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Oil sands challenge Technology advances take years to commercialize, not always unqualified success Gary Park For Petroleum News
There’s a widely held belief that new thermal recovery oil sands projects can compete favorably with other North American tight oil plays.
A study by Calgary-based investment dealer Peters & Co. that weighed a 30,000 barrel per day development in the Eagle Ford against a comparable 30,000 bpd in-situ development yielded a competitive result.
“Operators such as Cenovus Energy have shown that, with time and scale, manufacturing advantages can be achieved,” Peters said.
Glen Schmidt, chief executive officer of Laricina Energy, said “gains are realized and compounded once commercialized projects are established. Innovations (such as the use of injected solvents and infill wells) are leading to further reductions in supply costs below that of the base-case steam-recovery methods.”
“As an industry, we are seeing lower steam-to-oil ratios, faster startups and techniques and expansions built on initial operations.”
Schmidt said the use of solvents is adding incremental value of about 30 percent to production, while recovery of oil-in-place is increasing by 10 to 15 percent.
Technology challenges However, as the oil sands sector sifts its emphasis from the raw, brute force of open pit mining to recover bitumen to the more environmentally friendly technologies such as steam-assisted gravity drainage (and its many variations) the challenges grow.
Not least is the use of restricted quantities of fresh water, which is consumed at the average rate of 3.1 barrels for every 1 barrel of oil produced from mines and 0.4 barrels for every barrel of bitumen extracted from in-situ operations, creating a fresh environmental challenge for the sector.
Although the Canadian Association of Petroleum Producers estimates that only 0.6 percent of river flows from the Athabasca River — the major waterway through northeastern Alberta — is consumed by oil sands operations, that does not sway environmental organizations who are indignant over how much water is used and how much is contaminated.
The Canadian Oil Sands Alliance, made up of 14 producers, is exploring a variety of ways to reduce water needed for new steaming technologies and piping surplus water from mining to in-situ projects.
Currently, about 60 water experts from the alliance’s member companies are collaborating in the search for water solutions.
But it’s an accepted fact that taking an idea from conception to commercial application in the oil sands takes years and, even when a breakthrough seems imminent, trouble is lying in wait.
Toe-to-heel recovery Petrobank Energy and Resources has long championed THAI, toe-to-heel, recovery methods, which inject air through a vertical well to spark combustion of some oil, creating a heated chamber that warms the remaining oil, allowing it to reach the surface through a horizontal well.
The company’s hopes were pinned on its Kerrobert heavy oil field in Saskatchewan, until it reported a 43 percent drop in second quarter production to 135 bpd from 236 bpd a year earlier, causing a drag on share values.
Despite the disappointment with Kerrobert results, Chief Financial Officer Peter Cheung said “we do believe we know what the major challenge is,” with the blame divided between some technology hitches along with oil that could not be sold due to a lack of rail shipping.
The company said it is now experimenting with “multi-THAI,” adding more air injection wells along each horizontal section to expand the combustion zone. The first test is expected this fall.
Seepage of emulsion But that setback coincides with another challenge facing a new-generation technology that has been evolving over 30 years.
Since late May, Canadian Natural Resources has been grappling with the seepage of more than 8,700 barrels of bitumen emulsion in the Alberta oil sands region from four locations in the Primrose field.
The incident, which is being investigated by Canadian and Alberta government officials, has been tied to the use of high pressure cyclic steam stimulation, HPCSS, one of several variations on thermal recovery methods that now account for more than half of Alberta’s oil sands production.
CNR has insisted the seepage is being contained and recovered and believes the cause is more human error than the technology.
HPCSS, which is designed to reduce energy and water consumption, injects steam to separate bitumen from sand, allowing the bitumen to be pumped to the surface, is estimated to account for about 35 percent of all in situ production.
It also underpins a core element of CNR’s operations, with the Primrose area contributing 120,000 bpd in July of the big independent’s 440,000 bpd of oil and liquids output.
Bob Curran, a spokesman for the Alberta Energy Regulator, the province’s energy authority, said in a statement the four locations are being investigated to determine if they are related.
To date, he said the AER has not responded to a request by environmentalists and First Nations for a public inquiry into the steam injection process.
Curran noted that HPCSS is quite distinct from steam-assisted gravity drainage, which his viewed as a method of enhanced oil recovery, with the two main variations being cyclic steam stimulation and steam flooding.
The AER notes that HPCSS has been used for oil recovery in Alberta for more than 30 years, notably by CNR at its Primrose and Wolf Lake projects near Cold Lake, where Imperial Oil has gross output of about 150,000 bpd and expects to add 40,000 bpd from its Nabiye facility by late 2014.
May be mechanical failure CNR President Steve Laut said he is “pretty confident” that a mechanical failure of the well bores, not the technology itself, is responsible.
“At Canadian Natural everyone takes this event very seriously,” he said in a statement. “We are responsible and we are committed to ensuring the Primrose cleanup and reclamation work.”
Walter Janvier, a councilor with the Cold Lake First Nations, said there is no sign the leaks are slowing down, making a case for a serious technical review of HPCSS.
“It’s not so much the surface spill, which can be cleaned up,” he said. “When you can’t control what happens underground, that’s different story. We want an investigation that looks at all the technical data.”
Janvier said he is also concerned that CNR initially kept First Nations away from the sites, then limited visits to only two of the four locations.
Laut insists HPCSS is viable, having been used for 30 years by thousands of wells with only a few incidents, but said he does not disagree with an AER report into a 2009 spill which raised concerns about a possible geological weakness in the area.
Darren Bilous, energy spokesman for the New Democratic Party in the Alberta legislature, said rules and regulations tied to cyclic steam stimulation have not been updated since 1994, despite the 2009 spill.
He said the AER should take decisive action and adopt draft regulations that were written last year.
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