CAPP raises doubts oil production caused contamination cited in study by Reid Southwick, August 31, 2016, Calgary Herald
Government scientists will decide this fall how they will expand monitoring of lakes, wetlands and other surface water bodies near in-situ oilsands projects, after a study indicated such operations can release pollutants.
But an industry group questioned whether the study confirms that oil production from these deep underground wells caused the contamination, though it welcomed further testing.
Environmental monitoring authorities hadn’t previously focused on testing for surface water contamination from these projects because they involve drilling deep underground, according to Fred Wrona, chief scientist for Alberta Environment and Parks.
But a joint study by the University of Ottawa and Alberta Environment and Parks found rising concentrations of hydrocarbons in lake sediment near in-situ oil wells in the Cold Lake area.
The levels are too low to cause environmental damage or pose risks to human health, but Wrona said the study revealed a need for broader analysis into how oil production from deep underground wells has affected surface water.
“This, in my opinion, shows that we’re using emerging science,” he said. “We use that science to inform how we’re going to design and conduct environmental monitoring in the region.”
When federal and provincial government scientists meet this fall to plan their environmental monitoring for the coming year, they will use the research findings to expand their surface water testing near in-situ operations, according to Wrona.
Exactly where and what they will test, and at what cost, remains to be determined.
Until now, the oilsands monitoring program has largely focused on open pit mines along with their associated tailings ponds and other environmental effects. But most of Canada’s oil reserves are too deep to mine and require in-situ techniques that use steam to extract oil from underground wells.
Terry Abel, director of oilsands for the Canadian Association of Petroleum Producers, said he does not believe the study confirms the rising levels of hydrocarbons detected in lake sediment were the result of oilsands drilling.
Still, he welcomed further monitoring, noting the oil and gas industry contributes $50 million a year to environmental testing by federal and provincial scientists.
The study and others like it “contribute to that bigger body of information that we believe ultimately is going to prove that we’re not causing any significant impacts to the environment,” Abel said.
“If we are, it will give us a signal of what we need to focus on and pay attention to.”
Researchers who conducted the study said because there are no long-term records of pollution monitoring in the Cold Lake area, they relied on samples of sediment taken from a small lake near the site of a 2013 leak.
More than one million litres of bitumen emulsion had seeped from Canadian Natural Resources Ltd.’s Primrose operation, a spill the regulator ultimately found was caused in part by excessive steaming.
The study authors said they found evidence of contamination beyond the effects of the spill. The said they uncovered a “clear and steady increase” in toxic hydrocarbons tracing back to the 1980s, when oilsands operations began in the region. They noted the concentrations were lower than what has been detected in the Athabasca oilsands region in northern Alberta.
Canadian Natural said in a brief statement that it is reviewing the details of the study.
[Refer also to:
On the morning of the day he died, David Taylor and his crew were looking for a“chimney” — a fissure in the earth where steam and oil periodically spurted into the air in an oil field west of Bakersfield.
Taylor, a construction supervisor for Chevron, had been battling a long-standing problem near a dormant well in the Midway-Sunset oil field. His job was to control leaks at Well 20 in a primordial tableau of sinkholes, small bubbling pools of scalding water and geysers that on occasion spewed 40-foot plumes of oil, water and rocks.
The conditions, known as “surface expressions,” [What an evil way to make a deadly frac impact sound harmless] were in part the result of an oil extraction technique known as cyclic steaming. The process forces superheated water underground at high pressure to open pathways to siphon heavy oil.
An unintended consequence is that some fluids make their way to the surface through newly created ruptures or via old, broken, or unstable wells.
To mitigate the risk from the escaping liquids, state regulations require oil companies to perform an Area of Review, in which they must map and document every well — new, idle, plugged or abandoned — near an injection site and repair any potential problems. Companies must also analyze the site’s geology and freshwater sources, and calibrate injection pressures to reduce the chance that oil or steam will push their way to the surface or out of the oil-bearing zone.
But state and federal authorities say in many cases oil companies are allowed to bypass those safety requirements or avoid them through a regulatory loophole. [A global gift for the unconventional oil and gas industry?]
Taylor, 54, and two co-workers were dispatched to Well 20 on June 21, 2011. Chevron had been trying to control the well since 1997, spending more than $2 million.The company stopped injections near the area to try to ease the problem, but neighboring oil producers kept up high-pressure injections. More than 30 surface expressions existed within a mile of the well.
