Geological evaluation of Halfway–Doig–Montney hybrid gas shale–tight gas reservoir, northeastern British Columbia

Marine and Petroleum Geology 38 (2012) 53e72

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Geological evaluation of HalfwayeDoigeMontney hybrid gas shaleetight gas reservoir, northeastern British Columbia Gareth R.L. Chalmers*, R. Marc Bustin Department of Earth and Ocean Sciences, University of British Columbia, 6339 Stores Road, Vancouver, V6T 1Z4 B.C., Canada

a r t i c l e i n f o

a b s t r a c t

Article history: Received 30 March 2012 Received in revised form 21 July 2012 Accepted 23 August 2012 Available online 7 September 2012

Evaluation of the reservoir quality of the Triassic HalfwayeMontneyeDoig hybrid gas shale/tight gas reservoir in the Groundbirch field in northeastern British Colombia requires an integration of unconventional and conventional methodologies. Reservoir evaluation includes reservoir thickness and structure, total porosity, TOC content, organic maturity, pore size distribution (micro- to macro-pore size fractions), surface area, mineralogy and pulse-decay permeability. Quartz (10e74%), carbonate (13e73%) and feldspar (0e42%) dominate the mineralogy of all formations with illite (0e32%) being locally important. The Tmax values range between 443 and 478
C placing the reservoirs beyond the oil window. Pore size distribution by low-pressure gas adsorption analysis identifies a large variation between the contributions from the micro-, meso- and macro-pore size fractions. Matrix permeabilities range between 1.0E-3 and 6.5E-7 mD at an effective stress between 2400 and 3300 PSI (16.5e22.8 MPa). Changes in depositional environments and diagenetic processes manifest as differences in lithology and mineralogy within the Montney and Doig reservoirs which subsequently affect the fabric, texture and pore size distribution. Fabric, texture and pore size distribution contribute to the variation in the permeability and the proportions of free to sorbed gas within the reservoir. Quartz-rich, coarser-grained intervals (upper portions of Doig C, B and Halfway Formation) have lower surface area, greater porosities and a higher volume of macropores compared to the carbonate- and clay-rich finer-grained intervals (Doig A). Permeabilities do not vary according to lithology with higher permeabilities found within both fine-grained (Doig A) and coarser-grained (Halfway Formation) units. Permeability is controlled by pore size distribution. Higher permeability samples contain a balanced ratio between micro-, meso- and macro-porosity. The finer-grained intervals have higher sorbed gas capacity due to higher surface areas because of the higher volumes of finer mesopores and micropores than the coarser-grained units. However, porosity and permeability are low in some parts of the Doig A and fracture stimulation is necessary to achieve economic flow rates. Ó 2012 Elsevier Ltd. All rights reserved.

Keywords: Matrix permeability Mineralogy Pore size distribution TOC content Pyrobitumen Surface area

1. Introduction Exploration and development of the gas shaleetight gas hybrid play of the Lower Triassic Montney Formation in northeastern British Columbia in recent years focused on the overlying Doig Formation with the objective to coproduce the Doig with the Montney play. Shale gas reservoirs refer to non-buoyancy driven, continuous hydrocarbon plays that are composed of a lithologically diverse group of fine-grained sedimentary rocks that include true shales, mudrocks, limestones and siltstones (Chalmers et al., 2012). Tight gas refers to reservoirs composed entirely of free gas and are

* Corresponding author. Tel.: þ1 604 822 3706; fax: þ1 604 822 6088. E-mail address: [email protected] (G.R.L. Chalmers). 0264-8172/$ e see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.marpetgeo.2012.08.004

regionally pervasive (Dixon and Flint, 2007). Very large hydrocarbon resources are estimated for the Triassic strata of the Alberta Basin and production is well established, however, understanding of the geological controls on matrix permeability is not well understood and will have an impact of long term production profiles and well economics. For the Triassic strata, conventional oil in place is estimated at 800 million barrels and gas-in-place estimated at nearly 10 TCF (Edwards et al., 1994). Unconventional gas-in-place estimates are between 40 and 200 TCF for the Doig Formation and between 30 and 200 TCF for the upper Montney Shale Member (Walsh et al., 2006). Gas recoveries have been estimated from decline curve analysis for the upper Montney play in Dawson Creek area to be an average of 4.7 BCF per well for a 10 year period (Burke and Nevison, 2011). Horizontal wells are focused within the upper Montney Shale Member (Dixon, 2000, 2009a,b) with typically 10e18 frac stages in

54

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

1400e2400 m laterals (Canada Energy Partners New Release, 2010). The Doig Formation contains both tight gas and shale gas plays. Tight gas production occurs within the localised thicker sandstone of the upper Doig Formation (Walsh et al., 2006) and positive tests are being reported from the Doig Phosphate gas shale play (Canada Energy Partners New Release, 2010). Evaluation of shale gas reservoirs consists of determining the thickness and structure trends, mineralogy, porosity, pore size distribution (micro- to macro-pore size fractions), surface area, organic geochemistry and permeability. Examples of evaluation of shale gas reservoir studies include the Devonian Barnett Formation (Montgomery et al., 2005; Jarvie et al., 2007), the Jurassic Gordondale Formation (Ross and Bustin, 2007), the Devonian Horn River Formation (Ross and Bustin, 2008; Chalmers et al., 2012), the Cretaceous Buckinghorse Formation (Chalmers and Bustin, 2008), the Cretaceous Shaftesbury Formation (Chalmers and Bustin, 2012). Organic geochemistry data yields the maturity, TOC content and organic matter type and the likelihood of hydrocarbon generation. Very large gas-in-place estimates are common for gas shale plays and now an evaluation of the geological controls on matrix permeability is necessary to improve well completions and refine exploration models. Sedimentology has a large impact on the mineralogy, TOC content, fabric and texture of shale. The combination of these characteristics governs the pore size distribution and the matrix permeability of the Devonian Horn River shale reservoir (Chalmers et al., 2012) which directly impacts the productivity of the gas shale play and development strategies. An integration of unconventional and conventional methodologies is performed to evaluate the gas shaleetight gas hybrid play. Pore size distribution by mercury porosimetry measure pore sizes between 3 and 120,000 nm (120 mm) and do not measure micropores (<2 nm1). Low-pressure gas (N2 and CO2) adsorption analysis is used to evaluate the pore size distribution of unconventional reservoirs because gas adsorption analyses measures micropores, mesopores and some macropores (0.35 and 300 nm; Quantachrome, 2008). The study area is centred in the Groundbirch area, south of Fort St John in northeastern British Columbia (Fig. 1). The objectives of this study are to: 1) determine the influence sedimentology has on the distribution of the TOC content, mineralogy, porosity and the pore sizes; 2) resolve the influence mineralogy and TOC content have on the porosity and the pore size distribution; and 3) identify the controls on the matrix permeability. 2. Geological background The Daiber Group within the Peace River area of northeastern British Columbia consists of the Lower Triassic Montney and the Middle Triassic Doig and Halfway formations (Fig. 2). The Montney, Doig and Halfway formations were deposited along a passive continental margin and consist of a westward thickening siliciclastic prograding wedge (Edwards et al., 1994; Davies, 1997; Walsh et al., 2006; Dixon, 2009a,b). The Montney, Doig and Halfway formations (Fig. 2) represent the first and second of three transgressiveeregressive (TeR) cycles that deposited the Triassic strata in northeastern British Columbia (Gibson and Barclay, 1989; Edwards et al., 1994). The depositional setting for the Montney and Doig formations is described as an open shelf marine environment (Edwards et al., 1994). The palaeoenvironmental setting for the Halfway Formation is considered as barrier island shoreface sediments (Edwards et al., 1994). Palaeogeographic reconstruction for

1 Micropores (<2 nm), mesopores (2e50 nm) and macropores (>50 nm) are defined by physical gas adsorption characteristics of microporous and mesopores media (IUPAC., 1997).

Triassic sedimentation interpret a palaeoshoreline that prograded during sea level regressions to just east of the Fort St John and the Alberta/B.C. border (Kent, 1994). During this time, shallow shelf muds covered the study area and deeper marine muds deposited to the west of the study area. The Montney Formation unconformably overlies Carboniferous or Permian strata and consists of variable amounts of interbedded shale, siltstone and sandstone. Strata of the Montney developed during the first of three major transgressioneregression cycles. Within British Columbia, Dixon (2000) subdivided the Montney Formation into the lower SiltstoneeSandstone and the upper Shale members based on lithostratigraphy. Members are separated by a basin-wide unconformity that developed due to tectonic uplift of the basin margin (Dixon, 2009b). The Shale Member is absent within Alberta and progressively becomes thicker (up to 159 m) towards the foothills of British Columbia to the west (Dixon, 2000). North of the study area, Utting et al. (2005) subdivided the Montney Formation into two TeR couplets which correlates with the SiltstoneeSandstone and Shale members of Dixon (2000). The upper Montney Shale Member is more organic rich and radioactive than the lower Montney SiltstoneeSandstone Member (Dixon, 2000). The Montney Formation was deposited within an inner to distal shelf setting (Edwards et al., 1994) which varied from tempestites in distal shelf shales to deltaic/shoreline sandstones at the eastern margin (Edwards et al., 1994). Overlying the Montney Formation is the second TeR cycle deposited the Doig, Halfway and Charlie Lake formations (Fig. 2). Thickness of the Doig Formation varies from 790 m southwest of Fort St John and thins to 80 m towards the northeast at the British Columbia/Alberta border. In this study, to simplify descriptions and comparisons, the Doig Formation is subdivided into Doig A, B and C based on lithological differences (Fig. 2) and is similar to the informally subdivisions by Davies (1997): the lowermost phosphate zone (Doig A), middle siltstone (Doig B); and the upper-regressive coarsening-upward sequence (Doig C). Doig A is a highly radioactive unit that consists of phosphatic nodules and granules within argillaceous siltstone, interbedded with calcareous siltstone and dark-grey shale (Riediger et al., 1990). Doig B is medium to darkgrey argillaceous siltstone and shale which locally contains a thick shoreface sandstone (up to 25 m; Envoy and Hogg, 1998). Doig C varies from siltstone to fine sandstone and the boundary with the overlying the Halfway Formation is between an argillaceous Doig sandstone and an overlying cleaner Halfway sandstone (Evoy, 1998). The Doig Formation was deposited in a distal to mid shelf setting during a marine transgression. The Doig A and B were deposited in a distal shelf distal shelf setting with the Doig B sandstone being interpreted as deltaic to shoreface sandstone (Harris and Bustin, 2000). Doig C is interpreted to have been deposited in a proximal shelf to lower shoreface environment. The Doig Formation is overlain by the prograding beach barrier sandstones of the Halfway Formation (Fig. 2). The thickness of the Halfway Formation is less than 60 m within the Farrell area of the foothills and, similar to the Doig Formation, the Halfway Formation tapers out towards the east into central Alberta (Edwards et al., 1994). The Halfway Formation consists of predominately quartz arenite with dolomite and anhydrite cements and locally important coquinas (Edwards et al., 1994; Dixon, 2009a). Diagenetic processes are important influences on reservoir quality of the Doig and Montney formations. Dolomite, ankerite, calcite, quartz and anhydrite are common cements within the Montney Formation in west-central Alberta (Davies et al., 1997). The Doig B sandstone contains a combination of calcite, quartz, dolomite and anhydrite cements (Harris and Bustin, 2000). Paragenetic interpretation of the Doig sandstone shows late diagenetic secondary porosity (inter- and intra-granular and moldic) formed

