Canadian Natural GasNatural Gas in Canada – A Robust Resource

Natural Gas in Canada – A Robust Resource

Canada has a vast natural gas resource endowment, with resource development opportunities in many parts of the country and in many kinds of reservoirs. Development of conventional resources, mainly in Western Canada, formed the foundation for growth of natural gas production, transmission systems, and consumption, beginning more than 50 years ago. Production of conventional natural gas remains a very important part of Canada’s natural gas supply. However, during the past decade conventional natural gas exploration and development has become more technically and economically challenging. Over this same period, the industry has advanced technology that allows development of natural gas from a new source – unconventional natural gas resources.

Gas in Place (GIP) trapped in unconventional reservoirs – tight gas, shale gas and coal seams – is estimated at more than 3,000 Tcf (trillion cubic feet). Current development of these resources accounts for nearly twenty-five percent of Canada’s annual gas production and is expected to grow to over forty percent in the next 10 years. The Canadian Society for Unconventional Gas has estimated that the recoverable, marketable portion of this unconventional resource is from 376 to 947 Tcf. Remaining GIP in conventional reservoirs is estimated to be 692 Tcf, and 357 Tcf of that resource is expected to be recoverable and marketable, with a total marketable resource from both conventional and unconventional resources of 733 – 1304 Tcf.

Marketable resources have been presented as a range, reflecting the uncertainties in recovery and variability in gas chemistry attributable to specific resource plays. These estimates are considered to be conservative, as there are a number of emerging unconventional gas plays that are expected to contribute to the natural gas resource base in the future. At present, however, there is insufficient information for this resource to provide an appropriate estimate of GIP or the portion recoverable and marketable.

Most of the unconventional natural gas resources occur within the Western Canada Sedimentary Basin, a thick package of oil and gas prone rocks that cover much of Alberta, Saskatchewan, parts of

Executive Summary

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British Columbia, southwestern Manitoba and northwards into the Northwest Territories. However, as interest in unconventional gas development continues to grow, other sedimentary basins across the country represent potential regions for natural gas supply. Emerging opportunities have been identified in Quebec, New Brunswick, Nova Scotia, Ontario and the Yukon.

The growth of the unconventional gas industry can be attributed primarily to diminishing opportunities for growth of conventional natural gas supply, growth of natural gas demand in the North American market, and technological advances that have allowed these resources to be produced both economically and in an environmentally and socially responsible manner. Historically natural gas was a regulated commodity and exports outside of Canada were strictly controlled. In the mid 1980’s these export controls were lifted and substantial growth in exports to markets in the United States occurred. Today, Canada exports nearly fifty percent of its total natural gas production to the United States.

At current production levels of approximately 6 Tcf per year, it is projected that Canada has over 100 years of potential supply of natural gas (in the low case). In the United States, resource base estimates completed by the EIA in 2009 suggest that similar resource abundance exists, and that natural gas resources there also could sustain current production levels for the next century.

Through technology and innovation, the natural gas industry continues to identify new and emerging natural gas resources throughout North America. This abundance has created a solid foundation of potential supply upon which new opportunities for natural gas utilization can be considered. The use of natural gas for continental, national, regional or provincial energy strategies will be foundational for both Canada and the United States to achieve their environmental and economic goals in the near future.

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Source: Saskatchewan Ministry of Energy and Resources, National Energy Board. Miscellaneous Report 2008-8 (Saskatchewan’s Ultimate Potential for Conventional Natural Gas). November, 2008.

Canada is blessed with abundant natural gas resources that can be found from coast to coast to coast. These resources range from conventional deposits, ones that we have relied on for the past 60 years, to new emerging resources such as shale gas and natural gas from coal. Future resources for the next century may come from gas hydrates, a unique solid form of natural gas. Our country’s natural gas resources can be found in both conventional and unconventional reservoirs and are conservatively estimated to be almost 4000 Trillion cubic feet (Tcf) of gas in place (Petrel Robertson, 2010). Previous resource assessment studies did not account for the very large

Introduction

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contribution that unconventional resources make to the total resource estimate. The inclusion of these resources (excluding gas hydrates) has dramatically changed the picture of Canada’s natural gas potential. Table 1 presents a summary of the natural gas in place resource.

Table 1

Table 1A

Figures 1 through 4 present maps of Canada illustrating the general distribution of this gas in place resource for conventional gas, tight gas, shale gas and natural gas from coal (NGC), commonly referred to as coalbed methane (CBM). Each of these natural gas resource type sources will be discussed in further detail in the following section.

