“In this age of unconventionals, the United States and Canada find themselves awash in an unprecedented energy wealth few could have imagined even a decade ago,” said Joe Oliver, Canada’s minister of natural resources, in a presentation at IHS CERAWeek in March.
Energy wealth sounds like a boon, but in Canada’s case, it’s a double-edged sword. With its neighbor to the south becoming more self-sufficient, Canada is worrying about losing its only natural gas customer. Canada is the fourth-largest exporter of natural gas, according to the U.S. Energy Information Administration, but all of its natural gas exports are sent to U.S. markets via pipeline. With demand in the U.S. down—and therefore natural gas prices are depressed—operators in Canada are looking to liquids-rich plays to keep profits up and diversify their assets until the infrastructure is developed to get dry natural gas to new markets.
“We are seeing strong growth in the liquids-rich areas of the Montney tight-gas play,” said Simon Mauger, director for gas supply and economics at Ziff Energy. “Lower value dry gas plays such as the Horn River and Liard plays will see only limited development until new markets for Western Canadian gas are accessed.”
Working toward LNG
The most talked-about way Canada might access new markets is through proposed LNG facilities on the west coast.
“Market diversification will be crucial to the ongoing health of the Canadian natural gas industry,” said Encana Corp. spokesman Doug McIntyre. “To put it frankly, Canada’s traditional customer, the United States, no longer needs us to the extent it once did. At the same time, Asian energy demand is rising, projected to more than double by 2020. It is clear that market diversification through the export of liquefied natural gas to the growing Asian market will be key to the continued viability of Canadian industry.”
Eleven LNG projects are in the regulatory approval process, Oliver said, and they have the export potential of 165 MMmt of LNG annually. Chevron and Apache’s Kitimat LNG project in British Columbia (B.C.) is the most advanced of the proposed Canadian LNG projects and could be the first LNG project of its size in Canada to deliver LNG to the Asia-Pacific markets. Chevron Canada Ltd. and Apache Corp. signed a 50/50 joint venture agreement to build the project in December 2012. Plans are moving ahead, with the engineering, procurement and construction contract for the LNG facility awarded in January 2014, but the cost of a project this size is daunting. Apache is looking to sell part of its stake to offset the cost.
Shell also has a project in the works in Kitimat with Asian partners Korea Gas Corp., Mitsubishi Corp. and PetroChina Co. Ltd. Canada’s Financial Post, however, reported that this project could be delayed by the desire of Shell’s new CEO to reduce spending.
Licenses have been awarded for other proposed LNG projects in Western Canada, such as Pacific Northwest LNG, Prince Rupert LNG, WCC LNG and Woodfibre LNG, but no one’s going to get to the finish line without a time and money commitment.
Taxes on LNG exports are adding to the price of these projects. B.C.’s government proposed an LNG income tax in February 2014 that could top out at 7%, which may be too high for operators who are already investing billions to get these projects off the ground. Some companies are waiting until legislation is finalized in the fall before making a final investment decision on proposed LNG projects.
Drilling potential also may slow down progress. “Renewal of the U.S. rig fleet is well underway, replacing old low-tech rigs with new automated fit-for-purpose walking rigs,” Mauger said. “This equipment replacement is just picking up steam in Canada.” Canada will have to ramp up the equipment and people necessary for the drilling activity needed for LNG exports.
The looming potential for LNG exports means gas production won’t stop completely and may eventually see rates above those in the past. “LNG exports would provide access to new markets, and gas production in the next decade could be higher than the previous peak,” Mauger said.
Liquids focus
But until these LNG projects are operational, many companies are turning to liquids to provide needed diversification to their portfolios.
“In [Encana’s] case, we are focused on growing liquids production to build greater commodity diversity in our portfolio,” McIntyre said. “In terms of our broader strategy, we plan to unlock value from our resource base to build a portfolio of oil, natural gas and natural gas liquids that provide us with a range of high-margin investment options through commodity price cycles.”
Apache Corp. recently sold some of its dry gas-producing properties in B.C. and Alberta but maintained rights to the liquids-rich Montney. “The sale of these natural gas assets—and other Canadian gas-producing properties sold last year—will permit Apache’s Canada region to concentrate on liquids-rich opportunities that can provide more attractive rates of return and more predictable production growth,” said G. Steven Farris, Apache’s chairman, CEO and president in a news release.
Artek Exploration Ltd.’s 2014 planned capital program also will focus on liquids—it includes nine to 10 wells in the condensate-rich Inga/Fireweed area, including seven Doig horizontals and up to three Montney horizontals.
Husky Energy is concentrating on oil resources and gas plays with high liquids content such as the Duvernay, Montney, Cardium and Wilrich formations. It is planning to double production at its liquids-rich Ansell project in the Cardium.
