Reconciling longwall gob gas reservoirs and venthole production performances using

multiple rate drawdown well test analysis

C. Özgen Karacan ⁎

⁎ Tel.: +1 412 386 4008; fax: +1 412 386 6595.

E-mail address: cok6@cdc.gov.

National Institute for Occupational Safety and Health (NIOSH), Pittsburgh Research Laboratory, Pittsburgh 15236, PA, USA

abstract

Longwall mining is an underground mining method during which a mechanical shearer progressively mines

a large block of coal, called a panel, in an extensive area. During this operation the roof of the coal seam is

supported only temporarily with hydraulic supports that protect the workers and the equipment on the coal

face. As the coal is extracted, the supports automatically advance and the roof strata cave behind the

supports. Caving results in fracturing and relaxation of the overlying strata, which is called “gob.” Due its

highly fractured nature, gob contains many flow paths for gas migration. Thus, if the overlying strata contain

gassy sandstones or sandstone channels, gas shales or thinner coal seams which are not suitable for mining,

then the mining-induced changes can cause unexpected or uncontrolled gas migration into the underground

workplace. Vertical gob gas ventholes (GGV) are drilled into each longwall panel to capture the methane

within the overlying fractured strata before it enters the work environment. Thus, it is important, first to

understand the properties of the gas reservoir created by mining disturbances and, second, to optimize the

well parameters and placement accordingly.

In this paper, the production rate-pressure behaviors of six GGVs drilled over three adjacent panels were

analyzed 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. 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 suggest that conventional well test analysis techniques can be

applicable to highly complex gob reservoirs and GGVs 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 gob gas venthole systems.

1. Introduction—establishing the need for well test analyses

of the “gob”

1.1. Generation and properties of “gob” reservoir during longwall mining

Longwall mining occurs in a large, rectangular area, called a

“panel,” outlined by ventilation entries. During mining of a panel, roof

rocks are temporarily supported with hydraulic supports to protect

the workers and the equipment. As the coal is extracted from the

panel, the supports automatically advance and the roof strata are

allowed to cave behind. The caved zone created during this process is

highly fragmented, and generally extends upwards three to six times

the thickness of the mined coal bed. Caving results in relaxation of the

overlying strata that is characterized by mining-induced vertical and

horizontal fractures and bedding plane separations (Fig. 1). The caved

and overlying fractured zone collectively is called the “gob”.

Fracturing and relaxation in the gob creates new and highly

permeable flow paths. Methane inflow from the gob into the mining

environment is influenced by the magnitude of fracturing and the

extent to which the fractures stay open during mining. Singh and

Kendorski (1981) evaluated the disturbance of rock strata resulting

from mining and described a caved zone that extends from the mining

level to 3 to 6 times the seam thickness, a fractured zone that extends

from the mining level to 30 to 58 times the seam thickness, a bending

zone where there is no change in permeability that extends from 30

times the seam thickness to 50 ft below ground surface. Any gas that is

contained within the gob will be released over time and is a big

contributor to emissions, if not controlled (Fig. 1). Relaxation of the

roof rocks and the associated fracture connectivity allows gas to flow

from all surrounding gas sources toward the mine workings, which

eventually may create an unsafe condition for the underground

workforce. Also, depending on how the venthole interacts with the

gob and mining environment, there may be some ventilation air
leaking from the face into the gob and produced along with the

captured methane (Fig. 1).

Fig. 1. A schematic representation of longwall mining with a shearer. The figure shows the fractures extending the overlying strata, bedding plane separation, subsidence and

possible methane flow paths (red arrows) and air leakage from the face (blue arrow). A schematic of a GGV producing this gas is also shown.

The characteristics of fracturing and the subsidence of overburden

are revealed through predictive techniques and field studies (Luo,

1989; Cui et al., 2001; Palchik, 2005; Li et al., 2005). It was concluded

that rock failure leading to increased hydraulic conductivity in the gob

was initiated by high compressive stresses ahead of the face with the

fractures subsequently opened by tensile stresses behind the face (Liu

and Elsworth, 1997). Gale (2005) reported that the horizontal

conductivity can be significantly enhanced along bedding planes

within and well outside the panel. This probably will vary depending

on the nature of each site as reported by Whittles et al. (2006, 2007).

As mining progresses, the caved zone in the gob gradually

consolidates sufficiently to support large loads resulting from the

overburden weight (Pappas and Mark, 1993). Consolidation results in

a reduction in the porosity and the associated permeability. Although

reduced to some degree due to compaction, prevailing high

permeability pathways in the gob still affect the flow of methane

from surrounding sources into the gob and into the mine. Thus, an

understanding of resultant reservoir properties of gob material is very

important for developing adequate methane control strategies.

1.2. Gob gas ventholes “GGV” and their use in methane production and

control

One common technique to control methane emissions is to drill

vertical gob gas ventholes (GGV) into each longwall panel to capture

the methane within the overlying fractured strata before it enters the

work environment. Gob gas ventholes are commonly used to control

the methane emissions from the fractured zone and are drilled from

the surface to a depth that places them above the caved zone. The

bottom section of the pipe is slotted and placed adjacent to the

expected gas production zone (Fig. 1).

Although the drilling practices of GGVs may change based on local

conditions, most gob gas ventholes are drilled to within a short distance,

35–100 ft, of the coal bed and cased with steel pipe. Commonly, the

bottom section of the casing, generally about 200 ft, is slotted (Fig. 2-A

and B). The casing is cemented using 2–3 cement baskets (Fig. 2-C)

above the slotted section. Thus, the slotted section remains open to the

gob and supported by the cemented casing string from the surface. The

usual practice is to drill the gob gas ventholes prior to mining. As mining

advances under the venthole, the gas-bearing strata that surround the

wellbore will fracture and will establish preferential pathways for the

released gas, or the leaking mine air, to flow towards the ventholes

(Diamond, 1994) as shown in Fig. 1.

Exhausters are placed on gob gas ventholes (Fig. 1) to maintain a

vacuum on the wellbore to induce gas flow towards the venthole. Gas

production may exhibit variable gas quality. In the early stages of

production, the gas quality is generally high (>80%) after a hole is

intercepted by the longwall. Relatively high production rates with

high methane quality are usually sustained for a few weeks. Later in

time, especially towards the end of the panel mining or after the panel

is completed, gob gas production may exhibit decreased methane

levels as ventilation air is drawn from the active mine workings. The

quality of the gas from GGVs can be controlled to some extent by

varying the vacuum on the wellhead to correspond with the profile of

expected methane release. However, for mine safety, 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. Thus, 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. Therefore, from a

production point of view, there are two primary phases in the

producing life of a GGV: 1—production during panel mining (DM) and

2—production period after panel is mined out (AM).
Fig. 2. A pictorial showing of a slotted casing ready to be lowered (A), the dimension of each of the slots (B) and the baskets (C) used above the slotted interval to stop the cement to

flow beyond intended interval. It is difficult to predict production performance of gob gas

ventholes due to the involvement of multiple influential factors,

complex properties of the gob, and due to the lack of knowledge on

interactions of the GGV with the gob reservoir. Currently, a standard

approach that can realistically represent the multiple variables

associated with underground coal mining operations and their

interactions and influences on the performance of gob gas ventholes

does not exist. This may be related to the non-existence of enough

field tests and the actual reservoir data obtained using these tests and

the challenges and unknowns related to the gob environment. There

have been some modeling studies for predicting GGV performance

(Lunarzewski, 1998; Ren and Edwards, 2002; Palchik, 2002; Tomita

et al., 2003; Karacan et al., 2005, 2007). However all of these models

rely on predicted permeabilities based on geomechanical calculations.

