Coalbed Methane FAQs

Background

Development

Environment

Water

Royalties/Tenure

The Final Report

Background

What is the size of Alberta's CBM resource?

  • There is a lot of natural gas in Alberta's coal beds. According to a study by the Alberta Geological Survey, Alberta's coalbed resource could contain approximately 500 Trillion cubic feet (Tcf) of natural gas.
  • Unconventional natural gas sources, such as CBM, could help supplement Alberta's recoverable conventional natural gas reserves of 38 Tcf.
  • However, there isn't enough information at this time to provide a meaningful estimate of how much CBM is recoverable.

What is the difference between CBM and conventional natural gas?

  • Natural gas is a mixture of hydrocarbons in a gaseous state, comprised mainly of methane. Widely considered to be the almost-perfect fuel – it's clean, efficient, convenient, safe, abundant and economical – natural gas heats about one-half of Canadian households, and provides about 45 per cent of the energy used by the country's manufacturing industries.
  • CBM is unconventional gas because the coal acts as both the source of the gas and the storage reservoir. Most of the CBM is attached to or "adsorbed" on the coal surfaces and it may also be trapped in the coal fractures.
  • Conventional natural gas refers to a mixture of gaseous hydrocarbons that can be recovered from rock reservoirs such as sandstones and dolostones through commonplace completion and production techniques.
  • CBM and other unconventional natural gases, like shale and tight gas, are considered less proven, and potentially less productive and less economic than conventional natural gas, based on current conditions, knowledge, economics and technology.
  • Any type of unconventional natural gas resource can be considered conventional over time as the resource is developed

Is CBM considered a clean energy source?

  • The natural gas found in coal seams is "sweet," not "sour," and generally has few impurities. Small amounts of carbon dioxide and nitrogen may be present.
  • The gas is of near-pipeline quality when produced and typically does not require extensive processing.

How is natural gas extracted from coal seams?

  • CBM is attached or "adsorbed" to the coal itself, instead of being trapped in the pore space of the rock like most conventional natural gas.
  • Pressure from overlying rock and water within the natural fracture system of the coal seam keeps the methane gas bound to the coal.
  • CBM is produced by reducing the pressure in the coal seam, sometimes by pumping groundwater out, so the natural gas flows through fractures in the coal into the well bore. The natural gas would then flow up to the surface.
  • If few natural fractures exist, producers may use hydraulic fracturing to create channels in the coal. When the natural gas reaches the surface, it is compressed and transported through natural gas pipelines.

Why are we seeing an increase in CBM development?

  • Recent increases in natural gas prices and the maturation of the Western Canadian Sedimentary Basin have resulted in increased interest in new or undeveloped parts of the basin. The development of new technologies is also increasing interest in CBM.
  • This energy source has the potential to make a significant contribution to Alberta’s future natural gas supply for consumers

Development

Are surface and production casing required for CBM wells? How is casing regulated?

  • The ERCB requires water aquifers to be protected by cemented steel casing in all wells. This may be surface casing or production casing. The surface casing requirements are set for drilling control purposes to ensure casing is adequate.

Can the coal still be mined after the CBM gas is removed?

  • Yes. The coal remains in place in an otherwise unaltered state.

What measures are currently in place to address the concerns of surface property owners about CBM development?

  • The ERCB is responsible to review and approve technical aspects of development and requires gas and oil companies to work with landowners to resolve issues other than compensation, prior to issuing well licenses. If these are not satisfactorily resolved, the ERCB may call a hearing.
  • The Farmers' Advocate is also available to advise farmers and investigate complaints by landowners.
  • As with conventional oil and natural gas, the Surface Rights Act comes into effect when the surface owner or occupant and the company are unwilling or unable to reach a private agreement about access to and use of the land. The Surface Rights Board determines equitable compensation for land and operational disturbances relating to oil, natural gas, and other energy developments.
  • The Water Act employs a "first in time, first in right" principle to determine priority and as a means of protecting Albertan's water supply. Conditions attached to a Water Act authorization require the energy project owner to undertake corrective action if a landowner's well is impacted by the ground water diversion. A directly affected landowner can appeal a Water Act authorization to the independent Environmental Appeal Board.
  • The same proper practices for drilling and disposal of wastes from drilling activities (e.g. drilling mud) are required as for other oil and natural gas activities.
  • Proper site reclamation at the end of life of the project is mandated under the Environmental Protection and Enhancement Act (SRD - public land, AENV - private land).