As the crew walked the site, surrounded by a landscape dense with new and old wells and miles of pipes and casings, the ground gave way beneath Taylor. He fell feet first into a cavity burbling with 190-degree water and hydrogen sulfide.
Co-workers rushed to the brink but could not reach him. As they extended a length of pipe for him to grasp, Taylor slid further into the 10-foot diameter crater.
His wife stood vigil beside the sinkhole until rescuers could retrieve his body 17 hours later.
Chevron called Taylor’s death a “tragic and isolated incident,” and said it has a “long track record of safely conducting cyclic steaming in the Midway-Sunset Field.”
The study area, with its history of surface leaks, might be an extreme example. But Korosi said there might be other “hot spots.”
Texaco/1980s/Fort McMurray
In the early 1980s, Texaco experimented with steaming bitumen deposits with a Fort McMurray thermal pilot. “They had a blow-out and the steam geyser looked like Yellowstone” reportedGlen Schmidt, CEO of Laricina Energy, to the Edmonton Journal last year.
Imperial/1988/Cold Lake
High pressure steam from a cyclic steam stimulation operation broke through an abandoned oil sands evaluation well and spilled more than 6,000 barrels into the forest, along with 4,000 barrels of toxic water laden with chlorides. The blow-out temporarily contaminated three shallow aquifers with chlorides. The company trucked more than 22,000 barrels of bitumen, water and peat to the landfill.
Total/2006/Joslyn
French multinational Total blasted a 300-metre crater in the boreal forest that created a one-kilometre-long dust plume during the beginning of a new steam-assisted gravity drainage operation. (Most caprock failures occur after five to seven years of pressurized steam injection.)
Four years later the regulator called the explosion “catastrophic.” The regulator concluded that Total exceeded pressure limits and “was in noncompliance with scheme approval.”
Steam then pooled below the caprock and erupted through a fracture or abandoned well. There is no conclusive identification of the cause of the failure. Nevertheless, the event illustrated that the energy available from water and steam can be formidable.
With the exception of Mike Carlson, little has been written about this event. The Calgary engineer found that “there is virtually nothing from an engineering perspective on the caprock failure at Joslyn in the peer-reviewed technical literature.” He concluded in a 2012 paper that the problem for the Total blow-out has not been fully determined.
“The Joslyn failure is a significant catastrophic failure affecting [steam-assisted gravity drainage] developments. Future licensing of [these] projects will be uncertain if the cause of failure is not known with certainty.” The event rendered nearly 30 million barrels of bitumen unrecoverable. Total abandoned its steam plant project and opted for a surface mine instead.
CNRL/2009/Primrose East
At Primrose East, Canadian Natural Resources Ltd. injected high-pressure steam into 80 wells at four pads. At two well sites bitumen steamed to the surface and through two thin surface fissures on the ground in the dead of winter. The company eventually removed more than 12,000 tons of bitumen, water, snow and muskeg to the landfill.
The seepage event contaminated the Bonnyville Aquifer. “There remains uncertainty about how the bitumen emulsion will break down over time with heat from further steam injection and about what constituents may be released into the Bonnyville Aquifer,” reported the regulator five years after the vent in 2013.
Neither the regulator nor CNRL could agree on the cause of the bitumen seepage. Noted the regulator: “A contributing factor in the release may have been geological weaknesses in combination with stresses induced by high-pressure steam injection.”
Devon/2010/Jackfish:
In 2010, bitumen-laden steam burst 30 metres into the air at a steam-assisted gravity drainage well operated by Devon near Conklin, Alberta. The blow-out, which closed seven wells, was caused by a “catastrophic erosional wear” at the wellhead due to an unusual amount of sand production. It took nearly five days to control the steam release that poured nearly 300 cubic metres of bitumen and nearly 1,000 cubic metres of water on the surface. The company later blamed the event on failure to understand the gravity of sand erosion and lack of planning for well failure.
Imperial Oil/2013/Cold Lake
Every year Imperial Oil experiences well failures at its cyclic steam operation in Cold Lake, where approximately 3,000 wells produce 150,000 barrels of bitumen a day. The steaming causes the ground to heave, breaks well casings and can result in spills and blowouts swallowing entire well pads. In 2008, engineer Maurice Dusseault reported that tearing at the caprock occurs routinely at Imperial’s cyclic steam stimulation project and it “experiences dozens of well shear events; these wells must be repaired or replaced at considerable cost.” Casing well failure is routine in Cold Lake. A 2002 study found that 92 out of 585 wells on 22 pad sites failed over a five-year period.
