The use of numerical simulation in predicting coalbed methane producibility from the Gates coals, Alberta Inner Foothills, Canada: Comparison with Mannville coal CBM production in the Alberta Syncline

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International Journal of Coal Geology 74 (2008) 215 – 236 www.elsevier.com/locate/ijcoalgeo

The use of numerical simulation in predicting coalbed methane producibility from the Gates coals, Alberta Inner Foothills, Canada: Comparison with Mannville coal CBM production in the Alberta Syncline Thomas Gentzis a,⁎, Dale Bolen b a b

Petron Resources, L.P., 3000 Internet Boulevard, Suite 400, Frisco, TX 75034, USA Primewest Energy Inc., 150, 6th Ave SW, Suite 4700, Calgary, AB T2P 3Y7 Canada

Received 2 June 2007; received in revised form 7 December 2007; accepted 12 December 2007 Available online 5 January 2008

Abstract Two medium to low volatile bituminous rank coals in the Lower Cretaceous Gates Formation (Mannville equivalent), Inner Foothills of Alberta, were cored as part of a coalbed methane exploration program. The target seams (Seam 4 and Seam 10) were intersected at 652 m and 605 m, respectively. The coals were bright banded, relatively competent and reasonably cleated, with cleat spacing between 5–20 mm. The FMI (Formation Micro-Imaging) log identified two primary fracture directions, corresponding to both face and butt cleats, which were developed almost equally in some coal intervals. The amount of shearing was limited, in spite of the presence of numerous thrust faults and fold structures in the corehole vicinity. Total gas content was high, with an average of 17.7 cm3/g (arb; 568.1 scf/t). An adsorption isotherm of the thick Seam 4 showed gas saturation levels of 90% at in-situ reservoir conditions. Methane content was 92–96% and carbon dioxide levels were less than 2%. Isotopic studies on the methane confirmed the thermogenic origin of the gas, as anticipated based on the coal rank. The coal seams were fracture stimulated using 50/50 nitrogen and fresh water along with 9 to 12 tons of 12/20 mesh sand used as a proppant. It is believed that the coals were not stimulated properly because of the small proppant volume and the complex — and often unpredictable — fracture pattern in coals, particularly in the Inner Foothills region that has high stress anisotropy. An injectivity test showed coal absolute permeability to be less than 1 mD, the skin to be − 2 (indicating a slightly damaged coal) and water saturation in the cleats to be 90%. A four-month production test was conducted; gas rates declined from 930 to 310 m3/d (33 to 11 MCFD) and water rates were low (b5 BWD). Produced water was saline (TDS was 20,000 mg/L) and high in chloride and bicarbonate ions. Production testing was followed by history matching and numerical simulation, which consisted of numerous vertical and horizontal well development scenarios and other parameters. Simulating multiple parallel horizontal wells in the Gates coals resulted in the highest peak gas production rates, cumulative production and recovery efficiencies, in agreement with public data from the Mannville coals in the deeper part of the Alberta Syncline. The positive effect of constructive interference in depressurizing the coal reservoirs and accelerating gas production over short periods of time was demonstrated. Coal quality data from a nearby underground mine shows that drilling horizontal wellbores in the Gates coals would be challenging because of unfavourable geomechanical properties, such as low cohesion and unconfined compressive strength values, and structural complexity. © 2008 Elsevier B.V. All rights reserved. Keywords: Coalbed methane; Gates coals; Canadian Inner Foothills; Numerical simulation

1. Introduction The Greywolf 102/06-14-57-7W6 corehole (Latitude 53°56′N and Longitude 118°56′W), the subject of this study, was drilled in ⁎ Corresponding author. Tel.: +1 972 335 6478; fax: +1 972 335 6478. E-mail address: [email protected] (T. Gentzis). 0166-5162/$ - see front matter © 2008 Elsevier B.V. All rights reserved. doi:10.1016/j.coal.2007.12.003

a location approximately 12-km to the northeast of the town of Grande Cache in the Alberta Inner Foothills (Fig. 1). The corehole was drilled in late January 2003 to provide data related to coalbed methane (CBM) prospectivity of the coals in the Gates Formation in the area. In the corehole vicinity, structures range from gentle folding to severe folding and faulting. The corehole targeted a NW–SE-trending double anticline/syncline pair. This structure

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Fig. 1. Map of Alberta, Canada, showing the study area near the town of Grande Cache in the Inner Foothills region (modified from Ricketts, 1989).

lies within the Muskeg, Mason and Syncline Hills thrust sheets (Fig. 2), where the Gates Formation coals are found at 150- to 1400-m depth. The Grande Cache Member of the Lower Cretaceous Gates Formation in the Foothills and Mountain regions of Alberta is the equivalent to the Mannville Group in the Plains region. The Grande Cache Member has about 125-m thickness and is made up of sandstone, siltstone, mudstone, and coal (Fig. 3). Up to eight coal seams with cumulative thickness of 16.5 m have developed in the Gates Formation within the Smoky River coalfield. In the mining areas, Seam 4 is the thickest (up to 7 m as a result of tectonic thickening) and has an average ash content of 10 wt.% (dry basis) although lower ash intervals (4–8%) are also present. Seam 6 is less than 1.5-m thick and has an average ash content of 17%. Other laterally continuous coals include seams 3, 4, 6, 7, 10, and 11 (Fig. 3). Only seams 4 and 6 were cored in the Greywolf corehole. The Smoky River coalfield was deformed by tectonic events of the Laramide Orogeny (60 Ma. B.P). Strata, including coal seams are complexly folded and cut by numerous thrust faults. Surface traces of folds and faults trend to the northwest– southeast (Fig. 2). The majority of the faults are southwestdipping thrusts that display ramps that cut up the stratigraphic section and flats that are parallel to bedding planes. Fault displacements are in the order of 10 to 100 m, with structural shortening estimated at 33% (Norwest Corporation Report, 2004). As a result of structural complexity, it is difficult to quantify the CBM potential in the Rocky Mountain Foothills/ Mountains. Local geological features (e.g., the presence of

