Total gas-in-place, gas composition and reservoir properties of coal of the Mannville coal measures, Central Alberta

International Journal of Coal Geology 153 (2016) 127–143

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Total gas-in-place, gas composition and reservoir properties of coal of the Mannville coal measures, Central Alberta A.M.M. Bustin, R.M. Bustin ⁎ Department of Earth and Ocean Sciences, The University of British Columba, Vancouver, BC V6T 1Z4 Canada

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Article history: Received 4 August 2015 Received in revised form 24 November 2015 Accepted 24 November 2015 Available online 3 December 2015 Keywords: Coal Adsorption Desorption Isotopes Resources Saturation

a b s t r a c t The Lower Cretaceous Mannville coal measures in south central Alberta host one of the most successful horizontal coal methane developments, yet the contribution of thin coal seams and other organic rich strata to total gasin-place and producible gas remains unaccounted. In this study, well log, core, fluid, and gas analyses in the Mannville coal measures are evaluated in order to quantify and characterise the total gas-in-place resource that may be accessed by a horizontal well completed in the main coal seam which is the usual practise. Regionally, the estimated gas capacity and content of the coals increases from northeast to southwest in parallel with the depth of burial and the level of organic maturation (rank), although local variations exist. The isotopic composition of the methane of coals currently at depths greater than 1500 m have a strong thermogenic signature, shallower coals have a mixed biogenic–thermogenic signature, and the shallowest coals have a strong biogenic signature. The trend in gas composition is less well defined with the highest carbon dioxide contents occurring in the area of the lowest and highest ranks. Generally, the percentage of heavier gases (C2–C5) increases with maturity/depth of burial, but some low rank coals (Ro% ≈ 0.30) in eastern Alberta and Saskatchewan contain significant C2–C5 hydrocarbons. The origin of the heavier gases in the low rank coals is unclear; migration from a deeper source is the most likely explanation. The gas adsorption capacity of the coals varies regionally with depth of burial (pressure), coal rank, and ash content. The highest adsorption capacity at reservoir pressure and temperature, approaches 4001 scf/t, but most coals have values between 260 and 320 scf/t. The gas content of the coals, as measured by desorption, ranges from 230 to 350 scf/t and averages 310 scf/t. Most of the coals are saturated with gas within the accuracy of the analyses. Notable exceptions occur adjacent to the Saskatchewan border where the lower rank coals may be markedly under saturated. The amount of methane in solution (calculated) at a reservoir pressure of ≈1000 psig (6.9 MPa) is calculated to be between 7 and 10 scf/t (≈3% of total gas). Currently, Mannville coal gas production is limited to an area in central Alberta of about 2200 km2 (850 miles2). Outside the producing fairway, sustained commercial production has not been achieved due to low permeability. In the producing and prospective fairway, the net thickness of the coal within ± 20 m of the main coal seam, varies from 0 to 10.8 m and averages 5.1 m. Here the thickest coal seam ranges up to 4.7 m thick and averages 1.9 m. Due to limited gas content data from core for all seams and wells, a protocol was developed to extrapolate existing core data to non-cored seams and wells through petrophysical logs. The protocol takes into consideration the correlation between gas and ash content and the maturity of the coals. The total coal gas resource density in the current area of production and prospective areas determined by applying this protocol for the average well has a low estimate of 5.4 BCF/mi2(2) (m3/km2), a median estimate of 5.9 BCF/mi2, and a high estimate of 6.1 BCF/mi2. © 2015 Published by Elsevier B.V.

1. Introduction Coal measures of the Lower Cretaceous Mannville Group and overlying Upper Cretaceous Belly River Group and Horseshoe Canyon Formation have been developed for coal gas (CBM) through an area of about ⁎ Corresponding author. 1 cm3/g (SI unit) ≈ 34 scf/t (oil field units). 2 1 BCF/mi2 (=billions of cubic feet/miles2) ~1.1E7 m3/km2

10,000 mile2 (26,000 km2) of south-central Alberta. The total estimated coal gas-in-place resource is about 500 TCF3 (1.41 × 1013 m3), of which about 65% occurs in the Mannville Formation (ERCB, 2011). Currently, coalbed methane comprises about 6% of the total natural gas produced in Canada. To date, the Mannville coals cumulatively have produced about 1 TCF (28.3 × 109 m3; ERCB, 2011; NEB, 2014).

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http://dx.doi.org/10.1016/j.coal.2015.11.011 0166-5162/© 2015 Published by Elsevier B.V.

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TCF = trillion cubic feet.

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Through most of central and western Alberta, the Upper Mannville and stratigraphically equivalent coals have been shown in well tests to contain substantial gas-in-place with estimates ranging from about 2–10 BCF/mi2 with the higher gas-in-place values corresponding to the deeper and thicker coal intervals. However, sustained successful commercial production has been limited geographically to an area centred on the Corbett Creek area, where current production is cumulatively about 500 mmcf4/day from about 215 wells. Outside of this producing fairway, the low permeability of the coals has resulted in the lack of commercial production irrespective of the drilling or completion techniques employed. Even in areas of commercial production, the production profiles, total gas-in-place (TOGIP), and gas composition are highly variable (i.e. Hyland et al., 2010; Bearinger and Majcher, 2010) and commonly viewed as unpredictable. In Alberta, the Alberta Energy Regulator (AER, formerly the Energy Resources Conservation Board- ERCB) provides guidelines (ERCB, 2006; ERCB, 2010; ERCB, 2012) for establishing the gas content in coals, which in turn is used routinely by reserve auditing firms for evaluations and for determination of coalbed methane well density (spacing units). Under the AER guidelines, coalbed methane production is considered to be gas produced from coal seam completions, where a coal seam is defined as a lithologic unit comprised of greater than 50% organic matter by weight and greater than 30 cm in thickness. In developed and prospective areas, the Mannville coal measures include multiple coals, many of which are thinner than 30 cm, and interbeds and over and underlying organic rich mudstones. These thin coals and organic rich lithologies can reasonably be expected to contribute to the producible gas from horizontal wells drilled and completed in the targeted coal as shown in other coals by Bustin and Bustin (2011a, 2011b). Hence, the gas content quantified using the AER protocol underestimates the producible gas. Well spacing based on these estimates will be too low and not necessarily optimal for resource development. Additionally, based on experience with shale gas evaluation, it can be assumed that in addition to gas stored in the adsorbed state, that free gas in adjacent noncoal lithologies and in solution in all lithologies will exist (Bustin and Bustin, 2009, 2011a, 2011b). The main purpose for this study is to establish, in the producing and prospective fairway, how much gas is in place, its composition, and origin in the coal measures (coal and other organic rich facies), as well as determine how much gas will be produced from a horizontal well drilled and completed in what typically is the thickest coal seam in the succession. A secondary purpose of the study is to determine the optimum configuration (spacing, length and orientation) of the horizontal well(s), which will be addressed in a companion paper. This study also addresses the question as to why commercial gas production from the Mannville coals is limited to the Corbett area even though Mannville coals with high gas-in-place are broadly distributed over a much larger area of central Alberta. In this paper, we first refine the regional resource potential of the Upper Mannville coal measures in a study area of south-central Alberta based on analyses of core samples, well logs, and fluids. Within the area of production and recent exploration, we summarise and interpret the variation in gas content of the thickest coal and other coals that lie stratigraphically within ±20 m of the main seam. The ±20 m interval lies within the anticipated drainage volume of a horizontal well landed in the main seam based on reservoir and economic analysis. Other lithologies within this interval are anticipated to contribute to production based on reservoir modelling. In Bustin and Bustin (in press), the contribution of the non-coal organic rich lithologies to the total gas-in-place is considered. These two studies provide the metrics for reservoir modelling, which is the subject of a companion study (in preparation) that evaluates the total producible gas from the coal measures (coal plus non-coal facies) via horizontal wells of various configurations and spacing. 4

