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 article info Article history: Received 30 March 2012 Received in revised form 21 July 2012 Accepted 23 August 2012 Available online 7 September 2012 Keywords: Matrix permeability Mineralogy Pore size distribution TOC content Pyrobitumen Surface area abstract 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 uncon- ventional 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 T max 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. 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 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 esti- mated 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 * Corresponding author. Tel.: þ1 604 822 3706; fax: þ1 604 822 6088. E-mail address: gchalmer@eos.ubc.ca (G.R.L. Chalmers). Contents lists available at SciVerse ScienceDirect Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo 0264-8172/$ e see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.marpetgeo.2012.08.004 Marine and Petroleum Geology 38 (2012) 53e72