While Canadian natural gas producers slow drilling until prices rise, and hungry field contractors cut service rates, an Alberta applied science agency with a long pedigree of success has set out to sow seeds for the next generation of production.
Vast shale deposits along the eastern side of the Rocky Mountains in Alberta and British Columbia are virtually a virgin frontier for industry. But the Alberta Research Council’s professional technology pioneers already know production can be truly hot stuff.
A “thermogenic” variety of shale gas, made by baking ancient organic material over long stretches of geological time, steams out of wells three kilometers (two miles) deep at 120 degrees Celsius (250 degrees Fahrenheit), or a higher temperature than boiling water. A “biogenic” type generated by decay bacteria at shallower depths is less hot to handle but no easier to make flow from hard rock formations that contain both kinds.
“They’re very difficult to explore. They’re expensive to exploit. That is the future,” said Blaine Hawkins, the ARC’s enhanced oil and gas recovery technology manager. “It’s a very subtle technology. It’s something that requires a lot more scientific knowledge,” said ARC energy division vice-president Ian Potter. Hawkins and Potter aim to plant the science in Alberta industry through a new partnership with an American arm of the Schlumberger services and technology conglomerate active in 80 countries. ARC will work with a Salt Lake City branch of the French conglomerate, TerraTek Geomechanics Laboratory, on breeding a hybrid of Alberta earth science and American experience.
Unlike in the United States where unconventional gas development was launched a quarter-century ago, driven by tax incentives and the industry’s need to replace depleted wells, shale is almost an untried target in Canada.
But the writing is on the wall in Alberta that it is time to start trying. The province’s conventional wells in freely flowing geological reservoirs have reached the turning point — peak output, followed by decline — that Texas and Louisiana passed in the early 1970s, the Energy Resource Conservation Board (ERCB) reports in its latest annual reserve review.
Conventional Reserves Declining
The ERCB and the National Energy Board, in their latest studies estimated Alberta’s original endowment of conventional supplies was 223 Tcf. Gas production, which pre-dated oil, started before 1900 and by 2016 the ERCB predicts gas production, will exhaust 77% of those conventional resources.
In 1990 the chief Canadian producing jurisdiction satisfied demand for its gas with 28,500 wells. The number has climbed to about 110,000 and continues to rise while only replacing about two-thirds of annual output. Production will taper off at a rate in the 2%/year range even if soft prices firm up enough for industry to afford 12,000 to 13,000 Alberta gas wells every year, the ERCB predicts.
Early signs of the depletion — shrinking drilling targets, accelerating well decline rates and dropping reserves replacement performance — prompted a coalbed methane rush. Before 2001 only 200 wells tapped Alberta coal seams for gas. The number jumped to more than 11,000 before the drilling boom stalled last year, reports the Canadian Society for Unconventional Gas.
But coalbed methane is only a first and short-term response to the onset of old age in conventional gas, Potter said. Shale gas is a far bigger resource. Alberta Energy estimates the province’s natural endowment at up to an astronomical 1,000 Tcf.
The new target, however, is locked up tight in natural counterparts to bank vaults. In Canadian earth science theory, as in the U.S., shale formations are also known as “source rocks” or cradles of oil and natural gas. The layers are thought to be descendants of clay ocean floors where remains of ancient organisms settled in an era when continental drift located Alberta, the core of the Western Canada Sedimentary Basin, at a much warmer place on the globe. Eons of earth movements buried and hardened the muck, and heat or decay bacteria turned the organic part of the stew into fossil fuels. Fractions of the resources migrated from the clay into porous formations of other sedimentary rock. But most stayed in the shale, spread over vast areas and prevented from moving by a lack of natural flow channels or low “permeability.”
New Variations of Fraccing
ARC’s collaboration with Schlumberger will focus on remote detection of rich deposits and new extraction methods. No long-range budget for the work is disclosed, with ARC planning to expand it by recruiting consortiums of production companies.
In Canada the field requires highly evolved forms of echo-sounding seismic surveys to pick targets in shale, which registers as featureless gray masses when examined by standard techniques. New variations on “fraccing” or making fractures in rock with high-pressure injections are also essential, Hawkins and Potter said.
Conventional Canadian fraccing materials are blends of sand and water or water-based chemicals that can do more harm than good in shale. Water makes clay swell, closing instead of opening flow channels. Injections to fracture shale employ light synthetic hard materials instead of sand, and cold compressed fluid forms of gases such as nitrogen and carbon-dioxide.
In their computer models at least, ARC scientists have devised a gas industry version of diamond cutting. Horizontal wells across gas-rich rock and frac injections of chemically correct materials, made at just the right pressure points in geological formations, break open man-made webs of gas flow channels.
Early trials of Alberta shale gas production are underway by firms such as EnCana Corp. and Stealth Ventures Inc., an industry newcomer that includes a former ARC vice-president, Potter said.
“One of the major roles of ARC is to look to the future,” Potter said. “In our view shale gas is an important energy source for the future — maybe not in the next three years, but in the longer term,” Potter said. “We need to understand the technology and costs. By the time we need shale gas we want to be ready for it,” the ARC executive said.
The agency’s long-range strategy follows a classic Alberta pattern of hybrid government and private enterprise. ARC’s first employee, Edmonton scientist Karl Clark, invented and patented the oilsands production process in the early 1920s. He died a few months before the first commercial plant started up in 1967. But the method caught on and the province’s current bitumen rush is fueled by refinements of Clark’s original approach by generations of industry-government technical partnerships.
©Copyright 2008Intelligence Press Inc. All rights reserved. The preceding news reportmay not be republished or redistributed, in whole or in part, in anyform, without prior written consent of Intelligence Press, Inc.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 1532-1266 |