Not all the gas in place can be recovered and marketed. Marketable gas resource estimates are shown in Table 1A, reflecting the current estimate after consideration of constraints on gas recovery, removal of impurities (processing), and reductions attributable to fuel use for production and processing operations.

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The resource estimates presented in this report are based upon a recent assessment conducted by the Canadian Society for Unconventional Gas (CSUG). Petrel Robertson Consulting Ltd. (PRCL) prepared a report for CSUG summarizing the range of assessments of Canada’s natural gas resource base (“Assessment of Canada’s Natural Gas Resource Base”, March 2010) thus providing the foundation for which marketable resources could be determined.

Using the PRCL report, CSUG has estimated the total Canadian marketable gas resource to be 700 – 1300 Tcf: a wide range, reflecting the emergent nature of many of Canada’s unconventional resources. Individual inputs

to the resource estimate will change with time: some will go up, some will go down. As more information becomes available, particularly in emerging resource areas, adjustments in the estimates will be made dependent on the confidence level of the new additional data. It should be noted that at present, because the CSUG resource estimate has been developed at a broad, high level, some of the assumptions made are also broad.

Given the early development stage of many of the resource areas, coupled with geographic regions that are believed or even known to contain natural gas but for which no estimates are available, the estimates presented in this document

represent the best current assessment of Canada’s aggregate natural gas resource potential.

The foundation Gas in Place (GIP) inputs for CSUG’s estimate of Canada’s recoverable marketable gas are well grounded estimates of the GIP resource for various reservoir types, regions or development opportunities. The media often reports resource estimates without specification of the nature of the estimate or the source of the information. Estimates of resources for individual plays or opportunities are often available from a wide variety of sources (e.g. governments, companies, consultants); however, the basis for the estimates is not always apparent.

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Figure 1: Distribution of Conventional Natural Gas Resources in Canada

Figure 2: Distribution of Tight Gas Resources in Canada

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Figure 3: Distribution of Shale Gas Resources in Canada

Figure 4: Distribution of Natural Gas from Coal Resources in Canada

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Canada has a long history of producing natural gas, primarily from the Western Canada Sedimentary Basin, a thick package of oil- and gas-bearing sedimentary rocks encompassing most of Alberta and Saskatchewan, northeast British Columbia, southern Manitoba and the southwest portion of the Northwest Territories (Figure 5).

Figure 5: Location Map of the Western Canada Sedimentary Basin

Although drilling for natural gas (Figure 6) had been occurring in western Canada for several decades it was not until the 1960’s that natural gas development became an integral part of the industry with steady growth in production (Figure 7), reserves (Figure 8) and the true establishment of a natural gas export industry (Figure 9).

Alberta has historically been the central focus of natural gas development by the industry, but the 1960’s also saw the beginning of expansion of natural gas exploration and development into northeast British Columbia where a small number of wells were adding a disproportionately large amount of reserves. B.C. has experienced more or less steady growth in both production and reserves since that time.

Conventional Natural Gas Resources

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Figure 6: Natural Gas Wells Drilled in Western Canada

Figure 7: Historical Natural Gas Production by Province

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Although drilling in western Canada increased through the 1970’s, as did total reserves of defined natural gas, there was only modest growth in natural gas production due primarily to limited markets and limitations on exports.

Production and exports remained relatively flat through the 1970’s and up to 1986, in response to price regulation and regulatory constraints on exports, and correspondingly low levels of industry natural gas activity. Western Canada is a gas-prone

basin, and although gas-focused activity was low through this period, natural gas discoveries continued to be made both as a result of limited gas-directed drilling and through ongoing oil exploration and development.

Everything changed in late 1985

with de-regulation of prices and export controls: there was a rapid response in production and exports, even without increases in drilling activity for a number of years, as producers accessed already discovered and drilled gas reserves. The 1990’s was a decade of rapid production growth and pipeline expansion to both domestic markets and export markets in the U.S. Midwest and Northeast, and to the West Coast.

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This growth in production, exports and pipeline expansions was fueled by robust markets and ready access to low-cost supply already in producers’ inventory, as illustrated by changes in the Reserve Life Index (RLI). The RLI is simply the ratio of reserves to production, expressed in years. As illustrated in Figure 10, the RLI was very high when the natural gas industry was in its infancy but as the industry matured, the ratio fell rapidly with only modest increases in production. The index stabilized at 25 to 30 years until 1987 when industry began to grow production and run down the established reserve inventory. By the mid- to late-1990’s the index had again stabilized at 8-10 years as natural gas drilling activity accelerated in a search for new reserves. This level of reserve life index reflects market conditions and economic optimization, rather than the imposition of regulatory constraints.

