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Tight Oil Resource In Canada, U.S. Estimated At 6.48 Billion To 8.36 Billion Bbls
By Pat Roche
Low-permeability formations in Canada and the United States could contain 6.48 billion to 8.36 billion bbls of technically recoverable oil, a Calgary conference heard this week.
Contributing the biggest share of the technically recoverable tight oil resource is the Bakken formation of North Dakota, Montana and Saskatchewan with an estimated 3.65 billion to 4.3 billion bbls, said James Sorensen, senior research manager at the University of North Dakota's Energy & Environmental Research Center (EERC) in Grand Forks.
The estimates -- which Sorensen discussed at a Petroleum Technology Alliance Canada (PTAC) tight oil and gas forum -- were compiled from a variety of sources, including the U.S. Geological Survey, the U.S. Department of Energy and state agencies.
The second-biggest to the fourth-biggest (depending on whether the low or high range of the estimate is used) is the Cardium formation of Alberta with 660 million to 1.89 billion bbls of technically recoverable oil.
"The Eagle Ford in Texas is at 900 million bbls [of estimated recoverable oil resource], based on what I was able to come up with in reasonable sources [and] by talking with folks in industry," Sorensen said, adding that people working in the Eagle Ford "feel pretty strongly that's actually got the potential to be on par with the Bakken."
Recoverable oil resource in the tight Monterey formation in California is estimated at 718 million bbls, but Sorensen noted this play faces "a lot of regulatory issues."
He said other tight oil plays to watch are the Niobrara in Colorado and Wyoming (240 million bbls of recoverable resource), the Atoka-Cherokee in Colorado (146 million bbls) and the Mancos in New Mexico (75 million bbls).
There's definitely a lot of activity going on in those. And as more work is done, I think those numbers may go up as well," Sorensen said.
Though best known for shale gas, the Barnett shale in Texas is also estimated to contain 56 million bbls of recoverable oil resource.
Sorensen's smallest estimate of technically recoverable resource is for the Exshaw (Bakken equivalent) formation in Alberta and Montana (30 million bbls of oil), but that play is in its infancy.
On the production side, the leader has been the North Dakota Bakken/Three Forks, which produced more than 350,000 bbls a day last year, up from less than 50,000 bbls a day around the middle of the last decade, he said.
The Bakken in North Dakota is deeper, which makes exploitation more capital intensive, but initial production (IP) rates are higher. "To see an IP over 1,500 bbls a day is not uncommon," Sorensen said.
As in Canada, North Dakota Bakken wells have steep decline curves during their first year of production, but Sorensen said the wells continue to remain economically viable. While cautioning it's too soon to say what the cumulative production may be for a North Dakota Bakken well, Sorensen said he is "almost ready" to concur with estimates of 500,000 bbls of oil.
North of the border, Bakken oil production climbed to a peak of 64,000 bbls a day in Saskatchewan and 16,000 bbls a day in Manitoba, said Ken Brown of the Regina-based Petroleum Technology Research Centre (PTRC). He said Saskatchewan's Bakken output recently fell, but attributed this to the months of extremely wet weather and flooding that halted field activity.
Sorensen expects tight oil production from the North Dakota portion of the Bakken and Three Forks formations will average 500,000 bbls a day next year. That sounds like a safe bet as the state's total oil output reached a record 444,000 bbls per day in August (DOB, Oct. 14, 2011).
In fact, Sorensen said some analysts are predicting North Dakota's Bakken/Three Forks oil output will climb as high as 800,000 bbls a day.
Considering that the recovery factor in the Bakken is only one to two per cent, an increase of a couple of percentage points would translate into a huge increase in production.
"There's already operators out there looking for ways to bump that up," Sorensen said. "And I'm sure that the history of the oil production industry will tell you that will happen." He said technologies to boost Bakken recoveries may include carbon dioxide injection and even polymer flooding.
Some people like to refer to Bakken oil as "shale oil" -- which can be confused with synthetic oil coaxed from kerogen-bearing rock, or "oil shale," that has yet to yield large-scale commercial production. In fact, most of the Bakken's oil isn't even from the shales, Sorensen pointed out.
"The actual bulk of the [Bakken oil] production is coming from some of these low-permeability siltstones, sandstones and carbonates that are closely associated with [Bakken shales]," he said.
In fact, attempts to crack the Bakken in North Dakota early last decade didn't pan out initially because operators were targeting the actual shales, Sorensen said. At the same time operators in the Elm Coulee field in Montana were successful because they targeted the non-shale lithofacies of the Middle Bakken member.
In Texas, Eagle Ford tight oil output was about 77,000 bbls a day last year and is rapidly expanding, Sorensen said.
He predicts combined Canadian and U.S. tight oil production will exceed two million bbls a day in 2020 and will still be at that level in 2050. A comparable figure for current production wasn't offered.
However, with the boom in tight oil development has come challenges. Chief among these is the perception that fracture stimulation is harmful to the environment.
In North Dakota -- depending on the number of stages -- fracture treatments seem to require from roughly one million to five million gallons of fresh water per well, Sorensen said.
How much water is that? Not a lot in the larger scheme of things, he suggests.
He said one of his colleagues at the EERC whose expertise is in water resources calculated that all the water used on all the Bakken/Three Forks frac jobs in North Dakota in the past year "equated to taking less than an inch of water off of Lake Sakakawea, which is a big reservoir in the middle of the state."
But when local residents or out-of-state reporters see the long line of trucks queued up to take water, they get a different impression. He listed flaring and traffic jams in rural communities as other lightning rods for criticism of tight oil development.
Regarding whether hydraulic fracturing will be subject to more regulation, he said a key question is what the U.S. Environmental Protection Agency plans to do.
"I've personally seen a presentation made by the head of the EPA where she made it very clear that she intends to go after [hydraulic fracturing]," Sorensen said. "If you look at some of the things that have been coming out of the Obama administration in the past six months, they're clearly going after [fracturing]. If you look at things that are in the media -- New York Times, NBC News -- all these folks going after [it]."
He said industry is well equipped to deal with the straightforward technical challenges -- such as improving frac fluids and proppants. But "I think some of the less straightforward things are going to be what I call challenges of perception, [which is] something we need to keep in mind."
Many big companies abandoned U.S. onshore oil and gas decades ago, and shifted their spending offshore and overseas. Nonetheless, U.S. onshore oil production averaged 2.37 million bbls a day last year.
Stripper wells -- those producing 10 bbls a day or less -- account for roughly 280,000 bbls a day of U.S. output, Sorensen said.
U.S. federal and often state tax breaks enhance the viability of these wells that would otherwise be shut in, though there is concern the federal incentives could disappear as Washington seeks ways to boost tax revenue, Sorensen said.
"And if the politicians ... want to take the tax breaks away ... that is not an insubstantial amount of oil that's going to be taken off the marketplace."
He said it's also important that states look at tweaking some of their regulations and guidelines to enhance oil recovery from mature fields. Washington provides subsidies such as research grants to improve recovery from aging domestic fields.
Sorensen said U.S. production from enhanced oil recovery last year totalled 1.8 million bbls a day. This was mostly from waterfloods but includes about 260,000 bbls a day of oil produced through CO2 floods.