HOME PAGE SUBSCRIPTIONS, Print Editions, Newsletter PRODUCTS READ THE PETROLEUM NEWS ARCHIVE! ADVERTISING INFORMATION EVENTS PETROLEUM NEWS BAKKEN MINING NEWS

Providing coverage of Alaska and northern Canada's oil and gas industry
August 2010

Vol. 15, No. 32 Week of August 08, 2010

Alberta claims gas experience counts

Trails British Columbia in shale gas development; cites track record of regulating gas E&P; hopes it can avoid US shale debates

Gary Park

For Petroleum News

However much Alberta might be trailing British Columbia in the development of its shale gas — which could exceed 1,000 trillion cubic feet — the province is confident it has a long enough track record of regulating gas exploration and production to handle development of the resource.

Environment Minister Rob Renner, amid speculation that producers recently spent more than C$450 million to round up shale exploration rights in the Peace River Arch area of northwestern Alberta, said his government is hopeful it can avoid the contentious debates that are erupting in the United States over the potential environmental impacts of hydraulic fracturing that is an integral part of shale production, along with the use and contamination of water supplies.

He said the “significant” experience accumulated in Alberta from conventional gas development gives the province an edge over jurisdictions that have not had that opportunity.

But Renner concedes “we have to keep an eye on the issue, we have to ensure that we’ve got the appropriate technology in place and that we protect our precious resource that is ground water.”

“We will continue to keep an eye very clearly focused on technology (related to the protection of ground water) as it progresses and moves into Alberta,” he told an unconventional oil and gas forum in Calgary.

15 prospective formations identified

The Alberta Geological Survey has identified about 15 prospective shale gas formations in the Western Canada Sedimentary basin, although the Alberta government is unwilling to get drawn into forecasting the eventual scope of the resource until it has decided what regulatory measures are needed for large-scale commercial development.

The pressure on the government includes regulations governing the use of surface water in drilling; the pumping of water into tight and shale gas formations for reservoir stimulation; the production of water from reservoirs where it occurs naturally, but is not drinkable; and the penetration of ground water aquifers by wells drilled for gas production.

It helps Alberta that Encana and Talisman Energy have extensive shale gas experience in British Columbia and across the United States.

Jim Fraser, Talisman’s senior vice president of North American operations, said each play has different nuances in the supply, usage and disposal of water.

He said the Pennsylvania Marcellus play uses surface water from creeks and rivers; Eagle Ford in south Texas drills water supply wells; and northeastern British Columbia takes surface water as well as drawing water from a large lake.

But the mounting concerns over the gas industry’s impact on water have prompted the Environmental Protection Agency to study the effects of fracturing on groundwater, targeting early findings by late 2012.

Aside from the water-related issues, access to equipment and sand impose further burdens on development of the Horn River basin in the far northern reaches of British Columbia, says a report by investment dealer Peters & Co.

But the analysis estimates Horn River production could reach 5 billion cubic feet per day by 2020, assuming about 290 wells are drilled annually over the next decade to develop about 24 trillion cubic feet of gas resource.

At that level it would need 7.1 crews and hydraulic horsepower of 151,200; raising the target to 400 wells would require 10.1 fracturing rig crews and 403,200 in hydraulic horsepower.

Volumes of water an issue

The volumes of fresh water consumed in fracture stimulating just one Horn River well can be as high as 180,000 cubic meters, or the equivalent of 72 Olympic-sized swimming pools — levels that Peters & Co. said “are not sustainable.”

In addition, water needs to be heated during winter, which “presents an enormous cost to operators,” which will likely accelerate the trend towards summer fracturing programs.

The study said its base-case Horn River well, assuming 12 fracture stimulations per well, requires about 200 metric tons of sand per stimulation interval.

The flip side of the Alberta-British Columbia argument was laid out by David Smith, executive vice president at Keyera Facilities Income Fund, who said planning for British Columbia’s gas processing needs will hopefully avoid what has happened in Alberta, where more than 700 processing plants are working at about 50 percent utilization rates.

He urged producers to take a longer-term view in the design and development of processing facilities as they decide whether to proceed on their own or through third parties.

Smith said producers such as Encana are “more comfortable with third-party sourcing,” while Talisman likes to take control.

“The challenge for the industry is to make sure that competition doesn’t lead to over-investment in under-utilized facilities,” he said.






Petroleum News - Phone: 1-907 522-9469 - Fax: 1-907 522-9583
[email protected] --- http://www.petroleumnews.com ---
S U B S C R I B E

Copyright Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA)©2013 All rights reserved. The content of this article and web site may not be copied, replaced, distributed, published, displayed or transferred in any form or by any means except with the prior written permission of Petroleum Newspapers of Alaska, LLC (Petroleum News)(PNA). Copyright infringement is a violation of federal law subject to criminal and civil penalties.