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Yukon

55

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o

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B Figure 1. Index map showing the location of the wells used to construct the two cross-sections AeA0 , BeB0 and the isopach and structure maps (circles). Squares represent wells that are sampled for this project. Triangles are city/town locations. The names of structural elements defined by Berger et al. (2008) are italicised. The structural elements include the Peace River arch, the deep basin and the Fort St John and Groundbirch grabens. Lineaments of these structural elements were identified by high resolution aeromagnetic surveys (Berger et al., 2008).

by dissolution of earlier calcite cement and quartz framework grains (Harris and Bustin, 2000). Structural features located within the study area consists of asymmetrical pull-apart grabens with failed arms, shallow fault systems that developed during the Laramide thrusting and deeper basement faults that follow the basement terranes (Berger et al., 2008). Graben faults (Fig. 1) within the Peace River embayment were active during the Triassic, possibly effecting the deposition of the Montney and Doig formations. It has been argued that structural lineaments exert some control on the location of sweet spots

in the conventional and unconventional Montney and Doig plays (Berger et al., 2009). The four wells of this study lie within an area that contains the Deep Basin, Peace River Arch, Fort St John graben and the Groundbirch failed arm graben complex (Fig. 1). 3. Methodology Results and interpretations are obtained from a total of four wells, 11-7-78-20W6, 16-2-78-22W6, 6-28-78-19W6 and 15-3480-18W6 (Fig. 1). The Montney is sampled in all four wells with the

56

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Davies, 1997 This Study

Permian

Fernie Fm

Schooler Creek Gp

Pardonet Fm Baldonnel Fm Charlie Lake Fm Halfway Fm

Doig Fm Daiber Gp

Triassic Lower Middle Upper

Jurassic

Halfway Fm

Doig C Doig B

Phosphate Zone

Doig A

Montney Fm

Montney Fm

Belloy Fm

Belloy Fm

Figure 2. Stratigraphic table of the Triassic strata within the Peace River plains area of Northeast British Columbia (modified after Davies, 1997) and the subdivisions made to the Doig Formation in this study.

greatest range of depths analysed in the 16-2-78-22W6 well. The complete Doig Formation is sampled within the 11-7-78-20W6 well with Doig A being sampled from cores within the 16-2-7822W6, 6-28-78-19W6 and 15-34-80-18W6 wells. Sampling is dictated by core plug locations within the 11-7-78-20W6 well resulting in variation in the sampling density, i.e., higher sampling densities is found within the Doig A interval compared to the rest of the well (see Table 1 for sample depths). To evaluate the gas shale/tight gas reservoir character of the Doig Formation, core samples and sidewall cores (only from 11-778-20W6 well) were analysed to determine the distribution of the TOC content, organic geochemistry, mineralogy, porosity, pore size distribution (PSD), surface area and the matrix permeability. A total of three samples from the Halfway Formation, two samples from the Doig C, nine samples from the Doig B, 49 from the Doig A and 35 from the Montney Formation (Table 1). The TOC content, organic geochemistry and Tmax values were collected from a Rock Eval II apparatus with a TOC module. Maceral analysis of samples were performed in accordance with ASTM D 2799-05 (2005) and a total of 300 points (Bustin, 1991) were counted on each sample with a standard error of less than 2%. Pyrobitumen reflectance was performed according to standard ASTM D2798-11a (2011) for reflectance analysis of telovitrinite. To convert pyrobitumen reflectance to telovitrinite reflectance, Equation (1) was utilised from Schoenherr et al. (2007).

VRr ¼ ðBRr þ 0:2443Þ=1:0495 where VRr ¼ Mean random reflectance of vitrinite, BRr ¼ Mean random reflectance of pyrobitumen.

(1)

A normal-focus Cobalt X-ray tube was used on a Siemens Diffraktometer D5000 at 40 kV and 40 mA. For X-ray diffraction analysis, crushed samples (<250 mm) were mixed with ethanol, hand ground in a mortar and pestle and smear mounted on glass slides. The mineral composition was semi-quantified by Rietveld analysis (Rietveld, 1967) using Bruker AXS Topas V3.0 software. Impregnated polished thin sections (<30 mm), cut perpendicular to bedding, were examined using transmitted polarized light microscopy prior to carbon coating for back scattered electron microscopy (BSEM) analysis. BSEM micrographs were acquired using a Philips XL-30 SEM at an accelerating voltage of 15 keV. Elemental identification was obtain using a PrincetonÒ GammaTech PRISMIG energy-dispersive spectrometer, which allowed identification of the chemical composition of mineral phases by their X-ray spectra using Bruker Espirit V1.9 software with an accelerating voltage of 15 keV. Porosity was calculated from the skeletal density and the bulk density. Bulk density was calculated from the sample weight and bulk volume from mercury immersion. Skeletal density was obtained by helium pycnometry on oven-dried samples (i.e., Sw ¼ 0) with a grain size between 0.841 mm (20 mesh sieve) and 0.595 mm (30 mesh sieve). Pore size distribution, pore surface area and porosity were measured by a MicromeriticsÒ Autopore porosimeter on crushed (between 20 and 30 mesh sieve) samples. To measure the pore size distribution, a cylindrical pore geometry is assumed and the pore radius is calculated from the applied pressure using the Washburn Equation (Washburn, 1921). The pore size detection limit of porosimetry is 3 nm (approximate boundary between mesopore and micropore). The porosimetry-derived porosity is the ratio between the total intrusion volume of the sample and the bulk volume of the sample. Due to the analytical procedure of degassing and evacuating the sample prior to analysis samples are required to be oven dried at 110
C which results in the water saturation being zero (Sw ¼ 0). Therefore the porosity derived from porosimetry is the total porosity and does not consider water saturation or the microporosity of the sample. Microporosity is responsible for a large portion of surface area and storage of methane in unconventional reservoirs (Chalmers and Bustin, 2007; Ross and Bustin, 2009). As pore of unconventional reservoirs are generally more compressible than conventional carbonate and sandstone reservoirs (Rieke and Chilingarian, 1974), the difference between analytical pressures of pycnometry (20 PSI) and porosimetry (60,000 PSI) will affect the pore volumes as higher pressures will reduce the pore volume of the sample and reduce the total porosity calculation from porosimetry. The microporous surface area and gas saturation curves were determined by low-pressure (<127 kPa) adsorption analyses using a QuantachromeÒ Autosorb apparatus. Between 0.1 and 2 g of sample was degassed at 150
C for 12 h prior to analysis. The PSD from gas adsorption analyses is dependent on the theoretical equations used within the data reduction process. Gas saturation curves (PSD) were determined by low-pressure (<127 kPa) N2 gas adsorption at 196
C and CO2 adsorption at 0
C and using the Barrett, Joyner and Halenda (BJH) calculations (Barrett et al., 1951). Microporous surface area were calculated by carbon dioxide adsorption using the DubinineRadushkevich (DeR) equation at 273K using the cross-sectional area of CO2 molecule of 0.253 nm2(Unsworth et al., 1989; Marsh, 1989; Clarkson and Bustin, 1996). The PSD by CO2 adsorption is calculated using the Dollimore and Heal (DH) method (Dollimore and Heal, 1964). Permeability was determined by a pulse-decay permeameter using methane on 2.5 cm diameter and length core plugs and sidewall cores. Methods by Cui et al. (2009) were followed to correct for methane adsorption. No microfractures were present in samples before or after analyses. This was confirmed by partially

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

57

Table 1 Mineralogy, Porosity and TOC Content of 11-7-78-20W6 (11-7) well, 15-34-80-18W6 (15-34) well, 16-2-78-22W6 (16-2) well and 6-28-78-19W6 (6-28) well. All samples are from cores with the exception of samples from the 11-7 well which are side-wall cores. FSS ¼ Fine sandstone; VFSS ¼ Very fine sandstone; Sts ¼ Siltstone; S.Mst ¼ Silty mudstone; Mst ¼ Mudstone. Sample number

Interval

Depth (m)

Lithology

He porosity (%)

Hg porosity (%)

Quartz (wt %)

Illite (wt %)

Calcite (wt %)

Dolomite (wt %)

Feldspar (wt %)

Pyrite (wt %)