mmcf = million cubic feet

1.1. Stratigraphy, structural settings, and tectonic history The stratigraphy and sedimentology of the Mannville Group has been exhaustively studied, due to the economic importance of the conventional and unconventional petroleum and coal resources, the heterogeneity of the units, and the widespread distribution of the Group. A general overview of the stratigraphy and structural settings as it bears on this study is provided below. The Mannville Group is a Lower Cretaceous (Aptian to mid Albian) succession of marine, transitional marine, and non-marine deposits that underlay a large portion of Western Canada (Hayes et al., 1994; Figs. 1 and 2). The Mannville Group thickens from as thin as 40 m on the stable platform to the east to over 700 m in the Rocky Mountain foothills to the west. The Mannville Group was deposited in the then asymmetric Western Canadian Sedimentary Basin with sediment sourced mainly from the evolving Cordillera to the west. In Alberta, the coals occur at depths ranging from about 265 m to as deep as 3600 m adjacent to the deformed belt and cumulative coal thicknesses range from 0 to 16.5 m, including seams as thick as about 12 m (Fig. 1; Langenberg et al., 1997). The Mannville Group has been divided into Lower and Upper units. The Lower Mannville was deposited on an erosional surface of deeply eroded Early Cretaceous, Jurassic, and Paleozoic rocks (Fig. 2). The Lower Mannville in-filled the topography on the unconformity and consists of valley fill sandstone and associated clastic rocks (i.e. Wadsworth et al., 2002; Chalmers et al., 2013). The Upper Mannville Group is an overall regressive succession that varies from alluvial sediments and incised valley fill deposits in southern and central Alberta, through to coastal plain and transitional marine sediments to the northwest, where equivalent strata are assigned to the Spirit River, Gething, and/ or Gates formations. The Upper Mannville Group is overlain by a ravinement surface that is the base of the overlying Joli Fou Formation, except in the northwest part of the basin. Coal occurs in both the Lower and Upper Mannville Group; however, the most important coals, and those exploited for coalbed methane, are restricted to the Upper Mannville Group (undifferentiated). The Upper Mannville coal zone is comprised of interbedded sandstones, mudstones, siltstones, and coals. The mudstones and siltstone are variably carbonaceous and grade to coal.5 The same general stratigraphy extends throughout the basin, although in detail many facies changes occur. Detailed and extensive cross-sections of the Upper Mannville Group across western Canada have been published (Langenberg et al., 1997) and are not repeated here. The coal measures are interpreted as deposits of northward prograding coastal plains during regression of the Boreal Sea. Local deposition and fault controlled Paleozoic structural highs and lows impact the local stratigraphy and particularly the frequency, lateral continuity, and thickness of the coals (i.e. Wadsworth et al., 2002; Chalmers et al., 2013). Overall, the coals thicken from the stable platform in the east to what was the evolving foredeep to the west with the thickest coals locally approaching 12 m and the gross thickness of coal about 20 m. The number of major seams (thicker than 1.5 m) is generally one or two and the number of thin seams varies up to 8. Economically important stratigraphically equivalent coals in outcrop in the deformed belt to the west are assigned to the Gates and Gething formations. The Mannville coals are humic in origin and comprised of interbedded bright and dull bands. The sedimentology of the coals have been studied in detail by Wadsworth et al. (2002) and Banerjee and Kalkreuth (2002) who have interpreted the petrographic composition of the coals within a sedimentological framework. Gentzis (2009) has described the fabric and mechanical properties of the coals. The post depositional history of the Mannville Group includes deep burial, with the depth of burial increasing to the southwest. A major 5 The definition of coal used in the study is a deposit comprised of greater than 50% by weight or 70% by volume of organic matter.

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Fig. 1. Upper Mannville coal distribution in Alberta (inset map) and current depth of burial (A) and generalised isopach showing net coal thickness (B.). Stratigraphically equivalent coals extend to the west into British Columbia and to the east into Saskatchewan (modified from Berhane, 2009a, 2009b, 2009c). The red box labelled Corbett in the inset map shows the Corbett area referred to in subsequent figures.

period of uplift during the Late Cretaceous was followed by burial by Tertiary molasse, which was in turn deeply eroded. During burial, biogenic and thermogenic gas generation charged the coals and excess gas migrated and, where trapped, led to formation of important conventional gas reservoirs. During uplift, the associated drop in reservoir pressure led to desorption of gas and, in some areas in western Alberta, flushing of the fracture (cleat) water leading to so called ‘dry’ coals (coals that do not produce significant water on production). The current depth to the top of the Upper Mannville coal zone varies from a few tens of metres in Saskatchewan to in excess of 3500 m in the Rocky Mountain Foothills. There is an excellent correlation of regional coal

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rank as measured by vitrinite reflectance and current depth of burial with some notable excursions (Fig. 3). The stress regime in the Western Canadian Sedimentary Basin has been considered (i.e. Bearinger and Majcher, 2010) to be responsible for the variability in permeability in the coals and other rock units. The regional stress orientation is well established; the maximum principal stress is orientated northeast–southwest, which is consistent with the far-field stress predicted from the orientation of the Rocky Mountains (Bell and Bachu, 2003). Regionally, the cleat directions in the Mannville coals is consistent with their formation in this stress field, with the face cleat orientated southwest–northeast and the butt cleat, orthogonal to the face cleat, orientated northwest–southeast (i.e. Campbell, 1979). The coals are invariably fractured with two welldeveloped cleat, orientated orthogonal to each other and bedding (banding). The cleat spacing varies with band (bed) thickness and is more prominent in the bright banded coals. In areas where the coals are impacted by structural drape due to faulting, or salt dissolution, deviation from the regional stress field is anticipated (Haug et al., 2013). The coal resource potential in the Mannville Group has been studied both as a direct source of energy and as a source of gas (coalbed methane). Numerous comprehensive studies have been undertaken by the Alberta Geological Survey including regional subsurface mapping that includes isopach maps, coal rank, and estimated coal gas content (Beaton et al., 2006; Rottenfusser, 2002; Berhane, 2009a). Local studies of coalbed methane potential and production include articles by Langenberg et al. (1997); Beaton (2003); Gentzis et al. (2008); Hyland et al. (2010), and Bearinger and Majcher (2010). The main coal zone exploited for coalbed methane production occurs in the “undifferentiated” Upper Mannville Group. The estimated gas-in-place in the Mannville coals range from mainly 50 to 350 scf/t (2–10 BCF/mi2) and this resource occurs over a very large geographic area of southern and central Alberta (Figs. 1 and 2). Focused exploration for coalbed methane from the Upper Mannville Group began in the mid-1990s in south central Alberta and was stimulated by the successful production of coals of the Fruitland Formation in the San Juan Basin, New Mexico. Initially, Mannville tests were vertical wells. The flush production from fractures yielded rates up to 1 mmcf/day but stabilised production of only about 20–60 mcf6/day. Subsequently horizontal wells were tested utilising a variety of drilling and completion methods (Gentzis, 2011). Currently, the only sustained commercial production of coal gas from the Upper Mannville Group is in the fairway near Corbett Creek-Fort Assiniboine (hence forth referred to as ‘Corbett’; Figs. 1, 4). Elsewhere in the basin or commercial production rates have not been achieved even though a multitude of drilling and completion strategies have been attempted in areas where the coals are ‘wet’ and ‘dry’. In the Corbett area, coal gas is currently produced mainly from about 200 multilateral horizontal wells (Fig. 5). The development is spaced mainly at 3–4 wells per square mile (mi2ʹ = 2.59 km2), although both higher and lower well densities occur (Fig. 4). The wells are mainly orientated in NW-SE, N-S, and E-W and the horizontal (lateral) legs are between 1000 and 1500 m in length. Most horizontal wells are completed in a ≈ 1.5–2 m thick main seam. Adjacent thinner seams and carbonaceous mudstones also may contribute to the gas-in-place which is considered in this study. The impact of stress on directional permeability and production was investigated by Taylor et al. (2008) and Bearinger and Majcher (2010). Taylor et al. (2008) show a strong correlation between well azimuth and production rate from a series of wells within a constrained drainage area; the highest production occur is wells orientated perpendicular to the face cleat direction and the maximum horizontal stress azimuth (Fig. 4). Bearinger and Majcher (2010) show the production rate of 12 single horizontal wells have a maximum production of gas when drilled

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mcf = thousands of cubic feet.