faults and shear zones), the hydrologic regime (regional and local water tables) and depth of cover all play an important role in the retention of methane that has been generated by the mainly bituminous rank coals in these regions. Unlike much of the Deep Basin where the Gates Formation coals lie at depths greater than 2000 m and thus considered too deep for economic CBM production, there are a number of areas in the Inner Foothills where the Gates Formation coals are found at shallower depths (b 700 m). The reason is that folding, faulting, and topographic relief have in combination brought the seams closer to the surface or to shallow depths, which permits the drilling of relatively shallow CBM wells. Coal rank variations and coalbed methane potential in the Rocky Mountain Foothills and adjacent deep Foreland Basin have been described by Kalkreuth and McMechan (1984), Langenberg et al. (1990), Kalkreuth et al. (1989), and Dawson and Kalkreuth (1994). The coalification patterns of seams 4 and 10 show no significant change in rank across thrust faults in the Grand Cache area, which suggests that coal rank was established mainly before thrusting started (i.e., pre-deformation coalification on a local scale) although the biaxial optical indicatrix of many oriented block samples of Gates coal seams 4, 10, and 11 in the Grande Cache area suggests a small component of syn-deformation coalification (Kalkreuth et al., 1989). It is postulated that biaxial Gates coals (Romax parallel to the fold axes) resulted from the preferential orientation of the aromatic lamellae in a direction parallel to minimum horizontal compressive stress (Levine and Davis, 1984) and that coalification prior to folding and thrusting occurred in the presence of a tectonic stress field.

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Fig. 2. Map of the Alberta Inner Foothills showing thrust sheets and structural geology (redrawn from Kalkreuth et al., 1989).

1.1. Previous CBM exploration The objective of this study is to predict, by means of numerical simulation, the coalbed methane production from vertical and horizontal wells drilled in the Gates coals, Alberta Inner Foothills, and to compare the production to the stratigraphically equivalent Mannville coals in the Alberta Syncline. Reference to previous CBM exploration in the study area is given in Appendix A. The regional evaluation of the CBM potential of the Foothills/Mountains has been discussed by Langenberg et al. (2006). The public domain contains data from five CBM wells that have been drilled in the Gates Formation coals in the vicinity of Grande Cache. Mobil Oil and Chevron Canada drilled two coreholes near Susa Creek, within 100 m of each other and targeted coals at depth of 600–700 m. However, the intended thick coals were missed and thinner coals from the underlying Gladstone Formation (Fig. 3) were cored instead. Less reliable sidewall cores were taken from Seam 3 (0.5-m thick). Gas

content for Seam 3 was 16.8 cm3/g (ash-free). A Langmuir adorption isotherm at reservoir temperature and pressure resulted in a maximum gas holding capacity of 18 cm3/g (576 scf/t), indicating 93% saturation level. Four drill-stem tests (DSTs) conducted on Seam 4 and the overlying Seam 10 resulted in very low permeabilities (b 0.1 mD). A DST can provide information on the coal absolute permeability, skin factor, and initial reservoir pressure but generally has a limited use in coal reservoir engineering studies. Very low flow rates of dry gas were reported (0.01 and 0.14 m3 /d or 0.35 SCFD and 5.1 SCFD for Seam 4 and Seam 10, respectively). Technical problems related to the anchors of the heli pumps were encountered. No water was recovered during the limited production testing. The well was subsequently fracture stimulated with a non-linear gel and sand proppant. As a result of fracturing, the well produced 5633 m3 /d (200 MCFD) for one day and then stabilized at 4225 m3 /d (150 MCFD) before declining sharply to 1408 m3 /d (50 MCFD). The well was pumped for a few weeks and flowed at only 1.4 m3 /d from

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Fig. 3. Stratigraphic column in the Smoky River coalfield (redrawn after Norwest Corporation Report, 2004).

Seam 10. It was felt that an 18-inch (45 cm) mini-cavity had been inadvertently created in the coal seam (G. Sloan, pers. commun., 2003), which resulted in the higher — albeit shortlived — production rates. 2. Sampling and analytical methods 2.1. Gas content measurements and laboratory analyses In the Greywolf corehole, samples were obtained from wireline cores. Once the coal core samples were canistered, they were placed in a water bath at temperature well above reservoir temperature in order to quickly bring the core to the reservoir temperature of 27 °C. The temperature of both the headspace air and of the core were monitored and recorded. When the core reached reservoir temperature, the canisters were transferred to a heated air-bath maintained at reservoir temperature. Samples were allowed to desorb at reservoir temperature until desorption

had essentially ended almost three months later. Gas content data are presented in Table 1. For lost gas volume estimate, the cumulative desorbed gas volume was plotted against the square root of desorption time and a regression analysis was applied to the steepest linear part of the curve. The regression line was projected back to “time zero” (when gas began to desorb from the sample). In the early stages, desorbed gas volumes were measured frequently (every two to 5 min) in order to clearly define the steepest part of the desorption curve and to facilitate an accurate estimate of the lost gas component. As desorption rates declined, the measurement interval was increased to hours and eventually to days. Cumulative desorbed gas volume was plotted against total desorption time to provide a desorption curve for each canistered sample. With the exception of Canister 3, residual gas volumes were determined by crushing the samples in a closed system using the Ball & Mill method. For Canister 3, the residual gas component was estimated graphically.

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Four of the desorbed samples were forwarded to the laboratory for proximate analysis and specific gravity determinations. Selected samples were also submitted to commercial laboratories for adsorption isotherms and gas samples selected during desorption were analysed for composition/heating value, and for carbon and deuterium isotopes to determine the origin of the gas. Representative coal samples were analysed for vitrinite reflectance and maceral composition. 2.2. Numerical simulations A series of numerical simulations was conducted for both vertical and horizontal drilling scenarios to ascertain optimum well spacing, gas and water production rates, and gas recovery from one section of land (258 ha or 640 acres). Simulations were done using CMG's (Computer Modeling Group) GEM© simulation software, which is specifically designed for CBM applications and takes into account the coal matrix shrinkage effect during depressurizaton of the reservoir. GEM© is a multidimensional, isothermal equation-of-state (EOS) compositional simulator, which has the capability of being coupled with a thermohydromechanical simulator called FLAC© (Gu and Chalaturnyk, 2004). The input parameters used for the numerical simulations are shown in Table 2. Selecting a proper relative permeability curve is important in any numerical simulation exercise. For this study, one of the relative permeability curves established by Meany and Paterson (1996) from history matching of vertical coal well field production data in Australia was used. The Meany and Paterson curve is thought to be more applicable to the Gates coal reservoir than the more widely used Gash (1991) curve because of the high value of irreducible water saturation in the Gates coal cleats (Sw = 88%). This occurs when low viscosity gas displaces high viscosity water. The gas bypasses large portions of water, thus effectively trapping the water and resulting in high residual water saturation levels in the cleats, a phenomenon referred to as “viscous fingering” (Meany and Paterson, 1996).