Thus, despite the improvements detailed in these studies, experience

suggests that it is still difficult to accurately predict methane

production from a GGV. At this juncture, transient well tests analyses

methods, such as multi-rate drawdown, and interference and

pressure build-up tests that are applied in the petroleum and natural

gas industry and in coalbed methane reservoirs (Matthews and

Russell, 1967; Earlougher, 1977; Dake, 1978; Lee, 1982; King et al.,

1986; Mohaghegh and Ertekin, 1991; Mavor and Saulsberry;, 1996;

Engler and Tiab, 1996; Nashawi, 2008) can be reliable tools to

understand the characteristics of the gob reservoir and the interaction

of GGVs with the gob and mining environment.

1.3. Purpose of this study

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 and also for improved gas

capture. Thus, the objective of this paper is to make an attempt using

multi-rate drawdown gas well tests analyses to understand the

behavior of the gob gas ventholes and the reservoir properties of the

gob. In order to achieve this objective, the production rate-wellhead

pressure behavior of six gob gas ventholes drilled over three different

panels was analyzed using F.A.S.T WellTest® (Fekete Associates, 2009)

for parameters such as skin, permeability, radius of investigation, flow

efficiency and damage ratio for a better reservoir understanding of the

gob and the GGVs. In these analyses, the GGV production periods

during panel mining (DM) and after mining (AM) were analyzed

separately, using multi-rate production drawdown analyses techniques using infinite flow and pseudo-steady state (PSS) flow models,

respectively, since the reservoir capacity, behavior and gas production

potential changed between these two phases.

2. Description of overburden stratigraphy in the study area and

locations of GGVs

2.1. Overburden stratigraphy and the effects on formation of gob

reservoir

This study has been conducted in the Northern Appalachian Basin

in Southwestern Pennsylvania, in Greene County, Pennsylvania. This

area is very important for coal mining and for mining-related

methane emissions and capture using conventional boreholes and

gob gas ventholes.

In the study area, most of the longwall mining operations exist in

the Pittsburgh seam of the Monongahela Group and the methane

emissions from the gobs of these operations are captured using GGVs.

The Monongahela Group is located within the Pennsylvanian age

sediments and includes the interval from the base of the Pittsburgh

coal to the top of the Waynesburg coal. The general coal measures in

the Monongahela Group in Greene County and their thicknesses from

top to bottom of the group, can be listed as: shale (0 to 11.8 ft),

Waynesburg main coal bed (5.9 ft), clay (2.95 ft), sandstone (19.7 ft),

limestone (5 ft), sandstone and shale (60 ft), Uniontown coal bed (1 ft

to 3 ft), Upper Great limestone (17.7 ft), sandstone and shale (60 ft),

Lower Great limestone (55.1 ft), sandy shale (40 ft), Sewickley coal
bed (1 to 6 ft), sandstone (9.8 ft), the Fishpot limestone (17.7 ft),

sandstone and shale (25 ft), Redstone coal bed (1 to 3.9 ft), limestone

(9.8 ft), Pittsburgh upper sandstone (40–50 ft—sandstone paleochannel), shale (0 to 9 ft), and Pittsburgh coal bed (5 to 12.1 ft) (Penn State

University Libraries, 2000). Markowski (1998) reported that the main

coal beds that are consistent and continuous in the study area of this

paper are the Pittsburgh, Sewickley, and Waynesburg. The Redstone

coal bed and Pittsburgh rider coals are not continuous and can be

present at some locations. In this interval, the Sewickley coal bed, the

gassy sandstones within the gob interval and the Redstone and rider

coals are believed to be the main source of gob methane produced by

GGVs.

Fig. 3 shows three stratigraphic plots of these layers at three

example core-hole locations and the relative location of the slotted

casing in these boreholes. In order to show these thicknesses of

different strata at the same depth level, a depth correction procedure

was applied to the core-hole data (Karacan and Goodman, 2009). This

procedure allowed the rock layers, their thicknesses and the slotted

casing locations to be compared in the same depth scale (Fig. 3).

Fig. 3. Stratigraphic log and thicknesses of the formations at three example core-hole locations in the study area.

The example core logs given in Fig. 3 show that the thicknesses and

the presence or absence of layers change based on their locations. For

instance, in the first log, there is a thick sandstone layer (sandstone

paleochannel) above the Pittsburgh coal bed, which is present but not

dominant in the other two logs. And when it exists, depending on its

thickness, the bottoms of the slotted casings of the ventholes are

either in this sandstone or over it within a close proximity. Similarly,

the last two logs have thick limestone layers about 140 ft above the

Pittsburgh coal bed. Also, the number and thicknesses of other shale–

sandstone sequences are different in each location. This is characteristic of coal measure strata deposited in swamp and lacustrine

environments (Karacan, 2009). More importantly, the existence and

thicknesses of these layers at various borehole locations impact the

caving, fracturing and bedding plane separations in the overburden

during longwall mining. This eventually affects the formation of the

gob reservoir, gas availability and production of GGVs.

In the gob, horizontal fractures occur along weak-strong rock layer

interfaces during the movement of the overburden. The formation,

thickness and location of horizontal fractures influence the hydraulic

conductivity of the overburden strata, which creates methane

emission pathways and controls methane emissions into the mine.

The fractures are usually correlated with uniaxial compressive

strength and thickness of rock layers, distances from the extracted

coal seam to the rock layer interfaces, and the thicknesses of extracted

coal seams (Palchik, 2002).

In the study area, based on an investigation of hydraulic

conductivities and the estimation of strata fracturing (Karacan and

Goodman, 2009), it is more probable that fracturing and bedding

plane separations will occur within an interval between 40 ft and
145 ft from the top of coal bed. This interval contains thin limestones,

sandstones and weaker strata, such as coalbeds and shales (Karacan

and Goodman, 2009).

2.2. Location effects on the gob gas venthole production performances

The production performance of gob gas ventholes are closely

related to their locations on the panels, borehole completions,

wellhead designs, and the operation of the exhausters (Diamond,

1994; Ren and Edwards, 2002; Karacan et al., 2007; Karacan and

Goodman, 2009; Karacan, 2009). These may be important in

interpretation of the well test behaviors and results as well. Thus, a

few of the possible factors on gob gas venthole production-pressure

behavior will be summarized in this section.

Table 1 gives the actual drilling and location details of the 6

ventholes monitored for their production performance in this study.

As this table shows, panel dimensions, location details and venthole

completion details differ. Thus, varying production performances can

be expected from these ventholes.

Table 1

Drilling, location and borehole details of the 6 ventholes monitored for their production history in this study.

