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With Flaring Off Limits, Alberta Adds Gas Processing
Despite persistent surpluses, soft prices and an industry-wide switch of drilling targets to liquids, construction is beginning on the first large Alberta natural gas processing plant in recent industry or regulatory memory.
The project by Devon Canada Corp. highlights an Alberta difference that helps explain why the province’s natural gas supplies are only eroding by a slow annual average, in the range of 3-5%, instead of collapsing at an accelerating rate.
Generations of increasingly tight regulation enforce a general provincial prohibition against burning off natural gas, with waste incineration flares, in order to obtain more valuable liquid byproducts. Companies that want oil have to take any associated gas, too.
With increasing amounts of oil production, spurred by hydraulic fracturing (fracking), associated gas will slow the decline in Alberta’s natural gas production, according to a report published by the provincial Energy Resources Conservation Board (ERCB). Fracked oil production increased 14% in 2012, while oil wells directed to horizontal drilling and multiple-stage fracking increased by one-third (see related story).
Alberta has no counterpart to flares said to be visible from outer space in North Dakota, where the state mineral resources department has estimated that about 150 MMcf/d of unwanted gas from wells in the Bakken oil formation is being burned as waste.
The Canadian province also has no counterpart to heated debates among legislators, conservationists and oil companies over actions to put out or at least turn down the flames. Waste control is a settled issue in Alberta, where only small, unavoidable and temporary amounts of gas flaring are allowed in cases such as pressure releases by equipment safety valves during field emergencies. The provincial royalty regime includes provisions to encourage use of potential waste gas as fuel for oilfield hardware such as motors or small power generators.
Devon has no choice but to put associated new gas supplies on the market too. In a west-central Alberta area known as Ferrier — near Rocky Mountain House, a foothills resource industry town mid-way between Calgary and Edmonton — the new plant will add daily capacity for 100 MMcf of gas as well as 5,000 bbl of oil-like liquids.
Construction costs are undisclosed. But as owner of 375 square miles of mineral rights in the area, Devon has embarked on a long-range development program with thousands of potential drilling locations identified in promising central Alberta shale formations.
Putting a stop to wasteful gas flaring was the original job one of Alberta’s Energy Resources Conservation Board (ERCB) when the provincial legislature created the agency 75 years ago to impose order on an unruly industrial frontier. In the 1930s, oil fortune hunters lit up the sky south of Calgary with towering gas flares that burned up to 90% of the raw flows from wells in the province’s pioneer production field at Turner Valley. Overcrowded drilling locations acquired eloquently descriptive nicknames such as Hell’s Half Acre.
In addition to wasting an estimated 1 Tcf of gas, the practice destroyed a regional geological pressure cap, which was needed to tap oil that the embryo Alberta industry eventually discovered by drilling deeper at Turner Valley. Wells in the area petered out prematurely in the 1940s, and trials of potential well stimulation techniques using gas or fluid injections have yet to restore production to a deposit known to contain hundreds of millions of barrels of oil.
The ERCB this spring handed down a decision, rejecting a proposed drilling and production scheme, that stood out as a reminder to all concerned of the rule in Alberta: waste gas flaring is off-limits in the province. Privately owned Bernum Petroleum Ltd. ran afoul of the rule by planning to flare unwanted gas from two wells into an oily shale formation known as the Cardium, in an area 30 kilometers west of the industry capital of Calgary known as Lochend.
“Bernum submitted that its only option is to flare or incinerate the produced gas,” the ERCB said. “Bernum argued that, given the estimated volume of produced gas, the expected price of gas, the cost associated with possible tie-in locations, and the recoverable resources, conservation of gas is not economic at this time. Bernum also stated that if it were required to conserve the gas, it would not drill the wells.”
Even in the notoriously depressed conditions on current gas markets, which were emphasized by company projections, the ERCB verdict said, “the board does not accept Bernum’s negative conclusions regarding the economics of gas conservation. Further, the Board finds that economic analysis would support gas conservation when using the appropriate corrected factors, inputs, and discount rates.”
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