There’s no need to overhaul Alberta’s natural gas development rules to accommodate increasing coalbed methane development, say the province’s energy regulator and industry players.
Members of the public, however – including rural landowner, agricultural, municipal and environmental groups – say the adequacy of current gas-development regulations is their biggest concern about the expanding industry.
Existing regulations “provide the protection that we believe is required for the development of coalbed methane (CBM),” says Neil McCrank, chairman of the Alberta Energy and Utilities Board (EUB).
The EUB is prepared to adjust some rules if necessary as the industry grows, McCrank told the fifth annual Unconventional Gas and Coalbed Methane Conference, held in Calgary last week.
While the province has “very good regulations,” there is a need for closer co-operation among the industry, government regulators and all stakeholders, says Michael Gatens, chairman of the Canadian Society for Unconventional Gas, the industry group that presented the conference.
“We as an industry, we as a community . . . need to work more closely together to try to harvest that resource for the greater community in a way that works better for everybody,” said Gatens, who’s also the chief executive of MGV Energy Inc., a CBM developer in Alberta.
Conference co-organizer Mike Simpson, CBM manager at Nexen Inc., says Alberta’s framework for regulating development of hydrocarbons “is probably the best in the world.”
“The key is that we follow those regulations and, if we can, out-perform them if it makes sense from the industry point of view,” Simpson said.
Extraction of coalbed methane – the natural gas trapped in underground coal seams – is expanding in Alberta. Up to 700 CBM wells have been drilled, and 600 to 1,000 drilling applications are expected next year.
An EUB report released earlier this month says Alberta has 500 trillion cubic feet (tcf) of potential CBM reserves, although not all can be economically developed. In comparison, the province has an estimated 42 tcf of conventional natural gas reserves left.
Alberta’s fledgling CBM industry hopes to be producing up to one tcf per year of gas by 2010, industry players told the conference, which attracted more than 460 people.
Other Alberta companies active in CBM include EnCana Corp., Burlington Resources Canada Ltd., Husky Energy, Shell Canada, Talisman Energy, Enerplus Global Energy Management, ConocoPhillips Canada, Penn West Petroleum, Canadian Natural Resources, Trident Exploration Corp., and Spirit Energy.
Alberta Energy is leading a cross-department government team that is reviewing existing provincial policies and regulations to ensure they will protect the environment while allowing responsible CBM development.
In advance of a province-wide public consultation, the team met last month in Calgary with various groups. These stakeholders identified the adequacy of current provincial regulations as their chief concern about CBM development.
“We feel somewhat protected” by Alberta’s regulations compared with those in the U.S., especially in Wyoming’s Powder River Basin where CBM development in the past has caused serious environmental problems, Don Bester, a director of the Butte Action Committee of landowners, told the conference.
But there are areas where Alberta’s regulations need improvement, Bester said.
For example, other concerns identified include – in order of priority – CBM’s impacts on groundwater, effects on land, the lack of data and Alberta-based research about coalbed methane, and the need for more communication and education for the public.
The Canadian Society for Unconventional Gas devoted a day of last week’s three-day conference to stakeholder issues – for the first time in the event’s history.
Mary Griffiths, a researcher with the Pembina Institute for Appropriate Development, noted that the province is lacking data on underground aquifers. Landowners worry that pumping water out of coal seams to get at the gas could lower aquifer levels and affect their wells.
Alberta needs a policy to ensure landowners won’t be left without water if something happens to their wells, Griffiths said.
Unlike coal formations in the U.S. that can contain enormous volumes of this “produced water,” CBM deposits being explored in Alberta have so far produced little or no water – although that’s likely to change with more development.
Another concern is that Alberta – unlike B.C. – allows the venting or unburned release of CBM gas emissions.
The EUB’s McCrank responded that the goal in Alberta is to eliminate both the venting and flaring of gas emissions, although this might not prove economically feasible.
The Pembina Institute, in a recent report, also recommended that CBM projects in Alberta be subject to full-scale environmental-impact assessments depending on their size and impact. Provincial legislation currently exempts CBM projects from such assessments.
Regulators haven’t acted on Pembina’s recommendation, nor has the industry supported it. “Industry obviously doesn’t like the idea,” Griffiths said.