Tipping PointEvolving Technology Opening Doors For New Oil Resource Plays
By Elsie Ross
While there's a finite amount of oil to be extracted from the Western Canadian Sedimentary Basin, with new technologies, new ideas and innovative people there will still be great long-term opportunities with the right assets, an investment conference heard this week.
"Quite frankly all the easy stuff has been found, all the easy stuff has been produced and it's going to take newer and better technologies to unlock whatever is left," John Wright, president and chief executive officer of PetroBakken Energy Ltd., said during a panel session at the Peters & Co. Limited conference.
In the session, Wright along with CEOs from Legacy Oil +Gas Inc., Baytex Energy Corp., Bonterra Energy Corp. and Trican Well Service Ltd. discussed technology changes in oil resource play developments.
PetroBakken, whose Bakken assets were spun off from Petrobank Energy and Resources Ltd., was set up less than two years ago. The idea was that if leading-edge technologies were applied to some of the evolving resource plays in the WCSB, the company could generate significant long-term sustainable growth and that dividend yield could also grow over time in a strong price environment, said Wright. With its Bakken assets now a "cash cow," PetroBakken is now pursing similar objectives in the Pembina Cardium.
Legacy, whose main focus is the Williston Basin, was created in 2009 specifically to take advantage of advances in light oil development such as horizontal wells and multi-stage fracturing, said CEO Trent Yanko, president and CEO, whose previous company, Mission Oil & Gas Inc., was at the forefront of light oil resource development, mainly in the Bakken. "We have a lot of plays that are technology driven, that are using multi-staged fracking, enhanced recovery techniques, in this case waterfloods, to get more oil out of the ground," he said.
Legacy is interested in large oil-in-place accumulations with low recovery factors where every small increase in the recovery factor leads to a big change in reserves.
At Turner Valley, "the application of an unconventional technology in a conventional field is leading to a lot of value creation," said Yanko.
While some horizontal wells were drilled more than a decade ago, Legacy thought that changing the completion techniques from standard open hole to multi-stage acid fracking would greatly improve the economics of horizontal drilling. It drilled some vertical wells, and then did some fracking to understand the reservoir parameters before applying that to an understanding of the unconventional component of the completion. In February, Legacy recompleted an existing horizontal well that had been producing 25 bbls of oil equivalent per day. Initial production from the well was 110 boe per day and it is still producing 80 to 85 boe per day.
The field recovery factor at Turner Valley is only 12 per cent of the 1.3 billion bbls of 48 API crude in place. Legacy estimates that every 15 bbls a day of incremental initial production adds about $1 million to the company's net present value.
Another play that is going to be reliant on technology is the newly emerging Alberta Bakken play in southern Alberta, Yanko told the conference. A large play, it has a lot of different oil shows from a lot of different zones. Legacy is involved in a rolling option farm-in deal that gives it exposure to 183 sections (117,000 acres). "With success we can basically leverage into the play at $500 an acre," he said.
Legacy has drilled and completed one well, which it expects to come on production in early October.
The company did a two-part fracture, breaking the well into two pieces, which allowed it to try two different types of fracturing techniques, helping to optimize the cost. "We're doing quite a bit of work on coring, fracture logs, etc. so these wells are expensive from the initial standpoint but we feel we are getting very good data to help us understand the reservoir," said Yanko.
The second horizontal well in the north block, which offsets the best well in the area, is currently drilling. The Big Valley vertical well was drilled in 1979 and produced 250,000 bbls with no water.
Operating in the next spacing unit over, Legacy is accessing a zone that is about 25 metres thick with six per cent of porosity and two millidarcies of permeability. However, the size of the play also means that it is going to take some time to figure it out, he said.
However, "these types of plays would not exist without this technology and without high oil prices," he said. "We would not be doing a lot of the stuff we are doing today at $15 oil and we all fully understand that."
In the Williston Basin, Legacy continues to evolve the completion techniques in the Bakken, whether at Taylorton or Stoughton/Heward. Two years ago, the company was at the forefront of doing smaller and smaller fracs at more intervals and is having very good success, he said. Some wells have had 90-day IP rates of 350 boe per day.
"We are big believers in pressure maintenance, whether it's through waterflood [or] gas injection," Yanko said. One reason is the recovery factor enhancement that adds more reserves cost-effectively, he suggested. Waterfloods tend to have very low declines and once the capital is spent they become free cash flow generators that support other growth opportunities, analysts heard.
PetroBakken's Wright agreed that the next stage in the Bakken is going to be enhanced oil recovery. The company has looked at a number of different methods, including waterflooding and CO2 flooding, but has opted for natural gas flooding in the Bakken. Solution gas is readily available in the area and is less expensive and corrosive than carbon dioxide.
