Coalbed Methane Development

In Alberta, CBM is subject to similar drilling, production, and operational rules as other forms of natural gas.

Water

CBM development may, in some cases, have associated water production. If the well is drilled into a coal zone that is saturated with water, the water must be extracted to reduce pressure and allow the gas to be released. To date, little water has been produced in association with CBM development in Alberta.

The depth of the well plays a large role in determining the characteristics of the water produced. Shallow water wells typically produce non-saline (fresh) water. Deeper petroleum wells usually produce saline (salty water).

Handling saline water

Any saline water, in Alberta groundwater with more than 4,000 milligrams per litre of total dissolved solids, that is produced during gas production must be returned to a similar underground environment through deep disposal wells. The Alberta Energy Regulator (AER) regulates the production, handling, and use of water produced in association with natural gas, oil, and bitumen. AER Directive 65external link icon : Resources Applications for Conventional Oil and Gas Reservoirs and Directive 51external link icon : Injection and Disposal Wells provide more information on water disposal.

Handling non-saline water

If non-saline water is produced with gas, in addition to AER regulations, it must be handled according to regulations set out in the Water Actexternal link icon . The producer must be authorized by Alberta Environment and Parksexternal link icon to use, divert, or dispose of any non-saline water before the wells are drilled. Before authorization is granted, adjacent property owners, who would be impacted by the development, must be informed of plans to handle the water.

Aquifer protection

When drilled, a CBM well could pass through several groundwater aquifers. Well casing is cemented in place to protect groundwater aquifers. Well drilling, completion, and production requirements address how drilling fluids are handled, and prevent mixing water from different zones.  Alberta Agriculture and Forestry offers more information about Coalbed Methane Wells and Water Well Protectionexternal link icon .

Current water production in Alberta

Most of the current shallow CBM development in Alberta has not produced water. Some deeper projects in the Mannville zone mapPDF icon have produced saline water, and some Ardley test wells have produced small amounts of water of varying quality.

Well Spacing

CBM wells generally produce at low gas rates and low pressures. To optimize gas recovery from these wells, it may be necessary to locate the CBM wells closer together than some conventional gas wells. Closer well spacing is a long established practice in Alberta for oil and gas development, and it is becoming increasingly common throughout the province. Spacing for CBM wells could range from two to eight per section.

Standard gas well spacing for much of Alberta is one well per section per pool. However, standard spacing regulations provide for increasing well density through application to the AER. A significant part of the province, notably in areas of shallower gas development, has a common spacing of two to four gas wells per section per pool.

Regulations to reduce well spacing requirements

To reduce the spacing from set standards, an application must be filed to the AER in accordance with Directive 65external link icon : Resources Applications for Conventional Oil and Gas Reservoirs. Since August 2006, notification and the notification period of a well spacing application must be completed prior to filing an AER application (including Freehold mineral owners).

Best practices

Good land use practices, such as drilling multiple wells from a single location and aligning roads or pipelines along natural field breaks, can reduce surface disturbance. This also helps recover more gas from lower pressure wells. Industry commonly uses existing infrastructure and surface installations to minimize surface impacts and disturbance in areas that already produce conventional natural gas or oil. Industry has been consulted to develop a guideline of best practices for CBM development.

Techniques such as horizontal/directional drilling and well fencing can also reduce environmental impacts of denser well spacing and protect native prairie, sensitive environments, critical habitats, and important recreation areas.

Compression and Noise

Gas produced from CBM wells normally needs to be compressed so it can be transported by pipeline to market. Compressors may be located at well sites, but more commonly are located in a centralized location serving multiple gas wells. Companies are encouraged to take steps that will reduce the amount of noise.

  • Compressors with a total on site power over75 kilowatts (100 horsepower) must be approved by the AER. (see Directive 56external link icon : Energy Development Applications and Schedules).
  • Noise associated with compression in Alberta is regulated by the AER (see Directive 38external link icon Noise Control Directive).

Land Access

As with other natural gas development, a producer interested in developing CBM must get approval to access land from the landowner or land manager.

Access to private land

If a private landowner refuses to grant land access to a company granted a well licence by the AER, an appeal can be made to the Surface Rights Board. If it is determined the project is in the best interests of Albertans, the Surface Rights Board may grant access and may determine an appropriate amount of compensation to be paid by the energy company to the landowner.

Access to public land

An energy company seeking to develop CBM on public land may apply to Alberta Environment and Parks for access for a mineral surface lease or other surface access disposition. In some cases, a pre-existing disposition holder may need to grant consent for the company to access this land. If the company has a well licence and the pre-existing disposition holder denies consent, an appeal may be made to the Surface Rights Board. In the province's forested areas, the energy company may need to pay a Timber Damage Assessment charge as a condition of access.

Public Information

Public consultation requirements

When new energy projects are proposed, industry, regulators and the public must review the project's impact on current and future land use. Public discussions on specific project plans and options are often needed to fully understand and address impacts.

Energy developers must make all reasonable efforts to reduce environmental impacts, align development with existing regional strategies prepare, resource plans, and manage concerns about land fragmentation and local impacts.

Before a development application can be filed, the energy developers must consult with any parties who may be directly or adversely affected by the project. The requirements are outlined in the AER's Directive 56external link icon : Energy Development Application Guide and Schedules and Directive 65external link icon :Resource Applications for Conventional Oil and Gas Reservoirs.

