Figure 1. Pressure distribution for a hydraulic fractured — 0.1md reservoir.
(Graphics courtesy of Fekete)
The depletion of conventional gas reservoirs has shifted the focus of the petroleum industry to unconventional resources. Unconventional gas resources such as coalbed methane (CBM), tight gas, hydrates and shale gas account for a large majority of the remaining gas resources in the world. While CBM and tight gas have been attractive targets for companies operating in Western Canada, shale resources remain relatively untouched.

Western Canada shale gas potential
Assessing the potential of shale gas resources requires an understanding of the geochemistry of the shale. Two geochemical parameters are particularly important: total organic carbon (TOC) content and thermal maturity. The TOC content is used to evaluate the shale’s potential to produce large volumes of hydrocarbons. Thermal maturity measures the conversion of the organic carbon contained in the shale to hydrocarbons. An ideal shale gas play can be identified by finding a proper combination of the TOC content and thermal maturity.

  Figure 2. Distribution of free and adsorbed gas in Shale Play #1.
Preliminary studies of the geochemical and petrophysical properties of the Western Canadian Sedimentary Basin (WCSB) indicate that the basin contains vast quantities of natural gas in shale formations. According to the Canadian Centre for Energy Information the estimated original gas-in-place for five WCSB shales, shown in Table 1, is 860 Tcf.

Shale reservoirs
Shale is a unique gas reservoir for two reasons. First, it acts as both source rock and reservoir rock. This differs from conventional gas reservoirs, which trap gas that has migrated from a source. Second, shale has unique gas storage properties. Gas is stored in the matrix pore volume, like conventional reservoirs, and it is adsorbed on the surface area of the pores, similar to CBM reservoirs. The adsorption capacity of shale is modeled, similar to coal, using a Langmuir isotherm. The isotherm is defined by two properties: Langmuir volume (VL) and Langmuir pressure (PL). The Langmuir volume is the maximum amount of gas that can be adsorbed by the shale at infinite pressure. The pressure needed to adsorb half of the Langmuir volume is referred to as the Langmuir pressure. The distribution of free and adsorbed gas in a shale reservoir depends on initial pressure, petrophysical properties and adsorption characteristics.

Pressure distribution in shales
In order for a significant amount of adsorbed gas to be produced from the shale, the pressure within the reservoir must drop significantly. Shales typically have a matrix permeability in the micro- to nano-Darcy range, which causes the pressure disturbance within the matrix to progress very slowly. A simple simulation was conducted to illustrate this effect (Figure 1).

Figure 1 shows the reservoir pressure profile for a well in a 0.1 md reservoir with a fracture half-length of 500 ft (152.4 m). The simulation shows the pressure disturbance around the fracture extending only 360 ft (109.7 m) after 30 years of production. There are three main conclusions that can be taken from this simulation. First, only a minimal amount of gas will be desorbed from the outer region of the contacted area due to the small change in reservoir pressure. Second, tight well spacing will be required to reduce the reservoir pressure enough to desorb meaningful amounts of gas. Third, gas will desorb from the areas exposed to the fractures due to the high drawdown created at the fracture face.

It is important to note that a large network of fractures (usually present in shale plays) will draw the reservoir pressure down more effectively than shown in the simulation (single hydraulic fracture). Furthermore, the reservoir pressure disturbance is sensitive to matrix permeability. Any increase in permeability will expand the contacted area and decrease the pressure, allowing more gas to desorb from the surface of the shale.

Figure 3. Distribution of free and adsorbed gas in Shale Play #2.  
Production mechanism

The production mechanism by which gas is produced from a shale reservoir involves three main processes: depletion of the free gas stored in the fracture network, depletion of the free gas stored in the matrix, and desorption. The initial gas production will be dominated by the free gas stored in the high permeability fracture network. Due to the limited storage capacity of the fractures, the initial gas rates will decline steeply and eventually stabilize as free gas in the matrix and desorption begin to dominate production. The amount of matrix free gas produced compared to that produced by desorption can vary significantly depending on the shale properties. To illustrate this, two shale examples are presented. Shale Play #1 is a normally pressured reservoir, with a low initial water saturation and moderate adsorption capacity (VL = 90 scf/ton, PL = 400 psia). Shale Play #2 is a low-pressured reservoir, with a high initial water saturation and much better adsorption capacity (VL = 280 scf/ton, PL = 370 psia). Figures 2 and 3 show the amount of free, adsorbed and total gas stored for Shale Play #1 and #2, respectively. The production of gas by each mechanism can be inferred from these Figures. As shown for Shale Play #1, the increase in the amount of gas stored by adsorption between 1,000 and 4,000 psia is very minimal. Therefore, the amount of gas produced via desorption is relatively small until the pressure is reduced below 1,000 psia, which may take a considerable amount of time. This indicates that this shale behaves very similarly to a conventional tight gas reservoir until the reservoir pressure is depleted below 1,000 psia. Unlike Shale Play #1, most of the gas produced from Shale Play #2 will be via desorption. This is clearly indicated by the distribution shown in Figure 3, which shows very little free gas in the system. This process is very similar to a CBM reservoir, and may produce a similar production profile with increasing gas rates if there is a dewatering period.

Figure 4. Typical production histories for unconventional gas wells in the United States.  
In order to forecast production and estimate reserves, the amount of free and adsorbed gas stored in the shale needs to be understood. Determining the relative contribution from the matrix and desorption requires an understanding of the adsorption and petrophysical properties. However in some cases, like in the WCSB, the adsorption properties are not known. A recent report published by the British Columbia Ministry of Energy, Mines, and Petroleum Resources titled “Regional Shale Gas Potential of the Triassic Doig and Montney Formations, Northeastern British Columbia” addresses this problem by correlating adsorption properties of WCSB shales to the measured TOC contents. This correlation estimates low adsorption properties compared to typical CBM reservoirs, indicating that WCSB shale plays may have storage mechanisms similar to Shale Play #1 (Figure 2). A clear understanding of the storage mechanism will allow for the appropriate selection of a reservoir model and will lead to a reliable forecast.

Production profile
There is no reported shale gas production from the WCSB. Experience from US operations indicate that the recovery factor is 10 to 20%, and as shown in Figure 4, the production profile can be similar to that of a conventional gas well or to that of a CBM well, depending on the shale’s characteristics. The technology for completing and stimulating shale gas wells in the United States consists of very large fracs or multi-stage fracs in horizontal wells. An appropriate technology has yet to be developed for the WCSB. It is possible that technology already used in unconventional gas wells, like multizone completions or horizontal drilling, will be effective in Western Canadian shale gas wells. However, new technology may also be needed in order to make these wells successful.