Year of change for energy regulator, More transitions to come as AER boosts efficiency by Amanda Stephenson, May 14, 2014, Calgary Herald
Jim Ellis doesn’t mind admitting he’s had a challenging year. As president and CEO of the new Alberta Energy Regulator, which was launched in June 2013, Ellis has spent the past 12 months presiding over a transition that would give any complicated corporate merger or acquisition a run for its money. Folding in the former Energy Resources Conservation Board with the regulatory functions of the provincial departments of Energy and Environment, the AER replaces what was once three separate entities with a single body tasked with the full responsibility for energy development [de]regulation in the province.
Ellis and the staff at AER had to assemble all the pieces at a time when oil and gas activity in the province is again on the upswing, unconventional resource extraction is becoming the norm, and the eyes of the world are on Alberta’s energy sector as never before. “What we’ve accomplished this year has been in my opinion, quite frankly, herculean,” Ellis said in an interview. “It’s been a bit of a pressure cooker to try to do all of this at the same time.”
Alberta’s transition to a single energy regulator, which was completed March 31 of this year, emerged from a “competitiveness review” undertaken by the Stelmach government in 2010. The idea was to create a more streamlined regulatory system that would effectively [remove protections for] the environment, [decimate] rights of landowners, improve efficiency for industry, and inspire confidence [by lying and Charter violations granted complete legal immunity?] among the public – both at home and around the world.
“If you look at the history of the regulatory process in Alberta, it is certainly very strong and a global leader,” said Energy Minister Diana McQueen. “But quite frankly when you have all those lenses looking at one application together, I think it makes it a more effective regulator, a better regulator. And we can use that when we go and talk about Alberta.”
A lot of people ask Ellis if a “better” regulator means a tougher regulator – one with more teeth that will be quicker to penalize noncompliant companies. Ellis resists that characterization, because he believes the vast majority of oil and gas companies are doing good work. But he said the new AER has a host of new enforcement tools at its disposal, and it’s not afraid to use them when necessary. Last fall, for example, the AER ordered hearings in Peace River after repeated landowner complaints about odours coming from nearby oilsands operations. It was an unprecedented move, as public hearings have historically been associated with new project applications, not concerns that have arisen in relation to an existing operation.
“I wouldn’t say we’re any tougher than regulators in the past, though there are some things we’ve done in the past year that we’re moving quite quickly on,” Ellis said. “We’re holding companies accountable that are having difficulties, and we’re not afraid to come in and do what we have to do.” [By allowing Baytex to keep poisoning Alberta families? By arguing in court “no duty of care” for Albertans harmed by hydraulic fracturing? By arguing in court complete legal immunity for gross negligence, acting in bad faith, and even for violating Charter Rights to cover up Encana fracturing a community’s drinking water aquifers?]
The new AER has also resolved to be more transparent in its daily operations. One of its first moves was to begin online incident reporting, so the public is informed about spills or leaks as soon as the regulator receives the information. [Industry is self-reporting in Alberta, as in many deregulated jurisdictions. How often are toxic incidents and fracing of drinking water supplies reported?] “Most of the regulators around the world don’t do that,” Ellis said. “It’s a very big change.”
This week, the AER said it will begin offering live audio streaming of public regulatory hearings. And there are more [100% funded by industry, “no duty of care”] changes to come.
Ellis says the AER’s role is not only to protect the environment, but also to ensure Albertans benefit from the “world-class resource” that lies beneath their feet. [How do Albertans, rich or poor, benefit from contaminated air, land and water, and unsellable homes?] To do that, he says the regulator needs to allow industry to do [whatever it wants?]….
Over the next 12 months, Ellis hopes to be able to put timelines in place for regulatory approvals, so that companies know how long their applications will take to be processed. He also hopes to improve efficiency by having the AER devote less time to straightforward, low-risk project proposals, and more time to high-risk, complex ones.
Brad Herald, director of Alberta operations for the Canadian Association of Petroleum Producers, said industry will be watching during this year’s drilling season for reduced wait times and a more efficient approvals system [ In 2010, the Alberta energy regulator was already down to one day wait times for a non-compliant Encana application in a community where Encana’s fracing violated laws and regulations in place to protect drinking water and numerous water wells were contaminated. What next? Instant approvals?]. “We want to see it as seamless as possible, from start until a decision is rendered,” Herald said.