Recent In Situ Progress Presentations to the Alberta Energy Regulator reveal a myriad of problems. Steam from Imperial’s wells has travelled through fractures and broken into bitumen formations owned by Husky. Steam has also moved from a depth of 420 metres in the Clearwater formation to shallower formations closer to the surface, such as the Grand Rapids and Colorado shales. This “interzonal communication” can affect groundwater.
As a consequence of assorted fractures, well casing failures and leaks, Imperial is now investigating levels of benzene, toluene and ethylbenzene that exceed Canadian Drinking Water Guidelines in local groundwater. Imperial also reports numerous “bitumen in shale” incidents, where steamed bitumen finds its way into groundwater aquifers at depths of 153 metres or nearly 400 metres away from the target formation.
Steam has mobilized arsenic in the region and forced an elaborate groundwater monitoring program.
More in situ frac-induced contamination history:
1997 – “A hydraulically induced fracture containing bitumen was encountered in the Colorado Shale at Imperial Oil’s Cold Lake Operation, during development drilling in 1997. The fracture was apparently caused by an inadvertent release of fluids from Cyclic Steam Stimulation (CSS) operations in the Clearwater formation into the shale about 150 m above the producing formation. Subsequent drilling delineated the fracture to be over 1 km in diameter, extending over five 20-well pads.
Steam injection into the Clearwater formation induces overburden heave and also induces additional shear stresses in the shale.
These could cause the shale to slip along the fracture. Depending on the magnitude of the slip, casing strings could be deformed or even failed.
… A hydraulically induced fracture containing bitumen was encountered in the Colorado Shale (CS), during development drilling of the E07 pad in 1997. Fifteen Shale Evaluation Wells (SEW) were drilled through the CS to determine the extent of the fracture. Evidence of the fracture was found in wells drilled from five neighboring pads of CSS wells.
The evidence consisted of abnormally high fluid pressures, bitumen in the drilling returns, or, in the case of the initial observation, flow of bitumen to surface.”
https://www.onepetro.org/journal-paper/PETSOC-04-02-03
Note that all high-pressure methods experience advective instabilities such as viscous fingering, permeability channeling, water or gas coning, and uncontrolled (upward) hydraulic fracture propagation. These instabilities result in bypassing oil, isolating bodies of the oil by sweeping permeable channels clear of oil, early loss of wells because of excessive water production or gas production, early loss of reservoir energy, and so on.”
http://www.energy.alberta.ca/OilSands/pdfs/RPT_Chops_chptr1.pdf
“CSI with Hydraulic Fracturing
The idea of combining cyclic steam stimulation with hydraulic fracturing came out when both steam injection and completion (i.e, sand control completion) techniques generated potential formation damage thus, the permeability near the wellbore creating a choke was lowered that further reduces the oil mobility. Creating fractures allows a more efficient placement of injected steam, heating up larger volume of reservoir and reducing residual oil saturation.
Conclusions:
… Cyclic Steam Injection combined with unconventional technologies such as co‐injection with chemical additives, horizontal drilling and hydraulic fracturing have been highly successful, improving its conventional recovery factor up to 40%. Recent studies showed that this can be increased even higher.
CSI with Hydraulic fracturing has shown good results for low‐permeability formation. Further investigation on fracturing fluid needs to be acquired to solve sand productions during the operation.”
http://www.jpsr.org/paperInfo.aspx?ID=5755
“In cyclic steam stimulation (CSS), steam is injected above the fracture pressure into the oil-sands reservoir. In early cycles, the injected steam fractures the reservoir …
… Because the mobility of the bitumen depends strongly on temperature, the performance of CSS is intimately linked to steam conformance in the reservoir, which is largely established during steam fracturing of the reservoir in the early cycles of the process.”
https://www.onepetro.org/journal-paper/SPE-129686-PA
“CSS In Cyclic Steam Stimulation (CSS), high-pressure, high temperature (350°C) steam is injected into a vertical wellbore in the oil sands deposit, which is fractured by the steam pressure.”
https://petroleumshow.com/absolute-combustion-heating-up-the-oil-extraction-process/
Page 8 – Alberta Energy Regulator: “there is heave and subsidence seen around cyclic steam stimulation (CSS) operations in northeast Alberta, which involves high-pressure fracturing plus steam injection; the steam injection is responsible for some of the heave in this case.”
https://www.lethbridge.ca/City-Government/City-Council/Documents/Alberta%20Energy%20Regulator%20FAQ.pdf ]