Redrawing Mining Boundaries

Alberta's Regulator increases the size of the province's surface mineable area by 40 per cent.

By Peter McKenzie-Brown
Last year Alberta’s Energy Resources Conservation Board report rebalanced the provincial agency’s estimates of oilsands reserves, shifting them somewhat in the direction of surface mineable reserves. This raises questions about environmental impacts, for which the inimitable Pembina Institute have happily provided at least one group of answers.

The oilsands are a vast geological mystery, but last year the ERCB put into place a piece of the underlying puzzle 14.5 townships (1,350 square kilometres) in size. Mineable reserves are those with overburden of 65 metres or less. Based on an analysis of more than 2,000 exploratory wells drilled in recent years, the Board’s analysis increased the boundaries of the mineable Athabasca oilsands by almost 40%. The mineable oilsands area of north-eastern Alberta now measures 51.5 townships.

The first change in the surface mineable area since the Board first drew the boundaries in the early 1980s, this change increases total established mineable reserves – in many jurisdictions called “proved” reserves – by 11%, or about 3.5 billion barrels; more than Britain’s total reserves. These are new reserves. Previously, the Board had not done a resource calculation for the area.

While the mineable sands did well, deeper sands did not. As part of its report, the Board reduced established in situ reserves in the Peace River area on the principle that some previously booked reserves in the Bluesky-Gething deposit were too thin to be economic. As a result, the ERCB reduced the in situ component of established oilsands reserves by about 5.5 billion barrels. The net outcome was that Alberta’s established reserves of bitumen totalled about 170 billion barrels. About 20% of that resource is theoretically mineable. The balance will require in situ recovery procedures like SAGD.

Rick Marsh, a senior geologist with the Board, stresses that this report makes no differences for planning by individual companies, although he observes that landowners have posted this new assessment on their websites. “The purpose of this is to determine on a global or provincial basis what the bitumen reserves of the province of Alberta really are. There is no connection between the regulatory side and the (ERCB’s) resource assessment side. Whether regulatory approval to develop is given will determine whether our resource estimate is correct or not. If development doesn’t take place for environmental or economic reasons, or for any other reason, then we will have to de-book some of those reserves, adjust them downward.”

Marsh notes that there are spots within the boundary expansion that are not appropriate for mining (they would require in situ development) and stresses that, in any case, the new ERCB boundary has no regulatory effect. Leaseholders in the surface mineable expansion area include Shell, UTS Energy, Total S.A. and Synenco Energy; they can propose whatever approach to development they want, whether surface mining or in situ techniques. It’s up to regulators (primarily the provincial Department of Energy) to approve developments.

Economic and Environmental Implications
It isn’t difficult to figure out the energy implications of this analysis. From an economic and technical perspective, the ERCB report enlarges the technically more accessible sources of bitumen. The availability of more mineable reserves, if developed, would mean a lot more economic activity in Alberta, more royalties to the province and greater energy security to the world. Greater production would contribute greatly to Alberta’s status as an energy power. It would enable the industry to develop larger export markets – whether in the United States or, if a pipeline to the west coast is ultimately constructed, to East Asia. And, of course, the Canadian balance of trade would benefit. In a higher-oil-price world, the economics of oilsands development are terrific.

But what are the environmental costs? Especially in respect to air pollution, the balance of costs is well worth considering. According to an important 63-page Canadian Energy Research Institute (CERI) study, Green Bitumen, SAGD production generates 1.3 times the emissions of conventional oil. By contrast, integrated mining and upgrading projects produce 0.6 times the level of emissions. (Emissions from older plants are much higher than these averages.) As we shall see, this could dramatically change.

First, however, consider the notions of the Pembina Institute, which will always have an axe to grind in respect to bitumen production. “The technologies used to mine, extract and upgrade bitumen to synthetic crude make the product among the most environmentally costly sources of transport fuel in the world,” the organization proclaims.

In May, Pembina issued a report summing up its view of the relative environmental impacts of the two oilsands production systems as follows. In situ oil sands production generates more greenhouse gases and sulphur dioxide emissions per barrel. Oil sands mining affects habitat more from land clearing, generates more nitrogen oxides and uses more water during production.

This report follows Pembina’s release in March of a “report card” on nine non-mining plants in the oilsands. In that report Pembina observed that in situ plants are responsible for greater air pollution than mining plants. “When the land disturbance and fragmentation effects associated with natural gas production are considered,” the authors added, “the influence on wildlife habitat of in situ operations can reach (environmental impact) levels that are equal to and sometimes greater than mining.” According to Simon Dyer, the institute’s oilsands program director, “both mining and in situ oil sands development produce significant cumulative environmental impacts and those remain unaddressed.”

