drainage boreholes. In high-permeability

coals, in-mine horizontal boreholes can be used for shielding the gate

road entries to maximize gate road development, for reducing inplace gas content of longwall panels, and thus for promoting maximum longwall mining advance rate (Bohan, 2009). The impacts of

shielding the gate road entries on methane emissions and on reducing

ventilation airflow rates, as well as on improving mining advances, are

given in Fig. 4.

The importance of shielding the gate roads and its effects on

emissions with respect to the presence of boreholes and their

proximities to entries was also demonstrated by Karacan (2007a,b).

The author considered various mining and degasification parameters

in a systematic manner to predict methane inflows into gate roads

and associated airflow requirements. The predictions were compared

with the in-mine measurements available from the mining of tailgate

and headgate entries. The general results indicated that for shorter

development distances, marginal adjustments in ventilation airflow

may be adequate to keep methane levels under 1%. However, longer

gate road developments require significantly more ventilation air

capacity to keep methane levels constant, proving that shielding

boreholes is more important in this case. Thus, employing shielding

boreholes to protect entries from methane migration during mining is

an effective approach. Even if the boreholes cannot be operated for a

long time prior to the start of mining, their presence during mining

makes a big difference (about 25%) in methane inflow rates, especially

during mining of longer sections. In this context, positioning of

boreholes relative to entries is important. Positioning wellbores as

close to the entries as practically possible is effective, especially while

mining long development entries at higher advance rates. Fig. 5

illustrates the ventilation air requirements for entry development as

functions of methane levels, entry lengths, and advance rates without

using shielding boreholes during mining of a 2.3-m-thick seam

(Karacan, 2007a,b). This figure shows that as the lengths of the developments and the advance rates increase, the required air quantity to

keep methane concentrations at lower levels increases substantially.

In addition to the presence of boreholes for sustainability of

mining under safe and productive conditions, a coal seam's reservoir

properties also have a big impact on the productivity of these

boreholes and their effectiveness (Karacan, 2008a,b). Among all the

coal bed parameters evaluated for their effects on methane inflow into

gate roads during their development, coal bed thickness, pressure,

sorption time constant, permeability perpendicular to entries, and

adsorption parameters were found to be the most influential on
methane inflow rate. For shorter development distances, initial water

saturation was also found to be influential. Statistical analyses

(ANOVA) to evaluate the significance of these parameters showed

that, for all development distances, pressure, sorption time constant,

permeability perpendicular to gate roads, and Langmuir pressure

were more important independent variables for prediction by

comparison to Langmuir volume and coal bed thickness. Further, it

was shown that as the development distance increased, the order of

the relative importance of coal bed variables changed (Karacan,

2008a,b).

Other examples where long and cross-panel boreholes are used to

reduce in-place gas content are given in Fig. 6A and B. In Fig. 6A, multilateral horizontal boreholes are drilled from a single drilling location in

the headgate entry to reduce the gas content of the coal volume in the

panel area before mining. In Fig. 6B, boreholes drilled from various

locations in the mains extend into multiple panel areas to drain the gas in

a larger area before mining commences. Multiple wells can be connected

together as shown in Fig. 7 for gas gathering and transportation within

the mine.

One of the most important aspects of methane drainage using any

pattern of boreholes is estimating the amount of lead time required to

reduce the in-place gas volume sufficiently to effectively control gas

emissions during longwall mining. The importance of drainage time in

reducing methane content of the coal was reported by Aul and Ray

(1991). The authors noted that only 30% of the gas could be removed

from longwall panels in the Pocahontas No. 3 coal bed if the drainage

time were about 2 months. However, horizontal boreholes that

produced for about 10 months were able to drain 80% of the in situ

gas. Based on these data, the authors concluded that at least 6 months

was required to drain sufficient quantities of gas to have a positive

impact on methane emissions during mining. As a result of the

horizontal borehole methane drainage program, ventilation airflow

along the longwall face was reduced from 3420 m3

/min (120,000 cfm)

to 720 m3

/min (25,000 cfm).

The life of horizontal boreholes is dependent on the mine plan.

Typically, 6 to 12 months of gas production prior to mining is required to

sufficiently degasify an outlined longwall panel. Horizontal boreholes

drilled near the recovery rooms are usually allowed to produce gas even

after mining starts. However, as the longwall face approaches these

borehole locations, gas production is generally terminated as a safety

measure by injecting water or some other material into the borehole to

block the flow of gas. Thus, there are two phases in the production

history of a horizontal borehole: prior to mining and during mining. The

relative gas production contributions of these two phases will vary

considerably depending on the well configuration and spacing, duration

of pre-mining drainage, and rate of mining. Karacan et al. (2007a)

investigated the benefits of various borehole patterns and the premining degasification durations. Results of this study showed that dual

and tri-lateral boreholes were more effective in decreasing emissions

and in shielding the entries compared to fewer shorter, cross-panel,

horizontal boreholes parallel to the longwall face. Modeling results

showed that after 12 months of pre-mining methane drainage, the

average longwall face emission rates could be reduced by as much as

10.3 m3

/min and 6.8 m3/min using tri- and dual-lateral boreholes,

respectively. It was also shown that if pre-mining methane drainage

time were short, it is important to continue methane drainage during

the panel extraction to maximize reductions in longwall face emissions,

since additional face emission reductions achieved during this period

can be comparable to pre-mining degasification. Fig. 8 shows (as an

inset) the studied horizontal methane drainage borehole patterns for

degasification of the longwall panel and their performances during

different phases of degasification, after 3 months (solid fills) and

12 months (patterned fills) of pre-mining degasification.

Fig. 4. Immediate impact of a 500-m shielding borehole along the gate road on emissions, advance rate, and ventilation air requirement (Bohan, 2009).

Courtesy of REI Drilling.

Fig. 5. Airflow required for entry development to keep methane levels under certain

limits for variable entry lengths and advance rates without shielding boreholes during

mining of a 2.3-m-thick seam. Y-axis is advance rate in m/day.

3.2. Capturing methane from longwall gobs using vertical (gob gas

venthole) and cross-measure boreholes for reducing emissions

The formation of gob (for both the caved zone and fractured zone)

during longwall mining creates stress relief and resultant rock

damage. This changes the gas flow-related properties, particularly

the permeability, in the overlying (and in some cases the underlying)
strata (Karacan and Goodman, 2009). Any gas that is contained within

the coal beds and other gassy formations in this area of relieved stress

will be released slowly over time. The free gas in porous formations,

such as sandstones, will be released more quickly, as the permeability

of these zones is dramatically increased and as new permeability

pathways are created.

Relaxation of the roof and floor rocks and creation of the associated

fracture connectivities allow gas to flow from all surrounding gas

sources toward the low-pressure sink of the underground workings,

including the caved zone. In the absence of methane drainage boreholes

such as gob gas ventholes or boreholes drilled from the mine entry up

into the roof rocks (cross-measure boreholes), this released gas,

commonly referred to as “gob gas,” may enter the mine atmosphere

from above.

Fig. 6. Examples of using horizontal boreholes to reduce the in-place gas content of longwall panel (Bohan, 2009).

Courtesy of REI Drilling.

Fig. 7. An underground connection schematic of pre-drainage boreholes (Noack, 1998).

3.2.1. Longwall gob gas ventholes

Gob gas ventholes are drilled into the overburden above longwall

panels to capture the gas released from the subsided and relaxed

strata before it enters the mining environment, where it can be an

explosion hazard. Most gob gas ventholes are drilled within a short

distance, 10–30 m (30–100 ft) of the coal bed being mined, and cased

with steel pipe. Commonly, the bottom section of the casing –

generally about 60 m (200 ft) – is slotted and placed adjacent to the

expected gas production zone in the overburden strata. The usual

practice is to drill the gob gas ventholes from the surface prior to

mining. As mining advances under the venthole, the gas-bearing
strata that surround the well will fracture and establish preferential

pathways for the released gas to flow towards the ventholes.

Exhausters are placed on gob gas ventholes to maintain a vacuum

on the wellbore, so that they operate at the minimum possible flowing

pressure and create a pressure sink in the overburden strata to induce

gas flow towards the venthole.

Fig. 8. Horizontal methane drainage borehole patterns and their performances after 3 months (solid fills) and 12 months (patterned fills) of pre-mining degasification.

Gas production from gob gas ventholes may exhibit variable gas

quality. In the early stages of production, the gas quality is generally

high (N80%), and there is very little contamination by mine

ventilation air. Maximum daily methane production generally occurs

within the first several days after a hole is intercepted by the longwall.

Relatively high production rates are usually sustained for only a few

weeks or in some cases for a few months (Diamond, 1994). Later in

time, gob gas production may exhibit decreased methane levels as

ventilation air is drawn from the active mine workings.

The quality of the gas from gob wells can be controlled to some

extent by varying the vacuum on the wellto correspond with the profile

of expected methane release. However, maintaining the methane

concentration in the mine within statutory limits is always the

overriding factor for controlling the vacuum on the gob gas ventholes,

as it is for all other mine-related methane drainage systems. Commonly,

when the methane concentration in the produced gas reaches 25%, the

exhausters are de-energized as a safety measure, and the holes may be

allowed to free-flow.

The location of the ventholes on the panel is important. A study in

a coal mine in the Lower Kittanning seam showed that holes placed

near the gate roads of the panels were generally the highest-quantity

and longest-duration producers. This was attributed to enhanced

mining-induced fractures on the ends of the panels where the overburden strata were in tension on three sides due to the support of the

surrounding pillars. This observation led to the experimental placement of gob gas ventholes in the zone of tension along the margin of a

panel, instead of in the traditional centerline location, which is in

compression due to subsidence and re-compaction of the longwall

gob. Analysis of seven months of gas production data indicated that

the experimental near-margin holes produced 77% more gas than did

centerline holes on the same panel (Diamond, 1994).

Improvements in venthole gas drainage evaluation and prediction

capabilities for site-specific mining conditions and circumstances can

address longwall gas emission issues, resulting in ventholes designed

for optimum production and mine safety. To improve gas capture at a

reasonable cost, it is important to understand the behavior of the

entire gob gas venthole system, including the venthole placement and

completion strategies, the reservoir properties of the gob in the caved

zone behind the face, the fractured rock mass around the workings,

and, finally, the ventilation system. A theoretical reservoir modeling

approach is the best, if not the only, means to predict methane

emissions in advance of mining (Noack, 1998) under varying

conditions. Such an approach can also permit design of drainage

systems for either reducing the chance of unexpected methane

emissions or for responding more quickly and effectively to unknown

conditions encountered during longwall mining.

Keeping the other completion parameters constant, increasing the

gob gas venthole diameter usually increases cumulative methane

production from the subsided strata. Although a marginal decrease in

the methane concentration can be observed from this completion

change, possibly due to increased mine-air extraction with a larger

sink, the increased gas flow rate increases the overall volume of

methane produced when a larger diameter is used. Casing setting

depth also plays an important role in the amount and concentration

of methane captured. If the setting depth is close to or within the

caved zone, the methane concentration in the produced gas and total

amount of methane captured decreases. Increased casing setting

heights above the mined coal bed result in more cumulative methane

production (Karacan et al., 2007b).

One additional consideration for changing the setting depth for

the slotted casing may be the competency and productivity of the

formations surrounding the slotted casing. For example, if the

mechanical properties of the immediate strata above the coal bed at

one site are different from those at another site (caused by the presence

of a sand channel, for instance), a different caving height and fracturing

height may be expected as a result of longwall mining. Thus, the slotted

casing setting depth may need to be adjusted accordingly. Similarly, if

there are layers with appreciable gas emission potential (such as thin

rider coal beds), this may also be a consideration to capture the

optimum amount of gas by changing the setting depth of the slotted

casing. These considerations require a good understanding of the gas

emission zone above and below the mined coal seam based on the

mining and geotechnical conditions of the immediate strata.

The gas emission zones predicted by different researchers are given

in Fig. 9A and B. These graphs show the degree of gas emissions as a

function of varying distances from the mined coal bed in overlying

and underlying formations. It is not clear, however, whether these

profiles are applicable to all conditions. Itis reasonable to expectthatthe
size of the gas emission zone and the emission profiles are very much

dependent on local geology and the characteristics for formations.

Further,there is always someuncertainty associated withthe unknowns

in the overlying and underlying formations and with how they may

react to mining disturbances. Thus, a site-specific and probabilistic

approach todefine the gas emission zonemight be a better technique for

placing slotted casing and controlling emissions. Fig. 9C (Karacan and

Goodman, 2011a) shows a probabilistic method to estimate the size of

the gas emission zone based on various parameters. Fig. 9C presents the

probabilities of having less than 0.6-m displacement, with 90% of

the emission and a ratio of strata thickness to Young's modulus (T/E) of

15.2 m/GPa at various distances above the coal of longwall mines in the

Northern Appalachian basin.

Fig. 9. Gas emissions zones for longwall gob gas.
 

From Thakur (2006), Noack (1998) and Karacan and Goodman (2011a).
 

This figure shows that a gob gas venthole

drilled to within ~13 m (45 ft) above the coal seam and completed

with a 61-m (200-ft) slotted casing should be capable of withstanding

strata displacements of less than 0.6 m, especially at lower sections, as

the probability of having that much disturbance is 0.8–0.9. In addition,

the probability of capturing less than 90% of strata emissions with this

borehole is ~0.5 with a 61-m long casing. Similar probabilistic estimations for gas emission space can be made for other sites and for

various values of emissions and displacements. This methodology is

described in Karacan and Goodman (2011a).

In addition to the size of the gas emission zone, it is important to be

able to predict the properties of the gas reservoir (gob) created by

mining disturbances and to optimize the gob gas venthole parameters

and placement accordingly. Unfortunately, a standard approach does

not exist to evaluate the properties of gob and to properly design the

ventholes. Transient well tests analysis methods, such as multi-rate

drawdown and interference and pressure buildup tests that are

applied in the petroleum and natural gas industry and in coalbed

methane reservoirs, can be options to understand the characteristics

of the gob reservoir and the interaction of gob gas ventholes (GGVs)

with the gob and mining environment. The results of these tests can

be used to determine parameters such as skin, permeability, radius of

investigation, flow efficiency, and damage ratio.

The insights obtained from well test analyses can be used for a

better understanding of the gob and for designing more effective

GGV systems. However, the difficulty associated with application of
well tests is that certain reservoir geometries, boundary conditions,

and flow regimes should be determined or assumed in the absence of

relevant measurements. For instance, Karacan (2009b) analyzed the

production rate-pressure behaviors of six GGVs drilled over three

adjacent panels by using conventional multi-rate drawdown analysis

techniques. The analyses were performed for infinite acting and

pseudo-steady state flow models, which may be applicable during

panel mining (DM) and after mining (AM) production periods of

GGVs, and by radial flow models in composite homogeneous gob

reservoirs in the absence of strata separation data. Shown in Fig. 10A

and B is the flow potential versus logarithm of superposition time for

a gob gas venthole's DM and AM production periods, respectively.

These phases were analyzed separately since the reservoir properties,

due to dynamic subsidence, boundary conditions, and gas capacity of

the gob reservoir may change between these two stages. The results

indicate that reservoir properties of the “homogeneous” gob and well

productivities could be determined using these techniques. For

instance, permeability was determined to be around 3–5 darcies.