What is the current distribution of CBM wells in Alberta?

  • So far, approximately 94 per cent of the CBM wells drilled in Alberta have targeted the middle Horseshoe Canyon and Belly River coal zones in the Calgary-Red Deer corridor. Development in these areas is often less costly, in part due to the dry nature of the coals, which results in no water handling costs.
  • About four per cent of CBM activity is in the deeper Mannville zone in north-central Alberta. The deep coals (over 1,000 meters) tend to produce highly saline formation water, similar to conventional oil and gas wells at this depth.
  • A small number of CBM pilot projects are distributed over a broad area of west-central and southwest Alberta. Some CBM has been produced in the shallower Scollard (Ardley) area, with limited amounts of water that varies in quality. An even smaller number of CBM test wells have focused on the Kootenay coals in the Foothills region.

How many CBM wells are allowed per section?

  • The ERCB regulates the number of wells needed to effectively drain the hydrocarbons. Reflecting rock and fluid properties, the number of wells necessary can vary considerably throughout the province.
  • Natural gas well density for parts of Alberta starts at one well per pool per section but many areas, such as southeast Alberta have four or more wells per section, with provisions for greater density. A significant portion of the province, notably areas with shallower natural gas development, has a common density of two to four wells per pool per section. By comparison, most oil development requires four to eight wells per pool per section, with heavy oil or bitumen needing 16 or 32 or more wells per pool per section. CBM operators have generally expressed interest in two to eight CBM wells per section in order to optimize gas recovery from the coals.
  • Application to reduce spacing and increase well density can be made in accordance with the Oil and Gas Conservation Regulations. Such applications focus on energy conservation (avoiding resource waste) needs and impacts on offset mineral owners. They also support early disclosure to landowners.
  • It is important to understand that any reference to the number of wells in the ERCB spacing orders reflects the number of subsurface drainage points required to effectively recover the resource and not the number of surface locations that may ultimately be approved. Applying good land use management practices and consulting with the landowner can assist the energy company to significantly reduce surface impacts. Where appropriate, use of pad drilling, directional drilling from lower value/lower impact sites, common roads and pipeline corridors can all reduce the surface impact.

How many CBM wells exist in Alberta?

  • As of December 31, 2007, Alberta had 9,339 wells with some CBM production.
  • The first commercial CBM project was announced in 2002.

Is it safe to use existing pipelines for CBM development? How do you determne if there is a leak and who would deal with it?

  • Yes. It is safe to use existing pipelines. All pipelines in Alberta are subject to ERCB regulations, which include technical design, material control, monitoring operations and programs for corrosion prevention to prevent leakage. If appropriate, co-use or re-use of an existing pipeline can provide an important land use management benefit.

How long are CBM wells expected to produce? Is there any preliminary information on CBM production rates or decline curves?

  • There has not yet been enough production from CBM wells from either the dry gas coal intervals or the water bearing coal intervals in Alberta to determine a model production profile. Production information for the currently producing CBM wells (that are not deemed experimental by the ERCB) in Alberta is available from the ERCB.

What is the potential for CBM development in the Foothills?

  • Geological mapping by the Alberta Geological Survey (AGS) shows potential CBM resources in Alberta’s Foothills regions. Most of industry’s CBM activities have, to date, been concentrated in the Plains regions because the geology is less complex and the plays more economical. If CBM development extends into Foothills regions drilling plans must address local requirements.

