Horn River Basin Keeping Canada Hot

Nexen's summer frac operation in the Horn River Basin; new pipeline construction projects and export facilities in the region could guarantee improved transport of gas to global markets.
Nexen's summer frac operation in the Horn River Basin; new pipeline construction projects and export facilities in the region could guarantee improved transport of gas to global markets.

Canada’s Horn River Basin has been described as significantly larger than the Barnett shale area in Texas, which currently produces three billion cubic feet per day. Third-party estimates predict the Horn River area could hold 50-100 trillion cubic feet of natural gas, making it the hottest resource play in North America.

But anyone working in western Canada can attest that production and development of this resource is costly – and when it comes to transporting the resources to market, northeastern British Columbia is at the end of the proverbial pipeline.

What makes the Horn River competitive with other North American shale gas plays?

British Columbia offers a series of royalty credit programs that are helping to incentivize drilling activity in the province. And although most drilling sites are in remote locations, British Columbia’s reinforced road construction methods and unique well site drilling pads facilitate year-round drilling.

Plans for new pipeline construction projects and export facilities could guarantee improved transport to global markets.

In August, 16 companies doing business in British Columbia received royalty credit awards under the Infrastructure Royalty Credit Program totaling $115.6 million. They were Apache, Canbriam Energy, Cinch Energy, CNRL, Crew Energy, Encana, Encana-Questerre, Ironhorse-Grizzly, ISH Energy, Nexen, Pavillion, Ramshorn, Shell, Talisman and Taqua North.

British Columbia’s Minister of Energy, Mines and Petroleum Resources, Bill Bennett, instituted a series of innovative royalty deductions provided to companies in exchange for company investment in road and pipeline infrastructure projects that improve access to underdeveloped areas in British Columbia.

The royalty deduction programs provide incentives for infrastructure development, deep wells, marginal wells, remote drilling locations and wells drilled during the summer. These incentives are designed to provide enough profit margin to move technically complex and expensive-to-produce wells to economic viability, thereby making shale plays in British Columbia more competitive with other North American gas plays.

Year-round drilling is made possible with special drill site pads designed for the British Columbia climate and its pervasive “muskeg” environment – thick boggy layers of organic peat that forms a hard frozen surface in the winter but in summer are soft and wet. The credits also apply to reinforced road construction projects and well-site pads, and facilitate doing business during British Columbia’s wet, summer season.

The province encourages energy industry investment in general, and Bennett points to steps taken by the government and the ministry to streamline regulatory processes in helping to ensure a favorable return on investment in British Columbia’s natural resources.

“Shale gas plays in northeastern British Columbia may be a long way from market,” Bennett acknowledged, “but the British Columbia government has taken an open approach to ensure the country’s resources are competitive in North American markets.”

Evaluation and Strategies

Gas producing Devonian-Mississippian age strata in northeastern British Columbia have been described as thermally mature silicious shales. Shale gas production from the Horn River formation is well documented, along with the laterally equivalent Besa River, Muskwa and Fort Simpson.

Liard-Horn River-Cordova Basins schematic cross section.
Liard-Horn River-Cordova Basins schematic cross section.

Formation thicknesses of 500 feet and more represent enormous reservoir potential.

Rocks that are both silica rich and that have total organic content (TOC) of 5-plus percent are considered most favorable for shale gas reservoir exploration due to the rock propensity for enhanced fracturing of brittle, organic-rich and silica-rich facies, according to the integrated formation evaluation report of Ross and Bustin, University of British Columbia (AAPG BULLETIN, January 2008).

In other words, rock intervals that have higher carbonate and silica content may be expected to respond favorably to fracture stimulation.

Thanks in part to the credit program, Nexen Inc. has doubled its position in northeastern British Columbia to 90,000 acres – 10 percent of the company’s global holdings.

Ron Bailey, Nexen’s general manager for shale gas, describes the Horn River Shale as having “great rock quality – 50 percent thicker even than the Barnett.”

Bailey evaluates shale gas reservoir rock by five criteria:

  • Gas in place per section.
  • Estimated EUR per well.
  • Fracability – the Horn River Shale is a more fracable reservoir rock due to its higher silica content, two to three times greater than the Barnett Shale.
  • Gas quality – this is a negative factor in the Horn River Shale, having 10-12 percent CO2 that must be extracted before pipeline transport.
  • Reservoir productivity – the Horn River is highly productive.

“Nexen’s interest in the area has increased as we have learned more about production strategies,” Bailey said. “And by drilling larger programs, our costs have decreased while our confidence has increased.”

Nexen will soon deploy an eight-well drilling pad with an average of 18 fracs per well. According to Bailey, “Our frac program achieved an industry leading pace of 3.5 fracs per day.”

Pipeline Infrastructure

New pipeline construction projects are now under way or planned to connect British Columbia shale gas resources to global markets.

TransCanada kicked off construction Aug. 6 on the first pipeline to cross the Alberta-British Columbia border. The Groundbirch pipeline project will connect natural gas supplies in the Horn River Basin in northeast British Columbia to the Alberta system. The $200-300 million project is scheduled for completion by November 2012.