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Table 2 Input parameters used for numerical simulation using CMG's GEM© simulator software Property

Value

Units

Geometry Depth to the top of target formation Net thickness Drainage area Producing area Vertical geometry (net pay) Horizontal well Dip angle Wellbore radius

605 2.5 5760 640 2.5 800 5 0.079

m m acres acres m m ° m

Formation matrix properties In-situ average gas content Average mineral matter content Equilibrium moisture Langmuir volume (dmmf) Langmuir pressure Sorption time Average coal seam density

15.53 8.3 1.3 21.81 1543 18 1.31

cc/g wt.% % cc/g kPa h g/cc

28 5700 605 0.8 0.62/0.1555 Meany 100/0%

°C kPa m % md

93.3, 0.3, 1.3 0.835 1 0

mol% cP

Cleat system properties Reservoir temperature Initial pressure Pressure datum, kB Effective porosity Permeability distribution Relative permeability relation Fluid saturation distribution Pore volume compressibility Fluid properties Gas composition (C1, C3 and CO2) Water viscosity at reservoir conditions Water formation volume factor Skin

w/g

2.3. Coal geomechanics Although no Gates Formation coal cores were submitted for tri-axial testing, limited information on the geomechanical

Table 1 Analytical and gas content data, Gates Formation coals, Greywolf corehole Proximate analysis ADM Moisture

Gas content Ash

Volatile matter

%

% adb % arb % adb % arb

% db

2.64 0.96 2.06 2.68 1.94

0.34 0.35

2.97 1.31

10.96 15.52

10.67 15.37

0.30 0.23

2.97 2.17

2.42 4.78

2.36 4.69 8.27

11.00 21.91 15.57 17.61 NA 2.34 23.25 4.79 24.25

S.G.

% adb % arb % db

% daf

Lost gas

Desorbed gas Residual gas Total gas content (scf/t)

(adb) (scf/t; arb) (scf/t; arb)

(scf/t; arb)

(arb)

(adb)

(daf)

12.00 2.87 3.37 17.92 21.59 Mean

527.15 550.32 604.56 683.64 474.84 568.10

541.43 555.66 617.28 702.46 484.24 580.21

610.40 660.48 NA 722.10 509.78

21.33 17.44

21.98 24.70 17.67 20.93

1.33 1.40

22.91 23.78

23.61 24.20 24.31 25.53

1.27 1.27

97.57 93.07 117.56 85.12 80.49

417.58 454.38 483.63 580.60 372.76

Moisture, ash, and volatile matter values are in wt.%. ADM for canister 3 is assumed as mean value for the other four canisters. Residual gas was estimated graphically for this canister. arb = as-received basis. adb = air-dried basis. daf = dry ash-free absis. NA = not available.

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parameters of these coals is available (Norwest Corporation Report, 2004). Two such parameters, friction angle and cohesion (Wyllie, 1999), were measured. Friction angle is a parameter measured by the Mohr–Coulomb strength failure criterion and represents the angle between the tangent to a series of Mohr's circles with the horizontal plane on a plot of shear stress (Y-axis) versus effective normal stress (X-axis). Cohesion is another Mohr–Coulomb strength parameter, which represents the point at which the tangent to the Mohr's circles intersects the shear stress axis. The low cohesion value is typical of coal having low strength; for example, sheared or pulverized coal has almost zero cohesion. 2.4. Well stimulation The Greywolf corehole was acidized and the coal intervals were perforated. Fracture stimulation was accomplished using 50% nitrogen and 50% fresh water along with 9 to 12 tons of 12/20 proppant sand. Injection/pressure fall-off testing was conducted to provide information on absolute permeability, mechanical skin (Joshi, 1991), and initial pressure. This test is most widely used in new (not re-completed) coal wells.

Fig. 4. Transverse section of Gates Formation core taken from Seam 4 coal and showing good cleat development. FC is for Face Cleat. Core diameter is 8.75 cm (3.5 in.).

3.3. Formation Micro-Imager (FMI) log 3. Results and discussion 3.1. Drilling Simmons Drilling undertook the drilling operations using a wireline retrievable coring rig. The coals were targeted in two core intervals with a 37-m rotary interval between them. Core recovery in the first interval was only 66%, due mainly to the loss of a complete core (Run #2, 2.90 m) when the core lifters failed to hold the core in the barrel during the up-hole trip. Based on the drilling penetration rate, it is probable that most of this cored interval was in coal. Recovery in the second core interval was excellent at 98%. Wireline core retrieval facilitated quick recovery of coal to surface and minimised lost gas times. The Gates coal cores arrived at the surface within 15 min from the drilling depth of 600–700 m. 3.2. Coal character The coal lithology varied but was predominantly described as banded to banded-bright (i.e., 40% to 80% bright bands). Generally, there were two cleat directions developed, with face cleat (FC) spacing being 5 mm in the brighter lithologies and up to 20 mm in the duller lithologies (Fig. 4). Butt cleat was generally less regular and penetrative, but spacing was similar to that of face cleats. In some bright lithotypes, cleating was equally developed in both directions and the coal broke into 5 mm cubes. No mineralization was observed on the cleat surfaces. Overall, the core was relatively competent, illustrating a lack of major shearing that is often found in Rocky Mountain Foothills/Mountains coals. However, minor shear fractures with associated feather-like joints and minor thin zones with moderate shearing were present.

High-resolution (0.5-cm intervals) reservoir characterization of the Gates coals and adjacent sandstones and mudstones was facilitated by electrical borehole measurements made with the Formation Micro-Imager (FMI) tool. Unique reservoir characteristics provided by the FMI tool include dip and strike of beds, sedimentary structures, faults, and fractures including cleat development, orientation and well inclination. Quantitative assessment of thin partings and mineralized fractures or cleats, both of which can degrade coalbed reservoir permeability, can be visualized on borehole images. The FMI logs of the two intervals where the coal seams of interest were intersected in the Greywolf corehole and the locations of the canistered coal are shown in Fig. 5 (A–B). The corehole inclination and bearing are shown on the left-hand column. The bright intervals correspond to the coal seams and the darker intervals reflect interbedded clastic strata. The Canister 2 sample, taken from the darker interval overlying the coal seam, had 15.4 wt.% ash content. On the contrary, the Canister 4 sample, taken from a bright interval, had the lowest ash content (2.4 wt.%) and represented clean coal. The polar stereonet plot (see the middle column) shows the strike of the face and butt cleats. The majority of fractures in the upper interval (605– 610 m) had a strike of 323–335° whereas a second set of fractures had a strike from 21–37°. The azimuth of the majority of fractures was inconsistent with the present-day maximum horizontal stress direction, which is also the face cleat direction in the coals. However, the majority of fractures in the upper interval were consistent with the direction of butt cleats in coals, which, based on core description, were also well developed in this interval. Because both sets of cleats were equally developed in the upper interval, the FMI log did clearly differentiate between face and butt cleat orientation. In the lower interval (652–657 m), the majority of fractures had a strike from 11–49°

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Fig. 5. (A–B) FMI logs of cored intervals sampled by desorption Canister 1 (A) and desorption Canisters 2 to 5 (B).