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Fig. 2. Schematic cross-section (cartoon) across the Western Canadian Sedimentary Basin showing the main coal occurrences. Modified from Bustin and Bustin, 2011a.

perpendicular to the face cleat (i.e. northwest-southeast). Water production; however, showed no trend. Bearinger and Majcher (2010) suggests that the main controls on gas production are related to permeability and gas content; they found that neither well design, completion parameters, nor geological structure correlate with production. Differential compaction and early structures are considered to predate coalification and hence do not impact fracture development directly. 2. Methods In this study, the large public database of core data, including coal desorption tests and well logs available from the Alberta Energy Regulator (www.aer.ca) has been utilised. Some specialised well and/

Fig. 3. Variation in vitrinite reflectance, Upper Mannville Group. Data in part from compilation of Bustin (1991); Stasiuk et al. (2002) and Alberta Energy Regulator well files to June 2015.

or reservoir analyses that are not in the public domain were made available by industry. In addition, analyses were undertaken on some wells specifically for this study. The analyses include isotherms, petrology, mineralogy, porosity, permeability, rock mechanics, wettability, fines production, and sorption associated strain tests. In using such a diverse data set, different operating conditions and nuances of protocols exist that impact the results. To avoid such issues, the data from public analyses used in this study (including desorption, gas composition, and isotherms), with rare exception were carried out by a single service provider using protocols developed and/or supervised by the authors. Only this data is used in this study for consistency. The reliability of the data is discussed in the relevant sections. All gas desorption analyses and gas composition data used here are based on cores, almost all of which were wireline retrieved. The time between cutting the core and sealing the core in canisters (lost gas time) ranged from about 10 to 60 min. All early time desorption work was carried out at the temperature the gas was lost during retrieval. This temperature was calculated from consideration of the bottom hole and drilling mud temperature. The lost gas (gas lost during sample recovery prior to sealing) ranges from about 10 to 20% of the total desorbed gas content as determined by linearly extrapolating the early desorption data (i.e. Clarkson and Bustin, 2011). Gas samples were collected and analysed by gas chromatograph at selected times throughout the desorption period. The results were integrated to determine reservoir gas composition. Samples of all lithologies were preserved at the well-site using an inert gas flushing-vacuum sealing method, to facilitate later analyses that require retention of in situ moisture conditions and mechanical coherence. Proximate analyses were performed following ASTM procedures (ASTM, 2007). Laboratory methane adsorption isotherm experiments were performed using a Boyle's Law apparatus on samples preserved in the field at in situ moisture conditions or brought back to equilibrium moisture (Australian Standard, 2013). The isotherms were tested at the corrected reservoir temperatures from borehole measurements and the gas capacities were calculated at average measured reservoir pressure for the cored intervals. The effective porosities to gas were determined using He skeletal, and Hg bulk density measurements. The proportion of the pore space occupied by the adsorbed gas must be subtracted from the measured free gas volume to determine effective porosity available for free gas (Bustin and Clarkson, 1999). This correction was determined by calculating the adsorption volume from the isotherm at reservoir pressure

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stratigraphically of the main coal seam in which the laterally well is drilled. The contribution of over and underlying strata to production is dependent on their permeability, reservoir pressure, gas content and duration of production (Bustin and Bustin, 2011b). This interval is shown by reservoir modelling (Bustin and Bustin, in progress) to be of economic importance (i.e. would contribute to the net present value of the resource) based on metrics of the Mannville reservoir in the study area. With rare exception, all coal and most other organic rich facies are restricted to this stratigraphic interval. In the following sections on gas-in-place, the gas within this ±20 m interval is quantified within the coals. The intervals in the Upper Mannville that were selected for coal coring and desorption during exploration and development were designed to test the gas content and gas composition of the principal coal(s) targeted mainly for horizontal drilling and completion. There is little data from other coal seams or non-coal facies, and where cores exist, they were either obtained due to an error in selecting the core point or were intervals that closely overlay or are interbedded with the targeted coal(s). There is no core desorption data available that captures the entire coal measures in the study area. Since a goal of the study is to determine the total gas-in-place and producible gas in the coal measures, the gas capacity, gas content, and gas composition of all reservoir facies that lie within the stratigraphic interval of drainage (± 20 m) is required. The protocol utilised here is to determine the gas content, capacity and gas composition in the cored intervals, and then, keyed through petrophysical analysis and interpretation, extrapolate these measurements to similar facies based on log signatures within the reservoir interval (±20 m of principal seam). In the following sections, the gas capacity and gas content of the coal is documented and metrics established for extrapolating these measures. 3.1. Gas-in-place

Fig. 4. Locations of the Corbett producing and prospective fairway (upper diagram) showing the trace of horizontal wells (black radiating lines) completed in the coal and vertical wells (dots). The Corbett area location is shown in Fig. 1. Lower diagram shows the anisotropy of production of a horizontal well with azimuth in an area where production is confined by surrounding wells (red square in upper diagram). Highest production occurs in wells orientated perpendicular to the face cleat direction. Northwest–southeast; lower diagram modified from Taylor et al., 2008.

and temperature and assuming a liquid-like density, which for methane was taken as 0.42 g/cm3 (Shana'a and Canfield, 1968). The volume of gas in solution was estimated utilising Henry's Law, which is applicable at the reservoir pressure of the formations in this study (Cramer, 1984; Cui and Bustin, 2004; Cui et al., 2004). The weight percent water was derived from proximate analysis. All gas volumes reported in this paper are in oil field units, which are reported at 60 °F and 1 atm pressure (15.6 °C and 101.3 kPa). Organic petrology and vitrinite reflectance was determined using established methods. The data reported in this study is a combination of analyses performed specifically for this study as well as public data. The public data was performed either by the Geological Survey of Canada (Stasiuk et al., 2002 and references) or at our laboratory at The University of British Columbia and the methods employed and standards are the same. 3. Results For determining the total gas content and the producibility of the gas we have considered the interval within plus or minus 20 m

The most important variables determining gas-in-place of coal are the net thickness, capacity to hold gas, gas content, degree of saturation, and gas composition. The regional variation in thickness and number of seams in the Mannville Group has been mapped (Rottenfusser, 2002; Beaton, 2003; Berhane, 2009b) and detailed studies have interpreted the variation in thickness in terms of the sedimentology. In this study, the net thickness of coal in the Upper Mannville, based on regional well studies are utilised, except in the Corbett area where more detailed work was done as a part of this study, and is discussed in the section on total-gas-in place. The gas capacity and content of coals are traditionally referred to in terms of gas per unit mass (scf/t or cc/g7) referred to here as gas density and this convention is used throughout this paper. 3.1.1. Capacity The capacity of a coal refers to the amount of gas the coal can store at reservoir conditions. Coal capacity is well documented to depend on the rank, moisture, ash, and maceral composition, in addition to reservoir pressure and temperature. Additionally, different gases have different adsorption capacities and hence the capacity of coal varies with the gas composition. If the coals are 100% saturated with gas, it indicates that coal is at the adsorption capacity at reservoir pressure and temperature. If the coal is saturated, any available pore space is occupied by gas and liquids present (normally water or brine) is saturated with gas. The gas content, on the other hand, refers to gas that actually is present. If the content is less than the capacity, the coal is referred to as under saturated. An under saturated coal has excess adsorption capacity and hence pressure reduction is required (by production of water) to 7 Standard cubic feet per ton (scf/t) is determined in oil field units (temperature = 60 °F or 15.6 °C and 1 atm) whereas cubic metres per tonne (same as cubic centimetres per gramme (m3/t, cc/g) in SI is reported at standard temperature (0 °C) and pressure (1 bar).

