Alberta’s energy regulator says it is responding to a changing oil and gas industry by updating its requirements, expanding its publicly accessible information base and implementing a new, play-based planning approach.

“Enhanced planning, collaborative engagement, measured outcomes. Those are things you’ll be hearing over and over from the new regulator,” Bob Willard, senior advisor in the Energy Resources Conservation Board‘s operations division, told a recent Petroleum Technology Alliance Canada forum on water.

The ERCB and Environment and Sustainable Resource Development are to be merged and a new organization, the Alberta Energy Regulator, is set to begin operations Monday.

With the AER up and running, a number of changes are expected to occur, said Willard. These include a new governance model, the merging of staff and functions and the phased adoption of new responsibilities during the remainder of 2013 and into 2014, he said.

The new Directive 59: Well Drilling and Completion Data Filing Requirements establishes new water use measurement and sourcing requirements that must be submitted for all wells fractured in Alberta.

The directive requires electronic reporting of fracture fluid data, including the service provider, fracture scenario, carrier fluid type, proppant type and additives for all fractured wells.

Operators must submit water source data including source location, source type, diversion permit information, and volume for all water used in hydraulic fracturing operations with water quality information required.

“We take the approach that industry needs to know what is being injected into their wells, whether it’s chemicals or water

[and] where that water is coming from,” said Willard. “It’s a building block for good planning.”

The website provides public access to that information, he told the forum.

The British Columbia Oil and Gas Commission developed the website to facilitate the disclosure of hydraulic fracturing fluid information in Canada. Initiated in January, it will be enforced starting in August.

So far operators have submitted data on only about one-third of their wells, said Willard. “Let’s get busy, guys.”

Failure to submit data may result in increased auditing of a licensee’s data and other action by the ERCB.

As part of the improved baseline information, there will also be mapping of unconventional resources and both non-saline and saline groundwater, and public reports on flaring, land use, water use, spills, inspections, enforcement, drilling activity, reserves and incident investigations.

The regulator has issued an expanded hydraulic fracturing directive, increasing wellbore integrity requirements, increasing field presence, mandatory notification of fracturing commencement and a requirement that companies conduct a risk-management planning process, especially in regards to offset wells.

This is closely in line with the Canadian Association of Petroleum Producers‘ operating practices and is something everybody is recognizing as a new challenge, said Willard.

The ERCB issued a discussion paper on regulating unconventional resources in Alberta and is analyzing feedback it received.

The regulator plans to pilot some of its new concepts with seven or eight companies in the Duvernay shale, he said. “We realize that there are some major changes; we want to get it right and we need companies’ help and the public’s help, to work out some of the details of these changes.”

The ERCB wants the regulatory response to be proportional to the risk, so while historically much of its effort has focused on wells, it will add a new focus on regional plays — from single wells and single companies to multiple wells, multiple pads and multiple companies, he said.

“We want to manage that transition to that scale, providing effective, practical, operational solutions that will satisfy and address, for example, the government policy direction on regional planning and watershed planning. We need operational tools and plans not only to minimize impacts but to demonstrate to the public [that] practical ideas are working,” said Willard.

Instead of primarily prescriptive-type regulations, the regulator will focus more on outcomes, he said. Each play in Alberta has a different surface and subsurface risk profile so a lot of details will be different. “One-size-fits-all will not be successful in the future. We recognize that,” Willard told the forum.

The regulator expects changes to the pad approval process will include local planning with additional landowners to address their location, water use, noise, lights, trucking routes and emissions.

Subject to the outcomes of the pilot that will be conducted later this year, the ERCB is contemplating requiring operators to file project applications that integrate air, land and water planning and stakeholders will have the opportunity to give feedback on these plans.

This is to avoid unintended consequences, he said.

“As you go to full development, we want that development to be communicated effectively to the community and be part of a regulatory process and application. Putting development plans where it makes sense, we want the group of companies, say the Duvernay Fox Creek, to work together, to collaborate on things like water sourcing, waste management, perhaps even the transportation planning… to find large-scale solutions.”

Horizontal multistage fracturing is being applied everywhere in Alberta, with the potential to affect almost every watershed, almost every county and every synergy group so the regulator and the industry have to come up with models, frameworks and tools to allow the cumulative impacts and the play-specific risk factors and profiles to be properly addressed, engaging the public along the way, said Willard.