The importance of such analyses is that they give an indication of the

reservoir conditions of a longwall gob and the productivity of the

GGVs. This information eventually can be used for borehole completion designs and borehole drilling spacing. Results also can be used

to make forecasts related to long-term productivity of GGVs.

Similar techniques can be used if the presence of strata separation is

known and measured within the gob. Karacan and Goodman (2011b)

analyzed the multiple rate data of a GGV tested in such an environment.

However, since the existence of bedding plane separation was known

and its thickness and location were known, the model was set up for an

infinite acting fracture where the flow field was linear towards the

wellbore in the separation zone. Dual porosity was assumed in the

overlying and underlying gob zone. In the study, the boundary

conditions of the gob (except for the separation interval) were changed

from no-flow to infinite to observe the differences in determined

reservoir properties. Interestingly, neither the properties of the

separation interval nor the properties of rest of the gob changed.

Permeability of the bedding plane separation was close to 90 darcies,

whereas the dual porosity section was determined to have permeabilities of 200–300 mD (0.2–0.3 darcies). The permeability calculated for

the separation interval was in agreement with literature data.

Comparisons of the permeability data of this study with Karacan

(2009b) suggest that assigning homogenous properties to the gob, in

the absence of strata-separation information for well test analyses,

averages the permeability within the entire producing interval.

Well test techniques described above can also give an idea about

the effective approximate drainage radius of the boreholes drilled in

longwall gobs. For the two case studies described in the previous

paragraphs, the average drainage radii varied between 300 m and

2000 m, depending on the location of the wellbores. This information

can be helpful for both maintaining mining safety and for using such

boreholes for effective production of coal mine methane.

The above discussions briefly illustrate the challenges of designing and

operating gob boreholes under various controllable and uncontrollable

conditions. Karacan (2009a) and Karacan and Luxbacher (2010) discuss

the major factors that affect GGV productions and design parameters. In

order to address these challenges and to provide mine operators with a

practical tool, Karacan (2010) developed software [MCP version 2.0]

(http://www.cdc.gov/niosh/mining/products/product180.htm) that is

capable of predicting production rates and methane concentrations

from GGVs operating in active and completed longwall panels. The

software was developed using deterministic and stochastic methods, so

each output associates with a percentile value to indicate its place in the

entire solution domain that was considered. Fig. 11A gives a snapshot of

the outputfor aGGVoperating in an active longwall with an overlying gas

source in a low-medium volatile coal. Fig. 11B shows the variations in

methane concentrations and their percentiles that can be obtained from a

GGV under various operating conditions in active (A–A) and completed

(C–I) panels with different gas sources in the gob.

0.025 

0.02 

0.015 

0.01 

0.005 

Measured 

Model 

A 

1.E+00 1.E+02 1.E+04 

Superposition Radial Time (ΣΔta), hr 

ΔΨ/q, [106psi2cp)/MMscf/day] ΔΨ/q, [106psi2cp)/MMscf/day]

0.025 

0.02 

0.015 

0.01 

0.005 

Superposition Radial Time (ΣΔta), hr 

Fig. 10. Analyses of two different production periods of a gob gas venthole (infinite

acting: A, and pseudo-steady state: B), using flow potential versus logarithm of

superposition time in multi-rate testing.

Measured 

Model 

B 

0.E+00 2.E+03 4.E+03 6.E+03 8.E+03 1.E+04 

3.2.2. Cross-measure boreholes

Cross-measure boreholes are drilled with various design principles

for the purpose of draining roof and floor rock strata as they relax during

mining. In Europe, due to the greater depths of the longwall mines,

cross-measure boreholes are preferred over GGVs. These boreholes are

drilled at an angle over the longwall panel and oriented away from

the advancing face so that they drain gas from the entire length of the

relaxed zone on the return air side of the panel. Generally, crossmeasure boreholes drilled behind the longwall face achieve higher

production efficiencies and maintain higher gas purities than those

drilled in front of the coal face.

In longwall mining operations, strata below the mined seam may

be a major gas source, too, if they contain gassy seams or gassy

sandstones. In these situations, one advantage of cross-measure

boreholes compared to GGVs is that they can be drilled at an angle

into the strata below the mined coal bed to drain the gas of underlying

formations so it does not enter the mining environment. The angle

of cross-measure boreholes may vary from 20° to 60° from horizontal.

At least one hole is drilled at each site (Thakur, 2006), but hole

inclination and spacing can be different based on the gassiness of the

floor and roof as well as geotechnical considerations for hole stability

(Whittles et al., 2006, 2007).

Whittles et al. (2006) conducted geomechanical modeling research, augmented with field measurements, on a retreat longwall

coal panel at Thoresby mine, UK, where methane drainage using

cross-measure boreholes was undertaken for safe working conditions.

Boreholes of 75-mm diameter were drilled at regular spacings into the

roof and floor of the tailgate roadway inclined at an angle of 60° over

the longwall gob. The panel was at a depth of approximately 770 m

and 270 wide. The models predicted that there was a lack of connectivity of gas flow paths from the gas sources into the active workings,

which prevented gas inflow. Based on this observation, the
researchers speculated that coal seams that are disturbed by mining

above the longwall panel are unable to release their gas into the mine

if the intermediate strata layers are not fractured. Therefore, it was

proposed that if the cross-measure boreholes can be extended into

these coal seams, they may be producing substantially more gas.

In order to obtain an effective drainage of mine gas, sealing of the

casing collar in cross-measure boreholes is very important. A smallerdiameter liner is inserted and cemented at the borehole collar to

maintain the production. The gas produced from cross-measure boreholes may vary in rate and concentration depending on the sealing of

the borehole and gassiness of the gob. However, in any case, these

boreholes are connected to a larger pipeline system underground and

the gas is withdrawn with a vacuumsystem. Fig. 12 shows anexample of

a typical gas-gathering system for cross-measure boreholes.

Fig. 11. A snapshot of the output screen from MCP 2.0 for a gob gas venthole operating in

an active longwall panel (A) and the percentiles corresponding to different methane

percentage outputs from conditional MCP simulations of gob gas venthole production (B).

Fig. 12. Example of typical gas-gathering system for cross-measure boreholes.

From Diamond (1994).

3.3. Degasification borehole stimulation, stability, and completion issues

Stability and completion of boreholes is very important to effectively

capture methane so as to ensure the safety of the underground

workforce and to provide sufficient quantities of gas for possible

utilization purposes. This section covers some important aspects of

stimulation, completion, and stability related to various boreholes.

Coal is usually less permeable than conventional sandstone

reservoirs. Therefore, in order to effectively drain and capture coal bed

and coal mine methane, some kind of treatment (stimulation) is usually

needed to enhance the permeability around the borehole for some

distance into the coal. However, there has not been much consensus on

what type of treatment should be used. This is partly due to the fact that

the role of permeability in coal gas recovery and in well completions has

not been fully appreciated (Palmer, 2008).

Numerous published studies detail the stimulation and completion

of boreholes drilled into coal seams in various basins (Cameron et al.,

2007; Holditch, 1990; Palmer and Cameron, 2003), with some specific

strategies recommended. For instance, water-jetting has been

proposed as a stimulation technique to improve permeability and to

improve safety as well as productivity of the mining operation

through effective gas drainage (Lu et al., 2009). A water-jet cutting

system helps create artificial slices in the coal to increase its

permeability for improvement of methane drainage. Palmer (2010),

after collecting data on coal gas production worldwide, discussed the

role of permeability in choosing well completions. He defined

permeability bands as ranges of coal permeability in which certain

well completion types can be preferred. He suggested that coal

permeability in the coal seam to be produced or mined should be

defined and that well completions should be selected accordingly. In

effect, this approach leads to a decision tree which includes various

completion options as a function of the coal permeability.

Since the approach proposed by Palmer (2010) is based on

permeability, a permeability map of the coal seam should be generated

as completely as possible, with a large number of measurements that

will yield a valid statistical distribution. This is important because

permeability changes considerably due to the inherent variability in

coals as a result of the orientation of stresses, lithotypes, and rank, in

addition to other factors such as cleats and their origins. A good review

of cleat and fracture systems in coal is given in Laubach et al. (1998). A

general assignment of completions based on permeability is shown in

Fig. 13.

From a coal mine methane management point of view, multiple

seams in the gas emission zone may require horizontal wells in

overlying and underlying seams, especially if the purpose is to

degasify the emission zone and if the main source of gob gas is the coal

beds. In this case, a hybrid completion technique can be considered

based on a measurement of kH (permeability × thickness) values in all

seams. This selective stimulation is based on practical and economic

seam productivity and can be prioritized. For instance, for a vertical
borehole drilled to the main seam and with the seams within the gas

emission zone, the coals with the lowest kH values can be avoided,

whereas the highest kH seams can be completed with horizontal

boreholes and the mid-range seams can be stimulated by fracturing.

This procedure is illustrated for a hypothetical well in Fig. 14. A good

review of permeability and completions criteria is given in Palmer

(2010).

Permeability type Completion type <3 md 

Tight coal 

Multi-lateral wells 

or microholes 

Single lateral 

and/or fracturing 

Cavity, well from 

surface, fracturing 

Cavity completion 

Low-permeability 

coal 

High-permeability 

coal 

3 md 

20 md 

100 md 

Very highpermeability coal 

>100 md 

Fig. 13. Decision tree for various completion options as a function of the coal
 

permeability.
 

Modified from Palmer (2010).
 

Fig. 14. An example of selective hybrid completion based on kH. In this figure, green
 

bars represent the applicable completion techniques at different intervals, whereas red
 

bars represent that no completion is needed for the specified coal horizons.
 

Modified from Palmer (2010).
 

Stimulation of a vertical or horizontal coal mine methane (or

coalbed methane) well is often associated with hydraulic fracturing to

facilitate higher gas production rates. This method can be especially

effective if there is not much lead time to degasify the coal bed prior to

mining. Hydraulic fracture growth usually occurs perpendicular to the

least principal stress. For instance, if the least principal stress is

horizontal, the hydraulic fracture growth is usually vertical. A vertical

fracture of a CMM well that extends beyond the thickness of the coal

seam may be a concern for two reasons. First, the roof rocks of the

future longwall or room-and-pillar operation may be damaged and

create roof control problems during mining. Second, those wells with

high vertical fracture growth may experience exceptionally high

water productions that hinder gas production and effective degasification prior to mining. Colmenares and Zoback (2007) noted that in

Powder River basin, Wyoming, the coal gas wells with excessive

vertical growths produce large quantities of water, delaying gas

production significantly. However, hydraulically fractured wells with

shorter vertical fractures and lower water productions are excellent

gas producers, surpassing the gas production from horizontally

fractured wells in the same seam. Thus, it is important to engineer

and control hydraulic fracture directions and growths in CMM capture

boreholes.

In order to ensure the capture of coal bed and coal mine methane

effectively, stability of the boreholes drilled for these purposes is of

critical importance. In CMM production boreholes, stability and

reliability can be a significant problem because coal is a weaker

material than sandstones and limestones, and the stress concentration around the boreholes may cause boreholes to fail easily. In

addition, the stresses created by mining activities in the coal can lead

to additional stresses and displacements in the formations surrounding the boreholes, which can lead to borehole failure. These situations

are more severe when the boreholes are completed open-hole (not

cased).

Borehole stability problems can cause stuck pipes, borehole

enlargement (ballooning), poor cleaning, and deviation control when

drilling horizontal holes in coals. In engineering practice, there are

methods to testthe stability of wellbores during drilling in formations of

various strengths. These methods include the Mohr–Coulomb criterion

with parameters based on triaxial test data to predict the polyaxial

strength of rocks. However, Zhang et al. (2010) reported that this

method under-predicts and is significantly conservative in estimating

the minimum mud pressure required for ensuring wellbore stability. On

the other hand, the authors reported that the Drucker–Prager criterion

with parameters based on triaxial test data over-predicts the polyaxial

strength of rocks and is unsafe in relation to estimating the minimum

mud pressure required for ensuring wellbore stability. In the case of the

3D Hoek–Brown and Mogi–Coulomb criteria, the prediction errors were

relatively small (Zhang et al., 2010); thus these were recommended as

preferred methods.

Borehole stability issues may also arise during drilling and

production of methane from the coal seams. Therefore, designing a

drilling pressure based on the depth of the borehole and the type of

formation is important. In addition to conventional rock strength and

mechanics analyses that can be performed to assess the stability of

boreholes, one should bear in mind that effective pressure (overburden

pressure minus pore pressure) of the coal seam and the distribution of

cleats may play a significant role on the normal stresses acting on the

cleats and fractures in coal seams. Thus, if effective pressure changes

suddenly in the immediate vicinity of the boreholes, the fractures may

propagate and the borehole may fail suddenly. Therefore, drilling should

be performed by adjusting the bottom-hole pressure, especially if the

coal seam is permeable, so that the pore pressures do not change

suddenly around the borehole. In the case of permeable coal seams, coal

fines may also migrate easily and create a skin around the borehole

within the cleats and fractures. This skin creates a time-delay effect (Qu

et al., 2010) for re-establishment of effective pressure that should be

taken into consideration to prevent failure of horizontal wells,

particularly due to their length and the times necessary for their drilling

and completion.

Gentzis (2009) conducted an experimental and modeling study

specifically on coal samples for stability analysis of horizontal coal

seam methane wells in the Mist Mountain Formation, SE British

Columbia, Canada. The vertical stress gradient was calculated by

integrating a bulk density log from an offset well. Horizontal maximum and minimum stresses were estimated from regional stress

data, whereas formation pressure was estimated on the basis of a

local hydrological study. The 2D elasto-plastic STABViewTM numerical

modeling code was used. Stability analysis was performed at bottomhole pressures ranging from overbalanced to underbalanced (with

drilling pressure greater than and less than formation pore pressures,

respectively). This was done in order to simulate the conditions

expected during drilling and production. It was concluded that when

drilling at a 650-m depth in underbalanced to slightly overbalanced
conditions, there was a high probability of the drill pipe becoming

stuck. On the other hand, when peak cohesion of coal was reduced by

50% to reflect the conditions expected along weak intervals of a

horizontal wellbore, the predicted enlarged borehole was almost 85%

greater than the designed well diameter under the same drilling

conditions. The most unstable trajectory was perpendicular to the

maximum horizontal stress in the study area. Modeling indicated that

a production liner should be inserted immediately following the

drilling of the horizontal well in this structurally complex geologic

setting, since pressure drawdown and reservoir pressure depletion

would lead to enlarged yielded zones and collapse of the wellbore

over time.

In addition to geomechanical properties of formations and the

geological stresses where the boreholes are located, drilling-fluid

related issues may become a concern. For shallow wells or for wells

drilled from gateroad entries, this may not be a critical issue, but for

wells drilled from the surface into the coal seams, fluid invasion

during drilling and completion operations can produce formation

damage to low-permeability coals in the cleats around the wellbore.