Figure 8: Conventional Natural Gas Reserves in Canada (year end basis)

Figure 9: Natural Gas Exports from Canada

Source: CAPP

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Figure 10: Reserves Life Index – Canada & Alberta

Source: CAPP

*Various sources

While historically most of the natural gas production has been derived from Western Canada, exploration has occurred in the Arctic regions as well as offshore Eastern Canada. Significant natural gas reserves have been identified in the Mackenzie Delta region and the Beaufort Sea region in northern Canada although no transportation infrastructure has been constructed and as a result these reserves are stranded at present. In Eastern Canada, some modest onshore natural gas development has occurred in New Brunswick, but the most prolific discovery and development has occurred in the Sable Island field, offshore Nova Scotia.

Canada’s estimated remaining marketable conventional resource is provided in Table 2. It should be noted that nearly 1/3 of the total resides within the Arctic region where there is no transportation infrastructure. In Western Canada, while the remaining marketable resource is estimated to be 121 Tcf, conventional natural gas production has been declining since 2006. New conventional gas pools tend to be fewer in number and smaller in size, resulting in higher costs to develop. This is a critical element in the emergence of unconventional natural gas resource developments. However, conventional natural gas continues to comprise a significant proportion of Canada’s current natural gas production.

Table 2

During the past 20 years of conventional hydrocarbon exploration, industry has recognized the significant potential of natural gas resources within geological formations that had not in the past been considered to be economically viable. New technologies were required to enable this largely un-quantified resource to yield economic volumes of gas.

The development and widespread deployment of a variety of horizontal drilling and companion reservoir stimulation technologies has demonstrated that vast additional natural gas resources within coal seams, tight gas sands and carbonates as well as shale can be recovered in economic quantities. These resources have been defined as unconventional gas due to the requirement of advanced and in some cases unique technologies to enable economic gas production.

The development of Canada’s unconventional gas resources continues to grow and is expected to play a major role in shaping Canada’s long term natural gas supply. Currently in 2010, unconventional gas accounts for about 25% of the country’s natural gas production and that contribution is expected to grow with continued decline of conventional natural gas production.

Table 3 summarizes the total estimated marketable gas resources for Canada including an assessment of the unconventional potential.

Table 3

Unconventional Natural Gas Resources

Nikanassin tight sand, west-central Alberta

Very fine-grained sandstone, siltstone and carbonate sedimentary rocks containing natural gas are collectively referred to as “tight gas” reservoirs. The natural gas is trapped in the very small pore spaces within the rock matrix and requires some form of stimulation in order to create pathways for the gas to flow to the wellbore(s).

Known tight gas resources are primarily in Alberta and British Columbia and to a lesser extent in Saskatchewan, although emerging hydrocarbon opportunities have also been identified in northern Canada, Quebec and the Maritimes. While there are encouraging results being reported from some of these new exploration regions, insufficient data is available to estimate the marketable resource potential for these regions. As such no volumes have been included in the estimates for these areas, although there is an expectation that they will contribute to the country’s overall energy supply in the future.

For all tight gas reservoirs in B.C. and Alberta, marketable resources have been based upon low and high ultimate recovery factors (20% and 40% respectively). These end values are aligned with the range of expectations that producers from the regions have reported. Figure 12 illustrates the distribution of the marketable tight gas resources for Canada.

Note that the Montney Formation is considered to be a tight gas reservoir and is included in the tight gas estimates, rather than in shale gas. For this assessment, no gas in place estimate is available for the extension of the Montney Formation into Alberta, although preliminary observations suggest that the Alberta resource potential is large and in some localities, natural gas production is occurring. This presents a significant gap in tight gas resource numbers, but one that cannot be resolved at the present time.

The Alberta Deep Basin Cretaceous-age formations contain a very large gas in place resource. These values are based on a non-public domain estimate made from detailed work completed by Petrel Robertson during 2006 for the Alberta Department of Energy (with the involvement of three producers).

Tight Gas Resources

Petrel has permission to use the estimates but the underpinning geological and engineering work is not yet available to the public for confidentiality reasons.

In British Columbia, while the core area of the Montney Formation has been essentially defined, the limits of the play continue to expand to the north and west. As such, while an initial gas in place value has been generated, this number is expected to grow with time.

