Finding the best way to apply horizontal drilling and hydraulic fracturing poses the greatest challenge to producers trying to get a handle on how to commercially exploit rocks in the Exshaw/Bakken of Southern Alberta.
For all of the companies, including several majors, that have been active in the play, none has yet to proclaim a conclusive breakthrough, although some have hinted at encouraging results over the past three years.
But the drumbeat of optimism in 2011 has gone quiet over the past year, since people like Jon Noad, Murphy Oil’s exploration manager in Canada, told a conference last year that several companies were still trying to unlock the formation’s secrets after drilling 25 wells at a cost of C$7 million to C$12 million each.
“There’s been a decent amount of investment into this reservoir,” he said. “There’s a variety of sediments which you’re going to have to target (with the new techniques).
“The jury’s still out a little bit on the best way to drill into these rocks,” Noad said, suggesting that the reason many of the wells are non-commercial is tied to how they are completed, what kind of pressure has been applied to break the rocks open, what methods have been used to hold them open and where the wells have been targeted.
He said that of the other tight oil plays in Alberta which have been described as new are more accurately newly accessed plays that have been known for generations.
Early stages of development
In addition to the Alberta Exshaw/Bakken, Noad said many of Western Canada’s tight oil plays are still in the early stages of development.
The tight and shale oil revolution has spread across Western Canada, embraced by the success of the Cardium and Vikings plays, raising questions about what plays will be next in the production line-up, with the Exshaw/Bakken competing for attention among a formidable list that includes Duvernay, Muskwa, Nordegg, Second White Specks, Swan Hills, Beaverhill Lake and the Central Mackenzie Valley’s Canol shale in the Northwest Territories.
The monetary promise of these prospects has puts pressure on operators to assess the economic viability of the assets as early in the exploratory stages as possible and decide where the best bets exist.
Scrutinizing the geological potential, appropriate drilling and completion techniques and the most current well results will help determine the long-term production capability of the plays and whether they will be economically viable to exploit.
Multiple Exshaw operators
Canadian-side Exshaw shale operators noted in a report by Scotia Capital include Crescent Point Energy, Canadian Natural Resources, Encana, Nexen, ExxonMobil, Murphy Oil, Shell Canada, Penn West Petroleum, Argosy Energy, Blacksteel Energy, Bowood Energy (which is involved in a deal with Legacy Oil + Gas), DeeThree Exploration, Pace Oil & Gas (which is working on a merger with AvenEx and Charger Energy to form Spyglass Resources) and privately held Petro-Spirit Resources.
Companies developing the play in the United States include privately owned Anschutz Exploration, Newfield Exploration, Rosetta Resources, Abraxas Petroleum, Arkanova Energy, American Eagle, Compton Petroleum, Mountainview Energy, Passport Energy, Primary Petroleum and Stone Energy.
Specific current references to activities planned for the Exshaw/Bakken on company websites and in the latest capital program announcements are sparse.
‘Excellent source rock’
“The Exshaw formation in Alberta and northern Montana is a dark, organic-rich shale, an excellent source rock that has produced much of the oil found in conventional reservoirs in Alberta,” Brad Hayes, president of Petrel Robertson Consulting, told a conference.
He said it is the same age as the Bakken shale in the Williston Basin of North Dakota and Saskatchewan and has many of the same properties, with the exception of two key attributes of the Bakken that have yet to show up in the Exshaw.
Hayes said the distinguishing characteristics of the Bakken are a low permeability sandstone or siltstone bed in the middle that is a prospective tight oil reservoir and a target for horizontal drilling and, secondly, a tight siltstone in parts of the Exshaw that suggests overpressuring to the west, although the industry has yet to demonstrate that these factors are as well developed or extensive as in the Bakken.
He said the best methods of drilling and completion may vary as the reservoir conditions vary.
“We can’t tell yet whether the Exshaw will be as good as the Bakken,” Hayes said in suggesting that early signs point to a more difficult reservoir that will not be as productive.
He said the lands have largely been tied up by experienced companies, but, unlike the big flow rates reported from the Duvernay, there have been few conclusive disclosures of positive results.
Hayes predicted that while companies will continue to experiment and assess the pace may slow until bigger rewards are realized.
Differing views
Rick Morgan, senior exploration analyst with Canadian Discovery, noted that Murphy has posted success by placing wells in central Alberta’s Wabamun/Big Valley rather than the Exshaw, targeting the sweet spots.
He said production and test results by Murphy, DeeThree and privately owned TORC Oil & Gas suggest the Alberta/Montana Exshaw “may have some substance,” but it will need another year or so to see whether it stacks up against the Bakken in the Williston Basin.
Shell has been active on its 60,000 acres in the vicinity of Del Bonita in southern Alberta as it embarks on exploring the potential of the Bakken frontier light, tight oil play.
But a company spokesman emphasized that a “commercial operation must be economically viable, environmentally responsible and socially sustainable.”
Legacy Chief Executive Officer Trent Yanko said the Alberta Bakken has the attributes of a light oil resource play, but remains in the embryonic stage.
He said the industry has shown signs of converging on a solution, with a number of Legacy’s competitors yielding “very good well results. I think it got overheated initially. People have high expectations, but it was something that has never been tried before so it takes a little while.”
Yanko said Legacy wants to give the Bowood shareholders a chance to realize the potential they put in the play.
He envisions “multiple play types and multiple zones. It’s all for light oil. A lot of it appears to be over-pressurized.”
Accumulating reserves
Legacy, seen as a skilled strategist, is accumulating reserves at an impressive rate while it tests drilling and completion practices in the Turner Valley end of the Bakken play in pursuit of optimizing both production rates and capital costs.
The company said drilling to date has targeted infill locations testing areas of varying water cut, reservoir pressure, proximity to water injection and three different stratigraphic horizons.
It expects Turner Valley horizontal wells to produce at stable, low decline rates based on the production profile demonstrated by both the previously drilled wells, which have logged 64,000 barrels of oil equivalent in 14 months, 60,000 boe in 10 months and 33,000 boe in less than four months, with production trending higher.
The company’s overall proved plus probable reserves were evaluated at 94.16 million boe on Dec. 31, up from 87.99 million boe a year earlier, equating to a reserve life index of 14.8 years based on average production at the end of 2012. Production last year averaged 16,301 boe per day, up 29 percent from a year earlier and is forecast to reach 17,900 boe per day this year.
Legacy is also gathering a bank of knowledge and technical skill in Spearfish in Manitoba and North Dakota, North Dakota’s Bottineau County and various Bakken plays on the Saskatchewan/Manitoba border as it follows a course of leveraging technology.
For those tracking the more adventurous operators in the southern Bakken, Legacy should be on their list.