GGV Surface elevation

(ft)

Distance to

tailgate entry

(ft)

Depth to bottom

of slotted pipe

(ft)

Over

burden

(ft)

Venthole

diameter

(in.)

Dist. to coal bed

(ft)

Dist. from

panel start

(ft)

Panel length

(ft)

Panel width

(ft)

1B-1 −1356.80 232 793.80 828.80 7 35 550 11,030 1225

2B-1 −1166.16 305 599.16 644.16 8 45 372 10,798 1225

2B-2 −1321.76 223 744.76 789.76 8 45 2132 10,798 1225

2B-3 −1383.81 274 799.81 844.81 7 45 4492 10,798 1225

2B-4 −1294.00 238 691.00 731.00 7 40 6872 10,798 1225

3B-1 −1143.00 283 585.00 630.00 7 45 482 11,086 1425

In elevation data, sea level is zero and higher elevations are in negative direction.

These boreholes were drilled on three adjacent panels (1B to 3B)

as indicated in the first column of Table 1. The second numbers are the

GGV number on each panel. Each borehole was completed with 200-ft

of slotted casings, shown in Fig. 2. Due to the terrain of the study site

and the land ownership issues, each borehole was located at varying

elevations above sea level. Thus, the boreholes with highest elevations

are 1B-1, 2B-2 and 2B-3. Accordingly, the drill depths to the top the

slotted casing and the overburden depths are highest in these

boreholes. However, 2B-2 is closest to the tailgate entries of 2B

panel, which possibly locates this borehole in the tension zone around

the edges of the panel, where fractures are more open. Close-tomargin placements of the ventholes and its possible effect on

production difference of the ventholes, as the reservoir properties

change in cross-panel direction during transition from tension to

compression, are also one of the underlying assumptions of using a

composite model as the reservoir geometry in the well test analyses as

will be discussed in the next sections.

The GGVs do not have separate production tubing installed and

production is achieved through the casing. Table 1 shows that the

casing diameters used in monitored boreholes are 7 and 8 in. Keeping

the other completion parameters constant, increasing the gob gas

venthole diameter increases cumulative methane production from

the subsided strata (Karacan et al., 2007). Although a marginal

decrease in the methane concentration can be seen from this change,

possibly due to increased mine air extraction with a larger sink, the

increased gas flow rate increases the overall volume of methane

produced.

Distance of the slotted casing to the coal bed may also play an

important role on the amount and concentration of methane

captured. Reservoir modeling results (Karacan et al., 2007) showed

that when the setting depth was close to or within the caved zone, the

methane concentration and the total amount of methane captured

decreased. However, 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 based

on their mechanical properties and gas contents.

The distances from the start of the panels and the distances

between the ventholes along the panel are again based on maximizing

productivity, on the expected drainage radius of the ventholes, and on

the emissions into the mines. It has been shown that the location of

the ventholes on the panel is important for their performance

(Diamond, 1994). In general, the first holes on the start end of the

panels are the highest-quantity and longest-duration producers. This

is attributed to enhanced mining-induced fractures where the

overburden strata are in tension and open to flow with higher

permeabilities. Table 1 shows that three boreholes in this study (1B-1,

2B-1 and 3B-1) are the first boreholes in respective panels. However,

1B-1 was surrounded by virgin coal seam since it was the first

borehole in this new district and 3B-1 was located in a wider panel

compared to 1B and 2B. Thus, these differences may have implications

on the flow-pressure data and on well test results.

Fig. 4 shows the locations of the ventholes monitored in this study

on a 3-D surface elevation and on the sandstone paleochannel

thickness maps. The bottom diagram in this figure is an overlay of the

mine map showing the panels with the sandstone channel thickness

contours with a projection of borehole locations.

Fig. 4 shows that ventholes are located on rough terrain, which is

characteristic to the Appalachian basin. Some of the ventholes are

located on hill sides or tops and others close to the valley bottoms.

However, besides this and the other issues discussed on the possible

effects of borehole location on production performance, it should be

noted that 2B-2 and 3B-1 are located in a region (Fig. 4, bottom

diagram) where there is either no sandstone channel or it is too thin

to have a major effect on caving and gob formation. On the other hand

1B-1 and 2B-1 are in a region where sandstone channel thickness is

between 0 and 20 ft, and 2B-3 is in a location where sandstone

thickness is between 20 and 40 ft. 2B-4 is located in the thickest

section of the sandstone (>40 ft), where the slotted casing is either in

the sandstone or very close to the top of the paleochannel. The

presence and absence of this channel and its thickness is expected to

be very influential on the caving behind the shields and below the

ventholes. In situations where the roof material is stiff and thick, it

cantilevers behind the shields leading to a lesser degree of fracturing

in overlying strata and impeding development of high permeability

fractures around the borehole. Since the rock strength of sandstone is

much more than the shale-type formations, different subsidence and

thus venthole production histories can be expected based on this

factor.

3. Monitoring of the ventholes for production and pressures

3.1. Instrumentation of the gob gas ventholes

The six gob gas ventholes (Table 1; Fig. 4) that were drilled,

completed and monitored in this study were instrumented prior to

undermining their locations. As it was discussed in the introduction

section, these boreholes generally do not produce any fluid before the
strata is fractured as a result of undermining. After fracturing, these

boreholes produce gas of varying methane concentration throughout

the mining of the panel, even after panel completion, until the

methane concentration decreases to low levels. Thus, the total gas

production phase of a gob gas venthole can be described as the

production during panel mining (DM) and after completion of the

panel (AM). Water, which accumulates in the borehole in some cases,

flows into the gob during undermining and is not produced at the

surface. The total gas production in these ventholes comes from

different sources at different depths of the slotted casing interval and

was produced as a mixed gas stream by a methane-driven exhauster

that provided vacuum at the wellhead.

Fig. 4. A composite figure showing the surface elevation, sandstone thickness above the mined coal seam and mine map. This figure shows the approximate location of the ventholes

on the surface, the longwall panels and the relative positions of the panels and the ventholes with respect to the various thicknesses of the sandstone channel. “A” in the middle figure

is the section where the ventholes have slotted casings.

Ideally, for transient behavior of production and pressure, the

boreholes should be instrumented downhole to measure the flowing

bottom-hole pressure and the rates. Since these boreholes are closely

related to the underground safety of the miners, maintaining intrinsic

electrical safety is a must with any instrumentation used in the

downhole to prevent possibility of an accident. To avoid these risks,
the boreholes were instrumented on the surface before the exhauster

with flow meters, methanometers, thermocouples and pressure

transducers to measure the total flow rate, methane percentage,

temperature and pressure at the wellhead. Considering the fact that

the boreholes were not very deep and there was no standing water

column in the boreholes, measuring and using wellhead values, as

opposed to downhole measurements, in well test calculations can be

considered a reasonable approach.

3.2. Venthole production and pressure data

Fig. 5 (A–D) shows the total gas production (A–B) and wellhead

pressure (C–D) history of monitored gob gas ventholes during mining

(A–C) and after completion of panels (B–D). The production times in

these figures are the elapsed times since the boreholes first started to

produce gas during mining and the production times after the

completion of the respective panels. Although the data is scattered,

the general trends in observed gas productions show that the

ventholes initially produced at higher gas rates and then the rates

either stabilized or entered a decline period with increasing time. Four

of the six boreholes (1B-1, 2B-1, 2B-2 and 2B-3) continued producing

after the panel, over which they were located, was completed.