Apatite (wt %)

TOC content (%)

Tmax (
C)

15-34-1 15-34-2 15-34-3 15-34-4 15-34-5 15-34-6 15-34-7 15-34-8 6-28-1 6-28-2 6-28-3 6-28-4 6-28-5 6-28-6 6-28-7 11-7-46 11-7-45 11-7-44 11-7-43 11-7-42 11-7-41 11-7-40 11-7-39 11-7-38 11-7-37 11-7-36 11-7-35 11-7-34 11-7-33 11-7-32 11-7-31 11-7-30 11-7-29 11-7-28 11-7-27 11-7-26 11-7-25 11-7-24 11-7-23 11-7-22 11-7-21 11-7-20 11-7-19 11-7-18 11-7-17 11-7-16 11-7-15 16-2-1 16-2-2 16-2-3 16-2-4 16-2-5 16-2-6 16-2-7 16-2-8 16-2-9 16-2-10 16-2-11 16-2-12 16-2-13 16-2-14 16-2-15 16-2-16 16-2-17 16-2-18 16-2-19 16-2-20 16-2-21 16-2-22 16-2-23

Doig B Doig B Doig B Doig A Doig A Doig A Doig A Montney Doig A Doig A Doig A Montney Montney Montney Montney Halfway Halfway Halfway Doig C Doig C Doig B Doig B Doig B Doig B Doig B Doig B Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Montney Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A Doig A

2046 2049 2051.2 2054.2 2057 2059.3 2062.4 2065.8 2589 2594 2599.66 2604.69 2604.74 2609.2 2609.24 2650 2665 2677 2688 2705 2716 2721 2728 2733 2745 2755 2764.6 2764.8 2765 2765.2 2765.4 2772 2780.6 2780.8 2781 2781.2 2781.4 2787 2792.6 2792.8 2793 2793.2 2793.4 2800 2802 2808 2814 2995 2997.04 2997.24 3000.08 3002.26 3006.12 3008.22 3011.15 3016.53 3018.35 3021.71 3023.61 3026.98 3030.09 3031.89 3033.76 3036.8 3038.78 3041.8 3044.05 3046.92 3048.85 3051.92

Sts FSS Sts VFSS Sts S.Mst S.Mst S.Mst VFSS Sts Sts Sts Sts Sts Sts FSS FSS VFSS VFSS S.Mst Sts Sts Sts Mst S.Mst S.Mst Mst Mst Sts S.Mst S.Mst Mst S.Mst Mst S.Mst S.Mst S.Mst Mst Mst S.Mst Mst Mst Mst Sts S.Mst Sts Mst Sts Sts Sts Mst Sts Sts Sts Sts Sts Sts Sts Sts Sts S.Mst S.Mst Sts Sts Sts Sts Sts Sts Sts Sts

4.4 5.9 3.4 2.8 7.2 2.2 2.7 4.5 3.4 5.0 e 3.4 6.6 7.0 6.3 e 1.5 e 6.2 2.3 e e 6.6 e e 3.1 4.5 5.2 e e e e 5.2 e e 4.2 e 2.6 4.6 e e 2.9 3.2 e e 5.2 2.3 5.2 6.4 3.5 6.4 5.0 5.5 6.8 4.3 6.0 3.9 5.8 5.4 3.9 5.1 6.3 5.7 5.2 6.1 6.3 6.0 8.3 5.7 7.3

5.7 6.7 3.6 3.8 6.2 1.5 1.9 4.9 2.5 3.4 4.7 4.9 7.2 7.0 5.2 e 2.3 e 3.9 1.9 e e 6.5 e e 2.4 e e 1.8 e e 2.3 2.7 e 2.2 2.8 e e 1.3 e e 2.4 2.5 e e 5.2 2.2 4.6 4.1 4.0 4.8 3.2 3.8 4.9 3.7 5.6 3.4 4.1 3.7 3.2 2.9 3.2 3.6 4.3 4.5 4.4 3.7 3.4 3.7 5.2

37.9 46.1 26.9 18.7 31.9 13.5 25.5 37.6 15.1 20.6 26.7 28.7 31.6 29.5 30.1 39.8 49.1 74.5 66.1 36.2 64.9 47.9 58.5 47.4 25.5 21.6 23.7 20.0 13.4 25.9 26.5 15.1 20.8 22.7 26.1 21.8 24.4 22.7 17.1 19.3 18.6 17.2 20.4 34.7 27.3 28.7 27.9 15.2 21.1 9.9 16.7 16.6 15.0 27.5 16.7 29.8 13.1 23.0 17.7 19.5 15.1 19.6 12.3 29.6 24.8 27.4 13.8 16.0 17.8 19.9

17.7 0.0 13.3 5.8 4.5 7.9 18.5 4.2 6.1 14.8 15.4 5.8 15.8 13.4 12.2 0.0 0.0 0.1 0.1 15.2 1.1 4.5 5.5 8.8 15.6 5.4 19.0 19.4 5.2 13.2 31.7 14.4 13.5 11.9 15.4 11.5 4.5 2.9 3.4 7.2 11.1 10.3 10.5 2.1 4.6 4.9 11.3 7.1 16.4 3.2 14.1 12.0 7.1 12.2 8.7 5.3 3.3 10.2 2.9 10.6 16.8 8.4 2.8 5.1 3.7 5.8 5.6 16.3 4.6 7.9

7.8 36.3 9.9 39.8 15.5 43.3 14.7 17.2 28.4 11.6 7.4 32.1 12.5 7.4 7.4 46.8 45.7 13.2 14.6 23.1 8.8 16.4 1.8 4.1 15.2 41.7 17.5 23.7 50.9 19.5 12.8 42.7 22.0 17.8 20.7 26.9 29.0 14.3 35.2 15.4 22.4 34.9 22.4 18.2 21.1 18.1 21.6 46.0 12.0 31.6 24.0 28.6 33.4 16.5 40.7 15.4 46.7 25.4 39.3 38.8 28.4 33.1 42.3 18.3 17.0 12.7 34.7 23.4 32.9 16.7

7.5 9.8 15.3 14.0 21.4 16.7 20.0 10.9 9.1 9.7 15.5 6.2 11.1 7.2 8.7 9.8 3.9 4.4 4.5 6.9 7.6 13.8 17.3 16.6 26.6 16.0 15.7 13.2 21.8 16.0 10.8 9.9 25.4 19.0 19.1 15.3 18.6 26.0 23.7 34.3 31.0 21.5 22.6 28.4 16.5 23.5 9.2 10.8 19.8 30.1 20.1 7.6 18.0 7.9 16.6 24.4 9.6 10.9 11.1 10.4 10.3 10.4 8.2 22.1 23.0 28.5 11.8 10.1 11.5 29.1

23.2 7.8 28.4 17.4 23.1 15.2 17.2 23.9 34.6 33.5 32.0 22.4 25.2 39.3 38.5 2.2 0.0 6.0 12.1 13.0 10.1 14.5 15.2 21.0 14.3 13.4 18.1 18.0 7.6 17.2 7.4 11.0 12.6 20.3 13.4 20.5 19.9 23.2 17.3 17.2 13.6 12.9 18.3 15.2 20.0 23.2 23.8 17.2 27.6 24.0 20.7 29.9 23.0 32.9 14.9 21.2 24.9 25.7 23.3 14.7 25.4 20.7 26.7 20.7 28.6 23.0 28.8 28.6 24.2 22.9

3.6 0.0 3.0 4.3 0.0 1.2 2.8 1.8 1.7 2.7 1.9 2.2 2.3 2.3 2.3 0.3 0.1 0.3 0.3 2.3 1.1 1.2 0.6 1.3 2.2 1.4 3.5 4.0 0.2 4.9 3.1 1.3 2.4 3.7 2.6 2.8 2.0 0.8 2.0 2.0 2.3 1.7 2.1 1.0 1.1 0.6 1.7 3.0 2.5 0.7 2.8 3.5 2.0 1.7 2.3 1.2 1.6 2.2 1.8 1.4 1.0 1.9 1.5 1.1 1.2 1.7 2.0 2.0 2.1 1.5

2.3 0.0 3.2 0.0 3.5 2.3 1.4 4.5 5.1 7.2 1.2 2.6 1.5 0.9 0.9 1.2 1.2 1.6 2.4 3.3 6.5 1.7 1.2 0.8 0.7 0.6 2.6 1.7 1.0 3.3 7.7 5.6 3.4 4.5 2.7 1.2 1.5 10.1 1.3 4.5 1.0 1.6 3.9 0.5 9.3 1.0 4.6 0.7 0.7 0.7 1.6 1.7 1.6 1.3 0.0 2.9 0.8 2.6 3.9 4.6 2.9 6.0 6.2 3.1 1.7 0.9 3.4 3.8 7.0 2.1

2.0 0.9 4.0 1.3 1.3 2.7 7.0 3.2 e e e e e e e e e e 0.37 2 0.59 1.25 0.73 0.93 4.34 2.04 2.26 7.23 1.32 6.07 2.55 1.52 4.03 3.94 4.09 6.67 5.21 1.75 4.33 6.08 6.63 2.13 6.81 1.08 2.95 0.88 3.37 e e e e e e e e e e e e e e e e e e e e e e e

448 449 448 460 470 460 465 443 e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e 478 e e e e e e e e e e e e e e e e e e e e e e e e e e e

(continued on next page)

58

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Table 1 (continued ) Sample number

Interval

Depth (m)

Lithology

He porosity (%)

Hg porosity (%)

Quartz (wt %)

Illite (wt %)

Calcite (wt %)

Dolomite (wt %)

Feldspar (wt %)

Pyrite (wt %)

Apatite (wt %)

TOC content (%)

Tmax (
C)