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and a small number from 304–315°. The azimuth of the majority of fractures in the lower interval was consistent with the direction of the maximum horizontal stress in the Western Canadian Sedimentary Basin (Bell et al., 1994). 3.4. Proximate analysis and petrographic composition Results are shown in Table 1. Ash content was moderate to very low (2.4% to 15.5%; air-dry basis), which should provide a positive influence on both gas content and cleat development. There was a linear relationship between ash and specific gravity. Volatile matter on a dry ash-free basis (daf) ranged from 20.9 wt.% to 25.5 wt.% with a mean value of 23.8 wt.%. The volatile matter values are indicative of a coal rank in the medium to low volatile bituminous range (Stach et al., 1982). At this high rank level, coals have progressed beyond the zone of maximum gas generation and gas contents are expected to be high. Good cleat development with high density can also be expected for this coal rank. Coal from Canister 3 was not analysed as it was used for adsorption isotherm testing. Vitrinite reflectance is an accurate rank parameter over much of the range of coal rank. Minimal variation in rank is expected over the narrow depth interval that was sampled. Vitrinite reflectance of a Seam 6 sample taken from 606 m was 1.37% Romax. A sample of Seam 4 coal taken from 652 m had 1.47% Romax, which indicates rank at the boundary between medium and low volatile bituminous coal. Total vitrinite content in the samples analyzed was 61% (consisting mainly of collotelinite and collodetrinite), inertinite was 31% (made up of fusinite, semifusinite, inertodetrinite, and macrinite), liptinite was b1%, and mineral matter was 7%. 3.5. Lost gas The use of wireline core retrieval minimised the time during which gas could be lost on the trip up-hole. Core-retrieval time was 9 to 16 min and it generally took another 17 to 24 min to remove the core, describe and photograph it, and seal samples in desorption canisters. Lost gas time was typically between 26 and 40 min. Lost gas values were relatively high (2.51– 3.7 cm3/g or 80.5 scf/t to 117.6 scf/t; arb; Table 1) and lost gas was a significant proportion of the total gas content (12.4% to 19.4%; arb). 3.6. Desorbed gas Samples were allowed to desorb at reservoir temperature until desorption had essentially ceased and the curves were “flat”. Desorbed gas volumes ranged from 11.6–18.1 cm3 /g (372.8 to 580.6 scf/t; arb) as shown in Table 1. The coal with the lowest ash content showed the highest desorbed gas volume. Sorption time is defined as the time required for 63% of the lost and desorbed gas to desorb. For these coals sorption times were quite short, ranging from 12 to 16 h for four of the samples. Sorption time for Canister 2 was significantly longer at 28 h, although this still represented a fast desorption rate.

3.7. Residual gas This small volume of gas is usually not produced economically but it is important to include it in the total gas content for comparison with adsorption data, which always includes the residual gas. Residual gas varied from 0.09–0.67 cm3/g (2.9 to 21.6 scf/t; arb) (Table 1), thus not exceeding 4.5% of the total gas content. This is within the expected range. 3.8. Total gas content Total gas content values were high, ranging from 14.9 cm3/g (474.8 scf/t; arb) to 21.4 cm3/g (683.64 scf/t; arb) with a mean value of 17.7 cm3/g (568.1 scf/t; arb) (Table 1). Fig. 6 shows the relationship between gas content and ash (air-dried basis) for the four analysed samples. As has been found in larger CBM data sets, samples with very low ash often have gas content that is anomalously high when compared to predicted values derived from higher ash samples sets (D. Marchioni, pers. commun., 2003). In this case, Canister 4 had ash content of 2.43% (adb) and total gas content appeared to be very high. 3.9. Adsorption isotherm A sample taken from Seam 4 at 653 m depth was subjected to high-pressure methane adsorption at reservoir temperature of 27 °C and pressure of 5700 kPa. The ash content of the sample was 2.8% and its equilibrium moisture was 1.3%. Langmuir pressure (PL) was 1543 kPa and Langmuir volume (VL) was 21.8 cm3/g (698.7 scf/ton). At this rank level, equilibrium moisture in coals is low and similar to the as-received moisture. Consequently, in-situ moisture could also be similar to the asreceived basis moisture. At reservoir pressure, the Gates Formation coal sample had maximum holding capacity of about 18.7 cm3/g (597 scf/ton) while total gas content from desorption was 16.8 cm3/g (538 scf/ton; arb). This indicates an apparent saturation of 89%. 3.10. Gas composition and isotopic analysis The composition of desorbed gas can change over time due to differences in diffusion rates of the different gas components. Consequently, standard practice is to take several samples from designated canisters throughout desorption period. Four samples were taken from Canister 1 for analysis. The gas was dry with methane content of 92.2–94.5%. Ethane content was very low (0.2–0.3%) and carbon dioxide ranged from 0.8–1.8%, which is below the maximum specifications of 2% (by volume) for pipeline transportation in Alberta (TransCanada Pipelines website:www. gastransmissionnw.com). Nitrogen content varied from 2.3–3.1%. The heating value of the gas ranged from 35.4 to 36.5 MJ/m3 (moisture and acid-free basis), which translates to 970 BTU/ SCF (moisture-free basis). A gas sample taken from Seam 10 at 605 m resulted in δ13C of methane of − 40‰ and δD (Deuterium) of methane of − 252‰. These values are indicative of thermogenic gas (Rice, 1993), as also corroborated by the high rank of the Gates coals.

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Fig. 6. Plot of total gas content (air-dried basis) versus ash content, Gates Formation coals.

