A Primer for Understanding Canadian Shale Gas – Energy Briefing Note

A Primer for Understanding Canadian Shale Gas – Energy Briefing Note by National Energy Board, ISSN 1917-506X , November 2009.
However, as a technology driven play, the rate of development of shale gas may become limited by the availability of required resources, such as fresh water....

...As mud turns into shale during shallow burial, generally just a few hundred metres deep, in the “nursery”, bacteria feed on the available organic matter (up to 10 per cent of the rock volume but generally less than five per cent) and release biogenic methane as a byproduct (Figure 3). Natural gas is also generated during deep burial while the shale is in the “kitchen”, generally several kilometres deep, where heat and pressure crack the organic matter, including any oil already produced by the same heat and pressure, into smaller hydrocarbons, creating thermogenic methane (Figure 3). Some of the oil and gas manages to escape and migrate into the more porous rock of conventional reservoirs. In fact, the vast bulk of the world’s conventional reserves of oil and gas were generated in and escaped from organic-rich shales. But some oil and gas does not escape, as it is either trapped in the micropore spaces or attached to the organic matter within the shale. For example, the natural gas produced from the Second White Specks Shale of Alberta and Saskatchewan comes from shallow burial (it is shallow enough that gas is still being generated by bacteria), while the natural gas from the Devonian Horn River Basin and Triassic Montney shales was generated during deep burial. The Utica Shale of Quebec has both shallow and deep sections and there is potential for both biogenic and thermogenic natural gas, respectively.

The origins of natural gas become important when evaluating shale-gas prospects. For example, thermogenic systems often produce natural gas liquids with the methane, which can add value to production, whereas biogenic systems generate methane only. Thermogenic systems can also lead to the generation of carbon dioxide as an impurity in the natural gas, which costs money to remove and can increase greenhouse-gas emissions. Thermogenic plays tend to flow at high rates, but are normally exploited through the extensive use of horizontal drilling and are therefore more expensive to develop than biogenic plays, which flow at lower rates and are exploited through shallow, closely spaced vertical wells instead.
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However, shale gas, both biogenic and thermogenic, remains where it was first generated and can be found in three forms: 1) free gas in the pore spaces and fractures; 2) adsorbed gas, where the gas is electrically stuck to the organic matter and clay; and 3) a small amount of dissolved gas that is dissolved in the organic matter. ... Individual gas shales appear to have hundreds to thousands of billion cubic metres (tens to hundreds of Tcf) of gas in place spread over hundreds to thousands of square kilometres. The difficulty lies in extracting even a small fraction of that gas. The pore spaces in shale, through which the natural gas must move if the gas is to flow into any well, are 1000 times smaller than pores in conventional sandstone reservoirs. The gaps that connect pores (the pore throats) are smaller still, only 20 times larger than a single methane molecule. Therefore, shale has very low permeability. However, fractures, which act like conduits for the movements for natural gas, may naturally exist in the shale and increase its permeability.

Natural gas will not readily flow to any vertical well drilled through it because of the low permeability of shales. ... However, some shales can only be drilled with vertical wells because of the risk of the borehole collapsing (e.g. the Cretaceous Second White Speckled Shale of Alberta and Saskatchewan). The trade-off between drilling horizontal versus vertical is increased access to the reservoir, but at a far higher cost.
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In conventional reservoirs, as much as 95 per cent of the natural gas can be recovered. For shales, recoveries are expected to be around 20 per cent because of low permeabilities despite high-density horizontal drilling and extensive hydraulic fracturing.

Drilling and hydraulically fracturing wells can be water-intensive procedures; however, there is very limited Canadian experience from which to estimate potential environmental impacts.
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Frac water often contains chemical additives to help carry the proppant and may become enriched in salts after being injected into shale formations. Therefore, frac water that is recovered during natural gas production must be either treated or disposed of in a safe manner. ... Flow-back water is infrequently reused in other fracs because of the potential for corrosion or scaling, where the dissolved salts may precipitate out of the water and clog parts of the well or the formation.
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Shale gas wells can be very expensive because of the cost of horizontal drilling (a function of technology needed to drill horizontal and the extra time required to drill) and technology-heavy hydraulic fracturing techniques that may take several days to fracture a single well. A horizontal well in the Montney Formation will typically cost approximately 5 to 8 million dollars. In the Horn River Basin, a horizontal well costs up to 10 million dollars. Shale are expected to cost 5 to 9 million dollars. Vertical wells targeting biogenic shale gas, like in the Colorado Shale, are far less expensive: the resource is shallow and the wells cost less than $350,000 each.
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How much of that gas can be recovered still needs to be confirmed. Initial estimates are about 20 per cent. 
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The Montney is so thick (well over 300 metres in some places) that some operators are planning to pursue stacked horizontal wells, where horizontal legs are drilled at two elevations in the same well, penetrating and fraccing both the Upper and Lower Montney.
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Horn River Basin wells are very prolific...remembering that production declines in shale-gas are steep and within just a few months, production should be significantly less. ... It should be noted that the Horn River
Basin shale gas play extends into both the Yukon Territory and the Northwest Territories, although its northward extent beyond provincial/territorial borders is poorly defined.
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The Colorado Group consists of various shaley horizons deposited throughout southern Alberta and Saskatchewan (Figure 1) during globally high sea levels of the middle Cretaceous, including the Medicine Hat and Milk River shaley sandstones, which have been producing natural gas for over 100 years, and the Second White Speckled Shale, which has been producing natural gas for decades. In the Wildmere area of Alberta, the Colorado Shale is approximately 200 metres thick, from which natural gas has potential to produce from five intervals. ... Furthermore, the gas produced in the Colorado has biogenic rather than thermogenic origins.
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The Upper Ordovician Utica Shale is located between Montreal and Quebec City (Figure 13) and was deposited in deep waters at the foot of the Trenton carbonate platform. ... Biogenic gas can be found in the Utica in shallow areas, while thermogenic methane can be found in medium-deep and structured shales (Figures 13 and 14). The reservoir has an advantage over others in that it is folded and faulted, which increases the potential for the presence of natural fractures (Figure 4). Only a handful of wells have been drilled in the Utica, most of them vertical. After fraccing, each vertical well is reported to have produced approximately 28 000 m3/d (1 MMcf/d) of natural gas. Initial results from hydraulic fracturing and flow tests from three horizontal wells have yielded stable flow rates of 2 800 to 22 700 m3/d (0.1 to 0.8 MMcf/d) from medium-deep shales, less than expected but likely influenced by the lack of equipment to extract frac-water that flowed back during production.
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Finally, there are some environmental concerns with development of shale gas in Canada. Little is known about what the ultimate impact on freshwater resources will be. [Emphasis added]

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