16-2-24 16-2-25 16-2-26 16-2-27 16-2-28 16-2-29 16-2-30 16-2-31 16-2-32 16-2-33 16-2-34 16-2-35 16-2-36 16-2-37 16-2-38 16-2-39 16-2-40 16-2-41 16-2-42 16-2-43 16-2-44 16-2-45 16-2-46 16-2-47 16-2-48 16-2-49 16-2-50 16-2-51 16-2-52

Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney Montney

3053.82 3056.87 3058.28 3061.8 3063.75 3066.81 3068.27 3071.8 3076.19 3081.85 3085.6 3091.8 3096.26 3101.92 3106.92 3110.79 3116.78 3121.75 3126.84 3131.87 3136.75 3141.04 3147 3151.85 3157.03 3161.75 3166.81 3171.9 3176.77

Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts S.Mts Sts Sts Sts Sts Sts Sts Sts Sts Sts Sts

5.9 7.8 6.4 5.9 5.9 6.6 5.0 4.0 5.2 4.2 4.9 4.7 5.4 5.9 6.2 5.7 3.9 6.7 6.3 5.1 3.4 6.0 3.9 8.4 3.0 5.8 4.8 3.3 4.0

4.1 5.8 5.1 3.6 5.6 5.7 3.8 3.7 5.1 3.5 5.0 4.9 5.5 4.1 4.8 4.4 3.6 5.2 4.6 4.5 4.6 5.7 5.0 5.0 3.3 5.7 4.7 4.8 4.6

20.1 28.2 25.6 19.0 25.2 20.9 21.0 23.7 29.2 32.9 33.2 32.1 29.4 27.5 25.0 29.6 21.1 31.0 30.3 24.4 19.0 32.8 29.4 32.4 10.8 32.8 32.2 16.6 37.9

5.7 6.6 4.2 12.2 9.2 6.4 11.9 8.0 5.5 8.9 11.0 12.0 12.0 11.6 8.1 14.3 9.2 10.1 15.5 9.8 10.2 13.6 17.8 14.1 5.1 11.5 18.3 4.9 14.5

16.1 14.5 20.0 22.8 18.0 18.6 18.1 32.3 15.1 17.2 13.9 8.8 11.2 11.0 9.8 11.9 38.4 8.4 9.3 9.4 7.1 8.7 11.1 5.0 8.2 4.9 6.7 8.0 6.5

16.4 7.0 23.4 13.6 12.3 29.7 13.9 9.2 28.8 16.2 10.3 10.4 12.7 8.8 19.1 14.1 8.9 17.7 10.6 10.9 21.2 9.6 8.1 11.3 54.2 17.1 10.6 43.1 6.0

33.2 25.3 24.2 24.5 31.0 19.9 28.4 14.9 17.7 19.0 28.2 33.6 31.4 32.3 34.4 26.5 19.2 28.3 29.3 42.1 38.7 32.7 31.3 34.6 19.6 33.5 32.1 26.1 34.5

2.1 1.1 1.2 2.9 1.2 1.7 2.8 0.9 1.6 0.8 0.7 1.0 1.3 1.1 1.1 1.7 1.4 2.0 2.4 2.1 1.3 1.8 2.1 2.0 1.7 0.0 0.0 0.1 0.4

6.3 17.3 1.5 5.2 3.2 2.9 3.9 11.0 2.1 5.1 2.8 2.1 2.0 7.7 2.6 2.0 1.9 2.5 2.5 1.2 2.6 0.7 0.4 0.7 0.4 0.2 0.2 1.1 0.2

e e e e e e e e e e e e e e e e e e e e e e e e e e e e e

e e e e e e e e e e e e e e e e e e e e e e e e e e e e e

submerging samples in ethanol which identifies microfractures in cores. To compare samples, the average effective stress for each well was calculated by using their present depth and Equations (2) and (3) below. Permeability was measured with effective stresses at in-situ reservoir conditions and ranges between 2400 and 3300 PSI (16.5e22.8 MPa).




sh ¼ sv  a$Pp $ðm=½1  mÞ þ Pp

(2)

where:

sh ¼ Horizontal stress, Pp ¼ Pore pressure,

sv ¼ Vertical stress, m ¼ Poisson’s ratio, a ¼ Effective stress co-efficient (Biot’s coefficient). To calculate the mean effective stress (MES), Equation (2) was used.

MES ¼ ð½shmax þ shmin þ sv =3Þ  Pp

(3)

strata along depositional dip to the northeast (Fig. 3) with thinning being more pronounced with the Doig Formation. The upper Montney Shale Member and the Doig Formation show more consistent thicknesses along depositional strike (cross section Be B0 ; Fig. 4) compared to the depositional dip (cross section AeA0 ). The Montney and Doig formations increase in thickness in well D-10-C-93-P-8 and 1-10-82-23W6 with the Doig B and C increasing within 16-2-78-22W6. In most areas, the increase in the thickness of the Doig Formation occurs where the underlying the Montney Formation is poorly developed. For the study area (Fig. 1), the depths to the top of the Montney Formation range between 339 and 3418 m (Fig. 5A) and between 313 and 3102 m for the Doig Formation (Fig. 5B). Depths increase (from sea level) towards the south-southwest. Isopach maps for Montney Shale Member and Doig Formation show an increase in thickness towards the west and southwest (Figs. 6 and 7A and B). The thickness of the Montney Formation varies from 25 to 266 m and the Doig Formation varies from 26 m to 382 m. The thickness of Doig A varies from 5 m to 60 m with the thickness increasing to the west and southwest of the study area (Fig. 7B). This trend, however, is not uniform because of the presence of both thicker and thinner areas across the region.

where:

shmax ¼ Maximum horizontal stress, shmin ¼ Minimum horizontal stress.

4. Results 4.1. Isopach and structure maps and cross sections Cross sections AeA0 (Fig. 3) and BeB0 (Fig. 4) illustrate the stratal geometries along deposition dip and strike, respectively, through the study area. Cross section AeA0 shows an overall thinning of the

4.2. Mineralogy of the upper Montney Shale Member and Doig Formation The bulk mineralogy varies across the study area and stratigraphically between high and low carbonate (calcite, ankerite and dolomite), quartz and feldspar (albite and microcline) contents with clay (illite) remaining relatively low but locally important (Fig. 8A; Table 1). Illite is the only clay identified. Muscovite is also present as detrital grains (Fig. 11). Several samples from Doig C and Halfway Formation (11-7-78-20W6 well) have high quartz contents and very low clay and carbonate content whereas majority of samples from Doig A contain moderate amounts of carbonate and quartz (Fig. 8B). Higher clay contents are found in Doig A samples

Southwest

A

C-32-F-93-O-9 GR (GAPI) 0

Northeast

7-6-77-25W6

16-27-77-22

GR (GAPI)

150

0

16-2-78-22

GR (GAPI)

100

0

GR (GAPI)

150

0

100

11-7-78-20

6-28-78-19

15-30-79-15

GR (GAPI)

GR (GAPI)

GR (GAPI)

0

150

0

150

0

15-34-80-18

14-5-81-17

GR (GAPI)

150

0

GR (GAPI)

150

0

A`

7-27-84-14 GR (GAPI)

100

0

150

Halfway Fm

Halfway Fm

Doig C

Doig Fm

Doig B Doig A

Doig Phosphate

Montney Fm Shale Member

Montney Fm

Key:

Formation/Unit Top Inferred Top Unit Top Sampled Well Figure 3. Cross section AeA0 showing the stratal geometries of the Triassic sediments along depositional dip in the study area. The datum is the top of the Halfway Formation. See Figure 1 for cross-section location.

B Southeast D-10-C-93-P-8

Northwest D-61-I-93-P-7

8-26-77-19

11-7-78-20

16-35-78-21

1-10-82-23

10-22-84-25

GR (GAPI)

GR (GAPI)

GR (GAPI)

GR (GAPI)

GR (GAPI)

GR (GAPI)

GR (GAPI)

0

0

0

0

0

0

0

150

150

150

150

Halfway Fm Doig Fm Doig Phosphate

? Montney Fm - Shale Member

150

150

B`

150

Halfway Fm Doig C

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Montney Fm Siltstone-Sandstone Member

Doig B Doig A

Montney Fm Montney Fm Siltstone-Sandstone Member

Key:

Formation/Unit Top Inferred Top Unit Top Sampled Well Figure 4. Cross-section BeB0 showing the stratal geometries of the Triassic sediments along depositional strike in the study area. The datum is the top of the Halfway Formation. See Figure 1 for cross-section location. 59

60

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Figure 5. Structure maps to the top of the Montney (A) and Doig (B) formations. Surface dip to the southwest for both formations. Depths are in metres.

and finer-grained sections of Doig B and C. Other minerals include framboidal and euhedral pyrite and apatite. All wells show an inverse relationship between quartz and carbonate trends, for example, in well 11-7-78-20W6 the quartz content increases from the Doig A to the base of the Halfway Formation and the carbonate content decreases towards the base of the Halfway Formation (Fig. 9). In well 11-7-78-20W6, carbonate is observed in thin sections as either silt-sized detrital grains, cements or euhedral crystals (Figs. 10 and 11). The Doig A and the basal portion of Doig B are carbonate-rich although carbonate varies locally (Fig. 9). Higher illite contents are found within the top portion of Doig A (Figs. 10C and 11A) and the lower (finer-grained) portions of Doig B and C (Fig. 10B). The highest feldspar content is located in the Doig A interval with 11-7-24 (Fig. 10B and E) and 11-7-16 (Figs. 10F and 11D) containing the highest feldspar content. A large variation in carbonate, feldspar and illite contents occur between closely spaced samples in the Doig A of 11-7-78-20W6 well (i.e., 20 cm apart, 11-7-31 to 35; Fig. 9, Table 1) which illustrates the small-scale mineralogical changes within the reservoir. For instance, 11-7-33 (Fig. 10D) contains high carbonate content and low quartz and clay content with 11-7-34 (Fig. 10C) containing approximately half the carbonate content and quadruple the clay content. The change in

the mineral profiles between the Doig A and the rest of the core could be due to the increase in sampling density (Fig. 9). Quartz content in the 16-2-78-22W6 shows abrupt variations between 15 and 25% throughout the profile (Fig. 12). The carbonate content increases from the base of the Montney Formation to the top of Doig A with several large peaks at 3118 m and 3075 m. Doig A has a lower quartz and feldspar contents and higher carbonate content compared to the Montney Formation. The carbonate content of the Montney Formation in 16-2-78-22W6 well is composed of cement and euhedral authigenic dolomite (Figs. 10G and 11E and F), as detrital calcite scattered throughout (16-2-26; Fig. 10H) or concentrated in lenses. In 6-28-78-19W6 well the quartz content decreases from the Montney Formation to the top of Doig A. Two pairs of samples from the 6-28-78-19W6 well are sampled approximately 5 cm apart from each other at the depths of 2604.69 and 2604.74 m (Table 1). Samples 6-28-4 (Figs. 10I and 11G) and 6-28-5 (Figs. 10J and 11H) show a large difference in the calcite content; 32% and 13%, respectively. These samples have similar quartz contents but higher clay and feldspar contents within the calcite-poor 6-28-5 compared to the higher-calcite content sample (6-28-4). The higher calcite content in 6-28-4 is due to shell fragments and calcite cement (Figs. 10I and 11G).