However, this production phase had a faster decline compare to the

during-mining phase.

Fig. 5. Total gas production (A–B) and wellhead pressure (C–D) history of monitored gob gas ventholes during mining (A–C) and after completion of panels (B–D).

Comparison of Fig. 5-A and B with Fig. 5-C and D, respectively,

shows that total gas production rate was generally correlated with

applied vacuum (wellhead pressure). Although a vacuum applied to

the gob gas ventholes stimulates methane migration into the

ventholes from the surrounding strata and prevents occasional flow

reversals (Thakur, 2006), this advantage may be lost over time as there

is tendency for mine air to be drawn into the gob area and to dilute the

methane (Ren and Edwards, 2002). A higher suction pressure has a

positive but relatively small effect on drawing gas from overlying

strata into the venthole. In the monitored ventholes, the wellhead

pressures were generally between 11.5 and 13.0psia (Fig. 5-C and D)

and the wellhead pressures were generally lower during the panel

mining phase of gas production compared to production after the

panels were completed. This may due to a lower methane flow rate.

Fig. 6 shows the methane concentration in the total gas production

of monitored gob gas ventholes during mining (6-A) and after

completion of panels (6-B) as well as methane flow rates measured at

the wellhead for these two flow phases (C and D). The data show that

during mining, 1B-1 and 3B-1 had the highest methane percentage

(80–90%) in production. Both of these wells were the first ventholes in

the respective panels. The ventholes of 2B panel produced with ~50%

methane. The rest of the produced gas was air sucked from the mining

environment through gob (Fig. 1). The methane flow rate (6-C), on

the other hand, was highest in 2B-2 venthole and lowest in 2B-4

during panel mining, which may be related to location of the

ventholes.

After the panels were completed, methane percentages decreased

somewhat (6-B) compared to the DM phase (6-A). However, a marginal

methane percentage increase was observed in 2B-1 and 2B-2. Between

DM and AM phases, methane flow rates decreased from an average

rate of 0.25 MMscf/day (6-C) for all the ventholes, except 2B-2, to

0.1 MMscf/day (6-D). The methane flow rate of 2B-2 stayed almost

stable around 0.3 MMscf/day, making this venthole stand out among

others.

Table 2 gives the mean, standard deviation, minimum and

maximum values of total gas production rate and wellhead pressure

data presented in Fig. 5, along with production durations of each

venthole during and after panel mining.
4. Application of multi-rate well testing method for gob

gas ventholes

In this study, the gas flow rates (total and methane) and the

flowing pressures at the wellheads of six ventholes were measured as

a function of time during panel mining and after panel completion

(Figs. 5 and 6). In order to evaluate these data and to gain insights

about the ventholes' production behaviors and the reservoir properties of gobs, an analysis was carried out by using conventional multirate drawdown gas well testing methods. In the well test analysis

study, F.A.S.T. WellTest (Fekete Associates, 2009) software was used

to evaluate total gas production and wellhead pressure data. The data

matching and linear regression plots to semi-log and log–log data

were performed using the built-in APE (Automated Parameter

Estimation) algorithm. Single-well, radial-composite models were

used for infinite acting and pseudo-steady state flow periods during

panel mining (DM) and after panel completion (AM) production

phases of the ventholes, respectively.

Fig. 6. Methane percentage (A–B) and measured methane flow rate (C–D) from monitored gob gas ventholes during mining (A–C) and after completion of panels (B–D).

Table 2

Mean, standard deviation, minimum and maximum values of production rate and wellhead pressure data presented in Fig. 5.

1B-1-DM 2B-1-DM 2B-2-DM 2B-3-DM 2B-4-DM 3B-1-DM 1B-1-AM 2B-1-AM 2B-2-AM 2B-3-AM

Wellhead pres.

Mean (psia) 12.2099 11.6204 12.3896 11.7456 11.6094 12.7097 12.2991 12.1921 12.5166 12.3621

Standard Dev. 0.1170 0.1458 0.2195 0.1401 0.2165 0.0715 0.0919 0.2488 0.2034 0.0348

Min. (psia) 11.8402 11.2500 11.8877 11.5132 11.2081 12.5168 12.0423 11.4934 12.0150 12.2808

Max. (psia) 12.3762 12.1300 12.8220 12.0774 11.9474 12.9158 12.5234 12.5693 12.8196 12.4396

Gas prod. rate

Mean (MMsfc/day) 0.2402 0.4774 0.6856 0.3858 0.3102 0.2707 0.1099 0.2255 0.4425 0.1545

Standard Dev. 0.0358 0.0385 0.0337 0.0159 0.0563 0.0122 0.0445 0.0920 0.0978 0.0274

Min. (MMsfc/day) 0.1606 0.4020 0.6207 0.3440 0.2379 0.2494 0.0367 0.0578 0.3046 0.1056

Max. (MMsfc/day) 0.3761 0.5710 0.7447 0.4196 0.4243 0.2934 0.1950 0.3933 0.6311 0.2042

Production duration (h) 4440 2976 3048 1032 456 1604 2263 3282 3601 703

4.1. Basic assumptions and their justifications for analyzing GGVs using

conventional well testing methods

Some assumptions were made during analysis of the flow ratepressure data. First of all, it was assumed the flow is radial towards the

venthole within the slotted length of the gob. Normally, the flow

regime in gob reservoirs is highly complex due to its nature (Fig. 1).

There may be linear flow components around the boreholes due to the

existence of fractures. However, radial flow was assumed within the

whole reservoir in the absence of fracture width and length

information. It is difficult to measure these properties since they
change during dynamic subsidence. Thus, radial flow in the reservoir

minimized the unknowns and simplified the flow occurring in this

complex system. It was also assumed that the gob reservoir had noflow upper and lower boundaries. This can be considered as a valid

assumption since the slotted section of the venthole spanned almost

all the methane emission sources and the entire length of the

deformed section of overlying strata.

In the analyses, the production rate was used in multi-rate

drawdown analyses. In gob gas venthole production, small changes

in pressure result in changes in almost instant change in production

rate without the need of waiting a long stabilization period. Therefore,

it was assumed that, due to the high permeability of the gob

environment, the gas production rate between consecutive rate

changes and recorded measurements are constant allowing the

analyses of the data using multi-rate drawdown techniques. In this

environment pressure transients are short lived too.

Interference effects from other wells can affect the analyzed

pressure data during well testing in producing fields. Ideally, a

multiple well simulation model should be used for analysis using both

proper rate history for each producer and accurate reservoir

geometry. This way, the combined effects of neighboring wells can

be added to the response of the tested well. However, considering that

different wells may not produce from exactly the same layers or the

well spacing and the geometry of the reservoir boundaries may be

difficult to describe with an analytical model, this procedure becomes

very cumbersome and frequently many approximations have to be

made. In many cases, tests are analyzed with a single-well-model

approach (Bourdet, 2003). Considering the complexity of the gob, a

single-well-model approach was adopted in this study, too.