Environment

What is the potential for storing carbon dioxide in coal beds?

  • Coal beds have the potential to store carbon dioxide through an experimental process called "carbon sequestration" or carbon storage.
  • The Alberta Research Council is working on an enhanced recovery process, that in years to come, could pump carbon dioxide into coal beds and push out more natural gas.
  • This process could also contribute to Alberta's plan for reducing greenhouse gasses. Please refer to: Albertans & Climate Change - Taking Action.

Does methane from CBM production increase flaring and venting?

  • The ERCB oversees flaring (the burning of natural gas that cannot be conserved) and venting (the release of natural gas to the atmosphere where conservation or flaring is not practical) related to CBM development according to methods outlined in its Directive 60: Upstream Petroleum Industry Flaring Guide.
  • CBM is predominantly clean-burning methane, and contains no heavy hydrocarbons. The flares are similar in nature to the flame in your furnace, except larger in scale.
  • For all natural gas wells, flaring, or venting is restricted to initial testing or required maintenance activities.

What rules and regulations are in place to protect wildlife and plant habitats?

  • Companies developing CBM must comply with the existing policies and legislation put in place by the ERCB, Sustainable Resource Development, and Alberta Environment.
  • Regulatory requirements covering reclamation issues are already in place under the Environmental Protection and Enhancement Act.
  • The ERCB's regulations address technical, safety, and resource conservation aspects of oilfield and other energy development.
  • Sustainable Resource Development manages the land, including wildlife and habitat, and oversees operational aspects of land and environmental protection.

What other steps are being taken to limit the "environmental footprint" of CBM development on the landscape?

  • A variety of ongoing government and industry initiatives are helping to minimize impacts and protect native prairie, sensitive environments, critical habitats, and important recreation areas. These include Integrated Resource Management and Integrated Landscape Management at the broad scale, and careful project management, including industry best practices, at the local scale.
  • Sustainable Resource Development, the province's public land manager, and the ERCB ensure any issues associated with "environmental footprints" are minimized and that development is in the public interest.
  • The surface impacts of energy projects on public lands will be considered and addressed through Sustainable Resource Development's surface application process.
  • All land impacts associated with energy projects are handled through the ERCB's site application review and decision process.

Are methane leaks a concern?

  • Leaks of methane from coal seams or other geological formations to the surface can occur naturally from shallow, open, porous gas-bearing formations - with or without CBM development. Shallow formations are not likely to be targeted for CBM production if they have leaked their methane to the surface.
  • ERCB regulations require properly maintained well bores with cemented steel casings, which should not leak methane into the atmosphere.
  • CBM wells operate at generally lower rates and pressures than conventional natural gas; therefore, the possibility of leaks is low.

Does CBM have the potential to start underground coal fires?

  • No. Fire normally needs free oxygen not available at the depths being targeted for CBM development.
  • While lightning or other natural occurrences may ignite exposed coal seams, there is no evidence of coal fires being started either underground or on the surface through CBM production.

What regulations exist to address compressor noise associated with CBM development?

  • All gas wells require compression at some time during their producing life. CBM is similar to shallow gas development from sands in that it is low-pressure gas. Low-pressure gas typically requires compression at an earlier point in production. In most cases, compression is centralized and often can take advantage of existing infrastructure and current compression sites. Noise levels associated with the energy industry are regulated by the ERCB and strict cumulative noise limits are imposed on industry.
  • Noise associated with compression is regulated in Alberta by the ERCB, and details are available in ERCB Directive 38: Noise Control Directive User Guide.
  • Most produced natural gas requires compression at some location or time to keep it flowing in pipelines to market.
  • CBM wells, which are generally low-pressure wells, will normally require compression throughout their production life. This compression can take different forms depending on existing infrastructure, economics, and production characteristics.