A planned Pacific Trail Pipeline will move gas from northeast British Columbia to Kitimat, British Columbia, where the Kitimat LNG export terminal will open to the rapidily growing economies of the Asia Pacific export markets.

Kitimat’s terminal is approximately 400 miles north of Vancouver, offering a shorter, less expensive shipping route across the north Pacific. Natural gas will be cooled and liquefied at the terminal for export via ship to growing, natural gas markets in South Korea, Japan, China and Southeast Asia.

“When completed, the Kitimat LNG export terminal will provide a new market-demand outlet for British Columbia, a critical factor in the commercial development of the Horn River shale gas play,” said Mike Dawson, president of the Canadian Society for Unconventional Gas.

Kitimat is designed to be linked to the pipeline system servicing Western Canada’s natural gas producing regions via the proposed Pacific Trail Pipelines, a $1.1-billion (Canadian), 300-mile (463-kilometer) project.

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Regions and Sections

Regions and Sections Column - Carol McGowen
Carol Cain McGowen is the development manager for AAPG's Regions and Sections. She may be contacted via email , or telephone at 1-918-560-9403.

Regions and Sections Column

Regions and Sections is a regular column in the EXPLORER offering news for and about AAPG's six international Regions and six U.S. Sections. News items, press releases and other information should be submitted via email or to: EXPLORER - Regions and Sections, P.O. Box 979, Tulsa, OK 74101. 

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Oriental Companies Look to Canada

South Korea, China and Japan aren't waiting for Western Canada's energy resources to arrive at their docks.

Investment dollars from companies like Korea Gas Corp. (Kogas), China National Petroleum Corp. (CNPC) and Mitsubishi offer North American companies operating in western Canada the opportunity to accelerate development and bring more of shale gas potential to market.

In March of this year, Kogas – considered the largest LNG import company in the world – signed a five-year deal with Encana, Canada's largest natural gas producer committing to spend US$1.1 billion to explore and produce British Columbia shale gas.

A few months later, Encana signed a memorandum of understanding with state-owned CNPC to negotiate a joint venture to develop Encana's Horn River and Montney shale-gas properties in northern British Columbia.

Beijing-based CNPC is the parent company of PetroChina Co.

Then in August, Mitsubishi, Japan's largest trading company, acquired its first interest in shale gas development by entering into a deal to acquire a 50 percent interest in the Cordova shale-gas project of Calgary-based Penn West Energy Trust.

Mitsubishi and Penn West plan to drill hundreds of wells in the Cordova Embayment area in northeastern British Columbia in the next 15 years, with a daily production target of 500 million cubic feet by 2014, according to an August Bloomberg report. As part of the transaction, Mitsubishi will pay $237 million of Penn West's exploration costs.

In each of these joint ventures, the principle company remains the operator in western Canada – but these partnerships are a win-win for both sides:

Asian investment helps reduce the cost and the risk of developing large tracts of land in gas-producing regions.

Asian partners help free up Western Canada operators to invest in more immediate priority plays.

Asian partner companies invest capital to earn an interest in the assets and gain technical knowledge while also helping to reduce their country's total dependence on imported oil.


Regions and Sections is a regular column in the EXPLORER offering news for and about AAPG's six international Regions and six U.S. Sections. News items, press releases and other information should be submitted via email or to: EXPLORER - Regions and Sections, P.O. Box 979, Tulsa, OK 74101. For more information about AAPG's Regions and Sections, contact Regions and Sections development manager Carol McGowen via email , or telephone at 1-918-560-9403.

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Interpretation of seismic data from the Sorvestsnaget Basin, southwest Barents Sea, demonstrates gradual middle Eocene basin infilling (from the north) generated by southward-prograding shelf-margin clinoforms. The basin experienced continued accommodation development during the middle Eocene because of differential subsidence caused by the onset of early Eocene sea-floor spreading in the Norwegian-Greenland Sea, faulting, salt movement, and different tectonic activity between the Sorvestsnaget Basin and Veslemoy high. During this time, the margin shows transformation from an initially high-relief margin to a progradation in the final stage. The early stage of progradation is characterized by the establishment of generally oblique clinoform shifts creating a flat shelf-edge trajectory that implies a gentle falling or stable relative sea level and low accommodation-to-sediment supply ratio (lt1) in the topsets. During the early stage of basin development, the high-relief margin, narrow shelf, stable or falling relative sea level, seismicity, and presumably high sedimentation rate caused accumulation of thick and areally extensive deep-water fans. Seismic-scale sandstone injections deform the fans.

A fully prograding margin developed when the shelf-to-basin profile lowered, apparently because of increased subsidence of the northern part. This stage of the basin development is generally characterized by the presence of sigmoid clinoform shifts creating an ascending shelf-edge trajectory that is implying steady or rising relative sea level with an accommodation-to-sediment supply ratio of greater than 1, implying sand accumulation on the shelf. This study suggests that some volume of sand was transported into the deep water during relative sea level rise considering the narrow shelf and inferred high rates of sediment supply.

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