The models that are used in this study assume that the gob

reservoir is homogeneous and is of single porosity despite the fact that

there are various heterogeneities in the gob, including fractures,

bedding plane separations, tension and compression zones. Even for

conventional oil and gas reservoirs that do not experience major

strata disturbances, there is not a single reservoir that is actually

homogeneous. However, it has been suggested (Bourdet, 2003) that

many reservoirs behave homogeneously during production and well

test analyses. Therefore, in the absence of the information on the exact

heterogeneities and their locations, the homogeneous model assumption is the most widely accepted one in well test analysis.

In this study, 2-zone composite radial models with vertical

boreholes were used. The composite model assumes that the reservoir

properties change at a certain radius from the borehole. This

phenomenon does not necessarily occur in nature, although some

reservoirs behave like they are composite. For instance, a borehole

drilled in a naturally fractured reservoir with different fracture

distributions around the well path may behave as composite reservoir.

For a gob reservoir, this assumption can be considered as a valid one

since the properties of gob change in the cross-panel direction due to

subsidence and compaction. Thus, there may be a different flow

capacity (kh) reservoir around the borehole to some distance into the

gob in the radial direction, as compared to the rest of the gob reservoir.

The wellbore storage term was considered “zero” in the analyses

presented in this paper. Usually, this term is needed when the

compressibility of the wellbore fluid is not constant. Such situations

may involve large drawdowns applied in gas wells or drastic changes

in temperature in the borehole during production. In the study site,

the GGVs were relatively shallow and, thus, there was not much of a

temperature gradient. Also, the surface blowers were applying small

suction pressures for gas production. Therefore, wellbore storage

effects could safely be neglected under these circumstances.

The total, or apparent, skin factors calculated from the well tests

were corrected for partial penetration effects. The ventholes monitored in this study were completed over the entire gob thickness

(200 ft). However, they were communicating with the gob only

through the slotted openings, which were approximately 2in in width

and 8in in length, and were created approximately every 24in in the

casing (Fig. 2). The convergence of flow lines towards these slots

might have created an additional pressure drop due to restricted flow

entry as suggested by Brons and Marting (1961). Therefore, this

pressure drop was dealt with as if it was a skin effect and labeled as

the skin due to partial penetration or “pseudo-skin”. This “pseudoskin” effect was subtracted from the total skin to find the mechanical

skin. Based on the frequency and dimensions of the slots, as well as

the length of the completion interval, the b and h/rw terms given in

Brons and Marting (1961) and also in (Dake, 1978) were calculated as

approximately as 0.33 and 5.8, respectively. Using these data in the

graphs given in these references, the pseudo-skin factor was

determined nearly as +1.

As it was mentioned earlier in this paper, the production ratewellhead pressure histories of the ventholes were analyzed separately

during panel mining (DM) and after panel completion periods (AM),

since it is known that mining operation affects both reservoirbehavior and the gas in place for production from the gob. From the

production and reservoir-behavior point of view, the DM stage can be

considered when the reservoir is charged continuously with gas due

to creation of new gob strata as the longwall face advances. Thus in

this analysis, the DM period was considered as an infinite acting flow

period before the occurrence of any boundary or transient-limiting

effects.

In the AM phase, on the other hand, mining of the panel is stopped

and the panel is completed (and sealed in some cases). These cases

make the gas reservoir limited both in size and in gas in place and the

gob may act as a bounded reservoir, in which case a pseudo-steady

state acting period seems more appropriate to describe the flow

during AM production. Pseudo-steady state (PSS) is a flow regime that

occurs in bounded (closed) reservoirs after the pressure transient has

reached all the boundaries of the reservoir. Thus, radial-composite

models with no-flow outer boundary conditions were used with PSS

flow conditions to analyze the AM production phase of the ventholes.

4.2. Brief theory of the well test analysis techniques used for the

production data of this study

In multi-rate drawdown well test analysis, wells should ideally

produce with a constant rate to reach stabilized flow conditions after a

rate change, especially in low-permeability reservoirs. This is certainly

a limitation in situations where it is difficult to control production

rate. It is also a limitation for analyzing successive rate-pressure data

points. In order for the analyses to be valid in such situations, the

permeability of the reservoir should be high enough and the wellbore

storage should be negligible so that the pressure transients will reach

stabilization almost instantly after a rate change. In gob reservoirs,

these conditions may be satisfied due to their very high permeabilities

and the use of multi-rate testing theory in analyzing venthole

production data may be justified.

4.2.1. Constant rate solution for radial flow-infinite acting period-of the

venthole production (DM)

The constant rate solution for analyzing radial flow is (Fekete

Associates, 2009):

q T kt ψi−ψwfðtÞ = 1:632 × 106 g log a ′ kh "

φμ gictir2 −3:23 + 0:87s 1

w

ð Þ

where ψ is the real-gas pseudo-pressure that is used in place of

pressure in natural gas engineering. It is defined as:

p pdp ψðpÞ = 2∫

p μZ b

ð2Þ

#
Radial flow data will form a straight line when placed on a semilog plot:

6 qgT

ψi−ψwfðtÞ = 1:632 × 10 logðt kh aÞ ð3Þ

q T k + 1 632 6 : × 10 g ′ kh "

log −3:23 + 0:87s φμ c 2 gi tirw

The slope, m, of Δψ/q versus log ta is used to calculate permeability

by;

T k = 1:632 × 106 ð4 mh Þ

Using Eq. (4) and the slope from Δψ/q versus log ta plot, total skin

(s′) can be calculated using;

"

ψ s i−ψ kt = 1 wf a ′ :151 −log + 3:23 m φμ ð5 c r2 gi ti w

Þ

The signature of radial flow on a derivative plot, on the other hand,

is a horizontal straight line. The position of this line, along with the

original data, may be used to calculate estimates of permeability and

Δψ apparent total skin. The derivative, as defined , of radial gas Δ ln ðt flow equation is: Þ

Der = 7 088 × 105 qgT : = constant ð6 kh Þ

Thus,when the gas drawdown data is plotted log(Δψ/q) versus log

(ta), then the permeability and apparent skin can be determined from:

k = 7 088 × 105 qgT : 7 Der:h ð Þ

ψi−ψ s = 1 151"

wf kta ′ : − log + 3:23 8 2:303Der φμ c r2 gi ti w

ð Þ

The pseudo-skin due to partial penetration effects that was

calculated as +1 for the ventholes in Section 4.1 should be subtracted

from the total skin calculated using Eqs. (5) and (8) to find mechanical

skin around ventholes.

4.2.2. Constant rate solution for pseudo-steady state phase—bounded

reservoir—of the venthole production (AM)

The constant rate solution for analyzing pseudo-steady state is:

q T 0:000527kt 3 ψ i 1 6

wf = ψ − 417 × 10 g

"

a : + ln − + s′ 9 kh φμ 2 gictire 4 ð Þ

This equation is linear with time and, thus, pseudo-steady state

flow data forms a straight line when plotted on a Cartesian plot. In

Δψ addition to determining k, re and s′, the slope of versus time plot in q

PSS analysis can be used to find reservoir pore volume and gas in place

using drawdown data:

2347T Vp = ð10 mμgi cti

Þ

V 1−S

G = pð wiÞ 11 Bgi

ð Þ

The derivative analysis is carried out by taking the derivative of

Eq. (9) with respect to the logarithm of time, which gives:

2348q T t

Der = g a 12 A hφ μgi cti

ð Þ

This result is linear with time and the derivative of PSS data on a

log–log plot is a straight line with unit slope. Thus when log

versus log (tPSS) is plotted, it gives a straight line or a straight line

trend in the plot.