Laboratory tests conducted using large-diameter cores showed that

the three different mud systems tested (Xantham Gum, HEC, and NaCMC) did not negatively impact the coal permeability (Gentzis et al.,

2009). The use of FLC 2000TM and Q-Stop in two field applications

resulted in the successful drilling of 1400 m and 953 m of total

horizontal length, respectively. During production, a small pressure

drop was sufficient to remove the filter cake. Drilling was done in the

deep Mannville coals in Alberta and at depths ranging from 1150 m to

1400 m. No borehole instability problems were encountered during

drilling of the two horizontal wellbores. The mud losses were also low

in both cases, with the horizontal well #2 experiencing lower mud

loss. Horizontal well #1 remained stable, which allowed sufficient

time for the insertion of a production liner.

Stability problems are more severe in GGVs and cross-measure

boreholes since the strata displacements are unpredictable and can

completely destroy the borehole, and can shear-off or bend the casing.

For instance, two separate gob ventholes in Xieqiao mine in China,

which began production with 30 m3 and 10 m3

/min initially, ceased

producing gas. Investigations for the causes of lost production showed

that both the solid and the slotted sections of these wells were

sheared at multiple locations along the borehole (Han et al., 2009). A

similar situation was observed in the Zhangji mine (China). A well

that started production with more than 40 m3

/min ceased production

after a week due to casing failure.

Whittles et al. (2007) examined Panel 44 of the Thoresby mine, UK,

for the effects of the immediate roof geology and roadway support

system on the integrity and effective life span of gas drainage

boreholes drilled into the roof strata. The results obtained from the

models indicated that the immediate roof strata would experience

significant vertical and shear displacements where the magnitude of

the movements were very dependent on the roof geology, which

determined the roof movements. For a strong sandstone roof, the

predicted movements were relatively small compared to the movements of a siltstone bed, where the roof movements were large. Above

the immediate roof, it was noted that discrete horizontal shear planes

at approximately four horizons could potentially intercept and

rupture the borehole (Fig. 15).

Fig. 15. Deformation of a steel casing of a vertical hole drilled into the immediate roof of

a mine (Whittles et al., 2007).

The initial failure of the standpipes

due to horizontal rock shear was predicted at distances between 8.9 m

for a weak mudstone roof and 11.3 m for a stronger sandstone roof.

If the source of mine methane is in the floor and cross-measure

boreholes are to be used to control these emissions, it is necessary to

evaluate the stress state within the floor of the longwall panel. Zhao

et al. (2000) presented an analytical solution to determine the

horizontal stresses in the floor of a longwall mining panel. The authors

considered only the most important factors to develop an engineering

model. In that study, empirical models that were used to analyze roof

mechanical issues were extended and used to develop models for

floor mechanics. A number of parametric solutions using the proposed

method to solve the horizontal stress problem were given. This

method can also be used to evaluate the stability issues of crossmeasure boreholes drilled into the floor of a longwall mine to control

methane emissions.

4. Geological features and heterogeneities that affect gas

emissions and removal from mines

Abnormal, unanticipated mine gas emissions in quantities sufficient to create hazardous conditions have often been attributed to

various geologic features since the first recorded documentations of

methane explosions in mines. For example, geologic features such as

faults have long been recognized as conduits for gas flow from strata

adjacent to mined coal beds. Other features such as sandstone paleochannels, clay veins, changes in permeability facies and coal types,

and localized folding and shearing of the coal bed have also been

widely recognized for their impacts on gas emissions into mine

workings (Beamish and Crosdale, 1998; Diamond, 1982; Li, 2001, Li

et al., 2003; Noack, 1998; Ulery, 2006).

It is not surprising that strata adjacent to mined coal beds can emit

great quantities of methane gas into active mine workings. During the

burial and diagenesis of the organic matter that ultimately forms

mineable coal beds, similar dispersed organic matter in adjacent

strata can produce methane in quantities far exceeding the storage

capacity of the coal and surrounding rock. As a result, large quantities

of methane can remain trapped in these strata. The flow of this gas at

high rates into the mine workings may be either facilitated or

temporarily impeded by the presence of geologic structures or

anomalies during mining of the nearby coal seams. The emission

events that are often distinctly associated with geologic features of

varying scale are occasionally immediate and catastrophic; however,

more often, these emissions are subtler and not easily detected

without field reconnaissance and instrumentation.

The existence of various geologic anomalies and coal bed discontinuities, such as partings, faults, sand channels, and changes in

coal bed properties, can create serious problems in the drilling, completion, and production of degasification boreholes. These geologic

features can affect both the effectiveness of these boreholes for

draining methane from the coal bed and for limiting methane

emissions into the working sections by creating boundaries, high­
pressure gas and water pockets, and by changing flow characteristics

of the reservoir. Thus, site-specific considerations are required for

these challenging situations (Diamond, 1982).

In underground coal mines, the required amount of ventilation air

is based on estimates of gas release under normal conditions.

Occasionally, unanticipated and unusually high emissions are encountered. These emissions, despite normal ventilation controls, may

result in an explosive mixture at the face that may be ignited during

mining. Investigations have shown that such emissions can often be

associated with anomalous geologic features or conditions. While

most mine operators are aware that certain geologic features may

adversely affect productivity, few are aware of their potential as a gas

emission hazard (Ulery, 2006).

4.1. Effects of faults in coal bed on mining, mining gas emissions, and

degasification efficiency

It is known that faults affect production characteristics of nearby

coal bed methane boreholes. Faults can create boundaries for the

drainage radii of the boreholes. These boundaries can be favorable or

unfavorable in terms of gas production, depending on the size of the

bounded reservoir. If the bounded volume is small, a limited amount

of the reservoir will be drained and thus the production potential of

such a reservoir will be low. If the borehole is drilled into a large but

bounded reservoir, this will potentially lead to a faster pressure

drawdown when dewatering is initiated, causing higher gas saturations and faster production rates.

The effects of faults on coalbed gas productions have been

experienced in various regions. For instance, in the southeastern

Deerlick Creek field (Alabama), fault blocks have variable production

characteristics. Exceptionally productive wells drilled near the eastern

margin of the Strip Mine graben have penetrated a fault and are

actually completed in the Holt Lake half graben (Sparks et al., 1993).

Although production within the half-grabens is variable, large-scale

production patterns in the southeastern Deerlick Creek field indicate

that normal faults can compartmentalize coalbed methane reservoirs.

Similarly, production patterns in the Cedar Cove field of Alabama

(Sparks et al., 1993) indicate that being adjacent to a major fault

system has enhanced gas and water production. Pashin and Groshong

(1998) also reported major production experiences in complexly

faulted regions in the coalbed methane fields of Alabama. Evidence

suggests that faults in the Oak Grove field of the Black Warrior basin

affect gas and water production as well as the thicknesses of the

seams, especially in the up-thrown fault blocks. Patterns of gas and

water production in the Deerlick Creek field provide evidence of

structural segmentation of coalbed methane reservoirs by normal

faulting. Exceptional production of both gas and water in parts of the

Holt Lake and Franklin Hill half-grabens indicates local enhancement

of permeability, and may also indicate a heterogeneous distribution of

gas and water. Variable well performance in all parts of the field may

be a product of engineering practice as well as interwell heterogeneity

that is not discernible at the scale of the study. However, based on

these observations and on others in Alabama's coalbed methane

fields, Pashin and Groshong (1998) produced a conceptual model

(Fig. 16) on structurally controlled coalbed methane production. The

significance of these structures in terms of coalbed methane

exploration and production has yet to be fully appreciated (Pashin

and Groshong, 1998).

The tectonic events have had significant influence on the

generation and preservation of the coalbed methane (CBM) in the

Weibei Coalfield, China, as well. The Triassic–Cretaceous Orogenies

may have had significant influences on the generation of coalbed

methane, while the Tertiary Himalayan Orogeny may have had crucial

effects on its retainment (Yao et al., 2009). During the Triassic–Early

Jurassic, compressional deformation led to formation of a series of

thrusts and folds that significantly influenced the preservation of

methane in the Hancheng coal district where coalbed methane is

concentrated in the axes and slopes of anticlines and fault zones.

During the Yanshanian Orogeny (Jurassic–Cretaceous), compressional

structures switched to a NW–SE orientation and had the most

significant influence on the south margin of the Hancheng coal

district. This event provided a good preservation environment for

CBM and led to secondary gas generation and higher gas content (Yao

et al., 2009). Thus, provided that reservoir properties of the coals are

favorable, high methane productions and emissions in the mines in

these regions can be expected.

Kedzior (2009) evaluated the methane accumulation in the Upper

Silesian coal basin, Poland, and found that the Bzie–Czechowice fault,

with a 200–600-m throw to the south, is an important tectonic

element in the area. The study indicated that this fault and related

fissures had probably always been pathways for upward gas

migration. With the deposition of the Miocene clays, a methane

reservoir began to develop on the up-throw side of the fault with

methane contents relatively high (N10 m3

/ton coal) near the fault in

the Pniówek Mine. Measured methane contents in the Krzyżowice

#28 and #30 boreholes on the up-throw side (N6 m3

/ton coal)

exceeded those in the Bzie–Dębina #20 borehole on the down-thrown

side ( 3 b4 m /ton coal). These data clearly show that the methane field

is interrupted by the Bzie–Czechowice fault. The coal beds with the

highest quantity methane are Carboniferous and are usually found

near the up-thrown side of the fault, compared to the down-thrown

side, which is less gas-rich. This shows that major faults can

compartmentalize the coalbed methane reservoirs.

A related example was given Su et al. (2003). The authors

discussed the conditions that led to the abnormal pressure regime

of the Pennsylvanian age No. 8 coal seam in Liulin–Wupu District,

Eastern Ordos basin, China. Based on their analyses, the authors

suggested that the abnormally high pressures are associated with

local hydrodynamic trapping and that this is where most productive

coalbed methane wells are located. The authors further noted that

there is a change both in pressure and in its gradient from east to west,

where the southwestern part of the Anjianshan–Wupu area is underpressured. This was attributed to the influence of the F1, F2, and F3 (F3

shown in Fig. 17) fault zones. In this area, every fault zone is

composed of two normal faults that form a graben. The groundwater

and the coal seam gas escaped along the fault zones, which lowered

the gas content and hydrostatic head in the southwestern area. In

other words, the basin was compartmentalized.

Faults are important for underground mining due to their prementioned characteristics. Thus, effective mapping of faults in coal

mining is critical for productivity and safety of the workers. This is

especially true where the coal seams are impacted by large

displacements (Kecojevic et al., 2005; Molinda and Ingram, 1989).

For instance, underground room and pillar mines in the Coalsburg

seam north and south of the Warfield fault in Mingo County, West

Virginia, have been greatly impacted by the fault and related

structures. Due to the combined effects of the folding and faulting,

the northern mines are about 15 m (400 ft) higher in elevation than

the southern ones. Overland conveyor belts connect mining blocks

separated by the fault. The fault poses an extra challenge to mine

development in this part of the Appalachian basin (Coolen, 2003). The

location of faults is also important to mining of the Western Kentucky

No. 4 seam, since much of the mining occurs along the Pennyrile fault

system and many mines are bordered with faults. In this region, the

mines are sometimes forced to ramp up and down to reach a relatively

flat reserve (Greb et al., 2001).

Faults and the associated weakness zones may also be responsible

for high gas concentrations encountered during mining (McCulloch

et al., 1975). This is especially likely when there is stress redistribution

as mining approaches a large-scale fault. In Germany, Thielemann

et al. (2000, 2001) showed that in unmined regions, normal faults

regularly act as gas conduits for surface emissions into the atmosphere
from deep formations such as coal beds. The authors further

demonstrated that distinctly higher rates of surface gas emission

occurred from normal faults in mined areas. This was presumably

caused by the increased permeability ofthe fault and associated strata in

response to mining. Therefore, it would seem likely that such faults

could easily become pathways for gas emissions into mine workings

from adjacent source beds.

Fig. 16. Conceptual model of structurally controlled coalbed gas production in Alabama's coalbed methane fields.

From Pashin and Groshong (1998).

Fig. 17. A hydro-geological profile in Liulin–Wupu District, Eastern Ordos basin.

From Su et al. (2003).

Alsaab et al. (2009) presented a study to estimate the production

of methane, to define its migration paths and storage in formations,

and to forecast mining hazards in the Donets basin (Donbass),

Ukraine. The authors indicated that in the Donets–Makeevka area,

where specific methane emissions are ~60 m3

/ton, gas migrated along

faults, and gas accumulations were mostly close to structural

deformations and in the hanging walls of reversed faults. Gas also

migrated and accumulated along W–E extending faults in the region.

From a mining safety and CMM recovery point of view, the outburstprone coals are found in coal mines where specific gas emissions are

high. The zone with 60 m3 methane/ton of mined coal corresponds to

the Zasyadko coal mine that is located close to Donetsk city, which is

close to the Donets–Kadievka fault. This coal mine was reported as

very dangerous because of coal and gas outbursts. It was further

observed that (Fig. 18) the outbursts (circles) are located all alongside
of a particular panel of the mine and located in the vicinity of smalldisplacement faults and knee-shaped folds. Small-displacement faults

which caused dramatic obstacles for safe and efficient underground

coal mining have been traditionally interpreted in the Donbass as

being normal and/or reversed faults with a vertical or stratigraphic

displacement of less than a few meters.

Fig. 18. Structural and mine map of the coal seam in the Zasyadko coal mine.

From Alsaab et al. (2009).

Shepherd et al. (1981) integrated various aspects of stresses, gas,

and geological structure in a worldwide review of outbursts of coal

and gas in coal mines. The authors identified geological structures as a

prime factor in outburst occurrence. They noted that thrusts, strikeslip faults, and recumbent fold hinges are especially outburst-prone

and concluded that anomalous stress and gas conditions exist in and

close to geological structures. At such sites, mining-induced fracture

systems, microseismic noise, and abnormally high gas emissions have

been recorded. Cao et al. (2001) investigated four coal mines in the

Pingdingshan coal field, Henan Province, China. The authors reported

that coal and gas outbursts associated with reverse faults (Fig. 19)

almost always occurred in the footwalls of the reverse faults which

underwent greater tectonic deformation than those in the hanging

walls. In those areas, coal lost its banded character and was physically

transformed into microstructurally altered forms categorized as

cataclastic coal, granular coal, and mylonitic coal.

Fig. 19. Outbursts in the footwalls of reverse faults in the No. 12 coal mine of Pingdingshan
 

Coal Administration.
 

Modified from Cao et al. (2001).
 

They reported that

outbursts always occurred within a zone of this tectonically altered

coal surrounding the fault. Therefore, the identification of fault

and methane-pressure buildup zones may be the key for effectively

draining the coal gas ahead of mining to reduce gas pressure and to

control outbursts.

As demonstrated in the previous discussions, geologic faults in a

coal seam can cause intermittent production problems or can cause

unexpected amounts of water or gas to issue from degasification

boreholes. These faults also can impact methane emissions into the

mine workings, especially if they hinder proper and effective

degasification of the coal bed. Faulting may also cause gas pressure

buildups and result in compartmentalization of the gassy regions,

from which large quantities of water and methane may rush into

the mine workings. In order to investigate the effects of impermeable faults on the production performance of vertical and horizontal

degasification boreholes, and on methane emissions into an advancing

longwall, Karacan et al. (2008) conducted a reservoir-simulation-based

study.