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Fig. 5. Schematic representation of a horizontal well drilled and completed in the thickest seam in the sequence. Modified from Taylor et al., 2008.

promote desorption. The pressure to which the reservoir must be reduced in order to promote gas desorption, referred to as the critical pressure, can be determined by measurement of an adsorption isotherm and comparing the determined desorbed gas to the isotherm at the corresponding reservoir pressure and temperature. Even during well testing, an under saturated reservoir will produce gas due to reduced pressures below the critical pressure in the near well bore area. The adsorption isotherms to methane for a series of Mannville coals, grouped by rank, are shown in Fig. 6. The adsorption capacities of the same grouped coals, at a constant reservoir pressure of 1000 psi (6.9 MPa), are plotted against weight percentage ash in Fig. 7 for comparison. There is a predictable increase in adsorption capacity with rank. Although there is considerable scatter in the data, the adsorption for the 0.30, 0.43, and 0.60% Ro groups decreases as expected with increasing ash For the 0.53% and 0.75 Ro% groups, however, there is no obvious trend, which is likely due to a combination of coal compositional variations and the narrow range of gas capacity and ash values of available samples.

3.1.2. Saturation In the Upper Mannville coals, the adsorption capacity of the coals to methane and, if present, ethane and carbon dioxide, has been determined for numerous wells. For the same wells core desorption data is available and hence the degree of saturation can be determined from the ratio of the measured desorbed gas content to the adsorption isotherm capacity at the relevant reservoir pressure and temperature. The adsorption isotherm was measured on the same coal sample (canister) as the desorption data was collected to avoid, as much as possible, potential errors due to coal heterogeneity. The degree of saturation of the coals varies from 28% to 116%, after considering the adsorption effects of mixed gases, where relevant. The calculation of saturation involves several potential sources of error. In addition to analysis error, these include: the isotherm needs to be run at the appropriate reservoir temperature, moisture, and gas composition and the saturation calculation must be done at reservoir pressure. Additionally the gas content from canister desorption may include free gas (non-adsorbed and solution gas) and lost gas may be in error, particularly if mixed gases are present. Some, or all, of these variables may not be known accurately and produce sources of non-random error, yielding saturations too high or too low (also see Mares et al., 2009).

The variation in saturation is not readily predictable. There is a very low positive correlation of saturation with current depth of burial (Fig. 8) and a moderate positive correlation with coal rank (Fig. 9). Inasmuch as rank and depth are strongly correlated, their independent correlation with saturation cannot be resolved. There is no correlation between ash content and saturation (not shown). The lowest saturated samples (b40%) are shallow, low rank, and lie to the east, near the Saskatchewan-Alberta border (Fig. 10). The coals that have saturations greater than 108% are from isolated wells which are not part of any obvious trend, but are at maturities greater than 0.5% Ro. In a previous study, Bearinger and Majcher (2010) report that the Mannville coals are under-saturated in the area they refer to as Assiniboine (Corbett of this study) area; however, their conclusion is not supported by data of this study. The isotherm measurements provide an opportunity to predict the gas content of the coals in areas where only regional coal rank and reservoir pressure and temperatures are known or can be reliably estimated. The impact of varying moisture and ash content is corrected by subtracting their mass and reporting data on a dry ash free basis, in addition to reporting on an as received, equilibrium moisture basis. This dry ash free calculation is based on the assumption that the ash (mainly mineral matter) does not contribute to adsorption and the moisture content does not impact adsorption other than as mass diluent. Neither of these assumptions are strictly correct, but since the adsorption capacity of mineral matter in a wet state is low (due to water occupying sorption sites, i.e. Levy et al., 1997) and the moisture capacity is at the equilibrium state for the reservoir temperature (coals have free water), further correction to the data is not warranted. The maceral composition effects of the adsorption are welldocumented (i.e. Lamberson and Bustin, 1993): bright coal that are vitrinite rich have substantially higher adsorption capacity then dull coal that contain inertinite and semi-inertinite. The Mannville coals are thinly, banded, dull, and bright, but, at the level of the seam, all contain N N65% vitrinite and since the isotherm and desorption samples are composite samples of a depth range, it is unlikely that coal maceral composition is a major contributor to the observed variation in adsorption. 3.1.3. Gas content-desorbed gas Gas content determined by canister desorption from 135 cored wells in the Upper Mannville were considered in this study. The number of

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Fig. 6. Methane adsorption isotherms at equilibrium moisture grouped by approximate coal rank (±0.03 Ro%; mid points plotted) showing impact of rank, temperature, and weight percentage ash (wt.% indicated in legend). Note that the y axis of the graphs is not all the same. The temperatures are bottom hole temperatures from well logs from producing wells.

individual canister samples per well range from 5 to 40 and average about 20. In some wells, only coals were sampled and in other wells interbedded mudstones were included. In order to represent the seams in

Fig. 7. Variation in methane adsorption capacity with weight percent ash, at the indicated vitrinite reflectance and temperature, and at a pressure of 1000 psia (6.9 MPa).

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Fig. 8. Variation in saturation (ratio of desorbed gas to adsorption capacity at reservoir pressure and temperature) with current depth of burial.

a given well with a single mappable gas content, the median gas content, with the most extreme outliers removed, was chosen to characterise the gas density (scf/t) in order to minimise the impact of extreme population end members. The median desorbed gas content per well ranges, on as received basis, from 47 to 400 scf/t and, on dry ash free basis, from 63 to 430 scf/t. In Fig. 11, the areal distribution of the median gas content is mapped on a regional scale, and in more detail, for the Corbett area, where most core wells are located. At greater depths of burial there is greater variation in the median gas content (Fig. 12). The desorption data collected along a lateral well in a 2 m thick coal seam (Fig. 13) provides some insight as to the variation in gas content and gas composition that can exist over a relatively short lateral distance (120 m). The well bore is located in about the same stratigraphic interval within the seam as confirmed by well bore survey. With one exception, the gas content varies in the range from 310 to 365 scf/t, ash from about 1 to 11%, and methane content from 90 to 92%. The exception is the sample at 10 m, which is anomalous in having a very low gas ( scf/t) and high ash content (34%). The gas composition of this interval was not measured. The variation is much greater than analytical error and provides an appreciation of the lateral heterogeneity of the gas content of the coal.

Fig. 10. Percent variation in gas saturation of the coal based on the ratio of desorbed gas to adsorption capacity, based on the isotherm from the same sample at reservoir temperature and pressure, and equilibrium moisture. Contour interval — 5%.

3.1.4. Gas content-free gas The term ‘free gas’ in the coalbed methane and gas shale industry and literature refers to gas that exists in pores or fractures in the compressed state (i.e. gas that is not adsorbed or in solution). Coals, like conventional reservoir rocks, may contain free gas in matrix pores that are not completely filled by adsorbed gas or otherwise occupied by water (i.e. Sw b 1; Bustin and Bustin, 2011a). Obtaining in-situ porosity and water saturation from coals is difficult, due to the friable nature of coals and their susceptibility to change in fabric by drying.