Montney activity going strong
The Montney Tight Sand Play, which straddles the Alberta/B.C. border, has become the focus of activity in B.C., according to Hart’s North American Shale Quarterly (NASQ). It also is the play with the most ongoing industrial activity in Canada in terms of number of players, drilling activities and foreign investors. The play has attracted attention from operators in the region as areas such as Tower and Ante Creek have shown liquids-rich hydrocarbon content.
The Middle Montney Formation, which until now has only been targeted for 13% of the total wells drilled in the play, has been confirmed for NGL production, so it will likely see more activity.
Canadian Natural Resources Ltd. is the largest landholder in the play with more than 1 million net acres. The company explored options to monetize or joint-venture a portion of its Montney acreage in the liquids-rich fairway of Northeast B.C., and though it received a number of expressions of interest in the acreage, the company decided none of the expressions were sufficient and it retained the acreage.
Encana Corp. trails Canadian Natural Resources closely in terms of Montney acreage, with around 1 million net acres. Encana has recently adjusted its strategy to focus 75% of its planned $2.4 billion to $2.5 billion capital investment in 2014 on five oil and liquids-rich assets, two of which are in Canada—the Montney and the Duvernay. In the Montney, the 2014 plan is to accelerate development of the oil and liquids-rich areas in the play, specifically the Gordondale, Pipestone and Tower areas, according to McIntyre.
The Canadian arm of Malaysian national oil company Petronas has the play’s third-largest holdings, recently acquiring acreage from Talisman Energy. Arc Resources has increased its land holdings with additions at Ante Creek and Attachie.
NASQ estimated that the Montney will produce at an average annual rate of 93.7 MMcme/d (3.31 Bcfe/d) in 2014, and its total production rate will double by 2020. Long-term growth will likely be driven by the demand for diluent liquids in the Alberta oil sands region and by potential LNG exports down the road.
Duvernay continues development
The Duvernay Shale in Alberta continues to attract attention as an emerging unconventional play since the industry first started developing the area in 2010, largely because of its potential to produce liquids. The Duvernay consists of a dry gas window, a wet gas/condensate window, and a liquids-rich window, moving from gas-prone in the southwestern part of the shale to more liquids-rich to the northeast, where most current exploration activity is taking place. The industry seems to have segmented the play into two areas: Kaybob in the north and Willesden Green in the south. The Kaybob has seen the majority of activity, with operators reporting that this area has superior porosity and permeability. NASQ estimates an average gas fraction of 55% in the Duvernay, but it varies significantly within the play.
The industry holds almost 3.9 million net acres in the Duvernay. Canadian Natural Resources holds about 500,000 net acres; Athabasca Oil Corp. and Talisman Energy each hold about 350,000 net acres.
NASQ has forecast production from the Duvernay in 2014 at 51.38 Mboe/d. By 2018, that number is expected to jump to 260 Mboe/d.
The Duvernay has seen more than 100 wells drilled and more than 150 wells licensed as of the fourth quarter of 2013, according to NASQ estimates. Results released from wells drilled have affirmed the play’s commercial viability, and the potential for liquids has brought in attention from both junior and major operators.
Chevron Canada Ltd. concluded an initial 12-well exploration drilling program in the liquids-rich portion of the play. “Well performance and condensate yields exceeded our expectations,” said Jeff Shellebarger, president of Chevron North America Exploration and Production Co., in a news release. “Near-term plans include transitioning to a two-rig drilling program to optimize well and completion design and full-field spacing requirements.” Liquids yield for the first five completed wells of the program range from 30% to 70%, with initial production rates up to 212 Mcm/d (7.5 MMcf/d) of gas and 1,300 bbl/d of condensate.
Encana’s 805 well had a 160-day production rate of 350 bbl/d of field condensate and 56.6 Mcm/d (2 MMcf/d) of natural gas, and its 931 Simonette well has been completed and reported to be producing at a rate of 1,100 bbl/d of field condensate and 127 Mcm/d (4.5 MMcf/d) of natural gas after seven days. McIntyre said Encana is moving into full resource play hub development mode in the Duvernay with pad drilling in the Kaybob, and it is continuing to evaluate the Willesden Green area.
Talisman Energy drilled three wells in the Duvernay during 2013. Two of the wells in the south Duvernay had seven-day average rates of 79 Mcm/d (2.8 MMcf/d) of gas and 730 bbl/d of condensate and 45 Mcm/d (1.6 MMcf/d) of gas and 365 bbl/d of condensate, respectively. The company said in November 2013 it will look for a partner to help develop its properties in the play.
Looking ahead
What direction is the Canadian unconventional industry headed? “Up,” Mauger said. The main restrictions the industry currently faces are infrastructure and markets—two challenges Canada is addressing to make North America’s energy wealth work in the country’s favor.