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

61

between the pycnometry- and porosimetry-derived porosity for the 15-34-80-18W6 well. Average pycnometry-derived porosity for 16-2-78-22W6 well is 5.5% with porosity ranging between 3 and 8.5% and the average porosimetry-derived porosity is 4.4%, ranging between 3 and 5.8% (Fig. 12). Above average porosimetry-derived porosity is more common within the Montney Formation than Doig A while the pycnometry-derived porosity values alternate above and below average throughout both units. 16-2-78-22W6 well shows a separation between the porosimetry- and pycnometry-derived porosity within Montney Formation and Doig A. For 6-28-78-19W6 well, the average pycnometry-derived porosity is 6.2% and the average porosimetry-derived porosity is 5%. The pycnometry-derived porosity ranges between 3.9% and 8.2% and between 2.5% and 7.2% for porosimetry-derived porosity (Table 1). Both the pycnometry- and porosimetry-derived porosities show the same down-hole trend decreasing from the Montney Formation and into the lower section of Doig A (Table 1). The Montney Formation has above average porosity with the exception of 6-28-4 and Doig A samples are below average. A large difference in porosity values occur between closely-spaced (w5 cm) samples of Doig A (6-28-4 and 5; Table 1) illustrating the heterogeneity of the reservoir on a centimetre scale and below geophysical log resolution. The porosity difference between these two samples (6-28-4 and 5) is due to the difference in carbonate contents (32%e13%) with the more calcite/ankerite-rich sample (6-28-4; Fig. 11G) having the lower porosity than the more calcite/ankerite-lean sample (6-28-5; Fig. 11H). Positive correlations exist between porosity and quartz content and between porosity and quartz plus feldspar for all wells (Table 2). All wells show a negative correlation between carbonates and porosity, except for 15-34-80-18W6 (Table 2). Figure 6. Isopach map of the upper Montney Shale Member. The upper Montney Shale Member increases in thickness (m) towards the west and southwest.

The Pearson productemoment correlations show the strongest relationships between carbonates (calcite, ankerite and dolomite) and quartz; and between illite and pyrite (Table 2).

4.3. Porosity analysis Porosity was determined by helium pycnometry and mercury porosimetry with the former measuring pore sizes greater than the kinetic diameter of helium (0.26 nm) and the latter restricted to pore sizes greater than 3 nm. Any differences seen between these two methods (i.e., pycnometry-derived porosity > porosimetry-derived porosity) are an indication that there are pores within the size range of 0.26e3 nm. The reduction in porosity from porosimetry results will include the volume loss from pore compression under high confining pressures (i.e., 60,000 PSI). Pycnometry-derived porosity for 11-7-78-20W6 well varies between 1.6 and 6.7% with an average of 4.2% and porosimetryderived porosity varies between 1.9% and 6.5% with an average of 3% (Fig. 9). The two porosity profiles show a large difference within Doig A and C, indicating an increase in the fine meso- and microporosity within these intervals. Above average porosimetryderived porosity occurs within the coarser sections of the Doig Formation, at the base of Doig A and at the top of Doig B and C. The Halfway Formation and finer-grained intervals of Doig A, B and C have below average porosity (Fig. 9). Porosity ranges from 1.5% to 7% with an average porosity of 4.2% for 15-34-80-18W6 well and a large variation exists within the porosity of Doig A and B (Table 1). There is only a small difference

4.4. Pore size distribution (PSD) and surface area analysis Pore size distribution (PSD) is determined by mercury intrusion pore volume for 11-7-78-20W6 (Fig. 13A and B), 16-2-78-22W6 (Fig. 13C) and 6-28-78-19W6 (Fig. 13D). The Montney Formation and Doig A in all wells show similar bimodal PSD with high volume of pores within the 10,000 to 100,000 nm (10e100 mm) macropore size range and within the 3e50 nm mesopore size fraction (Fig. 13). Variation of the proportions of macro- and meso-pores exists between samples. Samples from Doig B and C and Halfway Formation have smaller proportions of mesopores compared to the Montney Formation and Doig A samples. Siltstones and very fine sandstone samples (i.e., 11-7-16; Fig. 13B) from Doig A also contain lower proportions of mesopores compared to finer-grained samples (i.e., 11-7-19). The bulk density measured from the porosimeter is less than 4% difference from the bulk density calculated from mercury immersion indicating that little to no void spaces between crushed shale grains contribute to the pore volumes in the 100,000e1,000,000 nm (100e1000 mm) size fraction. Samples that contain a greater proportion of the pore volume within the mesopore size fraction tend to have higher total pore surface areas (i.e., 16-2-30 and 6-28-4 and 5; Table 3). The macropore size fraction does not significantly contribute to the pore surface area in comparison to mesopores and fine macropores. For example, samples 11-7-42 and 11-7-16 have the lowest pore surface areas (Table 3) and have only small volumes of mesopores compared to macropores (Fig. 13A and B). Subtle differences in pore volumes within the mesopore size fraction can result in significant differences in the pore surface areas. For instance, 16-2-26 has a greater proportion of coarser mesopores than the 16-2-30 which results in 16-2-30 having a greater surface area (Fig. 13C: Table 3).

62

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Figure 7. Isopach maps for both the Doig Formation (A) and Doig A (Doig Phosphate Zone; B). Similar to the upper Montney Shale Member, the Doig Formation and the Doig A interval both increase in thickness towards the west and southwest. Black squares represent well locations and the numbers in B represent the thickness of Doig A. Units in metres.

Figure 8. Ternary diagrams illustrating the mineralogical differences between the four wells 16-2-78-22W6, 6-28-78-19W6, 11-7-78-20W6 and 15-34-80-18W6 (A) and between the Halfway, Doig A, B, C and Montney formations in well 11-7-78-20W6 (B). Data is normalised to quart, carbonate and clay contents. Samples are either enriched in carbonate, quartz or moderate volumes of both. Clay contents are moderate to poor.

Well Name : 11-07-078-20W6

GR (GAPI) 0

150

Mineral Content (%)

Sample # 46

20

40

60

Mineral Content (%) 80

0

10

20

Porosity (%) 30

2

4

6

Permeability (Methane: mD)

TOC Content (%) 8

1

2

3

4

5

6

8 7 1.0E-07

1.0E-06

1.0E-05

1.0E-04

1.0E-03

Depth (m)

2650

45 44

Halfway

(TOC at detection limits)

2675

43 42 41 40 39 38 37 36 35-31 30 29-25 24 23-19 17 18 16 15

2700

Doig C

2725

Doig B 2750

2775

Doig A 11-7-21

2800

2825

11-7-20

Apatite Pyrite

Quartz Carbonate

Illite Feldspar

Montney Porosity (He) Porosity (Hg)

Figure 9. Mineralogical, porosity, TOC content and permeability trends for the 11-7-78-20W6 well. Depth is in metres. Carbonate includes calcite, dolomite and ankerite. Higher gamma ray response within the Doig A is due to higher contents of clay (illite) and TOC. For porosity profiles, the dotted line represents the average porosimetry derived porosity and the dashed line represents the average pycnometry derived porosity. Samples are oven dried to compare between methods as samples cannot be moist for porosimetry (i.e., Sw ¼ 0). For the TOC profile, TOC contents were below the detection level of the Rock Eval II apparatus for samples within the Halfway Formation and Clean Doig member and are not included. Dashed line represents the average TOC content of 3.2 wt%. Higher gamma response is due to the higher contents of TOC and clay (illite). TOC contents below 0.5% are considered to be unreliable to publish (greyed area). For the permeability trends, small-scale changes occur in permeability measurements within the Doig A interval which reflects small-scale changes in the mineralogy and TOC contents. Filled circles represent sample location.

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

0

63

64

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

Figure 10. Optical mineralogy of selected samples from the 11-7-78-20W6, 16-2-78-22W6 and 6-28-78-19W6 wells. Some samples (Figs. A, B, C, and I) have been stained for carbonates (alizarine red S solution) and feldspars (amaranth solution). A. Pervasive calcite (Ct) cement within a Halfway Formation sample, Qz ¼ quartz. B and C. Detrital grains of feldspar (Fd), calcite (Ct) and dolomite (Dm) are common within the finer-grained portion of the Doig C and A intervals. D. Calcite filled fractures are observed and cross-cut organicrich (Om) parts of 11-7-33 sample. E. Apatite grains concentrated in lens in Doig A sample. F. Carbonate rich sample from Doig A which shows a low gamma ray value (refer to gamma ray profile in Fig. 9) due to a low concentration of clay and organic matter. G. Sub-angular to subrounded quartz grains (Qz) are common within all intervals and good examples are observed in 16-2-26 sample. Detrital calcite (Ct) is common within this sample as well. H. Organic matter (pyrobitumen in this case; Om) has filled majority of pore spaces within the 16-2-30 sample. A euhedral dolomite grain is also present which shows signs of some transportation (Dm). I. Shell fragments (Sh) and transverse section through spine (centre) are common in 6-28-4 as well as quartz (Qz) and feldspar (Fd) grains. J. Alternation of calcite (Ct) rich laminae and organic rich (Om) laminae. (For interpretation of the references to colour in this figure legend, the reader is referred to the web version of this article.)