Using well test analyses techniques briefly presented in this

section, flow efficiency (FE) of a venthole can be calculated. FE is a

relative index that is defined as the ratio of actual productivity index

of a well to its productivity when there is no skin (s′= 0). Flow

efficiencies of about 2.0 may be obtained after hydraulic fracturing in

formations of moderately high permeability; in low permeability

formations, the FE may reach 5.0 after a fracture treatment (Matthews

and Russell, 1967). The relationship that was used in this study to

calculate flow efficiency is:

―ψ −ψ FE = R wf 0

― 13

ψR−ψwf 0−0:869m s′ ð Þ

Similarly, the damage ratio (DR), which is also a relevant index,

was calculated using:

1 DR = ð14 FE Þ

Thus, higher FE and lower DR indicate better reservoir-flow

properties and more productive boreholes.

4.2.3. Superposition in time

In order to apply the presented Eqs. (1)–(12) and techniques for

multi-rate production histories, the “elapsed time” should be defined

using the superposition theorem. This theorem mathematically states

that any sum of individual solutions of a second order linear

differential equation is also solution of the equation itself (Dake,

1978). Thus, superposition in time for a well producing with multiple

rate conditions for various durations means that individual constant

rate wells can be placed in the same position in the reservoir at any

time and an expression for the resulting pressure distribution in time

can be derived (Dake, 1978). The superposition time used in this study

to analyze the data was:

n qj−q ∑ − t = j 1

n logðt−t

j q j−1 15 = 1 n

Þ Þ

n qj tn + Δt−t

Δtn = ∑ log j−1 16

j= 1 qn tn + Δt−tj

ð Þ

4.3. Reservoir and fluid properties

Table 3 gives the reservoir and fluid data that was used in the F.A.S.

T WellTest® software (2009) for calculating the test data and results.

The data have been calculated based on full gas saturation (Sg= 100%)

in the gob and using average compositions of produced gas streams,

average pressure and temperature conditions measured during the

production periods and the published correlations (Reid et al., 1977).

Porosity values of ~10% in DM between rock layers and for a newly

formed gob determined from logs (Karacan, 2009), and 5% in AM due

to compaction were used in the calculations.

#

#

#

#

ð
Table 3

Reservoir and fluid data that have been used in the well test analysis.

1B-1-DM 2B-1-DM 2B-2-DM 2B-3-DM 2B-4-DM 3B-1-DM 1B-1-AM 2B-1-AM 2B-2-AM 2B-3-AM

Well radius (ft) 0.29 0.33 0.33 0.29 0.29 0.29 0.29 0.33 0.33 0.29

cf (1/psi) 1.68E−05 8.34E−05 1.09E−05 1.09E−05 1.09E−05 1.09E−05 1.09E−05 6.48E−05 1.75E−05 1.75E−05

ct (1/psi) 1.32E−03 1.32E−03 1.32E−03 1.35E−03 1.33E−03 1.31E−03 1.31E−03 7.72E−03 1.33E−03 1.31E−03

cg (1/psi) 8.34E−02 7.15E−02 7.17E−02 8.34E−02 8.34E−02 8.34E−02 8.34E−02 8.34E−02 8.34E−02 8.34E−02

Porosity (%) 10 10 10 10 10 10 5555

Twellhead (F) 60 60 58.4 49.2 54.2 94 60 94.7 96.7 97.5

Z (comp. fact) 0.997 0.999 0.997 0.997 0.997 0.998 0.997 0.998 0.998 0.998

Gas Vis (cp) 0.0101 0.0103 0.0101 0.01 0.0102 0.0106 0.0101 0.0107 0.011 0.0108

Bg (bbl/scf) 0.1858 0.1862 0.1852 0.1959 0.1837 0.1981 0.1858 0.2136 0.1991 0.1993 5. Well test models and analysis results

Routine production tests are performed in the oil and gas industry

for long-producing wells in order to identify productivity changes in

the wells to manage the reservoir better. For instance, by measuring

the flowing bottom-hole pressure with time for a constant production

rate, it is possible to determine the parameters of permeability and

skin by using the radial inflow equation. These tests are usually

expensive and require sophisticated downhole instrumentation and

analysis methods. However, the obtained data from these measurements and analyses are so helpful that they eventually are used as

input to the reservoir simulation models for updating the reservoir

parameters by history-matching the productions. Owing to the

importance of the measurement techniques and the analyses

methods, various researchers developed methods to test conventional

oil and gas wells for a better understanding of reservoir parameters

and improved reservoir management (Valvatne et al., 2003; Kuchuk

and Onur, 2003; Escobar et al., 2007).

For unconventional wells, such as GGVs on the other hand, the

development of specific testing and interpretation methods remained

not existent. This was partly due to the difficulties associated with

instrumentation of these ventholes because of safety concerns to the

operating mine, partly due to the complexity of the gob reservoir

created upon strata relaxation during panel mining, due to venthole

stability issues, and partly due to the short production lives of the

ventholes compared to conventional oil and gas wells. Despite these

road blocks, the importance of understanding the properties of the

gob reservoir is still of critical importance in order to control methane

in the mining environment. This study presents a rare application of

conventional gas well testing methods for analyzing GGV productions

from gob reservoirs.

5.1. Data preparation and analysis methodology for GGV productions

The flow rate and pressure data should be as accurate as possible

during the testing period. During data preparation, the flow data of

the first several hours after venthole interception were eliminated

from the production histories, since gas flow rates were changing

rapidly and unreliably during initial installation and operation of the

exhausters. Additionally, no special attempts, such as estimation,

were made to introduce the missing rates in the production history

when the rate data were missing due to exhauster malfunctions or

instrumentation failures. These dates were treated as empty dates in

the software. Also, no-flow rate simplification procedure was applied

to the data set and the full and unfiltered production history was used

as the multi-rate testing data.

Initially, test simulations were performed on linear scales using

different interpretation models, defined on a single flow period as

suggested by Bourdet (2003). This initial approach was adopted to

check whether the interpretation models were applicable for the

complete test sequence and to see if the selected model was applicable

for long periods. This approach also enabled checking of the impact of

the potential changes in venthole condition during production, which is

not uncommon for GGVs due to dynamic subsidence.

Interpretation of well test data is an inverse problem for which

more than one model can be found applicable to describe the pressure

response. During the analysis of rate-pressure data obtained in this

study, a representative interpretation model was first identified.

Using diagnostic plots, radial flow in a homogeneous-composite

reservoir during infinite acting (DM) and pseudo-steady-state acting

(AM) flow periods were chosen as the interpretation models. These

models were found to be more appropriate for the studied cases and

for the measured data.

Fig. 7 schematically shows the two types of models chosen for the

interpretation of gas venthole production data and the reservoir

parameters.