Fig. 20 gives a cut-away view of the reservoir simulation grid

for the case of a down-thrown block (A) as well as the effects of the

proximity of the fault to a vertical borehole on water and gas

encroachment into the approaching longwall (B). The general

conclusions of this simulation study indicated that the methane

production of a horizontal borehole was not significantly affected by

the presence or displacement direction of a fault located 343 m

distant. This was not the case with a vertical borehole, which after

175 days of operation showed increased methane production compared to the base model. This increased methane production likely

arose from the pressure transients from the vertical borehole reaching

the impermeable fault boundary and causing increased production from the wellbore-side block. Further simulations showed that an

impermeable fault in close proximity to the vertical borehole had

greater impact on its production. A fault located farther from this

borehole had much less impact.

The location of a vertical borehole limits the methane emissions

into a mine in a faulted coal seam. Simulations were conducted of

methane and water inflows in the presence of a fault located 343 m

distant from a longwall face (Karacan et al., 2008). The results showed

dramatic reductions in gas and water inflows once the face passed

through the fault into the borehole block. These data suggest that

mining into the borehole block is preferable to mining in the other

direction, which would lead to dramatic increases in methane and

water inflows. Similar results were found when the impermeable fault

was located 114 m and 572 m distant from a vertical borehole.

Methane emissions and water inflows again decreased once the face
passed through the fault. Average reservoir pressures also decreased

at this point.

Fig. 20. A cut-away of the reservoir simulation grid for the case where a down-thrown block is shown (A) as well as the effect of the proximity of the fault to vertical borehole on

water and gas encroachment into the approaching longwall (B).

Ulery (2006) provided some borehole designs to drain potential

gas emission sources associated with normal and reverse faults. These

options are given in Fig. 21 for various types of faults and directions

from which the mine entry approaches.

Fig. 21. Methane drainage of a normal fault from “footwall” (A) and hanging wall (B) sides. Methane drainage of a reverse fault from the “hanging” wall (C) and “footwall” sides (D).

From Ulery (2006).

The author also indicated that

if the faults and their possible throws were not mapped accurately,

both vertical and horizontal boreholes may miss a portion of the coal

seam for degasification and this may result in inaccurate estimations

of expected gas emissions into the mine.

4.2. Effects of partings in the coal seam for coal mine methane emissions

and degasification

Coal beds can include various non-coal materials deposited during

peat accumulation. Such non-coal material may be referred to as

partings in the coal bed. These non-organic material-rich horizons are

composed of mineral matter that is commonly argillaceous (clay),

siliciclastic (quartz-dominated), and occasionally includes carbonate

rocks. Most are the result of changes in the depositional environment

within the peat swamp in which the coal was forming. A special form

of parting is composed of altered volcanic ash layers (tornstein) which

represent volcanic events of short duration and therefore are nearly

isochronous horizons, such as in the Ferron group in Utah, which may

also be found within coal seams (Lamarre, 2003). Rock partings or

parting layers create density variations in the coal, which are a

function of mineral material, or ash, within the coal seam (Beaton

et al., 2006; Manchioni, 2003). Most importantly in relation to fluid

and gas flow, these partings create strong discontinuities in the

petrophysical fabric (porosity and permeability) within the coalbed

methane reservoir.

During coal seam degasification, boreholes drilled in an area of

extensive partings could encounter irregular flows of gas. A horizontal

borehole drilled completely above or below an extensive parting, or a
collection of partings that effectively separates a coal bed into separate

reservoirs, may drain methane only from that portion of the coal bed.

The rest of the coal bed would remain undrained and the gas still would

represent a potential hazard to the future mining activity or would be

unavailable for commercial production (Diamond, 1982). In the case

of vertical boreholes, encountering partings can also be problematic to

the flow of gas. Since the length of a vertical borehole is much less than a

horizontal borehole, drilling into a thick parting interval may render the

borehole useless.

Extensive parting layers can create problems in stimulating wells,

too. If the fracturing treatment does not penetrate effectively above

and below the parting, the flow could be reduced. Parting layers that

compartmentalize the coal bed hydraulically are also important from

a mine ventilation standpoint since they can isolate large volumes of

gas that can suddenly be liberated when penetrated by a mine entry.

4.3. Effects of permeability facies and spatial changes in coal types and

coal microlithotypes on emissions into mines

One of the common features of coal beds is variation of coal types.

These variations manifest themselves as changes in petrographic

characteristics of the coal on various scales, from megascopically

recognizable units – lithotypes to microlithotypes and macerals – to

changes in geomechanical properties of the coal seam. The origin of

coal type variations can be due to groundwater level fluctuations in

the ancient peat-forming environments, different peat accumulation

rates (Silva et al. 2008, or changes in the type of primary vegetation

that contributed to the peat (Calder, 1993; Diessel et al., 2000; Moore,

1989). From duller to the brighter lithotypes, there is a significant

decrease of inertinite contents and an increase in vitrinite. Local

variations in inertinite contents can be linked to an incomplete

burning of the organic matter by local fires or aerobic biodegradation

due to bacterial attack when the water level dropped (Silva et al.,

2008.

It has been previously recognized and documented that different

coal components have varying gas generation and storage capacities

(Beaton et al., 2006; Gurdal and Yalcin, 2000; Karacan and Mitchell,

2003; Lamberson and Bustin, 1993. Most researchers agree that

vitrinite-rich, bright coals have a greater methane adsorption capacity

than inertinite-rich, rank-equivalent coals. However, in some cases,

inertinite-rich coals have been found to have the greatest methane

adsorption capacity (Clarkson and Bustin, 1996; Karacan, 2007a,b;

Mastalerz et al., 2004) mostly due to the volume created by the fusinites

with open-cell lumina. An example scanning electron microscope

(SEM) image of fusinites and phyteral porosity filled with clay minerals

is shown in Fig. 22.

Fig. 22. SEM image of fusinite in Acilik coal (Zonguldak Basin, Turkey) with phyteral
 

porosity partially filled with clay minerals.
 

Modified from Karacan and Okandan (2001).
 

Different coal types also have different desorption rates, which

can impact gas emissions and borehole productions. Studies on coal

samples have shown that dull coals desorb more rapidly than bright

coals (Karacan and Mitchell, 2003; Karacan and Okandan, 2001). Both

rank and coal type were found to influence effective diffusivity. Dull

coals have faster desorption rates (2–3 times) than their bright

equivalents in most cases (Laxminarayana and Crosdale, 1999) due to

a predominance of large, open-cell lumina (Crosdale et al., 1998;

Karacan and Mitchell, 2003; Karacan and Okandan, 2001). Bright,

vitrinite rich coals usually have the slowest desorption rates, which is

associated with their highly microporous structure. Therefore, a

horizontal borehole trajectory that follows the dull layers may have a

better chance of producing higher gas rates.

The importance of different coal lithotypes and microlithotypes in

underground coal mining has been summarized in previous studies.

For instance, variable gas desorption rates for different coal types

were reasoned to impact outbursts in mines (Beamish and Crosdale,

1998). As pressure is removed from the coal in the mine-face environment, different desorption rates of the coal lithotypes create a

large gas content gradient, as follows: (1) vitrinite-rich or inertodetriniterich coal bands do not desorb rapidly, retaining their gas and thus

producing a steep gas content gradient and (2) fusinite-rich or semifusinite-rich coal bands lose their gas more rapidly and thus have a

shallow gas content gradient. In addition, when the coal strength

information is combined with the sorption behavior of coal macerals,

it is suggested that the outburst-proneness of coals rich in vitrinite

and inertodetrinite is greatly increased (Beamish and Crosdale,

1998). Overviews of coal-gas outbursts are also given in Flores

(1998), in Beamish and Crosdale (1998), in Noack (1998) and in

Shepherd et al. (1981).

Permeability is a critical factor controlling methane and water

production from coal seam reservoirs and for determining the

efficiency of a degasification project. However, reservoir permeability

usually is not constant and not uniform throughout the reservoir. Coal

cleats, their spacing, and their permeability are known factors

creating preferential flow direction and magnitude in the coal seam.

Coal deformation is another factor affecting coal permeability. For

instance, in the Qinshui Basin of China, the coal seam is severely

deformed and contains mylonitic structures where the primary

permeability is obstructed. Thus, permeability of the coalbed methane

reservoir is controlled by shear fractures, creating significant reservoir

heterogeneity and making it difficult to describe a permeability

distribution (S. Su et al., 2005; X. Su et al., 2005) for degasification

studies.

Generally, high permeability areas in the coal bed are more

productive and better suited for methane production compared to low

permeability zones. For example, the highly productive “fairway

zone” of the Fruitland formation in the San Juan Basin of Colorado

and New Mexico contains individual wells that can produce 28–

170 × 103 m3

/day (1–6 MMscf/day). Permeability within the San Juan
Basin ranges from 15 to 60 mD in the high productive fairway zones

and tapers to less than 5 mD in the least productive areas of the basin

(Ayers, 2002). This and similar studies suggest that the highest

permeability coals have the best reservoir characteristics. However,

Bustin and Clarkson (1998) showed that such reservoirs consequently

may have the lowest gas saturation due to leakage and thus may

have poorer coalbed methane resource potential. On the other hand, if

the coal seam is non-permeable, it may have a higher gas content

which may be released only during the crushing process as mining

progresses. This condition may lead to lower gas production potentials during degasification, but higher methane emissions that may

create an unsafe atmosphere during mining.

In the Black Warrior basin, a strong structural control is present

on gas and water production, and the relationship of production to

structure is different in each field analyzed. Variable well performance

in all areas suggests that hidden inter-well heterogeneity related to

fractures, high permeability pathways, and shear structures influences production (Pashin, 1998). Thus, the regional permeability and

the gas content generalities cannot be applied uniformly across the

basin or to each coal seam.

5. Methane emission and recovery from abandoned underground

coal mines

Following mining activities, coal mines are typically sealed and

abandoned either temporarily or permanently. To prevent methane

buildup and gas migration to the surface through overburden

fractures, some underground abandoned mines may continue to be

vented to the atmosphere through wells, portals, and shafts. As work

stops within the mines, the methane liberation decreases but it does

not stop completely. Following an initial decline, abandoned mines

can liberate methane at a near-steady rate over an extended period of

time or, if flooded, for only a few years.

Unintentional venting of methane can also occur through the

conduits described above, particularly if they have not been sealed

adequately. In addition, diffuse emissions can occur when methane

migrates to the surface through cracks and fissures in the strata

overlying the coal mine. The following factors influence abandoned

mine emissions:

• time since abandonment;

• gas content and adsorption characteristics of coal;

• methane flow capacity of the mine;

• mine flooding;

• presence of vent holes; and

• mine seals.

Water encroachment into the abandoned mines is common if the

mines are connected to the local hydro-geologic system by faults or if

the extracted coal seam was part of the system. Continuous water

flooding into abandoned mines is important if it rebounds to the

natural levels and reaches the surface. These discharges from

abandoned mines are characterized by high sulfate and iron with

low alkalinity as a result of oxidation of pyrite. The ferrous iron often

subsequently oxidizes and hydrolyzes, precipitating “orche” that can

smother stream beds and can devastate the quality and ecology of

surface waters (Banks and Banks, 2001). Discharges from abandoned

mines from an extensive network of abandoned underground coal

mines in the Uniontown Syncline, Fayette County, PA, showed that

water quality can improve over time (Lambert et al., 2004). The

degree and rate of water quality improvement was found to be highly

dependent on the amount and duration of flooding in the mine voids.

Water quality of discharges from the substantially flooded mine voids

(roadways, gob, room-and-pillar sections) improved significantly,

going from acidic water with high sulfate and iron concentrations to

alkaline water with substantially lower sulfate and iron concentrations. In contrast, the water quality in the unflooded mines showed

less improvement.

Water quality and management of discharges from abandoned

mines is an important consideration, but it is beyond the scope of this

paper. Therefore, this discussion will simply note that abandoned

mines can be completely and partially flooded over time, which is

important from a gas management and capture point of view, since

flooding can inhibit gas emissions and buildups in the void spaces.

The rate and amount of methane buildup is usually proportional to

how much coal is leftin these areas,the coal's gas contents and reservoir

properties, the amount of mine void that is not flooded, and the

existence of other gas sources within the gas emission zone of the

abandoned area. Gas accumulation and pressure buildup within

abandoned mines can be potentially dangerous for active mines, if

they are nearby, by overloading the ventilation system as a result of gas

inflows into working areas during periods of decreasing atmospheric

pressure. Abandoned mines can also present a danger to active

mines operating at a greater depth if the abandoned mine happens to

be within the fracture zone, so that any methane accumulation can

migrate downwards into the active mine to create a sudden methane

emission into the ventilation system. Therefore, abandoned mines

sometimes are left venting to prevent gas accumulation.

Instead of releasing methane emissions from abandoned mines to

the atmosphere, recovery and utilization should be considered. This

will both reduce the possibility of methane emissions into underlying

or nearby operating mines and limit the greenhouse effect. However,

if the abandoned mine is close to the operating mines, drilling

production boreholes and setting operating pressures should be done

with full knowledge of the location and condition of the seals and the

mine voids.

5.1. Detecting mine voids

Detection of mine voids to produce gas from abandoned workings

has usually relied on existing maps and exploration boreholes.

However, maps may not be updated and thus may not show the

existing boundaries of abandoned workings. In addition, the extent

of pillars and old workings can change due to underground stress

conditions. Therefore, the maps that show the conditions at

abandonment may not give the most accurate information on the

latest conditions. A similar argument may apply to exploration

boreholes for voids: they may not be fully informative on the

conditions and sizes of voids, while the characterization of regions

between boreholes remains unknown. Therefore, geophysical measurements can be used to augment the borehole data, improve the

knowledge of intermediate zones between exploration boreholes, and

better identify the voids in abandoned workings. Furthermore,

geophysical techniques can be used to optimize the number and

locations of the producing boreholes and their proximities to

abandoned mine seals and active mines.

There are several surface geophysical methods that are applicable

to detect subsurface voids such as gravimetric, seismic measurements,

electromagnetic methods, magnetic, and ground penetrating radar.

The operational principles of these methods will not be covered here;

however, it has been demonstrated that commercially available

technology can effectively detect and delineate mine abandoned

mine workings (Johnson et al., 2002). Two techniques in particular

have shown the greatest potential for application. The DC resistivity

method offers the best potential for the rapid mapping of mine

workings at a depth of 40 m or less. For workings at depths of 40 m or

greater, the seismic reflection method, especially with the use of

S-waves, has the greatest potential for success.

Johnson et al. (2002) have demonstrated the use of various S-wave

profiles over abandoned coal mines to detect mine openings that

would be suitable targets for the installation of methane extraction

wells and to evaluate the conditions of these old workings. During the
trials to detect voids in these studies, boreholes were also drilled on

the basis of old mine maps. However, some of the boreholes did not

encounter the mine voids. S-wave surveys were performed in lieu of

conventional P-wave surveys to detect the mine voids, because

S-waves would not transmit through a void. It was demonstrated that

S-wave seismic surveys can be used successfully to locate mine

openings. Fig. 23 gives an example of detecting mine voids using

reflection amplitude for a mine in Danville, Illinois.

Fig. 23. Intact coal and mine voids detected using S-waves in a mine in Danville, Illinois.

Modified from Johnson et al. (2002).