The AER is also developing a pilot project that will test a new way of dealing with unconventional resource extraction. Rather than consider each application on a well-by-well basis, the AER will look at the impacts of an entire resource play [often called “blanket approval” by industry. It ensures being able to frac in secret with no consultation, no chemical or frac disclosure until it is too late, as happened at Rosebud], such as the Duvernay in west central Alberta.
Ultimately, Ellis said, the AER must establish itself as a “bestin-class” [“no duty of care”]regulator if Alberta is to maintain its standing as an energy giant and grow its markets around the world. “We’ve got the third largest resource base in the world right now for oil and gas,” he said. “The credibility of the [“no duty of care”] regulator and the acceptance of responsible development is critically important for us to have the social licence, or the permission from Albertans, to actually develop this resource.” [Emphasis added]
Research pushes industry into the future, New technology [includes] horizontal drilling and carbon capture by Barb Livingstone, May 14, 2014, Calgary Herald
Dingman No. 1 not only kick-started Alberta’s energy industry, it launched a century of locally grown entrepreneurism, research, and technology now used around the world.
Here is a look at what some longtime industry experts say are the biggest advances from large energy companies, oil and gas service companies, and collaborations between industry, government and universities.
Dr. Eddy Isaacs, CEO of provincial government funded Alberta Innovates [Refer below to Steve Wallace’s editing of Alberta Innovates’ “independent” reviews (when it was called the Alberta Research Council) by Dr. Alexander Blyth dismissing the water contamination cases in Alberta] — Energy and Environment Solutions. He has over 70 publications and six patents in the energy field. Isaacs has been instrumental in promoting innovation in energy and environment across Canada, and has served as co-chair of the Energy Technology Working Group of the Canadian Council of Energy Ministers:
1. SAGD (steam assisted gravity drainage) technology in the oilsands. The original patent was held by Imperial Oil but it was never exercised because it could only work once horizontal drilling was mastered. Both the horizontal drilling technology and the magnetic guidance technology that kept well bores closely parallel were Alberta innovations. This meant one well could inject steam and a closely parallel partner well could capture and produce the liberated oil. It’s also the best example of industry and government working together because Alberta Oilsands Technology and Research Authority (a precursor to Isaacs’ organization) was instrumental in the early days of horizontal drilling. It’s used today after being commercialized 12 years ago by Cenovus.
2. Horizontal wells are a French development perfected in Alberta in the late 1980s and early ’90s. Sperry Sun (later acquired by Haliburton), working in Leduc, developed a magnetic guidance method of keeping horizontal wells on the desired plane. Accurate horizontal drilling meant you could access a lot of reservoir instead of merely intersecting it with a vertical well. Today, 80 to 90 per cent of wells drilled around the world are horizontal. They’re also used in depleted fields to tap hard-to-reach oil and in “tight” rock formations, with hydraulic fracturing, to liberate trapped oil and gas.
3. Seismic technology. In the old days, the industry drilled dry hole after dry hole. New seismic technology sends vibration pulses through the earth and maps the rebound waves to identify potential hydrocarbon traps. Perfected in the last 20 to 30 years, seismic was developed by a University of Calgary research group and is used by everybody in the industry, worldwide, including the big two, Haliburton and Schlumberger.
4. Reservoir modelling. In the 1970s, the computer modelling foundation at U of C developed reservoir models that allowed companies to determine what injection practices they should use and what reservoir flow they would get. That group became a company called Computer Modelling Group Ltd.
5. CO2 Miscible Flooding (a form of enhanced oil recovery). Injected into depleted oil reservoirs, carbon dioxide (CO2) acts as a solvent [why not report on some of the many serious, potentially life-threatening risks and leakage caused by CO2 injection?] to mobilize additional oil volumes so that they can be pumped to the surface. Calgary-based Cenovus established a CO2-EOR project at the Weyburn Oil Field in southern Saskatchewan in 2000. The project is expected to recover an additional 130 million barrels of oil, extending the life of the oilfield by 25 years.