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

65

Figure 11. Back-scattered electron images for a selection of Doig and Montney formations samples from the 11-7-78-20W6, 16-2-78-22W6 and 6-28-78-19W6 wells. A. Organic rich sample which discrete laminae of organic matter (pyrobitumen, Om) and elongated grains of calcite (Ct) and muscovite (It) which creates a preferred orientation to the sample’s fabric. B. Sub-rounded quartz (Qz) grains and euhedral dolomite (Dm) grains that show some transportation. Apatite (Ap) is filling pore spaces between quartz grains. Feldspar (Fd) and muscovite (It) grains show minor transportation. C. Clasts include quartz (Qz), feldspar (Fd), calcite (Ct) and dolomite (Dm) detrital grains with large muscovite lath (It). The matrix is clay-rich in this sample with some pore (P) spaces. D. Interlaminated siltstone that contains calcite (Ct) cemented upper and lower laminae with a higher porosity lamination in between due to the lack of a calcite cement. E. Detrital calcite is common within 16-2-26 and no calcite cement is observed. F. Apatite (Ap) dominates 16-2-30, coating dolomite (Dm) grains, as discrete grains and finely disseminated throughout the sample. G. Pervasive calcite cement (Ct) infilling all intergranular spaces resulting in lowering porosity in this sample. H. Calcite cement has in filled intergranular spaces within a laminae of 6-28-5. The rest of the photomicrograph is composed of illite-rich matrix that has not be cemented by calcite. A well rounded dolomite (Dm) grain indicates that some dolomite has travelled further than the more typical dolomite grains.

From the gas adsorption analyses, the PSD is shown for micropores to macropores (<300 nm) for a selection of samples (Fig. 14). The proportion of the pore volume that is contained within the micropore size fraction varies from 15% to 58% and between 20 and 56% for the macropore size fraction (50e300 nm). Samples that

have a high proportion of the total pore volume within the micropore size fraction have higher CO2 adsorption surface area (Table 3) and higher TOC and clay contents compared to samples that have a lower micropore volume (Fig. 14; see Discussion for details).

66

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

0

GR (GAPI)

Well Name :16-2-78-22W6

150

Sample #:

Mineral Content (%) 0

20

40

Mineral Content (%)

600

20

40

TOC Content (%)

Porosity (%)

60

2

6

4

8

10

2

4

6

8

10

2980

1 4

Doig A

3020

12

22 26 30

Depth (m)

3060

35 37 40

3100

Montney

42

3140 47

52

3180 Quartz

Apatite

Illite

Carbonate

Pyrite

Feldspar

Porosity (He) Porosity (Hg)

Figure 12. Mineralogical, porosity and TOC content profiles for 16-2-78-22W6 well with sampling covering the Montney Formation and Doig A interval (Black arrows). The Doig A is not always enriched in phosphatic minerals as indicated by the low apatite content. For the porosity trends, dashed line represents the average porosimetry-derived porosity and the dotted line the average pycnometry-derived porosity. For the TOC Content profile, the dotted line in the TOC content down-hole profile is the average TOC content of 4%. Black arrows represent approximate location of samples in well.

4.5. Organic geochemistry of the upper Montney and Doig formations The TOC content ranges between 0.5 and 8.6 wt% with an average between 2.8 and 4 wt% for all three wells (Figs. 9 and 12; Table 1; no data for 6-28-78-19W6 well). The hydrogen index (HI) averages 29 mg HC/g TOC and ranges between 1 and 66 mg HC/g TOC with the oxygen index (OI) averaging 24 mg HC/g TOC and ranging between 5 and 172 mg HC/g TOC (Fig. 15). The average Tmax value is 457
C and ranges between 443 and 478
C (Table 1) placing the reservoirs beyond the oil window and into gas generation. The average equivalent vitrinite reflectance for pyrobitumen (Equation (1)) from the 11-7-78-20W6, 16-2-78-22W6 and 6-28-78-19W6 wells is 2.058% which is higher maturity than estimated by Tmax values but still at maturities that gas is produced. The discrepancy between Tmax and the equivalent vitrinite reflectance data may be due to Equation (1) being calculated from empirical data. Samples from the Halfway Formation and the top of Doig C have TOC values below the detection limits of the Rock Eval II analysis (<0.5 wt%) and are not included in the profile. The TOC content shows high variability throughout Doig A in 11-7-78 well (Fig. 9). For example, with a sampling distance of only 20 cm, the TOC content changes from 1.3% in 11-7-33 (Fig. 16A) to 7.2% in 11-7-34 (Fig. 16B). Pyrobitumen is the major component (average of 91%; i.e., Fig. 16) of the TOC content in all four wells with minor contributions from inertodetrinite (4%), fusinite (trace) and micrinite (0.4%; Fig. 16D). Pyrobitumen occurs within the matrix of the

reservoir and surrounds detrital clasts and authigenic minerals (Fig. 16B). The pyrobitumen commonly exhibits degassing pores and flow textures (Fig. 16E). Pores at this scale (5e30 mm) are common in kerogen that is either oxidised Type IV kerogen (i.e. fusinite), cell lumens in Type III kerogen (i.e. semi-fusinite) and in devolatilised pyrobitumen (Taylor et al., 1998). For the 11-7-78-20W6, a positive correlation exists between TOC and pyrite and negative trend exists between quartz and TOC content (Table 4). For the 15-34-80-18W6 well, a positive relationship exists between the TOC content and illite content (Table 4). 4.6. Pulse-decay permeability Permeability measured by pulse-decay permeameter indicates variability over a number of magnitudes (Fig. 17). Effective stress varies between wells with 3300 PSI for 11-7-78-20W6 and 2900 PSI for 15-34-80-18W6 well (16.5e22.8 MPa). For the 15-34-80-18W6 and 11-7-78-20W6 wells, the matrix permeability ranges between four orders or magnitude e 1.0E-3 to 6.5E-7 mD (Fig. 17). There are no clear relationships between lithology and matrix permeability values. Two orders of magnitude difference occurs in matrix permeability between 11-7-16 and 117-19 (Fig. 9) and this is, in part, interpreted to be due to the difference in their PSD (see discussion for details). The highest matrix permeability in 11-7-78-20W6 well is located at the top of Doig B and scattered throughout Doig A with permeabilities being

Table 2 Pearson productemoment correlation matrix for the mineralogical trends. N1 ¼ Number of data points compared between mineral contents and N2 ¼ Number of data points between porosity and mineral values.

11-7-78-20W6 15-34-80-18W6 16-2-78-22W6 6-28-78-19W6

N1

Carbonates and quartz

Illite and pyrite

Illite and carbonate

N2

Porosity and quartz

Porosity and quartz þ feldspar

Porosity and carbonate

32 8 52 7

0.71 0.54 0.81 0.47

0.74 0.63 0.12 0.47

0.11 0.53 0.67 0.81

15 8 52 7

0.58 0.84 0.61 0.84

0.59 0.66 0.57 0.76

0.55 0.35 0.61 0.78

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

67

B

A

C

D

Figure 13. The pore size distribution for 11-7-78-20W6 (A and B), 16-2-78-22W6 (C) and 6-28-78-19W6 (D) wells using the incremental pore volume (mL/g). Dashed line indicates the 2 nm meso-/micropore boundary and the solid line demarks the meso-/macropore boundary at 50 nm. Bulk density from the porosimeter is less than 2% difference with the bulk density calculated from mercury immersion indicating that no intergranular porosity from the crushed sample is contributing to the pore volumes in the 10,000e1,000,000 nm (10e1000 mm) size fraction. Matrix permeability is also shown for some samples. Sample location can be found in Figure 2.

two orders of magnitude greater than the lowest permeabilities. Permeability between closely spaced samples (20 cm) can vary significantly, for example, the matrix permeability varies from 7.7E07 to 3.0E-05 mD between 11-7-20 and 11-7-21, respectively Table 3 Pore surface area by porosimetry and surface area measurements by gas adsorption analysis. Porosimetry-derived pore surface area measures meso- and macro-porous surface area with CO2 gas adsorption surface area measuring the microporous surface area. Sample ID

Interval

Porosimetry pore surface area (m2/g)

CO2 adsorption surface area (m2/g)

11-7-16 11-7-19 11-7-26 11-7-27 11-7-29 11-7-33 11-7-38 11-7-39 11-7-42 16-2-26 16-2-30 6-28-5 6-28-4

Doig A Doig A Doig A Doig A Doig A Doig A Doig B Doig B Doig C Montney Montney Montney Montney

1.3 e 3.4 4.0 3.3 2.9 e 1.9 1.1 3.4 6.8 7.9 9.1

5.2 e 18.7 19.1 16.6 6.1 4.7 5.0 13.8 3.6 19.5 6.9 2.8

(Fig. 9). Permeabilities for 15-34-80-18W6 (Fig. 17) are in the same order of magnitude as the highest permeabilities from the 11-7-7820W6 well (i.e., 1.0E-04 mD). For comparison, high permeability for this study is consider greater than 8E-05 mD with low permeabilities consider less than 1E-05 mD. No significant trends are found between the mineralogy and permeability except quartz plus feldspar contents. Samples that contain greater than 65% total quartz plus feldspar have high permeabilities while samples that contain less than 65% vary between low and high permeabilities (1.0E-3 to 6.5E-7 mD; Fig. 18). Although samples with the highest permeabilities (11-7-16, 11-724, 15-34-4 and 15-34-8) have quartz plus feldspar contents less than 65%. These samples have moderate amounts of carbonate, quartz and feldspar and low clay contents (<6%).