Fig. 9. Variation in saturation (ratio of desorbed gas to adsorption capacity) at reservoir pressure and temperature to coal rank (vitrinite reflectance Ro. %). The data is based on coal as in situ conditions (as received moisture and ash from preserved samples).

Fig. 11. A. Regional variation in median desorbed core gas content in scf/t (as received) basis (contour interval — 15 scf/t). The inset map show in A and shown in B, is the Corbett area showing the variation in gas content scf/t (contour interval — 20 scf/t). The Corbett area is the only area of current production and development. The red dots are vertical wells and the red lines are trajectories of the lateral wells in the main Mannville coal seam.

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Fig. 12. Median gas content of canisters from coal desorption for all wells, as received basis.

The porosity of the Mannville coals were measured initially asreceived, and following removal of water by drying at 60 °C. The results of the analysis are plotted in Fig. 14. Samples are from the producing Corbett area and there is a wide range in values from 5% to 12%, which probably reflects differences in composition and, less importantly, rank. None of the coal samples available for this study were preserved or in a state in which it could be assumed that the as-received porosity was effective porosity to gas. In an earlier study of the Horseshoe Canyon coals (Bustin and Bustin, 2011a), we argued that free gas was an important component of the gas-in-place based on measurements that showed relatively high average porosity, that the coals were “dry’ (do not produce water), canister desorption gas volumes exceeded the adsorption capacity of the coal, and it could be shown for some wells that they produced more gas in their drainage area than present in the adsorbed state. The producing Mannville coals all produce water initially and hence are ‘wet’, with water at least present in the fractures. The Mannville coals have a higher rank with associated smaller pores and hence the adsorbed gas occupies a greater proportion of the pores space than that of the lower rank Horseshoe Canyon coals (i.e. Bustin and Clarkson, 1999). To date, the production data and drainage area are not adequately known to determine if free gas is present based on production. The only evidence of free gas in the Mannville coals is in areas where the gas content from desorption significantly exceeds the adsorption isotherm, causing coals to calculate as “over saturated”. Assuming no source of error in analyses and that the gas compositions and pressure and temperature used were the same in the reservoir, such values indicate gas storage in the free state. The solution gas component (discussed later) would be a minor contribution due to the low solubility of

Fig. 14. Porosity from coal samples in the Corbett area. None of the samples measured were in a preserved state. Note that the total and effective porosity not available for all samples.

methane in the water and solution gas is incorporated in the adsorption isotherm measurement. There is currently no commercial production from Mannville coals in areas where they are considered ‘dry’ nor in areas to the east where the coal is markedly under saturated. Even in the ‘dry’ coal areas, water is produced during testing and production so the coals are only ‘dry’ in a relative sense. If areas exist where the coals do not contain mobile water (Sw b1), then it could be argued that the coal contains free gas in that fraction of the pore space not occupied by adsorbed gas or inherent moisture. 3.1.5. Gas content-solution gas Mobile water in pores and fractures and inherent8 moisture in the coal will contain solution gas in equilibrium, or near equilibrium, with gas in the adsorbed state. Solution gas at the comparatively low pressures of this study can be quantified by Henry's Law (Bustin et al., 2009). Adsorption isotherms measured at in situ conditions will include gas in solution in the inherent water as an artefact of the measurement method. Hence, adsorption isotherms include both adsorbed and solution gas. The canister desorbed gas may or may not include solution gas (and free gas) depending on timing of sample retrieval and surface area of the recovered sample. The amount of methane in solution (calculated) at a reservoir pressure of 1000 psi (6.9 MPa), an estimated connate water salinity of 60,000 mg/l, and at 55 °C, is about 7–10 scf/t, assuming the coals are water saturated. The solution gas, thus represents about 3% of the total coal gas (Fig. 15). 3.1.6. Gas content-fracture porosity Porosity values summarised earlier do not include fracture porosity. Approximating reservoir fracture porosity from laboratory tests is challenging due to errors in scaling up fracture measurements from the sample to the reservoir scale, dilation of the fractures resulting from unloading during recovery and subsequent handling (e.g. Laubach, 2003; Ortega et al., 2006; Bustin and Bustin, 2011a), and difficulty in obtaining representative samples. Coals that do not fall apart because of recovery or handling tend to be either duller and/or less intensively fractured and hence, not necessarily representative. An estimate of the fracture porosity can, however, be obtained indirectly by assuming a match-stick fracture geometry which has been extensively used in describing and modelling coals (e.g. Seidel et al., 1992; Harpalani and Chen, 1997; Cui and Bustin, 2006; Bustin and Bustin, 2011a). The cleat spacing in Mannville coals averages on the order of 1–2 cm and backcalculating fracture porosity assuming such a spacing, using even the

Fig. 13. Variation in gas content (as received scf/t), weight % ash, and mole % methane along horizontal well drilled in a single seam.

8 Inherent moisture is water that is present in the adsorbed state and tightly held in small capillaries and hence is not mobile (i.e. Allardice et al., 2003).

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Fig. 15. Variation in solution gas and density with moisture (water) content for a series of samples of coal and mud rocks of varying density for a single well. Pressure is at 1000 psia and the brine is 60,000 mg/l total dissolved solids. The solution gas values are calculated from Henry's Law.

most optimistic permeability, yields a fracture porosity that is b0.25%. Inasmuch as the fracture porosity at best is a small number, and the coals are wet (Sw N0), gas storage in fracture porosity is not considered significant. 3.2. Gas composition The in situ gas composition was determined by sampling and analysis of the desorbed gas composition and volume over time and integrating the results. The first composition measured is used to calculate the composition of the gas lost during sample recovery. The composition of the desorbed gas is not constant with time, due to the competing effects of relative diffusion rates and preferential adsorption of different gases (Cui and Bustin, 2006). The most common observation is a progressive increase in carbon dioxide content with desorption time, due to preferential adsorption of carbon dioxide; a similar phenomenon seen during well production (e.g. Clarkson and McGovern, 2003). However, in some cases where the sample has a high surface area (i.e. crushed coal), the observed effect is the opposite, due to the higher

Average Maximum Minimum

CH4

CO2

C2–C5

90 100 65

3 25 0

8 24 0

diffusion rates of carbon dioxide than that of methane taking precedence over selective adsorption effects (Cui and Bustin, 2006). In order to determine the impact of selective adsorption or diffusion rates on gas composition determination, the time of desorption versus gas composition was investigated for a series of samples in the study area. Samples with significant non-methane gases (Fig. 16) show a decrease in methane with desorption time and increase in carbon dioxide and heavy hydrocarbons. The compositional shifts, although consistent, are not large (a few percent at most). In the sample population of the study area, methane content of the desorbed coals ranges from 65 to 100% and averages 90%. The carbon dioxide ranges from 0 to 25% and averages 3%, and C2–C5 alkanes range from 0 to 24% and averages 8% (Table 1). In Fig. 17, the variation in gas composition with vitrinite reflectance, depth of burial, saturation and total gas content (as received) are plotted. There is no obvious relationship between gas saturation and gas composition. The other variables all show a large scatter, but there is a general trend of increased carbon dioxide with rank, depth of burial, and gas content. Since these variables are all mutually correlated, the causality of the weak trend is not obvious. In contrast to this trend with coal rank, are the comparatively high carbon dioxide and C2–C5 values in the lowest rank coals. The lateral variation in gas composition was investigated regionally and in more detail in the producing and prospective area. Regionally, the limited data set indicates that the highest methane content (91– 94% contours) occurs in south central Alberta with the methane content decreasing to the east and west (Fig. 18). To the east, where the strata are shallower and less mature, both the carbon dioxide and, surprisingly, the C2–C5 increase. The higher C2–C5 values in low rank coals, where

Fig. 16. Variation in gas composition with desorption time for Mannville coals of indicated rank (Ro. %). Most canister desorption analyses for coals with significant non-methane sorbed gases, show a decrease in methane and increase in carbon dioxide, and C2–C5 alkanes with desorption time. Samples with little non-methane gas, commonly show no trend with time. Refer to text for further explanation.