5.2. Methane emissions evaluation

The U.S. Environmental Protection Agency (U.S. EPA, 2004) has

documented probably one of the most comprehensive and detailed

inventories of abandoned mines in the U.S. and developed a methodology to evaluate their methane emissions potential in relation to

producing this gas. This study classified the abandoned mines into

three general categories – sealed mines, flooding mines, and venting

mines – and proposed an evaluation strategy for each. Fig. 24 shows

U.S. EPA (2004) methodology for calculating abandoned mine

emissions.

As has been demonstrated in the previous sections of this review

paper, CMM generation and emission in active mines can be functions

of various coal- and mining-related parameters. However, in

abandoned mines, mining-related parameters can be canceled out

and methane emissions can be thought of and evaluated only in terms

of coal gas content and pressure at abandonment, the void space, gas

emissions space left from the mining disturbances, permeability of

the methane source into the mine voids, and the boundary conditions of the mine (i.e. whether it is being vented, tightly sealed, or

being flooded as a function of time). Therefore, an abandoned mine

can be characterized as a well experiencing rate transient (decline),

and decline curve techniques can be used to evaluate gas emission

potential and duration.

In traditional decline curve techniques, constant or timedependent decline rates can be analyzed using exponential,

hyperbolic, or harmonic decline functions. The U.S. EPA (2004)

method also uses these techniques and proposes that a hyperbolic

decline function can closely characterize the measured methane

emissions rate from abandoned mines as a function of time. By fitting

field data to a hyperbolic equation, the decline coefficients can be

determined for a particular mine, in a specific basin, and with

different mine conditions corresponding to flooding and venting

cases. From these data, future emission potentials can be forecasted

and engineering planning and economic analyses can be made.

Using traditional decline curves for evaluating emission potential of

abandoned mines can be acceptable for abandoned mines evaluation,

although traditional decline curves are mostly used for non-coal

reservoirs in oil and gas engineering. But more importantly, they are

formulated to be used only for the boundary-dominated flow regime of

a wellbore, neglecting any transient portion. Therefore, it may be a

better and a more informative approach to use the Fetkovitch type

curves (Dake, 1978), which have both traditional empirical decline

curve stems (exponential, hyperbolic, and harmonic) for the boundarydominated region, and a transient portion for the theoretical constant pressure solution to the diffusivity equation. This approach covers

both flow regimes while evaluating the emission potential of an

abandoned mine.

An example of Fetkovich-type curve with fitted data of a GGV is

given in Fig. 25. In this figure, different solutions in boundarydominated and in transient-flow portions are represented with

different colors to match the field data. In the boundary-dominated

part, curves with different colors represent the decline coefficients.

For instance, the red curve is “0” and indicates exponential decline,

whereas the green curve in the middle is “0.5” and indicates

hyperbolic decline. The transient portion is composed of theoretical

constant pressure solutions to the diffusivity equation for different

dimensionless external radii that are shown with different colors. In

this set of solutions, the dark blue is reD= 10,000, and the red is

reD= 10. Other colors correspond to different dimensionless radii

values. This information can be used to calculate permeability, skin,

original gas in place, expected ultimate recovery (EUR), and time to

abandonment.

Numerical reservoir simulation techniques can also be used to

model the abandoned mines and to predict their emissions and

methane production on a regional scale. However, as noted earlier,

the difficulty associated with this technique is that it requires an

extensive amount of data, some of which is impossible to obtain.

Therefore, numerical modeling techniques are adequate for sensitivity

studies to evaluate how various project parameters may change the

forecasts. Nevertheless, Collings (2003) used reservoir simulation of a

hypothetical mine to build simple models to show productivity of

boreholes drilled in an abandoned mine property and the longevity of

production in the face of flooding. The author also noted that such

models could help to develop resource areas and to evaluate the

effects of uncertainties in key parameters. Durucan et al. (2004), on

the other hand, applied reservoir simulation to model methane

recovery from an abandoned mine at the Saar Coalfield, Germany. The

authors used historical data on mining and methane emissions, as

well as long-term methane production monitored from the Hangard

shaft, to validate model development. As a result of the modeling,

high-methane partial-pressure zones in the region were identified as

potential sites to drill boreholes to produce high-purity methane and

to avoid air contamination. These studies show the use of numerical

reservoir simulation for identifying the methane production potentials from abandoned mines.

Surface coal mines also release methane as the overburden is

removed and the coal is exposed, but the level of emissions is much

lower than from underground mines. This primary reason for this is due

to the relatively low gas content of the coals that are mined from the

surface. The low gas content of these coal seams is likely related to the

shallow depth of burial and the fact that some are lower rank with

commensurately lower gas adsorption capacity. In addition, lower gas

content in the coals mined from surface mines may be that the gas that

was generated from these shallow coals migrated up and escaped to

atmosphere long before the mining activity began. Finally, some of the

methane retained in the coal after it leaves the mine is released through

desorption during processing, storage, and transport of the coal.

Coal mine methane that is successfully assessed and captured by

various techniques before, during, and after mining operations, or

from abandoned mines, can ensure the safety of an underground coal

mine. This gas can also be used as an energy source, thereby reducing

the greenhouse effects of methane. The rest of this paper is dedicated

to a review of how energy can be harnessed from CMM, thus reducing

its greenhouse effect with different applications.
Fig. 24. U.S. EPA (2004) methodology for calculating abandoned mine emissions.
Fig. 25. An example of Fetkovich type curves with fitted data of gob gas venthole production during mining and after the panel was sealed. The unit of time in this plot is “days,” and

the unit of production rates and cumulative amounts are m3

/day and m3, respectively. The field data in this analysis are matched to exponential decline and reD= 1000 for further

processing.

6. World coal mine methane (CMM) overview

CMM is released from coal mines throughout the world, and often

the largest emitters are countries with the highest production of highrank underground coal. Currently, the top two producers of coal and

emitters of CMM are China followed by the United States (U.S.). Other

large coal producers include Russia, Australia, the Ukraine, and India.

Over the past ten years, CMM emissions have been gaining greater

attention due to their status as a greenhouse gas (GHG) and their

potential use as a clean energy resource. As a result, many countries

have begun to perform periodic inventories of their CMM emissions.

Countries that are Parties to the United Nations Framework

Convention on Climate Change (UNFCCC) are committed to reporting

their national greenhouse gas inventories to the Secretariat of the

Convention. Developed (or Annex I) countries such as Australia, Russia,

the Ukraine ,and the U.S. have reported their stand-alone inventories on

an annual basis, which are then peer-reviewed by technical experts.

These inventories are posted on the UNFCCC Web site. Developing (or

Non-Annex I) countries such as China and India report their national

greenhouse gas inventories on a less frequent basis as part of a broader

national report called a “national communication.”

The U.S. EPA has worked with the reported UNFCCC data and has

developed historical estimates and projected estimates (1990–2020)

of the global GHG emissions and sinks for a multitude of emission

sources. The total 2005 global anthropogenic CMM emissions were

estimated to be 432.3 million metric tons of CO2e (MtCO2e). According

to the U.S. EPA equivalency calculator, the 2005 global CMM emissions

are equivalent to the total annual GHG emissions (CO2e) of approximately 77.2 million passenger cars. The percent contribution for

each county's estimated 2005 CMM emissions are illustrated in Fig. 26.

The global trend in estimated CMM emissions from 1990 to 2020 is

illustrated in Fig. 27. Between 1990 and 2000, CMM emissions

decreased by approximately 27.1%. The drop in global emissions is

associated with a decline in coal production in many countries, in

addition to a restructuring of the coal industries in countries such

as China, Russia, and other Easter European coal-producing countries

(U.S. EPA, 2006). From 2000, the global CMM emissions are projected

to rise by approximately 27.3% or greater. The expected overall

decline is attributed to underground coal mining production shifting

to less gassy surface mining (e.g. the Powder River basin in the U.S.)

and CMM emissions reductions due to an increase in methane

recovery and use projects (U.S. EPA, 2006).

6.1. China

China is the world's top producer and consumer of coal and coal

accounts for approximately 70.0% of the country's total national

energy consumption (Cheng et al., 2011). In 2008, China produced

2.58 billion metric tons of coal and consumed 2.57 billion metric tons

of coal (U.S. EIA, 2008). Following reorganization in 2009, current

estimates indicate that China has close to 15,000 mines, of which 268

are state-owned mines producing approximately one-third of China's

coal. Nearly 90% of the county's coal production is from underground

mining (U.S. EPA, 2009a) and approximately 85–95% of total CMM

emissions come from underground mines where ventilation air

methane (VAM) is the largest contributor (Cheng et al., 2011).

The State Administration of Coal Mine Safety of China labeled

15,071 coal mines in 2007, and 12,722 in 2008, in 26 provinces/

autonomous regions/municipalities, as “gassy” mines. It is estimated

that China's total emitted CMM was 19.3 billion cubic meters (289.8 Tg

CO2e or 289.8 Tg of carbon dioxide equivalent) and 20.2 billion cubic

meters (304.5 Tg CO2e) in 2007 and 2008, respectively (Cheng et al.,

2011). The Methane to Markets International (M2M) CMM Projects

Database currently identifies 82 active or proposed CMM projects
and one closed project in China. All but two are confirmed in active

underground mines. Table 5, in the “CMM capture and utilization

projects” section of this paper, lists the number of projects by type and

current operating status.

The closing of state-owned coal mines and town and village coal

mines that do not meet production and safety requirements leaves

many mines abandoned, potentially emitting large amounts of

abandoned mine methane (AMM). To date, China has not inventoried

its AMM emissions, and no AMM-related projects have been initiated

in China so far.

Fig. 26. 2005 estimated global CMM emissions (MtCO2e) (U.S. EPA, 2006).

Global CMM Emission

Estimates MtCO2e 

0 

100 

200 

300 

400 

500 

600 

1990 1995 2000 2005 2010 2015 2020 

Emission Years 

Fig. 27. Estimated global trends in CMM emissions (U.S. EPA, 2006).

6.2. United States

The United States is the second largest producer and consumer of

coal worldwide and is also the second largest emitter of CMM. Coal

accounted for 32.5% and 29.6% of the total energy production of the

U.S. in 2008 and 2009, respectively (U.S. EIA, 2009b). The U.S.

exported 6.96% of its coal production in 2008 and 5.5% in 2009, while

its imports equaled 2.9% of its total domestic production in 2008 and

2.1% in 2009 (U.S. EIA, 2009a). Although the U.S. coal mining industry

is privatized, the U.S. EPA has conducted annual inventories of CMM

emissions from active and abandoned mines since 1990.

In 2009, 14 out of 135 gassy active underground coal mines

collected methane from degasification systems and utilized this gas,

thus reducing approximately 16.2 Tg CO2e emissions to the atmosphere. Of these mines, 12 coal mines sold methane to natural gas

pipelines and one coal mine used methane from its degasification

system to heat mine ventilation air on-site. In addition, one of the coal

mines that sold gas to pipelines also used methane to fuel a thermal

coal dryer. The total 2009 CMM emissions (including AMM) are

estimated to be 5.5 billion cubic meters of methane (U.S. EPA, 2009b).

Of this amount, underground mines accounted for 70%, surface mines

14%, abandoned mines 8%, and post-mining emissions 8%. Fig. 28

depicts U.S. CMM emissions by source category.

AMM Recovered 

CMM Degas & Used 

Vented 3.0 

3.8 

AMM Emissions 

5.1 

VAM Emissions 

46.0 

CMM Degas 

Recovered & 

Used 

16.2	 

Surface Mine 


Emissions
 

14.3 

Post 

Mining 

7.7 

Fig. 28. 2009 CMM emissions by source category.

Courtesy of Ruby Canyon Engineering (2010).

The majority of the methane from abandoned mines in the U.S. is

vented to the atmosphere, and only 38 abandoned underground

mines recover methane (U.S. EPA, 2009c). According to the U.S. EPA

AMM Inventory in 2009, there were 469 abandoned gassy underground mines. It is estimated that the 469 abandoned gassy mines

emitted 8.1 Tg of CO2e, of which 3.0 Tg of CO2e was recovered. After

recovery and use, the total 2009 U.S. AMM emissions are approximately 5.1 Tg of CO2e (U.S. EPA, 2009c).

The U.S. EPA currently identifies 39 operating or planned CMM and

AMM projects and one closed CMM project in the U.S. A list of U.S.

projects can be found in Table 6 in the “CMM capture and utilization

projects” section of this paper.

6.3. India

India is the third largest producer of coal worldwide, and coal is the

most important source of electric power production in India. In 2009,

India produced approximately 613,402 thousand short tons of coal

and consumed 680,873 thousand short tons, which means that India

had to import over 67,400 thousand short tons of coal to meet its

domestic demand (U.S. EIA, 2009a). About three-quarters of India's

domestic electricity is generated from coal-fired plants. Other large

coal users include steel, cement, fertilizer, chemical, paper, and

industrial plants, while coal has largely been phased out from the rail

transport sector (U.S. EPA, 2009a).

Hard coals (anthracite and bituminous) account for 77% of the

country's proved reserves. In 2000, 27% of coal production in India

came from underground mines. Currently, that number has dropped

to 15%. Deep mines continue to be developed, but more surface mines

are also being developed due to the country's vast resource of shallow,

low-rank coal deposits (U.S. EPA, 2009a).

The U.S. EPA has estimated India's 2005 CMM emissions to be

19.46 Tg CO2e. India's carbon emissions are expected to continue to

increase throughout the rest of the decade. The rise in India's carbon

emissions is in part due to the low energy efficiency of coal-fired

power plants in the country. High capital costs of replacing existing

coal-fired plants, a scarcity of capital, and the long lead time required

to introduce advanced coal technologies point to the likelihood that
most of India's highly polluting coal-fired power plants will remain in

operation for the next few decades (U.S. EPA, 2009a).

The Methane to Markets International CMM Projects Database

currently identifies no CMM recovery projects in India, neither in

operation nor in development (M2M, 2010). There are two proposed

projects designed to produce electricity from methane captured at

opencast mines in India. While there is some drainage of CMM, there

are currently no commercial projects for its recovery or use in India.

About 5% of abandoned mines in India are considered gassy,

assuming the same percentage as active mines reported in the First

National Communication to the UNFCCC. No additional information is

available on abandoned mine methane in India at this time.

7. Benefits of capturing and utilizing CMM and mitigating

CMM emissions

There are many benefits for recovering and utilizing CMM,

including: reducing greenhouse gas emissions; conserving a local

source of valuable, clean-burning energy; enhancing mine safety by

reducing in-mine concentrations of methane; and providing revenue

to mines (U.S. EPA, 2009e). As a primary constituent of natural gas,

methane is an important, relatively clean-burning energy source.

The global coal industry, national governments, trade unions, and

worker safety advocates are concerned that the frequency and

severity of methane explosions, especially in emerging economies,

are unacceptably high. CMM drainage and utilization projects in

combination with good safety practices at coal mines could reduce the

risk of methane-related explosions by preventing the buildup and

migration of in-mine methane.

Effective gas drainage techniques reduce the risks of explosions,

and hence lower accident risks. Reducing these risks in turn reduces

their associated costs. Costs of methane-related accidents vary widely

from country to country but are significant. For example, a 10% work

stoppage or idling at a given mine due to a gas-related accident could

lead to between US $8 million and $16 million/year in lost revenues at

a typical high-production longwall mine. Additional costs of a single

fatal accident to a large mining operation could range from US

$2 million to more than US $8 million through lost production, legal

costs, compensation, and punitive fines (United Nations, 2010).

