Canadian liquids plays offer continuous upside

Canada is experiencing an uptick in economic prosperity thanks to an active oil and gas industry and the development of new conventional, unconventional, and heavy oil resources spurred by encouraging drilling incentives and a supportive regulatory environment.

Interest in the country’s vast and developing unconventional plays is attracting new investment opportunities despite low gas prices as operators have begun to derisk light, tight oil plays. Liquids drilling, which has proven to be economical for drillers while also limiting production out of dry gas plays, has helped to curtail the storage buildup in natural gas and has provided the industry with an end in sight to the North American gas glut.

This and other related topics about shale gas and oil were recently discussed at the inaugural DUG Canada conference and exhibition in Calgary, Alberta, Canada, in June.

Hot unconventional spots

Most Canadian plays have lower breakeven points, Glenna Jones, director of energy research for ITG Investment Research, told DUG Canada attendees. This is in spite of lower production rates, Jones said, adding that Canadian plays are shallower and the completions less intense. “Our gas wells generally produce at higher rates than our oil wells,” she said.

Jones likes Alberta’s Cardium play with its improved deliverability due to technology. Cardium wells produce gas, oil, and NGL, and almost all of the gas production from the well increases over time, she said. The average Cardium well’s breakeven point is $58/bbl at West Texas Intermediate (WTI) prices.

Northeastern British Columbia’s Horn River basin, which is composed of the Muskwa, Klua, and Evie shales, is one of the most attractive unconventional targets in North America. (Image courtesy of Apache Corp.)

Alberta’s Cardium formation already has produced 1.8 Bboe, and although the field is nearly 60 years old, it has the potential to produce at least 1 billion more.

In the past 18 months, operators have added approximately 70,000 boe/d and completely reversed the production decline of the light oil reservoir. Current drilling targets different play concepts: Wells are drilled in the interior of the old field, distal edges or halos are tapped, and wells are being aimed at tighter sands that lie below the main Cardium interval. The formation’s wells recover between 150,000 boe to 250,000 boe apiece, for capex of approximately US $2.4 million to $4.9 million.

About 10% of Canada’s rig fleet is working in the Cardium; to date, 1,500 horizontal wells have been drilled, and 1,000 of those have reported production.

“We are just scratching the surface [in the Cardium],” said Murray Nunns, president and CEO, PennWest Exploration. “Up to 17 billion boe remain in place, and we think there is another 1.1 to 2.6 billion boe of potential recovery at CAD $20 (US $20.56) a barrel finding cost.” That includes primary and secondary recovery. PennWest estimates that 5% to 10% of the remaining in-place oil will be recovered by primary methods and another 5% to 10% could be recovered by waterflood. “Also, we ultimately think there could be a COleg, and we’ve done enough experiments to believe it can be done and should be done at some point,” he said.

Increased focus on NGL production also has resulted in the Montney shale in British Columbia (BC) becoming the dominant play in Canada. According to Peter Howard, president and CEO of the Canadian Energy Research Institute, the play’s economic value is quite strong as it needs a minimum of 60 bbl/MMcf to be economic at gas prices of $1.87/Mcf.

Mayka Kennedy, acting chief engineer of the BC Oil and Gas Commission, added, “The Montney shale now has approximately 77 Tcf to 176 Tcf of marketable gas that resulted in the number of wells increasing from 94 wells in 2007 to 372 wells in 2011. Most of these wells are unconventional.”

The Montney has seen a total reversal in terms of well types as unconventional wells have increased from representing 15% of all wells in the play in 2007 to representing 86% of all wells in 2011. The BC Oil and Gas Commission reported there was a total of 535 Bcf of natural gas and 738,710 bbl of NGL produced in the Montney in 2011. The top producers in the play were Encana, Murphy Oil, Arc Resources, Shell Canada, and Talisman Energy.

Canada’s Exshaw oil play also looks promising; the formation has been associated with the US Bakken oil play, but the two formations are different. Exshaw wells are normal to overpressured, with IPs of up to 600 b/d vs. North Dakota Bakken wells IP at up to 1,500 b/d. One advantage of the Exshaw, however, is that the water cut appears to be no more than 5%, whereas the Bakken’s is closer to 30%. In addition, the Exshaw is less expensive to drill, with most wells only 1,554 m to 1,768 m (5,100 ft to 5,800 ft) deep, while Bakken wells are 2,438 m to 2,743 m (8,000 ft to 9,000 ft) deep.

“What puts the southern Alberta Exshaw play head and shoulders above? It lies above the Devonian Three Forks,” Murphy Oil Canada Exploration Manager Jon Noad said in Calgary. “The total organic content is up to 12%, and much of it is oil-prone.

“The Exshaw is not the Bakken, but several producing zones have been drilled horizontally, and they are very prospective. We hope to find the fracture corridors, and reducing completions costs is key.”

Horn River and Deep Basin

The Horn River basin has one of the thickest, most naturally fractured shale reservoirs on the continent, with high silica content. It also is highly fracable.

Because of the basin’s high-rate wells with lower decline rates and its relative proximity to Canada’s west coast, it will be ideal for LNG export, according to Ron Bailey, senior vice president, natural gas Canada, for Nexen Inc.