3.11. Water salinity and hydrology Total dissolved solids (TDS) in water produced during a 4month production test of the Greywolf CBM well ranged from 19,000 to 20,500 mg/L, of which about half (10,100– 10,700 mg/L) consisted of chlorides and 6400–7500 mg/L of sodium. Bicarbonate content varied from 1600–1950 mg/L while Ca, Mg, and K made up the remaining cations. The high chlorides content was of concern and initially was thought to be the result of drilling mud contamination. However, the water used for fracture stimulating the coals originated from the town of Grande Cache drinking water supply, the analysis of which showed low chlorides concentration (10.8 mg/L), low bicarbonate (233 mg/L), and low TDS (204 mg/L). Thus, the possibility of contamination was eliminated, suggesting that the high chlorides content represents formation water. The saline nature of the 7.3 pH water dictates that any produced water must be treated prior to disposal via injection in a suitable aquifer. From a hydrologic perspective, the bedrock in contact with the coal seams had transmissivity of 2 × 10− 4 to 5 × 10− 5 (m2/s) and a rate of recharge of 56 mm/year (Norwest Corporation Report, 2004). With such low recharge rate and low aquifer transmissivity, it is unlikely that the coal seams could be repressurized quickly enough after being pressure depleted as a result of CBM production via vertical or horizontal drilling. The only exception might be if a horizontal wellbore were to intersect a large fracture or a fault plane that extends all the way to the surface. 3.12. Coal geomechanics Data reported by Norwest Corporation (2004) showed that Gates coal with density of 1.3–1.5 g/m3 (corresponding to low-

and moderate-ash coal) has friction angle of 25–30°, which is on the low end of the typical range for coals. Cohesion of the coal was 100 kPa (0.1 MPa), which is low. Coal is weakest at ranks ranging from high volatile A bituminous to low volatile bituminous (Jones et al., 1988). The strength of the Gates Formation coal, as expressed by its unconfined compressive strength (UCS), ranged from 0.1 MPa (14.5 psi) to 7 MPa (1020 psi) (Norwest Corporation Report, 2004). Based on publicly available data on coals from various basins in the United States, the UCS of the Gates coal was expected to be in the range from 3.4 MPa (496 psi) to 13.7 MPa (2000 psi). The lower UCS values are indicative of the low strength of the Gates coal, which is most likely the result of intense deformation and shearing in parts of the seam and the high in-situ stresses these coals have been exposed to, particularly high horizontal stresses. Coals with such low UCS and cohesion values would be very challenging to drill horizontally even at shallow depths (b500 m). Problems with wellbore stability during drilling and/or during production would almost certainly arise. 3.13. Fracture stimulation Fracture gradients were high as a result of the high horizontal stresses, which are expected for coals in the Rocky Mountain Foothills/Mountains regions. Coals have higher Poisson's ratio (Poisson's ratio ν is the ratio of transverse contraction strain to longitudinal extension strain in the direction of stretching force) and lower Young's modulus (Young's modulus E is a measure of the stiffness of a given material and is defined as the rate of change of stress with strain) than sandstones (Anderson et al., 2003). As a result, coals tend to transfer overburden stress laterally and maintain higher fracture gradients than sandstones. It was felt that the thickest coal seams in the Greywolf corehole

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were not stimulated to their fullest extent, partly because of the small volume (10 tons) of sand proppant used. This is not totally unexpected because the natural fracturing system in coal can create complex hydraulic fractures that are difficult to predict. 3.14. Testing for permeability The Greywolf CBM well was placed on long-term production for a period of almost four months. The bottom-hole pressure (BHP), casing pressure, water and gas production rates are shown in Fig. 7. Calculated BHP was based on a fresh water gradient of 10 kPa/m. Gas production rates declined steadily from about 929 m3/d (33 MCFD) to 310 m3/d (11 MCFD) over the test period. Water rates also declined but more sharply than the gas rates. Over much of the test period, water rates averaged about b 1 m3/d (4–5 BWD). The Seam 6 coal appeared to be “tight” and had permeability to water (kw) of 0.45 mD. The coal's absolute permeability was judged to be about 0.76 mD. Skin factor was estimated to be − 2, indicating a slightly damaged coal. Water saturation (Sw) in the cleat system was estimated to be 90%. 3.15. Resource potential Mean gas content for both seams was 17.7 cm3/g (568.1 scf/t; arb) and mean ash was 8.3 wt.%, which is approximately

equivalent to a density of 1.32 g/cm3. Based on these parameters, it can be estimated that in-situ resources are of the order of 53.8 million cubic meters (1.91 BCF) per section (258 ha) for each metre of net coal (see Appendix A for the CBM original gas-inplace calculation formula). This represents a huge gas-in-place (GIP) resource potential. Pipeline infrastructure is reasonable in this area. The key to any successful CBM development in the Inner Foothills would be the ability to extract the gas at economic rates from these low permeability and tectonically disturbed coals (Gentzis, 2006). 3.16. Numerical simulations Fig. 8 shows the history match between the measured versus simulated gas and water rates of the horizontal well pilot during early production (within 80 days). A very good match was obtained for the gas, particularly after the initial 15 days. The match was not as good for the produced water, which showed great variation although the average rate was very small (less than 0.15 m3 per day after 15 days). Fig. 9 (A–D) shows one of the drilling and production scenarios. It consists of four parallel horizontal wells (each 800 m in length) and spaced 275 m apart from one another. The area designated as “A” is the least depressurized whereas the area designated as “C” is the most depressurized, as shown by the different shades of gray in the figure itself and also in the vertical bar to the right of the figure. Initially, there is limited

Fig. 7. Four-month production test graph showing bottom-hole pressure (BHP), casing pressure (CSG), fluid level joints (JFT), gas per day (MCFGPD) and barrels of water per day (BWPD), Greywolf well.

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pressure depletion (Fig. 9A) and over time the area between the horizontals becomes depressurized (Fig. 9B). Effective depressurization continues in the area between the horizontals (Fig. 9C) and the resulting constructive interference ultimately leads to the effective depressurization over time of a larger area around the horizontals (Fig. 9D). Using the relative permeability curve shown in Fig. 10, it is seen that gas recovery from the parallel horizontal 4-well pilot would be 67.1 million cubic meters (2.37 Bcf) (Fig. 11). Peak production would reach about 13,000 m3/d (~460 MCFD) in the first 1000 days before declining hyperbolically to about 3500 m3/d (~125 MCFD) after 11,000 days. Water rates were also high during early production (up to 55 m3/d or ~350 BWD) but would decline sharply to 3 m3/d (~20 BWD) after 7000 days of production. Furthermore, production rates from the “outside” versus the “inside” horizontal wells are different, as shown in Fig. 12. The inside well shows considerably higher gas production rates during the first 5000 days of production as a result of an effective constructive interference. The outside well shows only slightly higher rate afterwards as gas drainage is accelerated from the area surrounding the outside well. Considerably lower gas recovery factors 43.9 million cubic meters (1.55 Bcf) were obtained for the four 800-m long parallel horizontal wells (Fig. 13) when using the better-known and more widely used Gash (1991) relative permeability curve. Peak gas production reached just 9000 m3/d (~ 320 MCFD) and declined to 2250 m3/d (~ 80 MCFD) after 11,000 days. Water rates were initially 38 m3/d (250 BWD) and declined to less than 2 m3/d (~ 10 BWD) over the same time period. Fig. 14 (A–F) depicts the gas and water production and respective gas recoveries over a 30-year period (~ 11,000 days) from a single horizontal well having different length (e.g., 500 m, 800 m and 1700 m) using the Gash (1991) relative permeability curve. Ultimate recovery is dependent on the length of the horizontal. For the shortest single horizontal