Methane capture and use can add significant value to a mining

operation. Captured CMM can be directly used to supply or generate

energy, harnessing the value of a natural resource. In turn, this can

deliver economic returns to the mine through energy sales or cost

savings. Moreover, methane utilization adds intrinsic value by

generating capital that can be reinvested in mine safety equipment

and operations.

CMM capture projects may experience financial benefits from

pipeline sales revenue, reduced power, heating and/or cooling costs

from onsite electricity generation, and in qualifying countries for

carbon reduction credit revenue from GHG reduction programs such

as CDM (Clean Development Mechanism), JI (Joint Implementation),

and voluntary carbon credits. Revenue streams from carbon emission

reduction credits can come in the form of Verified Emission

Reductions (VERs), Certified Emission Reductions (CERs), or other

credits such as emission reduction units (ERUs). These potential

carbon-financing options may be a critical factor in making some

CMM utilization projects economically viable that would be otherwise

financially unattractive. In addition, carbon financing may provide the

only revenue streams for abatement-only projects, such as ventilation

air methane (VAM) oxidation (without energy recovery) or CMM

flaring. VAM can also be used for electric or thermal power generation.

At this time, VAM-derived power generation is not commercially

feasible without carbon revenues or other incentives, such as preferential electricity pricing or portfolio standards. VAM projects are

reported to deliver positive rates of return at carbon prices starting

as low as US $5–$10/tCO2e (United Nations, 2010).

Currently, investment decisions at most mines are likely to favor

expansion in coal production rather than development of CMM

utilization projects (particularly power generation) due to the high

opportunity cost of investing in power generation capital equipment

and infrastructure. To meet environmental protection targets in the

future, however, mine owners may be required to improve gas drainage

performance beyond the level strictly required to meet the safety needs

of the mines. Such improvements in the drainage system that yield

relatively high-quality gas may provide an additional incentive for

investment in gas recovery and utilization projects (United Nations,

2010).

Increased methane recovery also reduces methane-related mining

delays, resulting in increased coal productivity (U.S. EPA, 2009d).

Furthermore, the development of methane recovery and use projects

has been shown to result in the creation of new jobs, which has helped

to stimulate area economies. Additionally, the development of local

CMM resources may result in the availability of a potentially low-cost

supply of gas that could be used to help attract new industry to a region.

For these reasons, encouraging the development of CMM recovery and

use projects is likely to be of growing interest to state and local

governments that have candidate mines in their jurisdictions.

CMM emissions from active underground mines may be mitigated

by the implementation of methane drainage systems followed by

recovery and use projects. Mines can use several reliable degasification methods to drain methane. These methods have been developed

primarily to supplement mine ventilation systems that were designed

to ensure that methane concentrations in underground mines remain

within safe levels. Degasification systems include vertical wells (drilled

from the surface into the coal seam months or years in advance of

mining), gob wells (drilled from the surface into the coal seam just prior

to mining), and in-mine boreholes (drilled from inside the mine into the

coal seam or the surrounding strata prior to mining).

The quality (purity) of the gas that is recovered is partially dependent on the degasification method employed, and may limit how

the methane can be used. Potential utilization options for medium- tohigh-quality CMM (in the range of 30% to 100% methane) include a large

variety of applications, such as: (1) use as a fuel in steel furnaces, kilns,

and boilers; (2) in internal combustion (IC) engines or turbines for

power generation; (3) for injection into natural gas pipelines; (4) as

feedstock in the fertilizer industry; or (5) as vehicle fuel in the form of

liquid natural gas (LNG) or compressed natural gas (CNG).

Generally, only high-quality gas (typically greater than 95%

methane) can be used for pipeline injection. Vertical wells and

horizontal boreholes tend to recover nearly pure methane (over 95%

methane). In very gassy mines, gob wells can also recover high-quality

methane, especially during the first few months of production. Over

time, however,mine air may becomemixed withthemethane produced

by gob wells, resulting in a lower quality gas.

Applications for medium-quality (usually greater than 30%

methane) gas have been demonstrated in the U.S. and other countries,

and include: electricity generation (the electricity can be used either

onsite or can be sold to utilities); as a fuel for onsite preparation plants

or boilers, or for nearby industrial or institutional facilities; and in

cutting-edge applications, such as microturbines or fuel cells.

It is also possible to enrich medium-quality gas to pipeline

standards using technologies that separate methane from carbon

dioxide, oxygen, and/or nitrogen. Several technologies for separating

methane are under development. Another option for improving the

quality of mine gas is blending, which is the mixing of lower-quality

gas with higher-quality gas whose heating value exceeds pipeline

requirements (U.S. EPA, 2009e).

Even mine VAM, which typically contains less than 1% methane, has

been successfully demonstrated as an energy source. At a mine in

Australia, VAM was successfully used as combustion air in gas-fired

internal combustion engines. The application of using mine ventilation

air as combustion air in gas turbines and coal-fired boilers has also been
demonstrated. The world's first commercial-scale VAM oxidation

project, located in New South Wales, Australia, became operational in

September 2007. The plant generates approximately 6 megawatts

(MW) of electricity and reduces greenhouse gas emissions by more

than 275,000 tCO2e/year (U.S. EPA, 2009e).

8. CMM utilization technologies

CMM is gathered from underground mines and brought to the

surface via vertical frac wells, surface-drilled horizontal wells, gob

wells, and centralized vacuum stations, which collect the gas

produced by in-mine boreholes and VAM systems (U.S. EPA, 2009d).

Not all of the extracted gas is or can be commercially utilized, but

depending upon the gas quality and volumes the CMM could be used

in a variety of projects, including:

• natural gas pipeline injection;

• power generation;

• ventilation air methane oxidation;

• power electricity generators for the mine or local region;

•	 use as a an energy source—co-firing in boilers, district heating, coal

drying;

•	 use as a vehicle fuel, and manufacturing or industrial uses such as

ammonia production;

• flaring.

Currently, commercial CMM utilization is not technically nor

economically viable at many CMM drainage projects worldwide. As a

result, the drained gas is vented directly to the atmosphere via an

exhauster/well head blower. One option to reduce the environmental

impact of direct venting is to combust the vented methane in a

controlled flare system. CMM flaring has been used successfully in

Europe and Australia, but has yet to gain widespread acceptance in the

U.S. coal mining industry.

Fig. 29 illustrates several CMM capture and use technologies (and

destruction technologies) integrated at an active underground coal

mine.

Fig. 29. Multiple CMM end-use and destruction options for underground coal mines.

Courtesy of Sindicatum Carbon Capital.

The example demonstrates how methane can be used directly

to supply or generate energy, which in turn can deliver economic

returns for the mine through energy sales or cost savings. Good gas

drainage standards and practices will yield gas of stable and usable

quality, and will facilitate application of the lowest-cost utilization

opportunities. Due to constantly changing mining conditions, gas

supply can fluctuate in quality or quantity; thus utilization equipment

will occasionally fail or need to be shut down. In these cases, the

unused gas can possibly be flared (if N25% methane) to minimize

emissions. Methane that cannot be used nor flared can be diluted in

ventilation air and can be oxidized via a VAM destruction technology.

8.1. Pipeline injection

Methane liberatedduring coalminingmay be recovered andcollected

for sale to interstate pipeline systems. Typical pipeline standards require

a methane concentration of 90 to 95%. The key issues that will determine

project feasibility are: (1) whether the recovered gas can meet pipeline

quality standards; and (2) whether the costs of production, processing,

compression, and transportation are competitive with other gas sources.

Gas drained from vertical frac wells, horizontal wells, and in-seam

boreholes is usually of sufficient quality (greater than 90% methane)

for injection into natural gas pipelines with minimal processing

(usually dehydration and carbon dioxide removal) (U.S. EPA, 2009e).

Gas from gob wells and cross-measure boreholes is more variable in

quality (30–80% methane), depending on the amount of dilution

caused by air infiltration into the gob and boreholes. Gob gas and

other low-quality gas can reach pipeline quality if it is upgraded or

enriched through multi-stage treatment and compressions. Often the

gas is transported from individual wells, via an in-field gathering

system, to a central processing facility, where it is treated and

compressed to meet transmission pipeline specifications.

There are also other options to increase the quality of CMM, such

as improving the well and borehole design to improve gas recovery,

blending lower-quality CMM with higher-quality CMM, and increasing the energy content of the gas by spiking the CMM with higher

hydrocarbon gasses.

CMM is collected from the wellbore at relatively low pressures and is

compressed to attain the necessary pressure requirements for injection

into a transmission pipeline. The number of stages needed for

compression will depend on the suction and discharge pressures

needed to produce the wells and compress the gas into the transmission

line, as well as the compression ratios of the equipment. Three to four

stages of compression are common in CBM/CMM projects in the U.S. due

to the low suction pressures required to maintain gas production and

the high pressures (ranging from 200 to 1500 psig) required for
interstate transmission lines. Pipeline injection projects are the most

common CMM abatement projects in the U.S.

8.2. Gas processing

An integrated processing plant can be installed at a central facility

to remove contaminants and increase the quality of the gas to pipeline

specifications. In this process, CMM is treated in a series of connected

processes which first remove any hydrogen sulfide present (occasionally found in CMM), followed by removal of excess water vapor,

oxygen, carbon dioxide, and nitrogen. In the U.S., pipeline quality gas

typically must contain less than 0.2% oxygen, less than 3% nitrogen,

less than 2% carbon dioxide, and less than 112 kg/MMcm (7 lbs/

MMcf) of water vapor, while having a heating value of greater than

967 Btu/scf (U.S. EPA, 2009d).

Severaltechnologies are commercially used to separate methane from

other impurities, while some are still in the field demonstration stage.

Nitrogen rejection units (NRU) are used to remove the more difficult and

costly nitrogen contaminants. Currently, five technologies are available

for methane separation: cryogenic, pressure swing adsorption, solvent

absorption, molecular gate, and membrane technologies.

8.2.1. Nitrogen rejection unit (NRU) technologies

8.2.1.1. Cryogenic technology. The cryogenic process uses a series of

heat exchangers to liquefy the high-pressure feed gas stream. The

mixture is then flashed and a nitrogen-rich stream vents from a

distillation separator, leaving the methane-rich stream. Designers

locate the deoxygenation system at the plant inlet to avoid the danger

of explosion within the plant. Cryogenic plants have the highest

methane recovery rate (about 98%) of any of the technologies, and

they have become standard practice for large-scale projects where

they must achieve economies-of-scale. However, cryogenic plants

tend to be less cost-effective at capacities below 5 Mmscfd, which are

more typical of CMM drainage projects (U.S. EPA, 2008).

8.2.1.2. Pressure swing adsorption (PSA). Gasses when under pressure

tend to get adsorbed on solid surfaces. While more gas is adsorbed with

a pressure increase, reducing the pressure releases or desorbs the gas.

PSA utilizes the property of varying affinities of gasses for a given solid

surface to separate a mixture of gasses. In the case of CMM, nitrogen is

removed from low-quality gas by passing the gas mixture under

pressure through a vessel containing an adsorbent bed that preferentially adsorbsnitrogen, leaving the gas coming out ofthe vesselto be rich

in methane. When the adsorbent bed is saturated, the pressure is

reduced to release the adsorbed nitrogen, preparing the bed for another

cycle. Usually very porous materials are selected as adsorbents for PSA

systems because they provide surface areas large enough to adsorb

significant amounts of gas, even though the adsorbed layer may be only

one or only a few molecules thick. Adsorbents typically used are

activated carbon, silica gel, alumina, and zeolite.

Some specialty adsorbents including zeolites and carbon molecular sieves selectively adsorb gasses based on the size of their

molecules; only those gasses that have molecules smaller than the

pore size of the absorbents are allowed into the adsorbent structure.

In most PSA NRU systems, wide-pore carbon molecular sieves

selectively adsorb nitrogen and methane at different rates in an

equilibrium condition. The use of zeolites as an adsorbent for CMM

has so far been tested only on the bench scale (U.S. EPA, 2008).

PSA recovers up to 95% of available methane and can operate on a

continuous basis with minimal onsite attention. PSA systems have

excellent turndown capability, so they are able to operate effectively

with gas flowing at a fraction of the rated capacity.

8.2.1.3. Molecular gate. This process removes nitrogen and other

contaminants from the methane, whereas other processes remove the

methane from the nitrogen. The process uses a new type of molecular

sieve that has the unique ability to adjust pore size openings within an

accuracy of 0.1 Å. For CMM, the sieve pore size is set smaller than the

molecular diameter of methane and above the molecular diameters of

nitrogen, oxygen, carbon dioxide, and water, as indicated in Fig. 30.

Fig. 30. Molecular gate sieve pore adjustments (U.S. EPA, 2008).

This permits the nitrogen and other contaminants to enter the pores

and to be adsorbed while excluding the methane, which passes

through the fixed bed of adsorbent at essentially the same pressure as

the feed. The molecular gate process employs a PSA operation by

“swinging” the adsorbent bed pressure from a high-pressure feed step

that adsorbs the contaminants to a low-pressure regeneration step to

remove the previously adsorbed contaminants.

8.2.1.4. Solvent absorption. Sometimes referred to as “selective absorption,” this process uses specific solvents that have different absorption

capacities with respect to different gasses. In CMM applications, a

solvent selectively absorbs methane while rejecting a nitrogen-rich

stream in a refrigerated environment. The petroleum industry commonly uses selective absorption to enrich gas streams.

8.2.1.5. Membrane. This process uses membranes to selectively pass

methane, ethane, and higher hydrocarbons while retaining nitrogen.

A simple one-stage membrane unit is appropriate for feed gas containing about 6 to 8% nitrogen. However, more commonly, nitrogen

concentrations are higher and require a two-step or two-stage membrane system.

8.2.2. Other impurity and water vapor removal technologies

8.2.2.1. Oxygen removal. After nitrogen rejection, deoxygenation is the

most technically challenging and expensive process. It is especially

important since most pipelines have very strict oxygen limits (typically

0.1% or 1000 parts per million). NRU technologies such as PSA will

experience oxygen rejection in proportion to nitrogen rejection and

may need very little deoxygenation as a final processing step. Oxygen

rejection associated with cryogenic or solvent absorption NRUs is

more critical due to explosion danger, and it must be the first system

component. Since deoxygenation results in a substantial temperature

rise, if inlet gas is likely to contain over 1.5% oxygen, a two-stage recycle

system is needed to avoid unacceptably high temperatures.

8.2.2.2. Carbon dioxide removal. Several technologies are available

commercially, including amine units, membrane technology, and

selective adsorption. Amine units are tolerant of only low levels of

oxygen in the feed stream, so the amine unit must be downstream of

the de-oxygenation unit (U.S. EPA, 2008). Often amine systems are

used to treat gas removed from virgin coal beds, but an adsorption

system may be more attractive for treating highly contaminated gas

such as gob gas or abandoned mine CMM. However, amine systems

may experience corrosion and degradation from the amine solvents

used in the process. Amine systems commonly operate at high

pressure and require compression of the feed gas. The gas stream from
amine units is often water-saturated and a glycol dehydration unit is

used to bring the gas to pipeline specifications (Michael Mitariten,

2009).