The test simulations, using the models given in Fig. 7, were started

with initial estimates of the reservoir and wellbore parameters, which

were adjusted using F.A.S.T. WellTest's (Fekete Associates, 2009) APE

(Automated Parameter Estimation) iteration algorithm to match the

field data and to concurrently reduce the average error on three usual

plots: log–log, semi-log superposition and linear scale test history.

These plots focused on the complete flow and test sequence.

5.2. Results of tests and interpretation for GGVs and gob reservoirs

Figs. 8 and 9 show the example data matches for DM and AM

phases of production, respectively, obtained for 2B-1 venthole using

the models shown in Fig. 7. The calculated data and the model

predictions for wellhead pressure histories on linear scale (C-plots),

semi-log superposition (B-plots) and log–log scale (D-plots) are

presented in the same plots for comparison purposes. In each figure,

Plot-A is the measured gas rate and wellhead pressures used in the

analyses. These figures show that the model predictions on linear,

semi-log superposition and log–log data are generally good for both

DM and AM production phases of 2B-1 venthole production. By using

the data of these plots, average reservoir and wellbore skin

parameters were calculated for 2B-1. Similar analyses were performed for each venthole. The results of these analyses for each

venthole for their DM and AM production phases are given in Table 4.

Table 4 presents the findings of permeability and radius of

investigation results in the first four rows of the tables for DM and AM

flow periods of each venthole. For the DM flow period, the results show

that the estimated permeabilities were highest, 1173 and 1544 md,

around (Zone 1-Fig. 7) 2B-1 and 2B-2 ventholes, respectively.

Permeability values around the other ventholes were calculated as

650–700md. For 2B-1 and -2, the permeabilities calculated for the

reservoir portion beyond the radius of Zone-1 were also highest. The

permeability values calculated for Zone 2 for these ventholes were

around 2000 md, as opposed to ~1000 md for the other ventholes

except 2B-3, which had ~1500 md outside of Zone-1. However, it should

be kept in mind that these average effective permeabilities were

calculated for the whole 200 ft section open to flow through the casing

slots using a homogeneous model. Thus, individual fractures or bedding

plane separations might have higher permeabilities.
Fig. 7. Schematic representation of radial-composite models used in DM (A) and AM (B) phases of venthole production.

The radius of investigation of 3B-1 in Zone-1 was the largest of all

ventholes with a calculated value of ~2820 ft. This venthole was

followed with 2B-1 and 2B-2, whose radii of investigation values were

~1200 ft. On the other hand, 1B-1, 2B-3 and -4 had calculated Zone-1

radii values of 700–800 ft. However it should be emphasized that,

although the radius of investigation is frequently viewed as the

minimum radial distance to any event that will not be observed during

the test period, the transient radius may be greater than the radius of

investigation estimated from well tests due to layer permeability and

saturation variations. This is certainly a valid observation for the current

study due to the known existence of fractures and bedding layer

separations during mining. Thus, due to the averaging effects of the

interpretation results, the complete reservoir area affected by the well

production may be confined in a different circular area around the

wellbore (Oliver, 1990). The calculated radius of investigation from the

well tests gives an approximate value and an order of magnitude idea

about the true distance for the existence of boundaries (Matthews and

Russell, 1967) rather than an exact distance.

Fig. 8. Plots of gas flow rate-wellbore pressure (A), semi-log superposition time (B), linear pressure match (C) and log–log flow potential and derivative (D) for analysis of 2B-1 in DM

period—radial infinite acting period.

In all of the ventholes, calculated total skins and the mechanical

skins around the ventholes were high (increasing negative values)
meaning that the ventholes showed the properties of extensively

fractured wells. These values were in agreement with the gob

reservoir conditions generated during longwall mining as depicted

in Fig. 1. The calculated skin values were also in agreement with the

cumulative gas productions obtained from the ventholes and the flow

efficiency values.

Table 5 shows methane and total gas productions and their

average production rates, as well as methane percentages. These

values can be compared with the calculated reservoir properties from

the well tests. This table shows that 2B-2 had the highest cumulative

gas and methane production, as well as highest production rates in

DM flow phase. These data corroborates with 2B-2's permeability,

radius of investigation and skin values shown in Table 4.

Table 4

Results of multi-rate well tests analyses for DM and AM flow periods of all monitored gob gas ventholes.

1B-1-DM 2B-1-DM 2B-2-DM 2B-3-DM 2B-4-DM 3B-1-DM 1B-1-AM 2B-1-AM 2B-2-AM 2B-3-AM

re1 (ft) 729.2 1198.9 1218.9 781.7 781.6 2818.2 1787.3 579.8 360.8 620.5

kre1 (md) 651.9 1173.0 1543.8 700.2 715.6 633.6 864.7 1937.1 524.1 405.0

re2 (ft) inf. inf. inf. inf. inf. inf. 2062.3 9179.2 9173.8 6300.1

kre2 (md) 1050.0 1974.4 2145.8 1581.2 899.0 1076.8 1466.6 10788.2 15648.5 11223.5

Total skin (s′) −6.2 −5.5 −7.9 −7.4 −5.2 −8.4 −2.4 −3.6 −6.1 −5.5

Mech. skin −5.2 −4.5 −6.9 −6.4 −4.2 −7.4 −1.4 −2.6 −5.1 −4.5

Final rate (MMscf/day) 0.161 0.406 0.671 0.379 0.264 0.256 0.049 0.073 0.317 0.189

Cum. prod. (MMscf) 44.489 59.143 87.328 16.606 5.776 28.124 10.933 31.046 68.803 4.580

Final flow pressure (psia) 12.3 11.9 12.1 11.6 11.9 12.7 12.2 12.4 12.6 12.4

Ave. error (%) 0.98 1.08 0.88 0.77 1.14 0.47 1.83 0.79 0.70 0.86

FE 2.3 2.2 3.9 5.6 2.1 5.4 1.4 1.8 8.2 3.2

DR 0.4 0.5 0.3 0.2 0.5 0.2 0.7 0.5 0.1 0.3

Table 4 also shows the average gob reservoir parameters

calculated for the AM flow phase of gob gas ventholes using the

model shown in Fig. 7-B. In using this model, it was assumed that the

end of mining and sealing of the panel will create a bounded reservoir

effect on the ventholes' productions in which the pressure transients

reach the outer boundaries very quickly and start a pseudo-steady

state flow period. Since the AM phase of flow was monitored for only

four of the ventholes, the analyses were performed using that data.

Fig. 9. Plots of gas flow rate-wellbore pressure (A), superposition time (B), linear pressure match (C) and log–log flow potential and derivative (D) for analysis of 2B-1 in AM period—

radial pseudo-steady state acting period in closed reservoir.