"What we are trying to do is attenuate the decline and extend the economic life of the field by significantly increasing the ultimate recovery of each one of these wells," he said. PetroBakken has its first gas injection well on injection now with a total of five planned for this year with $20 million allocated for EOR pilots.
If gas flooding works, PetroBakken has identified about 100 locations, probably about 20 a year over the next five years, which will result in about half of its Bakken production on EOR in that period.
"The beauty of this is that we are actually going to start injecting our own solution gas," said Wright.
At today's prices, natural gas is almost a waste product so in putting "it in the ground it becomes a storage project," he said.
"Displacing oil out of the ground and ultimately producing that natural gas back on final depletion could be an optimal way to get the most value out of the Bakken and we are pretty excited about the potential that this offers for us."
Over the next six to 12 months, PetroBakken expects to have some initial indications over whether the gas flooding is working.
Completion technologies in the Bakken have continued to evolve since the company started out drilling 1,400 to 1,600 metre horizontal wells in the Bakken. PetroBakken began looking at ways to increase the frac intensity, which will result in higher oil recoveries and to become more efficient in applying that.
The next evolution was drilling the field using bilateral completions, in which the field was effectively downspaced to eight wells per section using only four wellheads. Two parallel wells are drilled underground and then they are individually and separately completed using between 15 and 20 stages of fracs down each of the laterals.
"We had some pretty some significant results comparing 140 bilateral wells and 140 offsetting single wells," said Wright. Each bilateral well cost $2.6 million compared to $4 million for two single lateral wells to access the same resources.
"They make more oil, they pay for themselves faster and on a capital intensity basis it's a better way to put money into the ground and get the oil out," he said.
Another PetroBakken technological innovation was prompted by necessity. In late 2010, in the northern Bakken, the company started encountering instances in which production would drop and the water cut increase. That was a clear indication it had fracked out of the zone and that it had problems with the Bakken cap rock.
The problems occurred after wells were brought onstream at high production rates (200 bbls a day to 250 bbls a day) and as PetroBakken dropped the pressure in the reservoir, starting to deplete the fracture system.
In response, the company came up with a new solution, using a new frac completion protocol called CleanTech, which allows it to frac the wells with a very low-viscosity, great-carrying-capacity frac fluid. The fluid can deliver high concentrations of sands with about the same volume of fluid but at much lower pressures and with no fears of sanding off. "These wells are actually outperforming our bilateral wells," said Wright.
The results have been so successful that PetroBakken is looking at using the technology in all its Bakken wells. "This obviously pushes out the economic limit of where the field can be exploited."
In 2010, PetroBakken acquired three companies and has now accumulated about 260 net sections in the Cardium where it is continuing to look at new technologies to exploit the field. The company sees the West Pembina area as the most prospective area in which to employ new technologies. It has focused on the halo area because it has the original reservoir pressure and has not yet been depleted.
PetroBakken believes that its latest innovations will over time increase production to about 250,000 bbls of oil per well. It currently uses slickwater fracs for completions. "We think it is a great answer today but it may not be a great answer tomorrow so we are trying a bunch of new things," said Wright. Other completion methods it is looking at to try to squeeze more oil out of the rocks involve different frac densities, injection pressures and sand concentrations.
Responding to a question from an analyst who suggested that one of the side effects of new technologies is high initial decline rates, which put companies on a production treadmill, Wright said that over time the average corporate decline rate actually declines into the teens as the plays mature. "The biggest cure for us for declines is execution of multi years of programs and our base decline just goes down and down and down as production goes up."
Meanwhile, Legacy has tried to address that by choosing not to chase extremely high growth in any one year but to take a more measured approach with an annual growth rate of 10 to 15 per cent drawing out of cash flow. "We bought Turner Valley because we liked the infill drilling upside," he said. "We also liked the ancillary benefit of essentially having a zero per cent decline pool underpinning our asset and becoming an internal source of cash flow."
In addition, in the way it is organized Legacy recalls the days when there were completions and drilling departments. It has four completion engineers, two drilling engineers and is continuing to add to those positions along with reservoir and exploitation and production specialists.
"We are organizing ourselves more like that technically-driven company that we used to do in the late 1980s and 1990s when oil was 15 bucks," says Yanko. "There was no multi-stage horizontals, all the big pools were found, horizontal drilling was still in its infancy and we had to make something out of nothing and we did it by doing a lot of very rigorous technical evaluations before we spent the money," he said. "It was aim, aim, shoot."
The industry then went through a period of "run and gun," drilling $400,000 wells and "dusting" 20 per cent of them, said Yanko. "The 1,000 wells a year, the Renaissance [Energy Ltd.] model was great for a certain period of time and again we exhausted those opportunities," he said.
"Technology has allowed us to have a third chance at this but it is capital intensive, people intensive and unfortunately it comes with that decline but there are ways around it."