Next big things:
1. Carbon Capture and Storage (CCS). With support from federal and provincial governments, Shell Canada is developing the first, fully integrated, commercial-scale CCS project in the oilsands. At its Scotford upgrading and refining site east of Edmonton, Shell is building a CCS unit that will capture 1.2 million tonnes per year of CO2 from its upgrader flue vents, compress it and inject it into a depleted gas reservoir. If successful, it will prove the feasibility of multiple CO2 capture and storage projects, aimed at reducing greenhouse gases, while providing valuable information about how to reduce the cost of future generations of CCS technology.
2. A significant amount of time and expertise is being put toward water treatment/tailings pond management. Thirteen companies — including Shell, Suncor, Cenovus, Imperial, CNRL — have signed an agreement to share intellectual property on environmental concerns [Why doesn’t the public, especially landowners potentially in harms way, have access to these concerns as well?] as members of Canada’s Oil Sands Innovation Alliance (COSIA).
Mark Salkeld, president and CEO of the Petroleum Services Association of Canada with more than 30 years of domestic and international industry experience:
1. Rotary steering system allows you to steer the bit down hole. Early steel tools, called bent subs, were like shoehorns placed next to the bit on the drill string and used to push the bit sideways to turn it from vertical to horizontal. Rotation of the drill string had to be suspended, so that the bent sub was always pointing in the right direction, and the drill bit had to be turned by means of a “mud motor.” Today the bit can be steered within metres of accuracy with advanced magnetic telemetry systems. Drill strings can be turned continuously with no need to pull the bit and bent sub assembly out of the hole after turning.
2. Marriage of horizontal drilling and multi-stage hydraulic fracturing.
3. Data collection and micro-sized analysis. Technology used to steer the drill bit to gather data through the drill stem is as close to real time as you can get. The data means you know what direction and where to steer the bit.
David Yager, national oilfield services leader at business consulting firm MNP. He is a founder of a now-global oilfield services company (Tesco) as well as other companies, former president of PSAC, and former co-owner/publisher/editor of oil trade magazine Roughneck.
1. Horizontal drilling was pioneered by Imperial Oil in the 1980s and the early tools were built in Nisku. Integration of vertical and directional drilling has been done by Alberta companies and few of today’s horizontal wells could be drilled without this. Alberta companies like Cathedral Energy Services and Phoenix Technology Services were leaders.
2. Multi-stage fracturing tools were pioneered in Canada and made horizontal drilling vastly more effective. Drilling horizontally reaches more of the pay zone with a single well. But if the oil doesn’t flow, you need to fracture the formation. Fracking one section of a horizontal well gives you only slightly more oil than a vertical well. You need to be able to fracture 10 to 40 sections of a horizontal well to access tight oil along its entire length. Canadian companies, including Packers Plus, have perfected the ability to place packers along the entire length of a horizontal well, closing two neighbouring packers at a time to isolate and fracture one section before moving on to fracture the next.
3. Top Drives have mostly replaced rotary tables to provide turning force to the drill string, so the drill bit cuts through rock formations. Top drives are located in the derrick, rather than the rig floor, and enable rigs to handle longer pipe sections for faster drilling and bit changing. Tesco led the development of top drives for land rigs, foreseeing that the ability to turn the drill string while pulling pipe out of the hole would be vital to efficient horizontal drilling.
4. World leaders in engineering, construction and fabrication, like Ledcor, started in the oilsands. Ledcor prepared the access road and well site for Imperial Oil’s discovery in Leduc and now employs more than 7,000 people across 20 offices throughout North America.
[Refer also to:
Slide from Ernst presentations
March 1, 2012: Potential for environmental impact due to acid gas leakage from wellbores at EOR injection sites near Zama Lake, Alberta
July 30, 2013: Denbury fined $662,500 for Mississippi blowout of CO2 injected in high pressure enhanced oil recovery, So much carbon dioxide came out that it settled in hollows, suffocating deer and other animals
Alberta Environment (now the AER) editing the Alberta Research Council’s (now Alberta Innovates) “independent” reviews and reports by geochemist Dr. Alexander Blyth:
June 2013; Alberta Energy Regulator (previously ERCB, previously EUB and ERCB before it was the EUB) 100% financed by oil and gas industry, will be corporate-style, allocate water, including for fracking ]