5. Discussion 5.1. Sedimentological and structural controls on the reservoir thickness This section discusses the cross-sections and maps constructed from geophysical wells (Figs. 3e7) with previous work summarised in the geological background (Section 2). The structure to the top of

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Figure 14. Cumulative N2 and CO2 gas saturation for a selection of samples from the 11-7-78-20W6 and 15-34-80-18W6 wells. TOC and clay contents are shown for each curve and high permeability samples are highlighted with an asterisk and curves are in black. Samples that contain a higher proportion of mesopores (i.e., 6-28-5) have higher pore surface area and lower microporous (CO2) surface area than samples that contain high proportion of micropores (i.e., 11-7-26 and 34). TOC contents are shown in Figures 9 and 12; Table 1. All data is from the Doig Formation except 15-34-8, 6-28-4, 6-28-5 which are form the Montney Formation.

both the Montney and Doig formations (Fig. 5) consists of surfaces that dip to the southwest and the thicknesses of both formations increasing in the same direction (Figs. 6 and 7). The decrease in stratal thickness to the northeast of the study area is due a reduction in accommodation space towards the shoreline of the passive continental margin (Kent, 1994; Davies, 1997). The Montney, Doig and Halfway formations were deposited during second-order

Figure 15. Modified van Krevelan diagram cross-plotting the hydrogen (HI) and oxygen (OI) indices derived from Rock Eval II analyses. Rock Eval pyrolysis was not performed on 6-28-78-19W6 well. Majority of data plot near the origins indicating kerogen is either oxidised plant material prior to deposition or is a carbon-rich residual resulting from hydrocarbon generation.

marine transgressioneregression couplets. Davies (1997) further suggests that the Montney Formation was deposited within a series of four third-order TeR couplets with the upper Montney Shale Member deposited during the last three TeR couplets. These thirdorder transgressions resulted in a shale-rich upper Montney compared to the underlying SandstoneeSiltstone Member. The Doig Formation was initially deposited in deeper marine conditions with the thicknesses of both the Doig A and the Doig Formation showing irregular development with areas of greater thicknesses juxtaposed against areas of thinner strata. There are two plausible explanations for the thickness variation of Doig A and the Doig Formation e 1) shelf exposure and erosion causing irregular topography prior to deposition or 2) pre- and/or syn-depositional faulting of the basement during the development of the graben complex giving rise to irregular topography. Using the palaeogeographic reconstruction by Kent (1994), the thickness variation across the study area is possibly due to depressions along the shallow shelf environment; inherited from the sequence boundary after the deposition of the Montney Formation. Evidence of truncation (Dixon, 2000) and development of a sequence boundary (Harris and Bustin, 2000) below the Doig A indicate exposure and erosion. This hiatus may have resulted in a highly irregular palaeosurface during the Doig transgression resulting in the thickness variation of Doig A across the shallow shelf environment (Fig. 7B). During the initial transgression, organic-rich muds and phosphates would have initially developed in the palaeolows on the irregular seafloor with bottom currents redistributing any sediment on the flanks into the palaeolows (i.e., expanding puddle model; Wignall, 1994). Intra-slope basins and shelf slumps within the shelf margin have been postulated for the preservation of the anomalously thick sandstone unit in the Buick field in northeastern BC (Dixon, 2009b) and these intraslope basins may also aided the development of thicker organic-rich phosphatic shale. The variation in stratal thickness across the study area could also be due to syndepositional faulting as observed by Zonneveld et al. (2010) within the Williston Lake area, west of the study area. The isopach map of Doig A shows a thinning of strata within the Groundbirch Graben but some wells show stratal thickening within the graben complex (i.e., 16-2-78-22W6 and 1-10-82-23W6; Figs. 1

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69

Figure 16. Petrographic characteristics of the Doig and Montney samples from the 11-7-78-20W6 and 16-2-78-22W6 wells. Oil immersion, plane white light, 40x objective. Symbols used within photomicrographs are: quartz grains (Qz); matrix (Mx); pyrobitumen (Om); inertodetrinite (In); carbonate (Ct); flow texture (Ft); feldspar grain (Fd); and degassing pore (Dp).

and 7B). This may indicate that syndepositional faulting is restricted to the west of the study area or faulting was only active in some parts of the graben complex during the deposition of the Doig Formation. 5.2. Sedimentological and diagenetic controls on mineralogy Mineralogical and depositional environmental interpretations are made using a combination of bulk mineralogy from X-ray diffraction analyses and observations from plane light and BSE microscopy of thin sections. Doig A is carbonate- or clay-rich and quartz poor with the Montney, Doig B and C being quartz-rich and carbonate/clay-poor (Figs. 9 and 12). The contrasting mineralogical character of the quartz-rich Doig B and C and (detrital) carbonaterich Doig A in well 11-7-78-20W6 indicates a change in the sedimentary environment, accommodation space and/or tectonic activity within the study area as the depositional conditions shift

Table 4 Pearson productemoment correlation co-efficient for TOC and mineralogy and porosity. N is the number of data points. Well ID

N

TOC and pyrite

TOC and quartz

TOC and illite

11-7-78-20W6 15-34-80-18W6 16-2-78-22W6

29 8 37

0.68 0.18 0.42

0.56 0.27 0.13

0.34 0.68 0.33

from carbonate deposition to clastic deposition. A greater influx of clastics in the upper Doig and Halfway formations is either due to increase tectonic activity or a reduction in accommodation space (shoreline progradation) as a sea level regression progressed. Diagenetic calcite cement is locally present with the Halfway Formation (Fig. 10A). Clay deposition occurred when quartz and feldspar influx is low and pyrite deposition was high. The high (framboidal) pyrite content indicates the wateresediment interface was depleted in oxygen during periods of clay deposition or during early diagenesis. Less detrital carbonate influx occurred during clay sedimentation as indicated by the strong negative correlation between illite and carbonate contents. Exceptions to these trends occur as not all carbonate deposition is detrital but also occurs as diagenetic cements. Mineralogical differences between closelyspaced samples (i.e., 5 cm apart, 6-28-4 and 5; and 20 cm apart, 11-7-31 to 35) highlight the small-scale heterogeneity of the Montney and Doig reservoirs and this heterogeneity needs to be considered when assessing down-hole trends in mineralogy. 5.3. The effects on porosity and PSD by TOC and mineral contents Intervals that exhibit a separation between porosity trends determined from pycnometry and porosimetry indicate the presence of pore sizes below 3 nm (microporosity plus some fine mesoporosity). Greatest separation occurs within the TOC- and clay-rich Doig A interval and the basal section of the Doig C interval.

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Figure 17. The relationship between matrix permeability (methane) and sum of quartz and feldspar contents to illustrate the large range of permeabilities that exist between samples. Effective stress ranges between 2400 and 3300 PSI (16.5e22.8 MPa) and was calculated using the Eaton Equations (1) and (2). Effective stress varies between wells with 3300 PSI for 11-7-78-20W6 (11-7) and 2900 PSI for 15-34-80-18W6 well (15-34).

Gas saturation curves (Fig. 14) further illustrate that the proportion of micropores compared to the total porosity increases with increasing TOC and clay content. Not all samples within the Doig A have a high proportion of micropores (i.e. 11-7-33; Fig. 14) which is due to high carbonate and low TOC and clay contents. The positive correlation between porosity and the quartz plus feldspar contents indicates intergranular porosity is an important component of high porosity samples. The negative correlation between porosity and carbonate content coupled with thin section observations, indicate porosity is low due to carbonate cementation (Table 2; Figs. 10A, D and 11D, E, G and H) but not all low porosity samples have high carbonate contents (i.e., clay-rich 11-7-42). Carbonate cementation of the pore network is responsible for the

Figure 18. Mineralogical ternary plot showing the difference between high and low matrix permeabilities from the 11-7-78-20W6 and 15-34-80-18W6 wells. Permeabilities >1.06E-4 are considered high while values <1.98E-5 are considered low. Samples that contain greater than 65% quartz plus feldspar have high matrix permeabilities with samples that contain less than 65% can vary between high and low permeabilities.