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(Fig. 14A), peak gas rate was about 1500 m3/d (~ 53 MCFD) and declined hyperbolically to about 650 m3/d (~ 23 MCFD). However, gas recovery was only 7.9 million cubic meters (0.28 Bcf) (Fig. 14B). For the intermediate-length well (Fig. 14C), peak gas rate was 2250 m3/d (~ 80 MCFD) declining to just below 1000 m3/d (35 MCFD) over the same time period. Gas recovery rate was higher, 12.7 million cubic meters (0.45 Bcf) (Fig. 14D). For the longest horizontal (Fig. 14E), peak gas rate was 4600 m3/d (163 MCFD) and declined to 2000 m3/d (~ 71 MCFD) after 11,000 days. Gas recovery was more than double than that of the intermediatelength well and more than three times higher than the shortlength well, and reached 26.9 million cubic meters (0.95 Bcf) (Fig. 14F). The initial water rates were also higher depending on the length of the horizontal well but showed the same shape of hyperbolic decline with time. A comparison of the simulation data presented shows that the peak gas rates of single horizontal wells are considerably lower than those of multiple, parallel horizontal wells. The data demonstrate the enormous advantage of drilling multiple singleleg horizontal wells in coals, at an optimum spacing that is a function of the coal's permeability, in order to create the necessary constructive interference, which leads to an effective depressurization (drawdown) of the coal reservoir. The volume of rock (coal) or “coal zone” depressurized will be affected by the permeability of the zone to the water phase. With an absolute permeability of less than 1 md, the depressurization drawdown cone is expected to be steep and narrow. Therefore, gas production from the Gates Formation coals at the Greywolf location will require an appropriately designed depressurization scheme and, more specifically, a scheme that will allow for a contiguous volume of coal to be depressurized, thus optimizing gas desorption and production. Such a depressurization or production scheme must involve horizontal and, likely horizontal multilateral drilling to effectively depressurize the coal zone.

Fig. 8. History matching of early stage (100 days) water and gas production data from the Greywolf well.

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Fig. 9. (A–D) Numerical simulation of horizontal well scenarios showing progressive pressure depletion as a function of time. Different shades of gray (areas A to C in this figure, except in A, and also in the vertical pressure bar) illustrate the degree of pressure depletion.

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Fig. 9 (continued ).

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Fig. 10. The relative permeability curve, based on Meany and Paterson (1996), used for numerical simulation in this study. Water saturation (Sw) is about 90%.

However, initial costs would be high and be a critical factor in the economic evaluation of the resource. It is also very important to stay within the coal seam while drilling horizontal wellbores and to avoid contact with water-bearing sandstone and/or siltstone units. 3.17. Comparison with Mannville coal gas data, Alberta Syncline The Gates Formation coals are not capable of producing high enough gas rates without a constructive interference, even if one were to drill relatively long (1700 m) single horizontal wells. This has been proven in field production in the Corbett Creek

area, Alberta Syncline, located about 170-km NW of Edmonton (Fig. 1). Trident Exploration has drilled in the Mannville coals a series of horizontal wells, ranging from single to multiple (three) horizontals in one section of land, and even an elevenwell (“wagon-wheel”) pattern in four contiguous sections of land. The length of horizontals drilled by Trident varied from 400 m in the early days of drilling to over 1300 m. The Mannville coals at Corbett are at about 1000 m depth, have average gas content of 8.7 cm3/g (280 scf/t) (range is from 7.8– 10.9 cm3/g (250–350 scf/t), and permeability in the range from 3–15 mD (Simpson, 2005) although the absolute coal permeability of the Mannville coals at Corbett Creek is near the low end of the range and closer to 4–5 mD (Gentzis and

Fig. 11. Gas and water production from a 4-well parallel horizontal pilot using the relative permeability curve (length of each horizontal well is 800 m, spaced 275-m apart).

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Fig. 12. Gas production from the “outside” versus the “inside” well of the 4-well parallel horizontal well pilot using the Gash (1991) relative permeability curve. Length and spacing of horizontal wells have remained the same.

Bolen, 2006). Prior to drilling horizontal wells, Trident and Nexen Inc. had drilled many vertical wells in the same area that were fracture stimulated. The poorly performing vertical wells peaked initially at 1400–1700 m3/d (50–60 MCFD) and declined after 15 months to almost 300 m3/d (10 MCFD). Water rates averaged 12.3 m3/d (80 BWD). An average vertical well peaked at 2800–5600 m3/d (100–120 MCFD) before declining to 0.6 m3/d (20 MCFD) 10 months later. Produced water rates averaged 26– 31 m3/d (170–200 BWD). The best vertical producing wells peaked at 6200 m3/d (220 MCFD) and stabilized for more than five months. Water rates averaged 23 m3/d (150 BWD) over the

same period (Simpson, 2005). Water was saline and had to be disposed by injection to a reservoir in the subsurface. During early production, some of the short single horizontals that Trident drilled produced only 2800–4200 m3/d (100–150 MCFD) of gas but production increased to an average of 8400– 14,000 m3/d (300–500 MCFD) after a period of dewatering, as shown in Fig. 15A. The above figure shows that daily gas rates of the 700 m long Corbett 11-24-62-6 W5 (Latitude 54°21′N and Longitude 114°47′W) horizontal well increased dramatically while at the same time daily water rates decreased considerably. After more than 18 months of production, this

Fig. 13. Gas and water production from a 4-well parallel horizontal pilot using the Gash (1991) relative permeability curve (length of each horizontal well is 800 m, spaced 275-m apart).