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Fig. 18. Areal variation in gas composition in mole %. A. methane, B. C2–C5, C. CO2. Contour interval = 1%. Well sample locations shown in A (red dots).

Fig. 17. Variation in gas composition with coal rank, degree of saturation, total gas content and current depth of burial. The gas content is the median gas content from each well, whereas the gas composition is the average composition.

higher maturity coal to the southwest. In the producing Corbett area, the coal gas is comprised of about 1–2% carbon dioxide and 1–7% C2–C5. 3.3. Origin of the gas-isotopes

biogenic dry, methane rich gas in anticipated, argues for a migration source from deeper, more mature, strata. The increase in C2–C5 hydrocarbons to the southwest are consistent with gas generation from the

It is generally assumed, but rarely established that adsorbed gas is self-sourced by fermentation (biogenic) reactions at low levels of

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maturation and thermogenic processes at higher levels of maturation. The isotopic composition of methane in desorbed gas from Mannville coals mainly indicate a thermogenic origin (Fig. 19), which is consistent with the presence of C2–C5 hydrocarbons and the degree of thermal maturation. Values of δ13C1 N50 ‰ suggest at least a partial biogenic contribution, possible mixed sources, and, for coals for which data are available, the values correspond to coals at a current depth of less than 1500 m. Most shallow Mannville coals in Saskatchewan have a marked biogenic signature. In one well, A1-4-48-22W3. The methane isotopic composition of the Upper Mannville Group ranges from −60 to − 70, which is indicative of a biogenic origin (Szatkowski et al., 2002). Gas sourced by fermentation reactions normally contains methane as the only hydrocarbon gas (dry gas). In western Alberta, however, Upper Mannville coals with low maturity (Ro ≈ 0.30%) contain several to 10% C2–C5 hydrocarbons. These values are not congruent with the level of maturity of the strata and, taken at face value, indicates that the gas was generated from a deeper source and migrated into the coals. This explanation is counter intuitive with what is known about the present permeability of the coal and migration pathways, but there is no obvious alternative explanation. 4. Total gas-in-place 4.1. Extrapolating gas content to areas and coal seams with no core data In most wells, only the thickest one or two seams are cored, and in many areas no core data exists. In order to extrapolate the core desorption data both to other coal seams in the same well, and to areas where no data are available, a protocol was developed that captures the dependence of gas content on organic content and inversely, ash, as well as maturity. Since coal rank (maturity) correlates with current depth of burial and hence reservoir pressure, as well as moisture content, the importance of these variables are encompassed in the maturity term even though isolating the importance of any one variable independently is not possible. The protocol used here is as follows: 1) quantify the variation in gas content with ash through use of bulk density in the corresponding canister samples for each cored well; 2) group results from wells of similar rank (and depth) in a given region (normally two townships by two

Fig. 19. Compilation of published and unpublished carbon isotope measurements of desorbed methane from Mannville coals. The existing data set of about 40 values fall within the shaded areas. The shallow data (blue circle) are from Szatkowski et al. (2002).

ranges = 144 miles2; 373 km2) to create a statistically significant sample; 3) perform numerical regression to establish the relationship between density and in situ gas content; 4) determine gas content at density cut-offs of P10, P50 and P90 density values from the distribution of measured values (see below); 5) use petrophysical logs to determine the net thickness of each coal interval via log interpretation in the stratigraphic interval of interest (± 20 m stratigraphically of the principal coal); and 6) multiply the gas density (scf/t; m3/tonne) from the regression equation (at P10, P50, and P90 values) to the thickness of the coal to determine the gas-in-place contribution of each coal on BCF/mi2 basis. Example plots of bulk density versus gas content for canister desorbed samples for wells of different coal rank, as measured by vitrinite reflectance, are shown in Fig. 20. Linear regression equations for 39 areas were used to estimate the in situ gas content of coals in wells from the same geographic area (maturity/depth), for which no data is available through use of petrophysical logs (Table 2). For some wells, rigorous determination of density from petrophysical logs was not possible due to the borehole being out of gauge due to caving, seams being too thin to avoid seam boundary effects, and/or the logs in some wells are of poor resolution for unknown reasons (logging speed?). Additionally, since the petrophysical logs at best have a resolution of 15 cm, coals thinner than 15 cm cannot be quantified. Thicker seams seen on core have a stratigraphic variation in composition at a scale much less than 15 cm, such that the logs yield a running average of density values. Thus, although rigour was attempted in the analysis, interpretation was needed in determining the gas content and thickness in some wells and thus a rigorous stochastic analyses was not possible. Hence in recognition that the gas content calculations include potential unquantified sources of error, the gas content from the appropriate regression equations (Table 2), at P10, P50 and P90 values are here referred to as high, medium and low estimates. The high, medium and low gas content estimates for the studies wells correspond respectively to coal density values centred in the range ≈1.25–1.36 g/cm3, ≈1.36– 1.5 g/cm3 and ≈1.5–1.8 g/cm3. The high, medium and low gas density estimates (scf/t, cc/g) were used to calculate the gas-in-place for wells in the producing and prospective region centred on Corbett (Fig. 4). In this area, the logs of some 203 wells were examined together with available core data using the methodology outlined above. Using the regression equations for the well groups (Table 2), the gas density (scf/t) for low, median and high estimates were made (Table 3). Using the lower coal density value (high estimate) for all studied wells, the maximum coal gas content on in situ basis is 350 scf/t, the minimum gas content is 277 scf/t, and the average is 336 scf/t. For all wells,

Fig. 20. Example of variation of desorbed gas content with bulk density of the canister samples. The slope of the relationship varies with maturity (rank); however rank, moisture, depth of burial and reservoir pressure are all mutually correlated and isolating the importance of any variable is not possible. The legend includes the township/range areas (see Fig. 4) of the wells, as well at the vitrinite reflectance.

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Table 2 Best fit linear regression(s) of bulk density (g/cm3) versus canister desorbed gas content (scf/t) for cored wells from the rectangular township-range area indicated (see Fig. 4). The linear equation was used to estimate the gas content for wells located in the same geographic area. Grouped area Township/range median 16–18/11–15W4 21–33/25–28W4 22–24/19-21W4 25–27/17–18W4 28–30/25–27W4 31–33/21–24W3 34–36/11–13W4 34–36/19–21W4 34–36/22–24W4 34–36/25–28W4 37–39/13–16W4 37–39/19–21W4 37–39/25–27W4 38–42/16W6 40–42/19–21W4 40–42/22–25W4 40–42/2–4W4 40–42/25–27W4 40–42/5–7W4 41–43/8–10W4 43–45/16–18W4 43–45/19–21W4 43–45/22–24W4 43–45/25–28W4 46–48/19–21W4 46–48/22–24W4 46–48/25–28W4 49–51/10–12W5 58–60/1–3W5 58–60/4–6W5 61–63/1–3W5 61–63/4–6W5 61–63/7–9W5 63–66/10–12W5 63–66/13–15W5 64–66/1–3W5 64–66/13–16W5 64–66/4–6W5 64–66/7–9W5