Water

What is the difference between saline and non-saline groundwater in Alberta?

  • The Water (Ministerial) Regulation defines saline groundwater as having greater than 4,000 milligrams per litre of total dissolved solids (mg/l TDS). Water with less than or equal to 4,000 mg/l TDS is considered non-saline and can be used for a variety of purposes, depending on the specific quality. Only a portion of non-saline water is considered to be “potable water” and suitable for human consumption.

How does a company inform a landowner and other local residents about CBM development and the impact on local aquifers?

  • Standard practice is for the the company to contact and inform all residents living in the neighbourhood. As part of the dialogue with landowners, the parties may identify or suggest other parties that may be interested. The ERCB expects companies to understand community needs and follow up on these suggestions. While the ERCB and Alberta Environment specify minimum requirements, they both expect that consultations fit the needs of each case.
  • In addition to consultation at the time of an application, ongoing consultation over the life of an energy project is encouraged. If all the information is not available at the exploration phase, Albertans can communicate their expectations to the company and schedule a follow up consultation when more data becomes available.

How does industry dispose of saline water produced from an CBM well?

  • The ERCB regulates produced water disposal to ensure the environment and farmland are protected. Saline water must be deep well injected, and the well must meet technical standards and testing requirements to ensure well bore integrity, sound disposal operations, and that the water stays where it has been disposed.
  • All groundwater pumped out of a CBM well, or from any oil or gas well, belongs to the Crown (the government).
  • The specific use of this water is indicated in the water diversion permit approved by Alberta Environment.
  • Licences or approvals are issued under the Water Act to grand licensees or approval holders the right to divert a specific amount of water. The licensee or approval holder can be either an individual (e.g., a farmer, a landowner) or a corporation (e.g., a company, irrigation districts, an association).

What steps are taken if surface water becomes contaminated as a result of CBM development? How are landowners and their water wells protected in the event of damage or loss of use?

  • Although unlikely to occur, in the event of contamination, a company would be required to take immediate action to clean up the contamination in accordance with current regulations and guidelines under the Water Act and the Environmental Protection and Enhancement Act.
  • Approvals authorized under the Water Act generally have conditions that require the licensee or approval holder to investigate and report back to Alberta Environment and ERCB if there is a complaint about their project. If their activities are found to be the cause of the problem, the licensee or the approval holder will have to undertake remediation.

Will potential long-term dewatering and contamination from CBM developments impact water wells?

  • Unless the CBM and domestic water wells are in the same zone and close together or are hydraulically connected, little or no impact is expected. A water diversion authorization from Alberta Environment can require observation wells to monitor groundwater conditions for early detection of problems before they impact other wells. Monitoring is the key to early detection of any potential impact. Companies must respond to all complaints of water well interference. They must investigate and report the results of their investigation to the stakeholder and to government agencies.

How much water is produced with a CBM development?

  • It depends on where the development is occurring. Production data indicates the three main CBM targets in Alberta have different water production characteristics.
  • Wells completed in the Horseshoe Canyon are mostly dry. This is the area where industry has concentrated most of its activities.
  • Wells completed in the deep Mannville coals produce water that is saline.
  • The few wells completed to date in the more shallow Ardley coals have tested a mix of water characteristics; some produce no water, others produce slightly saline water and some produce non-saline water.
  • Any well producing non-saline water must have a water diversion approval from Alberta Environment.

Is there a higher risk of creating a fracture between the coalbed and the adjacent aquifer with CBM compared to conventional gas fracing?

  • Fracturing is a standard technique to enhance hydrocarbon recovery that has been used in Alberta’s oil and gas industry for many years. Fracturing, or fracing, (the opening up of fractures in the formation to make gas flow more freely) a well is done to increase or initiate commercial production and is conducted in a controlled manner.

How do we know some of the CBM development difficulties encountered in Wyoming and Colorado will not happen here?