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well was producing about 10,700 m3 /d (380 MCFD) of gas and about 10.8 m 3 /d (70 BWD). Cumulative gas production has been 35.4 million cubic meters (1.25 Bcf). Depending on the geographic location, a few of the short-length single horizontals are producing close to 19,700 m3 /d (700 MCFD) as a result of interference. Production from one horizontal well of a pattern of three single horizontal wells (3-prong pattern) drilled from the same

surface pad in a section reached 19,700 m3 /d (Fig. 15B). The Corbett 16-27-62-6 W5 (Latitude 54°22′N and Longitude 114°46 W) horizontal well is about 1300 m long and the horizontal well has an E–W azimuth, thus it was drilled in such a way to intersect the face cleats at a high angle. In earlymid 2005, daily gas rates increased steadily while daily water rates decreased dramatically. In early 2006, this well was producing 18,300 m3 /d (650 MCFD) of gas and about

Fig. 14. (A–F) Schematic and gas/water production rates from a single horizontal well (500-m long) (A–B); the same from an intermediate-length single horizontal well (800 m) (C–D); and the same from a long single horizontal well (1700 m) (E–F). Different shades of gray (areas A to C in the figure and also in the vertical pressure bar) illustrate the degree of pressure depletion.

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Fig. 14 (continued ).

3.8 m3 /d (25 BWD). Cumulative production was 56.6 million cubic meters (2.0 Bcf) in less than 18 months. The above figures also confirm that gas production rates are a function of the length of the horizontal as well as of the interference effect.

The Doris 12-22-63-6 W5 (Latitude 54° 26′ N and Longitude 114° 36′ W) horizontal well is one of eleven horizontals that were drilled in a 360-degree “wagon-wheel” pattern in four sections of land. The well was drilled in late 2005 and has a length of 1300 m. Daily production of this horizontal increased

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Fig. 14 (continued ).

dramatically and exceeded 28,170 m3/d (1.0 MMCFD) after only two months of production before declining to about 22,500 m3/d (800 MCFD) (Fig. 15C). Cumulative production from this well has reached 49.5 million cubic meters (1.75 Bcf), which illustrates the accelerated rate of production as a result of constructive interference created by the large number of horizontals drilled in that location. Not all

horizontals of the wagon-wheel pattern produce the same volumes of gas since some of them are perpendicular while others are parallel to the face cleat direction. Based on publicly available data, the combined production from all eleven horizontals wells has exceeded 140,000 m3 /d (5 MMCFD), which demonstrates the beneficial effect of constructive interference among the horizontals in depressurizing the coal

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reservoir and in accelerating gas production at higher rates per horizontal well. This is exactly what the numerical simulation had predicted. 3.18. Comparison of horizontal wells with vertical pilot wells Another important piece of information can be gleaned by comparing horizontal well development with vertical well pilot drilling scenarios. Fig. 16A shows a scenario of an eight vertical-well pilot drilled in one section of land (i.e., at 32hectare spacing per well), in the same section as the four horizontal wells discussed earlier. It is obvious that pressure depletion in a vertical pilot is not as effective as in the horizontal well scenario and it takes much longer to establish any form of constructive interference. Gas recovery from the 8-well vertical pilot is 1.74 Bcf over a 30-year period (Fig. 16B), which is 73% of the gas recovery from the four horizontals. The highest gas rate was 8000 m3/d (284 MCFD) before reaching a plateau at about 4500 m3/d (160 MCFD). The highest water rate was 23 m3/d (150 BWD) during early production, declining sharply to 10 m3/d (65 BWD) and then hyperbolically to 5 m3/d after 30 years. Therefore, properly spaced horizontal wells of sufficient length (N800–1700 m) are predicted to not only produce higher gas rates but also to result in greater overall recovery

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factors and in accelerated production. All the above parameters help the project economics in spite of the greater initial cost of drilling horizontal wells, especially in the Inner Foothills region where topography, road access, and pipeline infrastructure are challenging factors, in addition to the problems related to the lack of lateral continuity of coal seams in the Inner Foothills region and effects of tectonic deformation on permeability. 4. Conclusion Numerical simulation was conducted using coal reservoir parameters established through history matching of data from a four-month production test. Results show unequivocally the positive impact that multiple but parallel horizontal wells have on the recovery efficiency, cumulative recovery and peak gas production rates from a low permeability (b 1 mD) but high gas content 17.7 cm3/g (568.1 scf/ton) coal seam in the Cretaceous Gates Formation in the Inner Foothills of Alberta. The effect of constructive interference between the parallel horizontal wells, which is required in order to effectively depressurize the coal reservoir and accelerate gas production in a short time frame, is highlighted through numerical simulations and references made to public production data from single and multi-horizontal wells drilled in the deep Mannville coals in the Alberta Syncline.

Fig. 15. (A–C) Gas and water production rates in the deeper Mannville coals, Alberta Plains; single horizontal well (A), three horizontal wells drilled in the same section of land (B) and eleven horizontal wells (wagon-wheel) drilled in four sections of land (C).

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Fig. 15 (continued ).

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Fig. 16. (A–B) Schematic of an 8-well vertical pilot (based on 32-hectare spacing), Greywolf well (A). Different shades of gray (areas A to B in the figure and also in the vertical pressure bar) illustrate the degree of pressure depletion. Gas and water production rates from the 8-well vertical pilot are shown in B.

Comparisons are made with other development scenarios (e.g., vertical pilots drilled on 32-hectare spacing, single horizontal wells with no constructive interference) and also as a function of the length of horizontals and type of relative permeability curve used in the simulation. Drilling horizontal wells in coal seams at

depths of 600–700 m in the structurally complex Foothills region would be challenging because of the low mechanical strength (low unconfined compressive strength) and degree of shearing (low cohesion) of the Gates coals, based on data collected from a nearby underground mine.