For instance, while placing several horizontal wells on a single pad offers considerable flexibility compared to multiple vertical wells, concentrated industrial impacts require greater care in selecting pad site locations and engagement of additional landowners, he said.

Industry is targeting 15 formations with horizontal, multistage fracturing, about one-third of them targeting the tight Cardium, said Willard.

“We have a limited number of wells specifically targeting tight shales but we expect that to change, and change quickly this year and next year so we have to be prepared for both drilling by horizontal wells existing pools to extend their producing life, drilling by horizontal wells the tight flanks of those existing pools. . . . so we have to cover a lot.”

There has been a wide range in the amount of water used in the more than 7,700 horizontal wells that have been drilled with multistage fracturing in Alberta since 2008, he said. “They can range from little or no water to — what has to be acknowledged– are very large volumes of water per well, per pad, per play, so we have to find solutions, effective tools, whether it’s low-water technology or good, effective water management planning in a practical way.”

Indicating an Alberta resource map, Willard said there is likelihood of development of the Duvernay around Fox Creek, Rimbey and Rocky Mountain House and the play has potential for spreading over a large part of the province. There are other plays above and below the Duvernay so it has stacked play potential, he added.

Addressing knowledge gaps in hydraulic fracturing is a new focus of PTAC’s water innovation planning committee, whose funding comes from the Alberta Upstream Petroleum Research Fund (AUPRF).

An integrated assessment of water resources for unconventional oil and gas plays in west-central Alberta is in its second phase.

Understanding the impact of permafrost on water availability in the Horn River Basin is another area of study. “The changes in the permafrost can really affect the water budget,” said Brent Moore, who is in charge of the committee.

The group is also developing the third phase of risk-based criteria for the treatment of saline water from source wells regarding its storage in earthen pits and transportation via overland pipelines. There’s been a real focus on treating flowback water, so the group will look at its storage and transportation, he said.

Three of the policy issues and knowledge gaps AUPRF will address in future are groundwater and surface water protection when fracing, finding alternative water sources and wetlands protection.

Are there really any physical and chemical changes to potable water associated with fracing near shale gas and tight oil development? The public wants more information on this subject so the group will come up with some hard and fast evidence, said Moore, who is also an environmental advisor at Devon Canada Corp.

AUPRF will also develop a tool to track water use relative to how much water is available in a given basin. Such a tool has been developed in British Columbia, and AUPRF wants to develop and maybe improve upon one for Alberta.

The industry is always looking for alternatives to using fresh water and there is a variety available so the group will assess the environmental net effects of using them.

Part of a new wetlands policy coming into effect involves compensation for wetlands disturbance so AUPRF will look at new ways of restoration enhancement, said Moore.

In 2013, AUPRF is funding 30 projects with a $2 million budget, with water research receiving $510,000 of that funding.

AUPRF is funded by an ERCB orphan well levy provided to the Canadian Association of Petroleum Producers and managed by PTAC.

Wayne Hillier of the Canadian Oil Sands Innovation Alliance (COSIA) told the forum that the team at COSIA’s water environmental priority area has pulled together projects worth $183 million. The largest single-member contribution is $34.9 million worth, he said.

“This is the basis of our future activity,” said Hillier.

COSIA is a hub in which 14 oilsands companies set priorities, drive and share innovation and accelerate the pace of environmental performance improvements.

Examples of COSIA’s current projects include: ceramic membrane technology; collaborative water management; improving water treatment; increasing water treatment skill; a pilot test of cyclic solvent process; sharing solutions to water challenges; streamlining water treatment and zero-liquid discharge.

A total of 145 technologies is under consideration by COSIA’s water EPA, he said, adding that one company has contributed 16 technologies.

A long list of technology contributions that has generated the most interest from COSIA members includes: a produced water evaporator; a disposal water system; steam assisted gravity drainage fresh-source-to-brackish-water conversion; salt-cavern disposal of seeded slurry evaporator concentrate; a Devonian aquifer study; water recovery from flue gas and a MacKay River zero-liquid discharge system.

By Lynda Harrison, The Daily Oil Bulletin