Linear best fit equation (x = density g/cc_

Correl. coeff. r2

# of samples

−249.58× + 535.91 −387.9× + 816.98 −495.87× + 955.83 −277.67× + 633.62 −523.99× + 988.03 −56.44× + 124.27 −334.4× + 642.47 −264.05× + 627.36 −296.01× + 689.79 −425.08× + 891.79 −133.95× + 327.02 −347.86× + 738.94 −123.5× + 255.26 −254.07× + 560.79 −263.81× + 607.4 −360.33× + 799.25 −198.86× + 391.63 −345.08× + 751.16 −110.7× + 263.17 −143.29× + 317.45 −277.88× + 613.24 −346.93× + 723.3 −266.05× + 648.49 −282.23× + 716.51 −211.2× + 506.81 −251.32× + 628.98 −282.24× + 673.48 −123.92× + 269.63 −240.81× + 561.5 −275.03× + 653.11 −540.34× + 942.38 −316.47× + 724.3 −273.33× + 668.2 −185.94× + 510.49 −337.79× + 745.33 −151.15× + 386.49 −415.96× + 857.39 −210.75× + 529.77 −256.89× + 637.25

0.98 0.86 0.97 0.85 0.79 0.21 0.66 0.51 0.80 0.63 0.97 0.76 0.67 0.87 0.97 0.38 0.88 0.45 0.50 0.87 0.93 0.92 0.94 0.96 0.93 0.94 0.93 0.92 0.96 0.78 0.71 0.81 0.95 0.51 0.80 0.85 0.73 0.95 0.97

6 5 12 16 16 19 15 135 5 71 16 40 18 18 27 17 43 58 24 10 18 39 24 15 26 62 78 8 160 54 10 58 6 15 14 12 11 55 18

assuming the median gas density maximum gas content is 331 scf/t, the minimum is 256 scf/t and the, average value is 311 scf/t. Utilising the low estimate (highest bulk density value), hence the lowest gas density, yields a maximum gas content of 282 scf/t, a minimum value of 228 scf/t, and an average value of 265 scf/t. For the gas resource assessment, the gas content of the thickest seam where the horizontal well is located, and coals thicker than 0.15 m (resolution of logs) within ±20 m of the principal coal are distinguished based on their near term versus longer term contribution to production. The thickness of the coals in each well was determined manually; automating the process was not viable due to log quality and paucity of digital logs available. Histograms of the net thickness of the thickest seam per well, and the cumulative thickness of coals thicker than 0.15 cm are shown in Fig. 21 and summary statistics are provided in Table 3 Gas-density in scf/t for the coal for wells in the study area. The high, median and low values were determined using methods described in the text. Coal gas content on well basis

Max Min Average

Estimate of gas content (scf/t)

Fig. 21. Distribution of net thickness by well in the Corbett map area of: A. thickest individual seam with partings less than ≈0.4 m, and B. cumulative coal N0.15 m thick. Gaussian distribution shown overlying the histogram.

Table 4 for all wells. The thickest single seam is 4.7 m thick and in two wells no coal exists. The average thickness of the thickest coal is 1.9 m. The maximum cumulative coal thickness in a well is 10.8 m and the average thickness is 5.1 m. The areal variation in the principal coal seam and total net thickness of coal on a per well basis are shown in Fig. 22.

Table 4 Summary of coal thickness statistics of on a well basis in the Corbett area. Reservoir facies

High

Median

Low

350 277 336

331 256 311

282 228 265

Net thick. (m)

Maximum Minimum Average Median

Thickest coal

Cumulative coal N0.15 m

4.7 0.0 1.9 1.8

10.8 0.0 5.1 5.0

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estimates of gas density. In the Upper Mannville coal measures, using the median gas estimates, the average well has a total coal gas resource of 5.9 BCF/mi2 and the values range from a high of 13.3 BCF/mi2 to a low of 0 BCF/mi2. The lateral distribution of gas-in-place at the median estimated gas density for the thickest coal seam and cumulative coal N0.15 cm thick in the Corbett area are shown in Fig. 23. On average, the thickest coal seam, the natural target for horizontal drilling and completion, contains about 37% of the total coal gas resource and thinner coals comprise the balance, assuming a median estimated gas content for the coals. 5. Discussion and conclusions 5.1. Gas content

Fig. 22. A. Isopach maps showing the lateral variation in thickness of: A. main coal seam (contour interval = 0.20 m); B. cumulative coal in seams N0.15 m thick (contour interval = 0.5 m). The thickness of the coal together with the median gas density are used to determine total resource per unit area in Fig. 23.

The absence or areas of thin cumulative coal in the map area correspond to the occurrence of massive sandstone channels in the Upper Mannville, which either resulted in non-deposition or erosion of the coal and organic-rich facies. The gas density of the coal on a well basis, when multiplied by the thickness of the coal per well, yields the total gas-in-place in the coal. In Table 5, the range, average and median gas resource (BCF/mi2) for all wells studied in the Corbett area are provided for the thickest coal and the cumulative resource values based on high, median, and low

The Mannville coals throughout a large area of Alberta includes an enormous gas resource in areas of existing infrastructure. Using a large desorption data set from wire line retrieved core, and extrapolating this data set to non-cored intervals through petrophysical logs keyed to core has enabled refinement of the lateral distribution of total gas-in-place, mapping of gas composition and adsorbed gas saturation. Regionally, the median desorbed gas content per well ranges, on as received basis, from 47 to 400 scf/t and, on dry ash free basis, from 63 to 430 scf/t, with values increasing from northeast to southwest parallel with the increase in current depth of burial and coal rank. In the producing Corbett fairway, the in situ gas-in-place varies from 260 to 330 scf/t and averages 310 scf/t. The gas adsorption capacity of the coals varies with depth of burial (pressure), coal rank, and ash content. The highest adsorption capacity of the coal at reservoir pressure and temperature approaches 400 scf/t, but coals have values between 260 and 320 scf/t. The amount of methane in solution (calculated) based on moisture and estimated free water content, at a reservoir pressure of ≈1000 psig (6.9 MPa) is calculated to be between 7 and 10 scf/t (≈3% of total). The contribution of free gas to the gas resource is difficult to determine as a result of the friable nature of coals and their susceptibility to change in fabric during laboratory testing, and the lack of ancillary evidence for free gas. The total gas resource in the producing area on a per well basis and with ±20 m of the completed seam varies from 0 to 13.3 BCF/mi2.The contribution of thin coals in the ± 20 m stratigraphic interval for the median gas estimate, comprises about 60% of the coal gas-in-place of the average well (Table 5). The thin seams, due to the proximity, are anticipated to be co-produced from horizontal wells drilled and completed in the thickest seam, which is the practise. On a regional scale there is an excellent correlation between current depth of burial and coal rank. The strong correlation is surprising inasmuch as the succession was buried, in some areas, under multiple kilometres of Tertiary molasse, most of which was subsequently uplifted and eroded. That the correlation exists suggests relatively uniform burial depths, and subsequent uplift and minor lateral variations in heat flow. The relationship between coal rank and current depth of burial is better than the correlation between desorbed gas content and current depth of burial. It is unclear if this results from the inherent variation in desorbed gas content due to measurements, the impact of varying saturation or, a general trend in coal quality.

Table 5 Range, average, and median values of gas resource of the wells in the Corbett area. BCF/square mile

BCF/square mile

BCF/square mile

High estimate Thickest coal Cumulative coal N0.15 m Median estimate Thickest coal Cumulative coal N0.15 m Low estimate Thickest coal Cumulative coal N0.15 m Maximum Minimum Average Median

5.7 0.0 2.3 2.3

13.5 0.0 6.1 6.1

Maximum Minimum Average Median

5.5 0.0 2.2 2.2

13.3 0.0 5.9 5.8

Maximum Minimum Average Median

5.3 0.0 2.0 2.0

11.0 0.0 5.4 5.4

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Fig. 23. A. Lateral variation in the gas content (BCF/mile2) using the median gas content estimate for the main (thickest) seam (contour interval = 0.5 BCF/mile). B. Lateral variation in the gas content (BCF/mile2) using the median gas content estimate for the cumulative coal in seams N0.15 m thick (contour interval = 1.0 BCF/mile).

