Shale Gas Reservoirs in the Western Canadian Sedimentary Basin a report by


Daniel John Kerridge Ross Geologist, Shell Canada Upstream


Shale Gas in Western Canada


Shale gas exploration and development in the Western Canadian Sedimentary Basin (WCSB) has undoubtedly been accelerated by the continued success of several ‘mature’ US shale basins, including the Fort Worth Basin (Barnett), Michigan Basin (Antrim), Illinois Basin (New Albany) and Appalachian Basin (Utica and Marcellus), to name but a few. The WCSB contains vast thicknesses of fine-grained, organic-rich siliclastic material, ranging in age from Ordovician to late Cretaceous1 with gas resource estimates of over 1,000 trillion cubic feet (TCF).2


Buoyed by success in the US, the push towards unconventional gas over the past five years in Western Canada has been aggressive, with companies spending over CA$6billion on crown land sales in the last two years alone. The primary focus of land sales has been the Devonian Horn River and Triassic Montney plays in northern British Columbia (BC; see Figure 1). These areas attracted over half the total land sale bids in 2009 (compared with Alberta and Saskatchewan). Despite the economic climate, operators continue to evaluate and invest in these areas, in part due to the favourable royalty credits and net profit royalty regimes offered by the BC provincial government. Furthermore, the BC Oil and Gas Commission has approved at least 12 experimental schemes since 2002 that allow operators to hold well data confidential for three years.


The Alberta and Saskatchewan provinces have not seen the activity levels of BC, but trust tax changes and new royalty frameworks and drilling credits in Alberta may provide the impetus for further investment, primarily for shallow gas wells. Prospective shale gas plays do not stop at the Horn River and Montney; other prospective horizons include the Colorado Group shales, Wilrich and Buckinghorse shales, Jurassic Fernie and Nordegg shales and Triassic Doig/Doig phosphate shales.


What Is a Shale Gas Reservoir?


Shale gas systems have historically been defined as low-permeability self-sourcing reservoirs, where gas is generated in situ and retained by sorption on internal surfaces (such as organics or clays) or as free gas in the porosity matrix (‘conventional’ compressed gas in open pores). Shale gas reservoir evaluation has focused on several key geological attributes, including:


• organic content (referred to as total organic carbon [TOC]); • thermal maturity; • water saturation; • porosity; • permeability; • mineralogy; • rock mechanics (fracability); • thickness; • lateral extent; and •


near well-bore and far-field stress regimes. 66


Reservoir cut-offs have often been applied to WCSB shales based on US shale plays in order to discover the next Barnett shale. However, shale gas reservoirs are extremely complex, heterogeneous rocks due to nanoscale variabilities (see Figure 2), and this complexity inhibits the development of reservoir models that can be applied to shale gas systems worldwide. The relationships between shale’s physical properties, gas contents and deliverability in one reservoir are not directly applicable to another.3


Further complications arise due


to the poor definition of a ‘shale gas reservoir’ being used in a broad, generic sense, since shale gas encompasses shales and tight silt/sand plays.


Western Canada


The Devonian–Mississippian shale play in the Horn River Basin (northern BC) provides the closest analogue to Barnett shale and is often touted as the most prolific shale gas play on the continent’. Horn River shales have TOC contents up to 5wt% and vitrinite relfectances >1.5VRo%, making them excellent shale gas candidates.4


Organic-rich shales of


the Exshaw, Besa River and Muskwa formations exceed 100m in thickness and gas-in-place (GIP) estimates exceeding 200billion cubic feet (BCF)/section.


The primary target in the Horn River Basin is the Muskwa shale, which can be organic-rich and highly siliceous (>80% quartz content), creating a reservoir that is both gas-saturated and fracable (due to the favourable mechanical properties of siliceous shales).


However, an inverse relationship between quartz content and porosity in some regions suggests that a balance may be required between a unit with the best propensity for fracture stimulation and one with acceptable GIP for further development.4


Due to the high geothermal


gradients in the region, reservoir temperatures exceed 100°C and gas contents are largely controlled by the free gas component.


To the west of the Horn River Basin (160km north-west of Fort Nelson) lies the relatively unexplored Beaver River area (Liard Basin region). Potential reservoir targets here include the Besa River shales, which range in thickness from 675 to over 1,000m. The upper black shale member is perhaps the most prospective zone within the Besa River package. Thicknesses can exceed 200m and porosities range from 4 to 7%.


However, higher clay contents compared with Muskwa shales may pose completion challenges due to the non-dilative response of ductile rocks.


With increasing land prices in Horn River, small-cap companies are at a disadvantage, especially where large contiguous blocks are posted. EnCana Corporation has been the most active operator in the basin since 2001, with 41 gross wells in the play and at least 13 on production.


© TOUCH BRIEFINGS 2011


Natural Gas


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