8.2.2.3. Water vapor removal. Dehydration of CMM is the simplest part

of any integrated system design. Inadequate water removal, however,

can result in corrosion damage to delivery pipes and can be quite

serious. Most system suppliers will employ a molecular sieve

dehydration stage because of its proven record and economical

operation.

8.2.3. Other CMM upgrading options

Horizontal boreholes and “longhole” horizontal boreholes also can

produce pipeline quality gas when the integrity of the in-mine piping

system is closely monitored. However, the amount of methane

produced from these methods is sometimes not large enough to

warrant investments in the necessary surface facilities. In cases where

mines are developing utilization strategies for larger amounts of gas

recovered from vertical or gob wells, it may be possible to use the gas

recovered from in-mine boreholes to supplement production.

Another option to upgrade gas quality is to blend the low Btu gas

with higher Btu gas to obtain a higher heating value above the

pipeline quality requirements. As a result of blending, the Btu content

of the overall mixture can meet acceptable levels for pipeline

injection. Spiking the CMM with higher hydrocarbon gasses such as

propane is also an option, but this application is dependent upon the

pipeline's acceptance of spiked gas. Gas processing may still be

required in combination with improved extraction techniques,

blending, and spiking in order to meet pipeline specifications.

8.3. Power generation

CMM may also be used as a fuel for power generation. Unlike

pipeline injection, power generation does not require pipeline-quality

methane nor much compression. Gas engines can generate electricity

using methane that has a heat content of 350 Btu/cf (U.S. EPA, 2009e).

Mines can use electricity generated from recovered methane to meet

their own onsite electricity requirements, and they can sell electricity

generated in excess of their onsite needs to utilities. Outside of the

U.S., power generation is often the preferred option for using CMM.

Power generation projects using CMM are operating at coal mines in

several countries, including China, Australia, the United Kingdom, and

Germany.

Currently, reciprocating or internal combustion (IC) engines are

the most likely technology to be used for a CMM project. Boiler/steam

turbines are generally not cost-effective in sizes below 30 MW, while

gas turbines are not the optimal choice for projects requiring 10 MW

or less. Furthermore, gas turbines typically cannot utilize CMM below

50% methane and require the gas to be compressed prior to use.

However, when used in the right applications, gas turbines are smaller

and lighter than IC engines, more efficient, and historically have had

lower operation and maintenance costs.

While maintaining pipeline quality gas output from gob wells can

be difficult, the heating value of gob gas is generally compatible with

the combustion needs of gas engines. One potential problem with

using gob gas is that production, methane concentration, and rate

of flow are generally not predictable—wide variations in the Btu

content of the fuel may create operating difficulties. Equipment for

blending the air and methane may be needed to ensure that variations in the heating value of the fuel remain within an acceptable

range for gas engines and possess approximately 10% allowable

variability for gas turbines.

The level of electric capacity that may be generated depends on

the amount of methane recovered and the “heat rate” (i.e., Btu to kWh

conversion) of the generator. For example, simple cycle gas turbines

typically have heat rates in the range of 10,000 Btu/kWh, while

combined cycle gas turbines could have heat rates of 7000 Btu/kWh

(U.S. EPA, 2009e). Gas engine heat rates can range from 9000 to

11,000 Btu/kWh, depending on the model of the engine.

8.3.1. Ventilation air methane (VAM) use technologies

VAM, the dilute methane emitted from mine ventilation shafts, is

now recognized as an unused source of energy. A host of recently

introduced technologies can reduce VAM emissions, while harnessing

thermal energy, and can offer significant benefits to the world

community.

A limited number of technologies that can beneficially use VAM

are currently available, while others are in the development and

demonstration phase. One existing approach is quite straightforward

and entails using VAM as combustion air, thereby supplying ancillary

fuel to internal combustion (IC) engines, turbines, or industrial and

utility boilers. Such VAM use in IC engines (running on CMM) has

been well-demonstrated in Australia.

In recent years, technologies have been developed that can destroy

very low concentration methane in mine ventilation air by thermal

oxidation. The primary purpose of these technologies is the reduction

of GHG emissions. Some of these technologies may be combined with

a heat recovery system for use at mines or district heating, or to run

steam turbines for power generation.

8.3.1.1. Thermal oxidation technologies. Flow-reversal oxidizers – both

thermal and catalytic – are commercially available and are capable of

oxidizing VAM. VAM entering thermal oxidizers encounters a bed of

heat exchange material that has been preheated to the oxidation

temperature of methane (1000 °C). The VAM oxidizes and releases

heat, which in turn maintains the temperature of the heat transfer

material at or above 1000 °C, thereby sustaining the auto-oxidation

process over time without requiring additional fuel input. Valves and

dampers repeatedly reverse the flow of incoming VAM to keep the hot

zone in the center of the oxidizer. Catalytic and thermal systems both

operate on this principle, although catalysts allow the reaction to

occur at lower temperatures (~800 °C). When VAM concentrations

are high enough, these systems can also provide excess heat energy

for electricity generation (U.S. EPA 2009f).

The U.S. EPA has identified several commercially viable technologies for destroying or beneficially using the methane contained in

ventilation air:

•	 two technologies based on a thermal oxidation process using

thermal flow-reversal reactors (TFRR) also known as regenerative

thermal oxidizers (RTO);

•	 a catalytic oxidation process called the catalytic flow-reversal

reactor (CFRR) also known as regenerative catalytic oxidizers (RCO).

These technologies employ similar principles to oxidize methane

contained in mine ventilation airflows. Based on the latest demonstration projects, these units can sustain operation (i.e., maintain

oxidation) with ventilation air having uniform methane concentrations down to approximately 0.1% and 0.2% for the CFRR and TFRR

processes, respectively. For commercial applications where methane

concentrations are likely to vary over time, the economic lower concentration limit at which oxidizers will be deployed is 0.5%. VAM

energy recovery has been successfully demonstrated in Australia,

using RTOs to convert VAM to electricity at a mine mouth power plant.

A VAM RCO has been proven at full-scale demonstration in a test unit

(Somers and Shultz, 2008).

8.3.1.2. Thermal flow-reversal reactors. TFRR equipment consists of a

bed of silica gravel or ceramic heat-exchange medium with a set of

electric heating elements in the center. The TFRR process employs the

principle of regenerative heat exchange between a gas and a solid bed

of heat-exchange medium. To start the operation, electric heating

elements preheat the middle of the bed to the temperature required
to initiate methane oxidation (above 1000 °C or 1832 °F, or hotter).

Ventilation air at ambient temperature enters and flows through the

reactor in one direction, and the air temperature increases until

oxidation of the methane takes place near the center of the bed.

The hot products of oxidation continue through the bed, losing

heat to the far side of the bed in the process. When the far side of the

bed is sufficiently hot, the reactor automatically reverses the direction

of ventilation airflow. The ventilation air now enters the far (hot)

side of the bed, where it encounters auto-oxidation temperatures

near the center of the bed and then oxidizes. The hot gasses again

transfer heat to the near (cold) side of the bed and exit the reactor.

Finally, the process is reversed again. Fig. 31 shows an example of a

thermal flow-reversal reactor system.

Fig. 31. Depiction of the thermal flow-reversal reactor process (U.S. EPA, 2008).

8.3.1.3. Catalytic flow-reversal reactors. CFRRs adapt the thermal flowreversal technology described above by including a catalyst to reduce

the auto-oxidation temperature of methane by several hundred

degrees Celsius (to as low as 350 °C or 662 °F). CFRR technology was

developed exclusively for the treatment of methane in coal mine

ventilation air (U.S. EPA, 2009e). Injecting a small amount of methane

(gob gas or other source) increases the methane concentration in

ventilation air and can make the turbine function more efficiently.

Waste heat from the oxidizer is also used to pre-heat the compressed

air before it enters the expansion side of the gas turbine.

There are two primary options for converting the heat of oxidation

from a flow-reversal reactor to electric power, which is the most

marketable form of energy in most locations:

•	 Using water as a working fluid: In this process, the water is

pressurized and forced through an air-to-water heat exchanger in a

section of the reactor that will provide a non-destructive temperature environment (below 800 °C or 1472 °F). The hot pressurized

water is flashed to steam and the steam is used to drive a steam

turbine-generator. If a market for steam or hot water is available, the

exhausted steam is sent to that market. If none is available, the

steam is condensed and the water returned to the pump to repeat

the process.

•	 Using air as a working fluid: In this process, ventilation air or ambient

is pressurized and sent through an air-to-air heat exchanger that is

embedded in a section of the reactor that stays below 800 °C

(1472 °F). The compressed hot air is directed through a gas turbinegenerator. If gob gas is available, it is used to raise the temperature of

the working fluid to more nearly match the design temperature of the

turbine inlet. If thermal markets are available, the turbine exhaust is

used for cogeneration.

Since affordable heat exchanger temperature limits are below

those used in modern prime movers, efficiencies for both of the

energy conversion strategies listed above will be fairly modest. The

use of a gas turbine, the second method listed, is the energy

conversion technology assumed for the cost estimates in this paper.

At a VAM concentration of 0.5%, it is expected that an overall plant

efficiency of approximately 17% will be achieved after accounting for

power allocated to drive the fans that force ventilation air through the

reactor.

Current VAM technologies are generally not able to process

methane concentrations below 0.2% without the use of an additional

fuel, but research efforts are underway to lower the concentration

threshold since VAM concentrations at many mines worldwide fall

below 0.2% (United Nations, 2010). Operations that use VAM to

generate power may need to optimize the inflow concentrations and

increase the VAM concentration inlet to the oxidation device.

One method of fuel enrichment (spiking) involves adding methane

from other sources such as gob or pre-mine drainage gas. If enrichment is being considered, low-quality drained gas (less than 30%)

should not be used due to the explosion hazard. Use of higherconcentration gas (greater than 30%) could divert gas from lower-cost

CMM power generation, and this should be evaluated as part of the

project feasibility.

Other VAM technologies under development include the catalytic

monolith reactor (CMR), lean-burning turbines reported to use VAM

at concentrations of 1.5% and lower, and rotary kilns that mix VAM

with waste coal fines.

8.3.2. Onsite use options of CMM by coal mines

In addition to pipeline injection, power generation, and VAM use,

CMM may be used as a fuel in onsite preparation plants or vehicle

refueling stations, or it can be transported to a nearby coal-fired boiler

or other industrial or institutional facilities for direct use.

Many large underground coal mines have preparation plants

located nearby. Mines have traditionally used their own coal to fuel

these plants, but there is the potential to use recovered methane

instead. Currently in the U.S., a major mining company uses recovered

methane to fuel the thermal dryer in one of its preparation plants in

the U.S. In Poland, while several coal mines have used recovered

methane to fuel their coal drying plants.

Another option for onsite methane use may be as a fuel for vehicles

as CNG or LNG. Natural gas is much cheaper and cleaner than diesel

fuel or gasoline, and internal combustion engines burn it more efficiently. Current estimates indicate that nearly 4000 vehicles operating

in China use CMM as fuel (Jianmin and Shengchu, 2010).

In addition to onsite methane use, selling recovered methane to a

nearby industrial or institutional facility may be a promising option

for some mines. An ideal gas customer would be located near the coal

mine (within 5 km) and would have a continuous demand for
gaseous fuel. CMM could be used to fuel a cogeneration system, to

fire boilers or chillers, or to provide space heating. In China, mediumquality CMM is often used in local communities for residential

cooking and heating purposes. In some cases, local communities may

find that the availability of an inexpensive fuel source from their

local mine can help them attract new industries and generate

additional jobs.

Additionally, there are numerous international examples of mine

gas being used for industrial purposes. For example, in the Ukraine

and Russia, recovered CMM is used in coal-fired boilers located at the

mine site. In the Czech Republic, CMM is used in nearby metallurgical

plants. In Poland, recovered CMM is used as a feedstock fuel in a

chemical plant. In China, CMM has been used in aluminum smelters

and carbon black plants. Finally, co-firing methane with coal in a

boiler is another potential utilization option, particularly for mines

that are located in close proximity to a power plant.

The flaring of CMM is an abatement option that may be attractive if

CMM utilization is not feasible. Typically, flaring is a low-cost

technology with short manufacturing and installation time periods

(Harworth Energy, 2010). Coal mines using flares to combust CMM

generally collect the gas from gob wells via an active compression

system (a system using a mechanical blower/exhauster). Flares are

either open “candlestick” or enclosed (ground) flares with destruction

efficiencies of approximately 98% and 99% respectively; however,

open flare efficiencies can be decreased by high crosswinds, high CO2,

and other factors (U.S. EPA, 1999). To install a flare a mine must have a

gas drainage system capable of draining methane above 25% purity

(Harworth Energy, 2010).

Preferably, each utilization project should be equipped with a flare

in case of equipment malfunction, when scheduled maintenance

requires that the project be shut down temporarily, or during the

early mine development stage when methane production has not yet

reached commercially viable levels. Also, this action can accommodate any excess methane not being used by the project.

For the purposes of attaining carbon credits, the Clean Development Mechanism (CDM) Executive Board has established rather low

default values of 90% for enclosed flares and 50% for open flares. Actual

efficiencies can be measured and monitored for enclosed flares, but

not for open flares. A final consideration is that enclosed flares have

greater esthetic appeal in that the flame is not visible and combustion

pollutants can be better managed (United Nations, 2010).

The coal industry and mine regulatory authorities in some

countries have opposed flaring at mines over concerns that the

flame could propagate back down through the drainage system into

the mine, causing an explosion. At the very least, safe flaring requires

rigorous design incorporating flame and detonation arrestors, seals,

sensors, and others safety devices. That said, CMM flares have

operated successfully in a number of countries including Australia,

China, and the United Kingdom.

In the U.S., flaring has not been implemented due to the coal

industry's primary concern for safety and preventing flame propagation that could lead to underground explosions. The U.S. EPA Reports

Conceptual Design for a Coal Mine Gob Well Flare (U.S. EPA, 1999) and

Benefits of an Enclosed Gob Well Flare Design for Underground Coal

Mines (U.S. EPA, 2000) contain further information on flaring and the

benefits of flaring.

8.4. Emerging technologies

The U.S. EPA has also identified other technologies that may be

able to play a role in and enhance opportunities for VAM oxidation

projects. These new technologies include volatile organic compound

(VOC) concentrators, lean gas fuel turbines, and using VAM as an

ancillary fuel. Each emerging technology is briefly described in the

subsections that follow.

8.4.1. Concentrators

Volatile organic compound (VOC) concentrators offer another

possible economical option for application to VAM. Currently there

are three technologies available: the carousel, rotary disk, and fluidized

bed, with the fluidized bed considered to be the most applicable

technology to concentrating CMM (U.S. EPA, 2010b). Concentrators

operate by passing the methane-laden air up through a bed of adsorbent

material (e.g., activated carbon or zeolite beads) on which the methane

accumulates, increasing the weight of the adsorbent, which falls

downward. An inert carrier gas is used to strip the methane in a

desorption step; the adsorbent is then returned to the fluidized bed for

another concentration cycle.

The benefits of a concentrator include increasing the concentration

of methane in VAM for use in turbines and IC engines, reducing the

upgrading requirements for pipeline injection of mid-quality gas, and

increasing the commercial use options for low-quality gas streams.