Figure 12: Summary of Marketable Tight Gas Resource Estimates (Tcf)

Natural Gas from Coal (NGC) is commonly referred to as Coalbed Methane (CBM). NGC resources are present in the three western provinces, Yukon, NWT, and the Maritimes (Figure 13). Most of the resources occur in Alberta, (Figure 14), and production has been

established in areas of two of the three main coal-bearing formations (Horseshoe Canyon and Mannville). The Horseshoe Canyon Formation NGC resources lie in a multi-layered package of sedimentary rocks containing up to 20 coal seams. Production is from vertical wells

and the coal seam gas production is essentially dry, with no (or very minor) water production.

Current production of NGC in Canada is derived primarily from the development of the Horseshoe Canyon core region that lies between and east of

Natural Gas from Coal (NGC)

Calgary and Edmonton. This production has grown rapidly during the last 10 years and now accounts for approximately 750 million cubic feet (Mmcf)/day (Figure 15).

In contrast, the deeper Mannville CBM production involves producing saline formation water from the coals prior to gas production, although Encana has recently demonstrated that in some locations, good production rates are possible in dry, deep Mannville coals seams. The Mannville Formation, while making up only three percent of the total NGC producing wells, accounts for over fifteen percent of total NGC production (Figure 15). The productive coal horizons tend to be at a greater depth and are geologically more mature, yielding

a significantly higher GIP volume. Individual wells tend to have higher production rates, once the coal seam(s) have been de-watered.

Fractures in Mannville coal seam, Alberta

Figure 13: Summary of Marketable NGC Resource Estimates (Tcf)

Although there is a large CBM gas in place resource in British Columbia recoverable resources are currently estimated to be small, primarily due to the absence of demonstrated producibility and resource access constraints.

Figure 14:

Distribution of NGC Resources within Alberta

(from ERCB ST98)

Figure 15:

NGC Production Growth from Both Horseshoe Canyon and Mannville Formations (from ERCB, ST98)

There is also a large CBM gas in place resource identified in the Maritimes region, primarily offshore Cape Breton Island. A low recovery factor has been assumed for this region to reflect only the onshore opportunities which exist in Nova Scotia.

The Saskatchewan government has identified a small CBM GIP resource in the province. Any prospect will be modest.

Yukon, NWT, and Nunavut all are believed to have CBM gas in place; however, they have not been included due to the limited information.

Shale gas resources have been identified in western Canada, Quebec, the Maritimes and a very small area in southern Ontario (<1 Tcf). In places extensive exploration work is being conducted to quantify the resource potential, but at present sustained production is only occurring from the Horn River Basin in northeast British Columbia and a small field of shallow shale gas in the Wildmere region of east central Alberta. Resource estimates have been generated based primarily on thickness of potential gas-bearing shales for which volumetric gas in place numbers exist. In all regions, testing and development are at an early stage. As a result, recovery factors reflect a wide range, from 5% to 40% depending on the shale play type, and the nature of the challenges faced.

Figure 16: Summary of Marketable Shale Gas Resource Estimates (Tcf)

Shale Gas Resources

The Horn River Basin, located in northeast British Columbia, has experienced extensive shale gas exploration since the early 2000’s. Production is limited at present to pilot projects, although encouraging results suggest that commercial development could occur within the next two years. Current production is less than 200 Mmcf/day (in early 2010) but completion of additional infrastructure and gas processing facilities will enable that volume to increase significantly (Figure 17).

In Quebec, a number of companies are active in exploring for shale gas in the region referred to as the “Quebec Lowlands”. Natural gas is present in the Utica and Lorraine Formations at depths ranging from shallow to deep along the St. Lawrence River and extending southwards into the Appalachian region. Exploration activities are not as advanced as in the Horn River basin although early efforts have yielded encouraging results. The Quebec shale gas “play” is of particular interest to many companies due to its proximity to major markets in central Canada and the northeast United States. The pace of development for this new resource region will be dependent on the repeatability of and improvement on initial test results during the pilot testing phases of exploration.

In New Brunswick, a number of companies have initiated exploration projects to test the potential of the Central Maritimes Basin. Early results are encouraging, but evaluation is in a very early stage and as a result, the resource estimates are very preliminary.

Black Shale, Location Unknown

Figure 17:

Projected Growth of Horn River Basin Shale Gas

Production

As the importance of unconventional gas continues to grow, the natural gas industry continues to expand into new regions where there is limited knowledge of the resource potential. Although there is interest and some exploration in many of these regions resource estimates have not been provided due to the limited data available relative to the size of these emerging opportunities. It is expected that our understanding of Canada’s resource base will grow substantially as exploration work continues. Key resource opportunities not included in the current estimate include:

The Montney Formation in Alberta – No public estimate of the resource could be identified. The resource is large and exploration and development activities are evolving from the core Montney region in B.C. into this area.