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Acknowledgements The authors would like to thank Dr. David Marchioni of Petro-Logic Services, Calgary, Alberta, for coring the Gates coals and for the subsequent desorption and analysis. Mr. John Robinson, currently with Schlumberger in Oklahoma, performed the numerical simulations. Mr. Ken Carnes of Petron Resources, L.P. drafted the figures. The authors would like to thank the two reviewers for their constructive comments and suggestions. Appendix A OGIP = 1359.7 (A) (h) (RhoB) (Gc) + 43560 (A) (h) (Por) (1 − Sw) (Bg) Where: OGIP = Original Gas-In-Place A = area of reservoir being calculated h = thickness of reservoir Por = average porosity of reservoir interval being calculated RhoB = average density of reservoir interval being calculated Sw = average water saturation (fractional) of reservoir interval being calculated Gc = average gas content of reservoir interval being calculated Bg = gas compressibility factor, driven by reservoir pressure Mobil Oil, in collaboration with Smoky River Coal Ltd. drilled a coal exploration drillhole near Mine 3, located 14-km northwest of Grande Cache (location is Latitude 54°03′N and Longitude 117°10′W or 08-21-58-8 W6; Fig. 2). The thinner (up to 1.5 m) Seam 11 was cored at depths of 233– 245 m. Gas content was low, ranging from 1.8 to 2.8 cm3/g (ash-normalized). An adsorption isotherm resulted in maximum gas holding capacity of 19.1 cm3/g (611 scf/t). The shallow depth of intersection and the proximity of the drillhole to the mine, along with the high ash content of Seam 11, most likely accounted for the low volumes of desorbed gas. The Geological Survey of Canada, in collaboration with Smoky River Coal Ltd. undertook a desorption study of coals from seams 4 and 10 taken from an exploration corehole located within the Smoky River coal mine site. Because the two seams were intersected at depths shallower than 400 m, lost gas accounted for less than 10% of the total desorbed gas volume. Gas content (ash-normalized) in Seam 4 averaged 8.6 cm3/g and in Seam 10 averaged 3.3 cm3/g. Diffusion rates reached peak values during the first few hours of desorption before declining with time. It was presumed that the high diffusion rates were a function of the highly sheared and rubblized nature of the cored seams. References Anderson, J., Simpson, M., Basinski, P., Beaton, A., Beyer, C., Bulat, D., Ray, S., Reimheimer, D., Schlachter, G., Celson, L., Olsen, T., John, Z., Khan, R., Low, N., Ryan, B., Schoderbek, D., 2003. Producing Natural Gas from Coal. Oil Rev. 8–31.

Bell, J.S., Price, R.A., McLellan, P.J., 1994. In-situ stress in the Western Canada Sedimentary Basin. In: Mossop, G.D., Shetsen, I. (Eds.), Compilers, Geological Atlas of Western Canada Sedimentary Basin. . Bull. Can. Soc. Petrol. Geol. Alberta Research Council, pp. 439–446. Dawson, F.M., Kalkreuth, W.D., 1994. Coal rank and coalbed methane potential of Cretaceous/Tertiary coals in the Canadian Rocky Mountain Foothills and adjacent foreland: 1. Hinton and Grande Cache areas, Alberta. Bull. Can. Pet. Geol. 42, 544–561. Gash, B.W., 1991. Measurement of rock properties in coal for coalbed methane production. Paper No. SPE 22909, 66th Annual Technical Conference and Exhibition, Dallas, TX, USA (Oct. 6–9). Gentzis, T., 2006. Economic coalbed methane production in the Canadian Foothills: solving the puzzle. Int. J. Coal Geol. 65, 79–92. Gentzis, T., Bolen, D., 2006. The role of horizontal wells in CBM development. 8th Ann. Can. Soc. Unconv. Gas Conf., Calgary, AB. Nov. 15–17. Gu, F., Chalaturnyk, R.J., 2004. Sensitivity study of coalbed methane production with reservoir and geomechanic coupling simulation. Paper 2004-054 presented at the 55th Annual Technical Meeting of the Petroleum Society, Can. Inst. Mining, Metall. & Petrol., Calgary, AB, Canada. June 8–10. Jones, A.H., Bell, G.J., Schraufnagel, R.A., 1988. A review of the physical and mechanical properties of coal with implications for coal-bed methane well completion and production. In: Fassett, J.E. (Ed.), Geology and Coal-bed Methane Resources of the Northern San Juan basin, Colorado and New Mexico. Denver, Rocky Mountain Assoc. Geol. Guidebook, pp. 169–181. Joshi, S.D., 1991. Horizontal Well Technology. Pennwell Publishing, Tulsa, OK. 526 pp. Kalkreuth, W.D., McMechan, M.E., 1984. Regional pattern of thermal maturation as determined from coal-rank studies, Rocky Mountain Foothills and Front Ranges north of Grande Cache, Alberta; Implications for petroleum exploration. Bull. Can. Pet. Geol. 32, 249–271. Kalkreuth, W.D., Langenberg, W., McMechan, M.E., 1989. Regional coalification pattern of Lower Cretaceous coal-bearing strata, Rocky Mountain Foothills and Foreland, Canada — implications for future exploration. Int. J. Coal Geol. 13, 261–302. Langenberg, W., Kalkreuth, W.D., Levine, J.R., Strobl, R., Demchuk, T., Hoffman, G., Jerzykiewicz, T., 1990. Coal geology and its application to coal-bed methane reservoirs. Lecture notes for short course. Alberta Res. Counc. Info. Ser. 109 159 pp. Langenberg, C.W., Beaton, A., Berhane, H., 2006. Regional evaluation of coalbed-methane potential in the Foothills/Mountains of Alberta, Canada. Int. J. Coal Geol. 65, 114–128. Levine, J.R., Davis, A., 1984. Optical anisotropy of coals as an indicator of tectonic deformation, Broad Top Coalfield, Pennsylvania. Geol. Soc. Amer. Bull. 95, 100–108. Meany, K., Paterson, L., 1996. Relative permeability in coal. SPE Paper 36986 presented at the 1996 SPE Asia Pacific Oil & Gas Conference, Adelaide, Australia. October 26–31. Norwest Corporation Report, 2004. Coal geology, resources and reserves of the No. 12 mine, south B2 pit area, Smoky River coalfield, Grande Cache Coal Corporation, August 24. Rice, D.D., 1993. Composition and origins of coalbed gas. In: Hydrocarbons from Coal. AAPG Stud. Geol. (38), 159–184. Ricketts, B.D. (Ed.), 1989. Western Canada Sedimentary Basin: A Case History, Can. Soc. Petr. Geol., Calgary, Alberta. 320 pp. Simpson, M., 2005. The Corbett CBM Field: an emerging giant gas field? Presentation given at the 7th Annual Can. Soc. Unconv. Gas Conf., Calgary, AB, Canada. November 8–10. Stach, E., Mackowsky, M.-Th., Teichmüller, M., Taylor, G.H., Chandra, D., Teichmüller, R., 1982. Stach's Textbook of Coal Petrology, 2nd edit. Gebruder-Borntraeger, Berlin. Wyllie, D.C., 1999. Foundation on Rock, 2nd edition. Taylor & Francis, London. 384 pp.