8.4.2. Lean fuel gas turbines

Currently efforts are underway to modify selected gas turbine

models to operate directly on VAM or on VAM that has been enhanced

with more concentrated fuels. These efforts include technologies

such as carbureted gas turbines, lean-fueled turbines with catalytic

combustors, lean-fueled catalytic microturbines, hybrid coal and

VAM-fueled gas turbines, and the use of VAM as an ancillary fuel.

These technologies are briefly discussed below. More information on

these emerging technologies is available in the U.S. EPA paper,

“Identifying Opportunities for Methane Recovery at U.S. Coal Mines:

Profiles of Selected Gassy Underground Mines 2002–2006” (U.S. EPA,

2009e).

8.4.3. Carbureted gas turbine (CGT)

A carbureted gas turbine is a gas turbine in which the fuel enters as

a homogeneous mixture via the air inlet to an aspirated turbine. It

requires a fuel/air mixture of 1.6% by volume, so most VAM sources

would require enrichment. Combustion takes place in an external

combustor where the reaction is at a lower temperature (1200 °C or

2192 °F) than for a normal turbine, thus eliminating any NOx

emissions.

8.4.4. Lean-fueled turbine with catalytic combustor (CCGT)

A lean-fueled turbine with catalytic combustor gas turbine is

under development by CSIRO Exploration & Mining of Australia.

This turbine could use methane in coal mine ventilation air and

could oxidize the VAM in conjunction with a catalyst. The turbine

compresses a very lean fuel/air mixture and combusts it in a catalytic

combustor.

8.4.5. Lean-fueled catalytic microturbine

A lean-fueled catalytic microturbine is being jointly developed by

two U.S. companies, FlexEnergy and Capstone Turbine Corporation.

The application will start at 30 kW and will operate on a methane-inair mixture of 1.3%. Capstone microturbines have been successfully

demonstrated utilizing CMM at an abandoned mine in Japan in 2004.

8.4.6. Hybrid coal and VAM-fueled gas turbine

CSIRO is developing a system to oxidize and generate electricity with

VAM in combination with waste coal. CSIRO is constructing a 1.2-MW

pilot plant that co-fires waste coal and VAM in a rotary kiln, captures the

heatin a high-temperature air-to-air heat exchanger, and uses the clean,

hot air to power a gas turbine.

8.5. Benefits and disadvantages of end-use technologies

Each end-use technology has associated advantages and disadvantages. Table 4 summarizes the most common advantages and
disadvantages for each of the primary end-use technologies utilized at

coal mines globally.

Table 4

Summary of advantages and disadvantages of end-use technologies.

Use Applications Advantages Disadvantages

High-quality pipeline gas Purified high-quality CMM. • Natural gas equivalent.

• Profitable where gas prices strong.

• Good option where strong pipeline

infrastructure exists.

• Pipeline purity standards are high and

purification is costly.

• Only feasible for high-quality, pre-drained CMM

or treated CMM.

• Requires reasonable access to pipeline.

Power generation

VAM flow reversal

oxidizers

Gas-engine generators producing power for mine

use or export to the grid.

Destruction of dilute concentrations of methane

often less than 1% in VAM. Potential for waste

heat recovery for energy generation.

• Proven technology.

• Waste heat recovery for heating mine

buildings, miner baths, and shaft heating

and cooling.

• Destruction of large source of CMM

emissions.

• Can capture waste heat for water or

space heating.

• Interruptible and variable output; therefore, may

not be conductive for the electric grid.

• Regular maintenance requires commitment of

mine operator.

• High capital costs at initial stage of project.

• High capital costs at initial stage of project.

• Regular maintenance requires commitment of

mine operator.

VAM as combustion air Using VAM as combustion air to supply ancillary

fuel to combustion devices.

• Destruction of large source of CMM

emissions.

• Can be used to generate electricity for

onsite or offsite use.

• High capital costs at initial stage of project.

• Regular maintenance requires commitment of

mine operator.

Medium-quality

“town” or industrial gas

N30% methane for local residential, district

hearing and industrial use such as firing kilns.

• Low-cost fuel source.

• Localized benefits.

• May require minimal or no gas cleanup.

• Cost of distribution system and maintenance.

• Variable quality and supply.

• Costly gas holders needed to manage peak

demands.

Chemical feedstock

Mine Site

Vehicles

High-quality gas for the manufacture of carbon

black, formaldehyde, synthetic fuels, and

di-methyl ether (DME).

Heating, cooking, boilers, coal fines drying, miner's

residences.

Purified high-quality, pre-drained gas and CBM for

CNG and LNG.

• A use for stranded high-quality CMM

supplies.

• Displaces coal use.

• Clean, low-cost energy source.

• Market access for stranded gas supplies.

• Vehicle fuel prices are very high.

• High processing cost.

• No CDM potential when carbon can be liberated.

• May be less economically beneficial to use

onsite than off-site.

• Processing, storage, handling, and transport

costs.

• Purification standards are very high.

Flaring Destruction of drained CMM or excess CMM from

other utilization technologies.

• Generally low-cost destruction option.

• Destruction efficiencies between 98%

and 99%.

• Generally requires a methane concentration

of 30%.

• Concerns over safety of flares at mining locations.

9. CMM project barriers and a global overview of projects

9.1. Barriers to the recovery and use of CMM

Currently, a number of commercial and institutional barriers (and

other project risks) can alter the ultimate economic viability of CMM

projects. These obstacles include technical challenges with varying

gas quality and quantity, unresolved legal issues concerning ownership of the CMM resource, lack of pilot projects for new technologies

to demonstrate site-specific economic recovery and utilization, lack of

financing or capacity to obtain financing, and pipeline locality and/or

capacity constraints.

The above constraints will vary from country to country. For

example, in China, barriers to CMM development include lack of

accessibility to pipeline networks and limited drainage technologies

and low drainage rates. In the U.S., unresolved legal issues (especially

of federal lands in the western U.S.) and lack of financing present

larger challenges to CMM project development. Conversely, mine

locality-to-pipeline networks and access to highly efficient CMM

drainage technologies are not barriers in the U.S. (U.S. EPA, 2009a).

The barriers and constraints for some of the large CMM-emitting

countries are presented in Table 5.

Table 5

Constraints to CMM development for top CMM-emitting countries.

Country Primary constraints

China • Most mines are not accessible to gas pipeline network.

• Limited drainage technologies/low drainage rates.

• Regulations for foreign project developers may be unclear.

• Most CMM is low‐grade, i.e., less than 30% methane.

UnitedStates • In much of the U.S. (especially in western states) there is limited

pipeline capacity relative to supply.

• Relatively low electricity prices have made power projects (either

for onsite use or sales to a utility) less attractive.

• Ownership of carbon-based mineral rights are often divided

between oil/natural gas and coal.

Russia • CMM and CBM must compete with large, in-country proven gas

resources with low-cost production capacity.

• The region lacks the technological capability to extract CBM

economically from saturated, low-permeability coal seams.

• There is a general lack of state support for unconventional fuel

production (M2M Workshop—Russia, 2005).

• Most CMM is low‐grade, i.e., less than 30% methane.

Australia • Power generation costs are relatively high—may not be able to

pass on the full cost of emission credits in market power prices.

Ukraine • Methane in coal is owned by state but assigned to companies, mines,

and individuals and rights to methane are not easily transferred.

• Most coal enterprises are not profitable, and only a few have seen

significant private investment.

• Most CMM is low‐grade, i.e., less than 30% methane.

India • Lack of clarity about legal and regulatory issues, especially ownership

of the gas.

• Lack of technology and technical knowledge.

• Lack of CMM resource assessment, technology selection, and

formulation of feasibility studies.

• Lack of pilot projects to demonstrate site‐specific economic recovery

and utilization.

• Lack of infrastructure to utilize gas.

• Lack of financing or capacity to obtain financing.

9.2. CMM capture and utilization projects

The Methane to Markets Partnership (M2M) is an international

initiative that advances cost-effective, near-term methane recovery

and use as a clean energy source. The goal of the Partnership is to
reduce global methane emissions in order to enhance economic

growth, strengthen energy security, improve air quality, improve

industrial safety, and reduce emissions of greenhouse gasses (U.S.

EPA, 2009a). Since its inception in 2004, the Partnership has grown

from 14 to 38 governments – including the top 10 methane-emitting

nations – who account for nearly 70% of global methane emissions.

In October 2010, the Partnership countries decided to expand and

enhance their effort by launching a new global effort on methane called

the Global Methane Initiative (GMI). The Initiative will build on the

success of the Methane to Markets Partnership while maintaining its

same administrative structure. The GMI estimates thatin 2010 there are

over 300 planned or operating CMM projects worldwide. Based upon

the data in its International CMM Projects Database, it is estimated that

through draining, capturing, and utilizing methane, CMM emissions to

the atmosphere are reduced by 45 MtCO2e per year. Fig. 32 represents

the total number of CMM projects reported to the GMI that are active or

under development globally, based on type of end-use.

Fig. 32. Global CMM projects (M2M, 2010).

Worldwide, the majority of the capture and use projects are located in

China,Germany, andthe UnitedStates. Table6 lists the estimatednumber,

operating status, project type, and location of the M2M projects by the

partnership countries and the U.S. projects identified by the U.S. EPA.

China has the highest number of listed operating and planned

projects of all participant countries, with all but two projects located

at active underground coal mines. The second largest project developer is

Germany, followed by the U.S. Nearly 77.0% of the projects in Germany

and 62.0% of the projects in the U.S. are at abandoned mines. Power/

combined heat and power (CHP) projects are the most common project

types in China andGermany; however, CMM projects in the U.S., Ukraine,

Russia, and Poland are predominantly pipeline or boiler fuel projects.

Pipeline projects are more popular in the U.S. due to the relatively

close proximity of coal mines to existing commercial pipelines and the

high value of methane used as a natural gas compared to electric or

thermal energy (on a million Btu basis) (U.S. EPA, 2009e).

Table 6

Estimated global CMM projects as of 2010 (M2M, 2010). A space filled with dash (–) indicates that there are no projects listed under that category. The number of U.S. projects in the

table may vary from the project numbers listed in the M2M database.

China Germany United United Ukraine Poland Czech Australia Russia Mexico France Slovakia Japan Kazakhstan Romania South

States Kingdom Republic Africa

Number of 83 47 40 34 22 21 20 18 7 4 3 3 2 1 1 1

projects

Project status

Operating 64 43 37 19 17 13 20 13 4 1 3 2 – 1 1 1

projects

Projects in 18 – 2 8 5 1 – 3 2 2 – – – – – –

development

Closed projects 1 2 1 4 – – – 2 1 – – 1 2 – – –

Proposed projects – – – – – – – – – 1 – – – – – –

Unknown project – 2 – 3 – 7 – – – – – – – – – –

status

Project location

Projects at 81 9 14 15 18 19 6 13 7 3 – 1 – 1 – 1

underground

mines

Projects at active 1 – – 1 4 – – – – – – – – – 1 –

surface mines

Projects at – 36 26 18 – 2 5 5 – 1 3 – 2 – – –

abandoned

mines

Unknown project 1 2 – – – – 9 – – – – 2 – – – –

location

Project type

Power/CHP 44 47 2 22 8 6 19 10 2 3 – 3 1 – – –

Pipeline injection – – 31 1 – – 1 1 – – 1 – – – – –

Boiler fuel 7 – – 4 9 8 – 1 5 1 – – – 1 1 –

Town gas 15 – – – – – – – – – – – – – – –

VAM 8 – 3 – – – – 3 – – – – – – – –

Industrial use 5 – – 1 1 3 – – – – 2 – 1 – – –

Flaring – – – 5 3 – – 3 – – – – – – – –

Coal drying – – 1 – – 4 – – – – – – – – – –

Vehicle fuel 3 – – – 1 – – – – – – – – – – –

Heating/cooling – – 1 1 – – – – – – – – – – – –

Other 1 – 2 – – – – – – – – – – – – –

10. Summary and conclusions

Coal mine methane (CMM) is a term given to the methane gas

produced or emitted in association with coal mining activities either
from the coal seam itself or from other gassy formations underground.

The high amounts of methane released during coal mining can present

concerns about adequately ventilating the mine for ensuring the

safety of workers and about providing opportunities to generate

energy if the methane were captured and utilized properly. This

article reviewed the technical aspects of CMM capture in and from

coal mines, the main factors affecting CMM accumulations in

underground mines, different methods for capturing and utilizing

methane using boreholes, mine safety aspects of capturing CMM, and

global CMM emissions and activities for energy production and

greenhouse gas (GHG) reduction.

CMM is set apart from CBM (coalbed methane) in that CMM

activities are associated with coal mining activities, whereas CBM is

not associated with any particular coal mining operation. There are

many factors that affect the quantity of CMM emissions during mining

in addition to coal reservoir properties. In addition, the gas produced

in CMM activities can be either high-quality gas, such as methane

produced in advance of mining, or low-methane concentration gas,

such as VAM. The gas produced from gobs of sealed and active

longwall mines and from abandoned mines can be considered as

medium-quality gas, since it is often contaminated with air.

CMM capture using boreholes during mining in the pre- and postmining phases fundamentally utilizes the same techniques that are

used or adapted from conventional CBM operations. Therefore, most

of the time, similar geological factors, borehole drilling and completion, and production evaluation methods apply. However, in CMM

activities, the projected locations of future mines and the current

locations of existing operations should be taken into account and the

boreholes drilled and completed accordingly. Also, in CMM-capture

activities, borehole stability becomes a more important issue for

sustaining production. This is especially important for GGVs where

the overlying strata fracture and displace, possibly damaging the

production casing.

Depending on the quality of CMM gas produced, it can be directly

injected into a pipeline to be utilized as town gas, or it can be improved

by removing the contaminants, such as oxygen and nitrogen. There are

available and demonstrated technologies for improving the quality of

CMM. In the case of VAM, it is costly and almostimpossible to upgrade it

to pipeline-quality gas. Thus, different engines and reactors are used to

generate power from this low-methane-content energy source. These

technologies have beendemonstrated and are being successfully used in

the U.S. and in Australia.

The countries with the most CMM emissions are China, the United

States, Australia, the Ukraine, India, and Russia. Recognizing the importance of capturing and using CMM for mine safety, energy production, and greenhouse gas reduction, these countries are implementing

various CMM projects. However, depending on the economic, social,

and regulatory conditions in each of these countries (and also in

other CMM-emitting countries), the implementation of different CMM

projects are faced with multiple challenges that may slow down or

curtail their progress. These challenges must be addressed and

resolved with the collaboration of both government agencies and the

private sector in each country, and also through cooperation on an

international level by funding and demonstration of the importance

of CMM capture and utilization to improve mining safety, energy

production, and greenhouse gas reductions. Along these lines, the

Global Methane Initiative, currently made up of 38 partner countries,

engages both governments and private sector entities, bringing

together the technical and market expertise, financing, and technology

necessary for methane capture and utilization at an international level.

Disclaimer

The findings and conclusions in this paper are those of the authors

and do not necessarily represent the views of the National Institute

for Occupational Safety and Health. Any commercial product or

software mentioned in this paper is not endorsed by NIOSH nor the

U.S. EPA.

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