5.2. Controls on gas saturation and gas composition Most of the coals are saturated with gas within the accuracy of the analysis but important exceptions occur. On the eastern side of the basin there is a progressive decrease in saturation, and near the eastern edge of the study areas, the saturation is as low as 40%. Under saturation of coals has been attributed to a number of factors including (Bustin and Bustin, 2008): 1) volume of generated gas is less than the increase in sorption capacity of the coals during diagenesis; 2) gas was stripped in solution because of water flow and coals were uplifted; and 3) the overlying sedimentary strata eroded, thereby lowering the reservoir temperatures resulting in increased adsorption capacity without additional gas generation. Along the eastern margin of the study area, where the gas has a biogenic signature, it can be argued that potentially too little gas was generated to saturate the coals. To the west, however, the gas is party thermogenic and the argument is difficult since mass balance considerations indicate more gas generated from coals than their adsorption capacity. It has also been shown by Bustin and Bustin (2008) that only with very high geothermal gradients and low pressure gradients can

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under saturation be generated during uplift as a result of thermal effects alone. The origin of under saturation in the Mannville coals is not obvious. A possible mechanism is related to the tectonic history. The strata were deeply buried during the Late Cretaceous and Tertiary and subsequently uplifted many kilometres. This tectonic history have been invoked to account for a variety of pressure and saturation phenomena in the Western Canadian Sediment Basin, including over pressures, under pressures, and varying degree of fluid saturation (e.g. Jiao and Zheng, 1998) To account for under saturation of the Manville coals in the eastern part of the study we invoke the following working hypothesis: gas saturation at depth, due to thermogenic gas generation, followed by uplift, and an accompanying drop in pressure, resulting in gas desorption (Bustin and Bustin, 2008) and, if uncontained, possible flushing by gas of water filled fractures and pore space. This process would lead to gas saturation in the fractures and open porosity, but also would result in under pressuring if a significant gas column is developed. Such a history may account for the dry coals of the Horseshoe Canyon Formation (Bustin and Bustin, 2011a) and dryer Mannville coals. Such a history does not necessarily in its self yield under saturation, indeed if the reservoir is sealed, over pressures may be generated. For under saturation to occur a return to higher pore pressure is required which would require re-introduction of water through migration, and stripping of gas. Such a working hypothesis is supported by the under saturated low rank coals at the eastern edge of the study area, which have high C2H5 and carbon dioxide which, in the lack of an alternate explanation, argues for migration. In several locations in the study area, the desorbed gas content exceeded the adsorbed gas content calculated from the adsorption isotherm such that the coal calculates as over saturated. Since gas in the adsorbed state is maintained by pressure, having more gas in the adsorbed state than dictated by the isotherm at reservoir pressure is not possible, if the system is at equilibrium. Solution gas would not contribute to over saturation, since gas in solution is included in routine isotherm measurements. A potential mechanism for creating ‘apparent over saturation’ is that if during gas generation and migration through the coal, moisture is stripped due to dehydration by the expanding gas. The adsorptive capacity of the coal, having lower moisture, would be markedly increased (i.e. Levy et al., 1997). Hence if the gas content is at equilibrium with this partially dehydrated coal, but the isotherm was measured at equilibrium moisture, the coal would appear over saturated. The gas composition and methane isotopes across the basin are consistent with the degree of maturity of the coals; increasing thermogenic gas with depth of burial and associated increase in C2–C5 hydrocarbons. The exception is the higher C2–C5 hydrocarbons in the low rank coals at the eastern edge of the study. The only apparent explanation for these hydrocarbons is a thermogenic source and hence they were generated in deeper source rocks and migrated into the low rank coals. There are local occurrences of oil and bitumen (Gentzis and Goodarzi, 2009) in low rank Mannville coals from eastern Alberta, which supports migration events. 5.3. Origin of the productive fairway Gas charged Mannville coals, although wide spread in Alberta have only been successfully exploited in an area in central Alberta of about 2200 km2 (850 miles2), about 10% of the area of gas charged coal. Outside the producing fairway sustained commercial production has not been achieved irrespective of the multitude of drilling and completion strategies. Of the about 80 wells that tested the Mannville coal outside the fairway in the last 20 years, currently about 30 wells produce minimal gas, in the range of 60 to 70 mcf/day. The Mannville coal everywhere in the regional study area has well developed cleat (fractures), is gas charged, and is mainly bright banded and vitrinite rich. Nevertheless, commercial production is restricted to less than 10% of the total

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resource area as depicted by Berhane (2009a, 2009b). The lack of commercial development outside the producing area is widely attributed to low system permeability and particularly the lack of fracture permeability (i.e. Gentzis et al., 2008; Hyland et al., 2010). That fracture permeability does not exist in a coal which is thoroughly fractured (cleated) attests to the in situ stresses being high enough that the fractures (cleat) have no effective aperture. That highly fractured coals exist with no effective fracture permeably is common and is perhaps the rule. There are many more examples of gas charged, cleated, and sheared coal in the World that do not produce gas commercially than there are examples that do, in spite of many attempts (Bustin, 2006). This observation undoubtedly reflects a combination of factors including the high compliance of coal (i.e. high Poisson ratio and low Young's modulus), propensity to produce flow blocking fines, and the common lack of asperities on cleat surfaces, which when present in other rocks self-prop the fractures. There are variations in cleat spacing and coal composition that may be important in specific areas in the Manville coal, but these alone cannot account for the localised production at Corbett. The importance of stress on the Mannville coal system permeability is documented. In the Corbett area the role of situ stress on production was shown by Taylor et al. (2008) and Bearinger and Majcher (2010) who demonstrated the higher production rates in wells orientated to take advantage of the less stressed face cleats (orientated parallel to maximum horizontal stress). That the in situ horizontal stress(es) are lower in the Corbett area than in the areas of non-commercial production is evidenced by the higher system permeability. In the producing fairway, the system permeability determined by some 115 well tests averages about 10 md (range from 5 to 95 md; Bustin and Bustin unpublished) and the few (b20) reliable matrix permeability measurements at reservoir effectives stress are in the 1E-2 md to 1-E4 md range. Outside the producing fairway there are few measurements of system permeability. Hyland et al. (2010) report system permeability from well tests in the Mikwan area (south of the producing fairway) as less than 0.5 md and Gentzis et al. (2008) reports values of 1 to 1.5 md. In the same area, Hyland et al. (2010) argue that based on seismic attributes and bed curvature, due to structural drape, areas of higher permeability can be identified. In the Hyland et al. area of study, which they refer to at the Mikwan dry coal fairway; however sustained commercial production has not been realised. Gentzis et al. (2008) show, based on few data points, that there is a general decrease in Mannville coal permeability with depth, although it is not clear how the measurements were made. Current depth of burial in itself does not account for the higher permeability in the producing fairway; coals to the east and south that are shallower than those at Corbett are non-productive. From examining the regional coal rank, current depth of burial, and gas content maps of this study, the most interesting telling feature is that the producing fairway is located next to a significant re-entrant in the current depth of burial, vitrinite reflectance and gas content. Taking these observations at face value, suggests the Corbett area has a thermal maturity higher than adjacent areas of similar current depth of burial, and is located at an area of regional flexure, due to differential burial and/or uplift. Although the higher rank may reflect variation in lateral heat flow, another explanation is this area has been preferentially uplifted such that higher rank coals occur at shallow depths than observed regionally. Accompanying the uplift the lateral and vertical stresses would be reduced, which might account for the localised higher system permeability. Clearly, additional studies on the current state of stress at the local level are needed.

Acknowledgments This research was supported by the Natural Sciences and Engineering Research Council of Canada and Trident Exploration. Editor Ozgen

Karacan, and Tim Moore and an anonymous reviewer are thanked for their careful and constructive comments for the manuscript.

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