For the AM phases of productions, the calculated permeabilities

were highest in Zone-1 of 1B-1 and 2B-1 with values of 864 md and

1937 md, respectively. Radii of these zones extended approximately

to 1790 ft and 580 ft from 1B-1 and 2B-1, respectively. However, the

total and mechanical skins were lower in these ventholes compared to

other two ventholes (2B-2 and 2B-3) that had somewhat lower

permeabilities within a smaller near-venthole zone, particularly for

2B-2. The outer zones of the gob reservoirs around these ventholes

were generally large (6000–9000 ft), except 1B-1, and had high
permeabilities (11,000–16,000md). The highest permeability

(~15,650 md) and one of the largest influence zones (~9174 ft) was

calculated for 2B-2. This borehole had the highest skin (−6) and the

highest flow efficiency (8.2), which resulted in the highest methane

and cumulative gas production and the highest production rates

(Table 5). Although 2B-3 had also a high skin value, reasonably high

permeabilities and large influence zones, its production rate and

cumulative production were low.

Although the reservoir and borehole data calculated using well

testing methods generally corroborates the productivity of the

ventholes, the well test results are average values based on the

homogeneity assumption of the well test model. Therefore, the

properties of individual heterogeneities may not be well represented

in this approach. Furthermore, there are other factors that affect

properties of gob reservoirs and the productivity of gob gas ventholes,

such as tension and compression zones and the location of the

ventholes with respect to these zones. It has been established in the

introduction section that the caving action and formation of a gob

reservoir are very complex and highly dependent on the strata. In

such an environment, the location of the ventholes is of critical

importance. The ventholes, when they are located close to the entries

and particularly tailgate entries (Fig. 4), produce better since they stay

in the tension zone compared to the center locations, which are under

compression. 2B-2 is one of those ventholes that was located closest

to the tailgate entry of the second panel.

Specific to this site, there was a sandstone channel with varying

thicknesses above the mined coal bed, which spatially replaced the

weak shale units (Fig. 4). 2B-2 and 3B-1 were located where there was

no sandstone above the coal bed. 1B-1 and 2B-1 were drilled where

the sandstone thickness was between 0 and 20 ft, and 2B-3 and 2B-4

were located where sandstone thicknesses were >20 ft and 40 ft,

respectively (Fig. 4). The presence of this sandstone and its thickness

below the ventholes affected both caving behind the shields and the

fracturing of the overlying strata. Interpretation of well test results

(Tables 4 and 5) along with the sandstone channel thickness below

the ventholes generally suggest that when it is absent or thin, the well

test calculated permeability of gob reservoir around the ventholes and

radii of investigations are larger. In these boreholes, high negative

skins and high flow efficiencies are also observed. These calculations

corroborate the total gas and methane production potentials (Table 5)

of the ventholes drilled in locations where sandstone was thin or

washed out, as opposed to ventholes drilled in thick portions of this

sandstone (2B-3 and 2B-4).

This study and the approach undertaken suggest that conventional

well test techniques can be a promising way to evaluate complex gob

reservoirs and to assess gob gas venthole performance for safety

purposes during longwall mining and for optimizing methane

capture. However, the well test results should be interpreted with

the integration of local geological and geophysical data, as commonly

practiced in oil and gas industry.

Table 5

Cumulative gas and methane productions, and their production rates from each ventholes in DM and AM phases of flow.

Venthole/

flow phase

Average CH4

(%)

Average gas (CH4+Air)

rate

(MMscf/day)

Cumulative

gas production

(MMscf)

Average CH4

rate

(MMscf/day)

Cumulative

CH4 production

(MMscf)

1B-1-DM 90.5 0.240 44.48 0.220 40.77

2B-1-DM 40.2 0.477 59.14 0.192 23.75

2B-2-DM 46.2 0.685 87.32 0.317 40.23

2B-3-DM 53.8 0.385 16.60 0.209 8.98

2B-4-DM 45.7 0.310 5.77 0.139 2.64

3B-1-DM 87.5 0.270 28.12 0.238 15.90

1B-1-AM 75.7 0.109 10.93 0.086 8.13

2B-1-AM 40.8 0.225 31.04 0.088 12.10

2B-2-AM 59.2 0.442 68.80 0.252 37.83

2B-3-AM 39.8 0.154 4.58 0.061 1.79

6. Summary and conclusions

The ability to analyze the gob gas venthole data and to reconcile

gob properties is important for designing better methane control

strategies to improve the safety of the underground workforce and to

improve methane capture from the gob as a clean fuel. This study

presented an effort for application of well test analysis techniques for

determination of gob reservoir properties and gob gas venthole

performances.

Wellhead gas production rates and pressures were monitored for 6

ventholes located on adjacent panels during and after mining. Since

these two stages potentially resulted in varying gob reservoir

characteristics and gas capacities, they were analyzed separately

using two different models. Multi-rate well test techniques were used

for both situations. The application of these techniques was justified

given the high permeability of the gob reservoir which enabled almost

instant stabilization of pressure after a rate change at the wellhead.

The results showed that conventional well test analyses methods

can be used for the appraisal of gob characteristics, such as

permeability around the venthole and out in the gob, radius of

investigation, total and mechanical skin around the ventholes and the

ventholes' flow efficiencies and damage ratios.

The results specific to this study and the mine site showed that

although the gob reservoir and venthole data calculated using well

testing methods generally corroborated the productivity of the

ventholes, there were other factors that should be considered in

evaluations. For instance, reservoir heterogeneities during caving and

formation of the gob were very complex and were highly dependent

on the local strata. In such an environment, the locations of the

ventholes were of critical importance. This study proved that

ventholes located close to the entries, particularly tailgate entries,

produced better.

The presence of the sandstone channel and its thickness below the

ventholes affected both caving behind the shields and the fracturing

of the overlying strata. Interpretation of well test results along with

the sandstone channel thickness below the ventholes generally

suggested that when the sandstone was absent or thin, the well test

calculated permeability of the gob reservoir around the ventholes and

the radius of investigations predicted in the gob were larger. In these

boreholes, high negative skins and high flow efficiencies were also

observed. Quantitative well test results corroborated with the total

gas and methane production potentials of these ventholes and their

locations with respect to the spatial thickness of the sandstone.

It was shown that conventional well test techniques could be a

valuable tool for reconciling gob gas reservoirs and gob venthole

performances since there is no other more effective alternative.

Owing to the complexity of the system, model choice should be

performed with care and by considering the details due to mining

effects. Furthermore, local geology and geophysical data, as well as

proven caving characteristics, should be integrated into the
interpretation of well test results and into the methane controlsystem design process.

Nomenclature

A drainage area m2 ft2

Bg formation volume factor –

c compressibility kpa−1 psi−1

DR damage ratio –

FE flow efficiency –

h net pay m ft

k permeability md md

kh flow capacity md.m md.ft

k/μ mobility –

kh/μ transmissivity –

m slope of transient plots –

P pressure kPa psia

Pi initial pressure kPa psia

PR average reservoir pressure kPa psia

Ptf flowing wellhead pressure kPa psia

Pwf flowing sandface pressure kPa psia

q j ow rate m3 j th fl /d scf/d

qn nth 3 flow rate m /d scf/d

re external radius, or radius m

of investigation

rw wellbore radius m ft

s skin factor –

s′ apparent skin factor –

Sg saturation (gas) –

t time h h

ta pseudo-time h h

tn nth flow period, –

or superposition time

Ψ pseudo-pressure for gas kPa2

/Pa.s psia2/cp

Subscripts

f formation or flowing

g gas

i initial

w wellbore

–

–

–

–

–

–

ft

–

–

–

–

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