Devonian shales in Alberta – The lateral equivalent of the Horn River productive formations, these formations cover a large geographic area and are referred to in most of north-central and northwest Alberta as the Duvernay and Ireton shales. They are reported to have a high organic content and are “gassy” when intersected.

Devonian shales in the Mackenzie Valley corridor – Formations which are laterally equivalent to productive shale units in the Horn River area also trend the length of the Mackenzie Valley. Upstream assessment of this opportunity is in a very early stage.

The Liard Basin – This area is west of the Horn River basin, and hosts shales of similar age but at greater depth. It is an active exploration area, but is also more remote than the Horn River basin. The trend includes parts of BC, Yukon and Northwest Territories.

Deep thermogenic Colorado Group shales in western Alberta – shallow Colorado Group shales in central and eastern Alberta tend to have a low reservoir pressure and low productivity, with reservoir stimulation challenges. In contrast, the Colorado Group shales in western Alberta are deeper with a higher reservoir pressure and are believed to have potential for higher productivity. No public estimates of the resource could be identified.

St. Lawrence Lowlands – Only that part of the Utica Shale resource where estimation methodologies could be identified is included in the current estimate. As evaluation work in Quebec continues, additional Utica shale resource potential will need to be added. No estimate has been identified for the Lorraine Formation, a tight gas, predominantly silty formation that overlies the Utica Shale, although it too is being evaluated by industry. As this work continues the Lorraine resource potential will need to be included in Canada’s natural gas resource base.

Central Maritimes Basin – This basin is located predominantly in the Gulf of the St. Lawrence but with an onshore component in New Brunswick and the southern tip of Newfoundland. Limited exploration has been conducted in the region but recent

Emerging Opportunities for Unconventional Gas in Canada

exploration licenses will lead to a better understanding of the onshore potential during the next few years.

Natural gas hydrates – A very large resource has been estimated by various parties for natural gas in hydrates. Hydrates are present across broad areas of the Arctic and offshore of the west and east coasts, with gas in place estimates totaling thousands of Tcf. Most of the Canadian expertise with respect to gas hydrates resides within Natural Resources Canada.

Canada exports about half of its production to United States markets and changes to the supply/demand balance in the United States have profound implications for natural gas development in Canada. United States natural gas exploration programs have identified numerous opportunities for unconventional gas development in a large number of basins across the country over the past 20 years (Figure 18).

Figure 18: Major Tight Gas and Shale Gas Basins in the United States (from EIA, December 2009)

Shale gas and to a lesser extent natural gas from coal were extensively explored in a number of eastern U.S. basins during the 1980’s and 90’s but the overall contribution from these developments was relatively small compared to the gas being produced elsewhere from conventional reservoirs.

Unconventional Gas in the United States

As conventional supplies began to decline, new sources of supply came to fruition after many years of investment, technology development and experimentation. Development of new fields of natural gas from coal in both the San Juan Basin and the Powder River Basin employed new and at that time novel technologies to increase and optimize production. At the same time as these NGC developments were expanding, many companies were beginning to explore for tight gas reservoirs in the Rocky Mountains region. New fields such as Jonah and Pinedale demonstrated that economic quantities of natural gas could be produced from very low permeability reservoirs using unique drilling and completion technologies.

During the past few years a significant boost to unconventional gas production has come from the development of shale gas reservoirs in the Fort Worth Basin in east Texas. Utilization of horizontal drilling, coupled with multi-stage hydraulic fracture stimulation enabled large volumes of gas to be recovered from very fine grained “shale” reservoirs. Similar sedimentary rocks are prolific across sedimentary basins in North America and success in the Barnett shale play led to widespread exploration in other “shale basins” in the United States.

Growth of shale gas production in the United States has truly altered the dynamics of the North American natural gas market. While demand has remained relatively flat during the past 5 years, supply has increased with a major contribution to growth coming from shale gas developments (Figure 19).

Figure 19: Growth of Shale Gas Supply in the United States (from Southwestern Energy, 2009)

Unconventional gas now accounts for over fifty percent of total United States gas production with shale gas alone representing nearly twenty percent. Shale gas production, which represented only 1% of US supply in 2000, could grow to as much as fifty percent of total natural gas production by 2030 (CERA, 2010).

The vast resources of unconventional gas across North America together with our highly integrated continental pipeline network, the capacity and location of our natural gas storage facilities and well developed LNG import capability near major demand centers provides assurance that any disruptions or imbalances between natural gas supply and demand will be quickly resolved.

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