porosity reduction within the Halfway Formation (11-7-45; Fig. 10A) and Doig A (i.e. 11-7-16; Fig. 11D) with a high carbonate content and low porosity (Fig. 9). The detrimental effect calcite has on porosity is also illustrated by the difference between two closely-spaced (w5 cm) samples from the 6-28-78-19W6 well (6-28-4 and 5) as the lower porosity sample contains a greater amount of calcite cement. Calcite cement is observed between dolomite (16-2-26, 11-7-24, 6-28-4; Fig. 11) indicating that porosity destruction within the Doig and Montney formations is not from dolomitisation but from calcite cementation. A PSD which has a higher volume of macropores, larger mesopore apertures and lower total pore area is more common in intervals with higher quartz plus feldspar and lower TOC and clay contents (i.e., Doig C) compared to lower quartz, higher clay and TOC content samples (i.e. Doig A; Fig. 13). Mineralogy affects the PSD, for example, the illite content has been shown to increase porosity in the mesopore size fraction (Chalmers and Bustin, 2008) and higher mesopore volumes are found within illite-rich samples compared illite-poor samples (Fig. 13D). Siltstone samples contain higher proportions of meso- and macro-pores and less fine mesopores compared to shaly samples. Siltstones in 16-2-78-22W6 well have greater clay content and lower quartz content than the very fine sandstone samples which results in the siltstone having greater surface area and less coarse mesopores than the very fine sandstone (Table 3; Fig. 13C). Within Doig A, 11-7-16 and 11-7-33 samples show large pore volumes at 100 nm (0.1 mm) and the pore volume decreases towards the boundary of the micro-/mesopore size ranges (Fig. 13). Both 11-7-16 and 11-7-33 are siltstones and differ to the other samples (mudstones) within Doig A and this results in the lowest total pore surface areas (Table 3), Majority of the shaly samples from the Montney Formation and Doig A show high micropore surface area from the gas adsorption analyses (Table 3) with greater than 50% of the total pore volume is from the micropores size fraction (Fig. 9). 5.4. Influences on the TOC distribution The maturity of the Montney and Doig formations is beyond the oil window and gas would have been produced. All macerals in this study do not fluorescence in blue light and coupled with low HI and OI values indicate the kerogen has experienced a high degree of hydrocarbon generation or the kerogen is originally oxidised plant material or a combination of both. Kerogen is defined as organic matter is insoluble by organic or alkaline solvents (Tissot and Welte, 1984). The dominance of pyrobitumen in the TOC rich intervals suggests both the Montney and Doig reservoirs had converted majority of primary kerogen into migrabitumen (Jacob, 1989) with a proportion retained within the matrix and further degraded into pyrobitumen. The presence of secondary pore development with the pyrobitumen (Fig. 16E) is likely from secondary cracking of retained oil (migrabitumen) to gas. The minor amount of primary kerogen in the reservoir suggests either most of the primary kerogen was converted to bitumen or the bitumen is allochthonous and has migrated from other sources. The positive correlation between pyrite and TOC content and the negative correlation between quartz and TOC content indicates kerogen was deposited and then converted to oil/bitumen within the reservoir. The variability in TOC richness between closelyspaced samples (20 cm) is due to changes in depositional environment of the organic matter. There is still the possibility that some of the pyrobitumen is from migrated sources within the selfsourcing reservoir system. The Doig Formation has a greater TOC content than the Montney Shale Member (16-2-78-22W6 well) due to the Doig transgression which increased accommodation space, reduced clastic input and

G.R.L. Chalmers, R.M. Bustin / Marine and Petroleum Geology 38 (2012) 53e72

increased in organic matter preservation by the depletion of oxygen at the sedimentewater interface. Doig A contains the highest TOC contents (i.e., Fig. 16B and E), the lowest quartz contents and the highest content of carbonate and/or clay (Fig. 10C and D). This observation is highlighted by the negative correlation between quartz and TOC contents (Table 4). The positive correlation between TOC and pyrite indicate the sedimentewater interface was depleted in oxygen during organic deposition and was more common within Doig A. Units with higher TOC contents (i.e., 11-726 in Doig A; TOC of 6.7 wt%) contain greater surface area than TOClean members (i.e., 11-7-39 in Doig B; TOC of 0.7 wt%; Table 3) and also a greater portion of porosity in TOC-rich samples is within the micropore size fraction (Fig. 14). Microporous surface area is found to increase in more thermally mature residual TOC and this surface area provides storage for gas in the sorbed state within the reservoir (Chalmers and Bustin, 2008). 5.5. Controls on matrix permeability PSD is influenced by mineralogy and TOC contents. The PSD controls the matrix permeability of the Doig and Montney reservoirs. Higher matrix permeability (>8E-05 mD) is located within the Doig C, upper portion of Doig B and with small-scaled variation between high and low (<1E-05 mD) permeabilities in Doig A interval. The difference between the high (>8E-05 mD) and low (<1E-05 mD) permeabilities of samples from 11-7-78-20W6 and 15-34-80-18W6 wells is due, in part, to the mineralogy; with quartz plus feldspar rich samples (>65%) all having high permeabilities (Fig. 9). The highest permeability samples do, however, have quartz plus feldspar contents below 65%. No relationship exists between the TOC content and permeability. High permeability samples have TOC values ranging between 0.5 and 7.2% (Fig. 14). Pore size distributions are compared between samples that differed in matrix permeability by two orders of magnitude in Figure 13B. The higher permeability sample, 11-7-16, has a greater proportion of pores at the meso-/macropore boundary compared to 11-7-19 which contains a greater volume of pores at the micro-/ mesopore boundary. Both high and low permeability samples have bimodal pore size distribution. The low permeability samples have a greater degree of separation between the two populations of pore sizes (i.e., four orders of magnitude; 11-7-19) than higher permeability samples (three orders of magnitude; 11-7-18), suggesting high permeability samples have a greater degree of communication within the matrix. Higher permeability samples have more balanced ratio between micro-, meso- and macro-pores (Fig. 14), similar to the PSD seen within the high permeabilities samples of the Devonian Horn River Shales in northeastern BC (Chalmers et al., 2012). It is postulated that the equal distribution between micro-, meso- and macro-pore size fractions provides a greater interconnectedness within the shale matrix (Chalmers et al., 2012). Samples that contain either a higher proportion of macropores or micropores tend to have low permeabilities. 5.6. Gas distribution within the Doig and Montney reservoirs Within the Montney/Doig reservoirs, gas is distributed as either sorbed, free, solution gas or a combination of these three components. Down-hole trends for porosity and PSD show a high degree of heterogeneity between intervals (i.e., Doig A, B and C). These changes will affect the ratio between sorbed and free gas contents within the reservoir. Finer-grained, TOC-, carbonate- and clay-rich intervals (i.e., Doig A) contain higher volumes of fine mesopores/ micropores and lower volumes of macropores which increase the surface area and results in a larger sorbed gas component (Chalmers and Bustin, 2012) compared to the coarser grained,

71

quartz plus feldspar-rich, TOC- and clay-poor intervals (i.e., Doig C). The coarser-grained, quartz plus feldspar-rich intervals will have a larger free gas component and with the higher matrix permeabilities, will be more easily produced. 6. Concluding remarks The evaluation of the Doig and Montney reservoirs within the Groundbirch area of northeastern British Columbia were investigated by characterising the mineralogy, porosity, pore size distribution, surface area, organic geochemistry and matrix permeability. Down-hole profiles illustrate the small-scale (below geophysical log resolution) heterogeneity in the mineralogy, TOC content, porosity and permeability. The finer-grained, quartz-poor, TOC-rich, lower-porosity intervals have larger surface areas than the coarser-grained, quartz-rich and TOC-poor intervals. The variation in permeability within the Doig Formation is, in part, by the mineralogy variation, with quartz plus feldspar rich samples having higher permeability than quartz plus feldspar poor samples, although higher permeabilities occur in the latter. TOC contents (pyrobitumen) do not influence the permeability of Doig samples with TOC-rich samples exhibit either high or low permeability. Doig A has a greater microporous surface area and micropore volume than the coarse units of Doig B and C. Higher permeability samples have more balanced ratio between micro-, meso- and macro-porosity compared to low permeability samples which is a similar observation made in the Devonian shales of the Horn River basin (Chalmers et al., 2012). References ASTM D2798-11a, 2011. Standard Test Method for Microscopical Determination of the Vitrinite Reflectance of Coal. ASTM D2799-05, 2005. Microscopical Determination of Volume Percent of Physical Components of Coal. Barrett, E.P., Joyner, L.G., Halenda, P.P., 1951. The determination of pore volume and area distributions in porous substances. I. Computations from nitrogen isotherms. Journal of American Chemical Society 73, 373e380. Berger, Z., Boast, M., Mushayandebvu, M., 2008. The contribution of integrated HRAM studies to exploration and exploitation of unconventional plays in North America, part 1. Reservoir 10, 42e48. Berger, Z., Boast, M., Mushayandebvu, M., 2009. The contribution of integrated HRAM studies to exploration and exploitation of unconventional plays in North America, part 2. Reservoir 36 (2), 40e45. Burke, L.H., Nevison, G.W., 2011. Improved Hydraulic Fracturing with Energised Fluids: a Montney Example. CSPG CSEG CWLS 2011 Convention, 8th to 11th May, 2011, Calgary, Alberta, Canada. Bustin, R.M., 1991. Quantifying macerals: some statistical and practical considerations. International Journal of Coal Geology 17, 213e238. Canada Energy Partners New Release, 2010. Canada Energy Partners Announces Successful Horizontal Montney Test. 6th July, 2010. http://www. canadaenergypartners.com/news/2010/index.php?&content_id¼107. Chalmers, G.R.L., Bustin, R.M., 2007. The organic matter distribution of the Lower Cretaceous strata of northeastern British Columbia, Canada. International Journal of Coal Geology 70, 223e239. Chalmers, G.R.L., Bustin, R.M., 2008. Lower Cretaceous gas shales in northeastern British Columbia, Part I: geological controls on methane sorption capacity. Bulletin of Canadian Petroleum Geology 56, 1e21. Chalmers, G.R.L., Bustin, R.M., 2012. Light volatile liquid and gas shale reservoir potential of the Cretaceous Shaftesbury Formation in northeastern British Columbia, Canada. AAPG 96, 1333e1367. Chalmers, G.R.L., Ross, D.J.K., Bustin, R.M., 2012. Geological controls on matrix permeability of Devonian gas shales in the Horn River and Liard basins, northeastern British Columbia, Canada. Online version. International Journal of Coal Geology. URL: http://www.sciencedirect.com/science/article/pii/ S0166516212001401. Clarkson, C.R., Bustin, R.M.,1996. Variation in micropore capacity and size distribution with composition in bituminous coal in the western Canadian Sedimentary Basin: implications for coalbed methane potential. Fuel 75, 1483e1498. Cui, X., Bustin, A.M.M., Bustin, R.M., 2009. Measurement of gas permeability and diffusivity of tight reservoir rocks: different approaches and their applications. Geofluids 9, 208e223. Davies, G.R., 1997. The Triassic of the western Canadian sedimentary basin: tectonic and stratigraphic framework, palaeography, palaeoclimate and biota. Bulletin of Canadian Petroleum Geology 45, 434e460.

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