An example of public consultation is the 2003, multi-stakeholder advisory committee (the MAC), their terms of referencePDF icon were set. It was established to review existing regulations and policies to ensure continued responsible coalbed methane development, preliminary findingsPDF icon were delivered in 2005. The MAC Final ReportPDF icon in 2006 contained 44 recommendations on water, surface and air impacts, royalties, tenure, industry best practices, and non-specific coalbed methane issues/broad energy topics. A second multi-stakeholder group (the MAC II) issued annual update reports in 2007PDF icon , 2008PDF icon and 2009PDF icon .

Well data

Since CBM is a form of natural gas, all CBM wells are licensed as natural gas wells in Alberta. This means that data on CBM wells, including produced fluid volumes and rates (oil, gas, and water) must be collected and reported to the AER in the same manner as occurs for other gas wells in the province. Also, produced fluids must be sampled and analyzed. All this information is public, according to standard data confidentiality provisions and regulations.

Test Wells

An energy company may apply to the AER for experimental scheme status in accordance with standard regulations. Under experimental scheme status, limited well information can be held confidential by the AER for 3 years. All data must still be reported to the AER for release at the end of the experimental scheme, or earlier if conditions warrant. All experimental scheme applications are public documents.

Links to more information on public information

Air Emissions

Flaring is the burning of natural gas that cannot be economically conserved. Venting is the release of natural gas to the atmosphere where conservation or flaring is not practical due to gas volumes being too small. The AER regulates flaring and venting according to the methods outlined in its Directive 60external link icon : Upstream Petroleum Industry Flaring Guide, they also offer a Flaring & Incinerationexternal link icon guide. Public notice of any extended flare testing is required.

Because CBM is predominantly clean-burning methane and contains no heavy hydrocarbons, the flares are similar to the flames that burn in home furnaces, except larger in scale.

Efforts by the Alberta government, the petroleum industry and stakeholder organizations such as the Clean Air Strategic Alliance (CASA)External link icon have reduced flaring by 62 per cent and venting by 44 per cent since 1996. In 2005, industry achieved a 96.3 percent solution gas conservation rate. 

Royalty

CBM is governed by the same royalty system as all other natural gas production on provincial Crown ("the Crown") land in Alberta. Energy companies producing on Crown land must pay a royalty to the province for oil and gas.

Royalty calculation

Royalty is the price that the owner of a natural resource (i.e. the Alberta government) charges
for the right to develop the resource. In 2010, the Emerging Resources and Technology Initiative was established to encourage the development of the province’s vast unconventional resources.

The amount of CBM royalties owed is calculated at the wellhead. As with all other types of natural gas production, the amount of royalty revenue collected on CBM production will be impacted by a number of factors, including current market gas prices, the amount of energy in the gas stream, and when the gas pool was discovered.

Since a gas producer produces and processes the Crown's share of natural gas and gas products, the Crown shares in the costs of gathering, compressing, and processing by providing cost allowances that are deducted from the amount of royalty to be paid. The Crown royalty on natural gas, natural gas products, and CBM is established under Natural Gas Royalty Regulation, 2009 and the Alberta Natural Gas Royalty Principles and Procedures, June 2003.  Current Royalty framework information is available.  

Tenure

Tenure is the process of leasing and administering petroleum and natural gas rights owned by the Province of Alberta.

The provincial Crown ("the Crown") owns 81 per cent of Alberta's mineral rights. The remaining 19 per cent are freehold mineral rights owned by the federal government on behalf of First Nations or in National Parks and by companies and individuals.

The Petroleum and Natural Gas Tenure Regulationexternal link icon governs CBM. There is no regulatory distinction between conventional natural gas and CBM land tenure.

Legislation

The Mines and Minerals (Coalbed Methane) Amendment Act, 2010 clarified that coalbed methane mineral ownership is and has always been natural gas, for both Crown and freehold minerals, providing certainty on ownership of coalbed methane in split title situations (News releaseExternal link icon ). The changes can be found in section 10.1 of the Mines and Minerals Actexternal link icon

Background

Split title occurs when separate parties own the coal and natural gas mineral rights under the same parcel of land.

During the 1800s and early 1900s some mineral rights were ‘split’ between coal and natural gas. When the mineral titles were originally split, coalbed methane ownership was not generally addressed. This led to uncertainty about whether the natural gas rights owner or the coal rights owner owns the coalbed methane. Split titles are estimated to be less than five percent of Alberta.

In 2003, the Mines and Minerals Act was amended to clarify that a Crown coal lease did not grant any rights to the natural gas, including coalbed methane. The amendment did not apply to freehold land which was addressed in the Mines and Minerals (Coalbed Methane) Amendment Act, 2010. 

Freehold Oil and Gas Issues Consultation

In 2009, a stakeholder consultation was undertaken on freehold oil and gas issues. Stakeholders who participated in the consultation represented individual freehold mineral rights owners, oil companies, natural gas companies, coal companies and associations. Freehold Oil and Gas Issues: Stakeholder ConsultationPDF icon (May 2009) considered the issue of split title ownership, as well as several other freehold issues.  

Details about the Mines and Minerals (Coalbed Methane) Amendment Act, 2010

The legislation contains several major provisions;

  • it declares that coalbed methane is and always has been natural gas, for both Crown and freehold minerals.
  • it honours existing agreements entered into by the natural gas mineral owner or their lessee and the coal mineral owner or their lessee in respect of coalbed methane. (existing agreements
    will not be affected.)
  • it protects coal owners or their lessee, surface owners, and the government from being
    sued by the natural gas owner or their lessee for past extraction, production or removal of coalbed methane.

Surface and mineral rightsexternal link icon are explained on the Land Titles Office website with Service Alberta.