Third-party evaluators have estimated the company’s land in the Horn River and Cordova basins holds between 4 Tcf and 15 Tcf of recoverable contingent resources, while its land in the Liard basin contains an estimated 5 Tcf to 23 Tcf of prospective resources.

Southwestern Alberta’s Deep Basin is one of several important tight gas areas in North America. The basin is an immense permeability trap in lower Cretaceous sediments. About a dozen formations are entirely gas-saturated, with no mobile water. The Deep Basin is one of the largest sweet gas provinces in the world, and to date it has produced 11.1 Tcf.

Deep Basin rocks have several advantages over shales. The Cretaceous reservoirs have permeabilities ranging between 0.01 to 1 millidarcy, values that border on those seen in conventional reservoirs. They also have porosities between 5% and 10%, which ensures tremendous storage capacity. Well deliverabilities and reserves also have been increasing. As of June 2012, per-well costs are $1.85 million and estimated ultimate recoveries are 1.8 Bcf to 2.5 Bcf. The basin makes around 3.5 Bcf/d, according to Tourmaline President and CEO Michael Rose. Rose said with some recovery in gas prices, daily volumes could reach 5 Bcf.

“The Deep Basin has multiple targets, but not all of the zones will be successful because the reservoir quality varies, and that really matters,” Jones added. Nonetheless, all of the play’s wells are deemed to be oil wells, making them valuable even as some of them produce about 50% gas.

Looking east

BC’s Kitimat LNG export project represents the shortest shipping route to Pacific Basin LNG markets compared to other international energy markets. The average laden voyage to Asia is estimated at approximately 11 days. (Information courtesy of Kitimat LNG)

The relocation of the rig population from natural gas plays into rich gas plays due to low natural gas prices is driving the need for new pipeline infrastructure.

At present, TransCanada moves about 14 Bcf through its pipelines and manages approximately 380 Bcf of gas through its storage facilities. When the company’s Keystone XI pipeline is completed, the company will transport a total of 1.44 MMbbl of oil, which is about 40% of all Canadian oil production, according to Greg Lohnes, president of natural gas pipelines for TransCanada Pipelines. By 2020, he said, the country will produce about 17 Bcf/d, and export facilities will be needed to find new markets.

Developing export markets for Canada’s abundance of natural gas reserves will be a long-term goal for Canada and was a topic echoed by other speakers at the conference. Many producers see Asian markets as the best export targets, and efforts to construct and supply LNG export terminals are seen as the remedy for the country’s ultra-low gas production netbacks.

TransCanada supports any LNG project to be built in BC because the coast is a preferred connection point, Lohnes said. “The gathered gas can come from various resources, and that coast has the best proximity to Asia markets,” he explained.

According to another DUG Canada speaker, the Kitimat LNG export project in BC is the best bet for getting Canadian gas to foreign markets. Apache Canada Ltd., EOG Resources Canada Inc., and Encana Corp. are joint partners, and Apache will operate the facility, said Janine McArdle, senior vice president of gas monetization for Apache Corp.

Meanwhile, TransCanada plans to design, build, and operate its Coastal GasLink project to move approximately 1.7 Bcf/d across Canada. The 700-km (435-mile) pipeline will cost about $4 billion. Shell Oil, Kogas, Mitsubishi, and PetroChina will be partners in the project.

Alberta leads the way

Alberta Premier Alison Redford said in her keynote speech that unconventional resource development has the potential to make significant contributions to Alberta’s future natural gas supply as advancements in drilling and completion technologies allow for the cost-effective development of more shale gas resources. Indeed, the province is “seeing such tremendous opportunity and investment [from the oil and gas industry],” she said.

Approximately 11 Bcf/d of natural gas was produced in Alberta in 2010. However, shale gas development in the province is in its early stages, Redford said, with 250 producing shale gas connections made in 2009 and annual production of 7.8 MMcf/d.

"Development activities have been mainly concentrated in east-central Alberta with the Colorado group shales," but interest is growing in plays such as the Duvernay and Muskwa formations, Alberta Premier Alison Redford said. (Photo by Don Molyneaux, courtesy of Hart Energy)

Redford addressed risks facing Canada’s natural gas market, including the most recent drop in oil prices, which “has persisted to the point where we have to consider this, from our perspective, to be the new normal,” she said. As a result of steep price declines from $8/gigjoule (GJ) in 2005 to the then current AECO price of $1.65 to $2/GJ, natural gas producers are experiencing “challenging times.”

Nevertheless, Canada has many positive operating advantages, including lowest overall taxes; simple, high-quality regulation; availability of infrastructure; a highly skilled workforce; proximity to US markets; and an untapped opportunity to export LNG to Asian markets, she said.

According to Redford, the province’s conventional natural gas industry is expected to contribute between $746 billion and $861 billion in GDP to the Albertan and Canadian economies, respectively, in the next 25 years. And, for the first time in provincial history, Alberta exceeded $3 billion in petroleum and natural gas land sales for calendar year 2011. The record land sales were the result of new drilling initiatives introduced by the Alberta government to encourage developing unconventional and challenging reservoirs, including tight gas, shale gas, and coalbed methane.

With a nod to the Canadian Society of Unconventional Resources’ 10th year anniversary, Redford added, “The efforts to increase awareness about unconventional resources in Canada have been instrumental in the development of a flourishing energy industry.”