  • Each coal basin is unique and Alberta’s basins are no less unique.
  • Approximately 94 per cent of the current development involves coals that produce little or no water.
  • In areas where there may be water, Alberta has a strong regulatory system that addresses the production, use and disposal of both non-saline (fresh) and saline water. For example, saline water is deep well injected, the same as for conventional gas, and is not allowed to be disposed of on the surface.

Royalties/Tenure

How is CBM royalty calculated?

  • In Alberta, CBM royalty is calculated in the same manner as natural gas from conventional sources. The Natural Gas Royalty Regulation governs the calculation of the royalty from natural gas in coal seams.

Who owns the mineral rights to CBM? Where there is a split title, who owns the CBM?

  • Provincial legislation (the Mines and Minerals Act and associated Regulations) is conclusive in determining the ownership of CBM where the Crown owns both coal and natural gas. However, in the instances of where coal rights are freehold owned and natural gas rights are Crown-owned, vice versa, or two separate freehold owners exist, the matter is to be determined and ruled on by the courts. For Crown-owned mineral rights, CBM is considered to be natural gas and is administered in the same manner as conventional gas.

How does the Department of Energy administer CBM tenure on Crown-owned land?

  • The Petroleum and Natural Gas Tenure Regulation governs CBM. There is no regulatory distinction between conventional natural gas and CBM land tenure.
  • The amendment to Section 67 of the Mines and Minerals Act by the Energy Statutes Amendment Act, 2003  confirms that the right to the natural gas in Crown coal, including coalbed methane, does not belong to the lessee of the Crown coal rights and, when read in conjunction with section 4(2)(b) of the Petroleum and Natural Gas Tenure Regulation, by implication or inference grants that right to CBM to the petroleum and natural gas lessee.
  • In Alberta, the right "to win, work and recover" CBM is granted under a conventional petroleum and natural gas lease. A Crown coal lease does not grant the right to recover natural gas, except for safety or conservation reasons as outlined in section 67 (1) and (2) of the Mines and Minerals Act.

The Final Report

Who was represented on the Coalbed Methane Multi-Stakeholder Advisory Committee? (the MAC)

  • The MAC represented a cross-section of Albertans with an interest in coalbed methane. Committee participants included Albertans from environmental, landowner and agricultural organizations, local governments, the energy industry, and provincial government departments and agencies. A full list of committee members is available in the Final Report.

What is the focus of the recommendations within the Final Report?

  • The Final Report submitted by the MAC to the government contains 44 recommendations on water, surface and air impacts, royalties, tenure, industry best practices, and non-specific CBM issues/broad energy topics.

When will work start on the recommendations?

  • Work has begun on all but one of the recommendations in the 2007/08 fiscal period.

How did the MAC develop its Final Report on CBM development?

  • The first MAC meeting was held January 2004 and they reviewed existing data relating to the development of CBM in Alberta, developed working groups on key issues, examined the feedback from eight public information sessions held in spring 2004 and invited the feedback of Albertans on their Preliminary Findings document, which was released summer 2005.

How was input from Albertans on the Preliminary Findings document incorporated into the Final Report?

  • The majority of the input from Albertans on the Preliminary Findings document supported the MAC’s recommendations. The underlying themes of the feedback included:
    • Protecting acquifers, particularly fresh water aquifers.
    • Minimizing surface disturbance.
    • Setting sufficient staffing levels for regulatory enforcement by officials with Alberta Environment and the Alberta Energy and Utilities Board (EUB*).
    • Improved communications.

*Note:  On January 1,  2008, the Alberta Utilities Commission Act split the EUB into two new regulatory bodies, the Energy Resources Conservation Board (ERCB) and the Alberta Utilities Commission (AUC).  The ERCB is responsible for the development of Alberta’s oil and gas resources and the AUC is responsible for the distribution and sale of electricity and natural gas to Alberta consumers.

Last reviewed/revised: 2008-07-11