Gas Reservoirs, Deep Basin, Western Canada
Authors: McMaster G.E. 
Published: March 2010

Introduction

The "Deep Basin" straddles the Alberta - British Columbia border in front of the over thrust belt in the western edge a/the Alberta Sedimentary Basin, covering some 26,000 square miles (67,000 km2).

Its geology is complex: at least 18 different zones from the 15,000-ft (4600-m) section of clastic rock, ranging in age from Permian to Upper Cretaceous. These multiple stacked gas bearing reservoir sandstones are found downdip of strati graphically equivalent water-bearing zones.

The "Deep Basin" consists of two basic reservoir types: conventional and tight. Conventional reservoirs consist of medium-grained sandstones to conglomerates with porosities of 8% to 12% and permeabilities in the millidarcy to darcy range. Unstimulated flows in the range of 1 million to 28 million cubic feet per day are common (28,000 m3/d to 78,000 m3/d).

The Spirit River Formation, a conventional reservoir, is a thick clastic sequence composed of a series of transgressive marine and regressive coastal/deltaic cycles. The major hydrocarbon reservoirs are mature, pea-sized openwork conglomerates deposited on the beach face during either an initial transgressive event or a regression of a shoreline.

Tight reservoirs or low-permeability fine-grained sandstones (generally less than 100 microdarcies), have porosities In the 4% to 7% range with natural flows of 100 to 750 thousand cubic feet per day (2,800 to 21,000 m3/d).

The Nikanassin Formation, a tight reservoir is a sequence of sands, shales and siltstones and minor coals that thin from west to east. The Upper Nikanassin sands are composed of fine- to medium-grained quartzose sandstones with abundant chert and carbonaceous particles and were deposited on a distal braided plain.

The main characteristic that distinguishes a tight gas sand reservoir from the more common conventional type is its extremely low permeability, requiring a massive hydraulic fracture stimulation for sustained commercial development.

Through fracturing and other technological advances, significant quantities of gas from various tight horizons will be delineated and the "Deep Basin's contribution to Canada's natural gas reserves will be recognized and produced.

Introduction

The largest natural gas field in North America was discovered in 1976 in the "Deep Basin" of Alberta. Many aspects of this area have already been discussed in previous talks at other conventions. John Masters of Canadian Hunter(1) in 1978 postulated that the Deep Basin could contain 440 trillion cubic feet of recoverable natural gas, almost seven times the amount then recognized as recoverable in Alberta and British Columbia. Dave Sandmeyer(2) and Richard Flury(3) of Amoco Canada have discussed the evolution of the word "resource" as distinct and separate from reserves when discussing recoverable natural gas. However, both recognized the importance of the Deep Basin play.

The Deep Basin is located to the east of the disturbed belt along the front of the Rocky Mountain Foothills. It's major portion as shown on Figure 1, is approximately 430 miles (692 km) long and encompasses approximately 26,000 square miles, (6,734,000 hectares). The area outlined indicates Amo