Plain Facts
It’s easy to find yourself flinching at the organization’s messianic sense of its own rightness. However, the Pembina Institute plays an important gadfly role within the oilsands industry. As an advocate for better environmental performance, it brings public and governmental pressure to bear on the industry.

Pembina does confirm its raw data with producers before conducting its analysis and releasing its publications, and that is to the ENGO’s credit. However, the organization then invariably puts its collective boots to the necks of lesser environmental performers – or, when justified, damns exceptional performers with faint praise. In one presentation on its website, Pembina labels statements from the Alberta government and the industry as “Spin” but describes its own biases as “Plain Facts.” Perhaps a reality check is in order. To use just one example from the table above, in situ projects mostly use non-potable groundwater, 90% of which they recycle, and then re-inject that water into underground formations. In the interest of spin, Pembina forgets to mention this plain fact.

The good news about the ERCB’s expansion of the surface mineable area in the Athabasca sands is that it describes a huge volume of petroleum that can be developed safely and, as technology and production practices improve, in more environmentally sustainable ways. Especially if your biggest concern is air pollution, oilsands mines are the way to go. Where to go is a plain fact of the ERCB report.

According to the highly-respected Canadian Energy Research Institute, combining carbon capture and storage or using nuclear energy as a component of production could create oilsands plants producing fewer greenhouse gas emissions per barrel than conventional crude oil. In the study noted earlier, CERI describes an astonishing scenario. “The oil sands could pave the way as a bold new energy system,” CERI argues, “producing hydrocarbons to power our economy with almost zero GHG emissions being released into the atmosphere.” Looking forty years into the future, the institute suggests that “by 2050 the reduction from CCS coupled with nuclear energy would enable the oil sands to produce at 2030 rates with zero emissions being released, creating the cleanest sources of produced crude oil on the planet.”

The irony, of course, is that in this case the real visionary is a research institute with ties to the University of Calgary and funded by industry and government. Like the Pembina Institute, most ENGOs are just gadflies. They have a role in the ecosystem, but revolutionary change is taking place without them.

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Colossal Chore

 

Even government computers are strained by oilfield waste

This article appears in the May 2009 issue of Alberta Oil Magazine

by Peter McKenzie-Brown

The story of petroleum is a story of waste.

Consider the volumes involved: At perhaps 3.5 million barrels per day, Canada is the world’s seventh-largest oil producer, and at 16.9 billion cubic feet per day, the third-largest natural gas producer. Add in the gas liquids and related products and the sheer volume of fossil fuels that flow out of the Canadian soil starts to become astronomical.

And these numbers measure “spec” oil and gas – products that are clean enough for pipeline transport. Consumers rarely consider the huge amounts of waste created as the industry brings its output up to spec.

At every stage, considerable volumes of waste need to be treated. Consider the sources of upstream oilfield waste. Seismic surveys, wellsite construction and drilling produce wastes ranging from bush cuttings to rock chips to drilling and fraccing fluids. Production wastes include salty byproduct water, gunk in tailings ponds, contaminants like carbon dioxide and hydrogen sulfide, and soil contaminated with sulfur. Once a plant needs to be decommissioned or a well shut in and abandoned, the producer creates more wastes that need to be carefully managed.

How much waste is involved? In Alberta, the Energy Resources Conservation Board regulates oilfield wastes. After a lengthy explanation of the limitations of the board’s computer system, Susan Halla, a regulatory manager, says, “We’ll be able to give you exact information in 2011.” In the meantime, she won’t even guess.

Even when detailed data are available, it will be incomplete. The reason is that most wastes from oil sands mining operations are not considered oilfield wastes. They are classified as “industrial wastes” and regulated by Alberta Environment rather than the ERCB.

Petroleum waste only begins in the “upstream,” exploration and production side of the industry. Once spec products flow through the pipeline into the “downstream,” refining and distribution processes produce wastes of their own. Like waste from oil sands mining, they are classified as “industrial wastes” and regulated by Alberta Environment.

By far, however, the largest volumes of physical waste occur in the distant downstream end of the petroleum products life cycle. Many items – plastics and chemicals, say – end up in landfills and dumps, unregulated incinerators, beaches and worse. Equally important, consumers burn natural gas and refined products to generate energy, thereby yielding carbon dioxide, nitrogen oxides and a variety of other unsavory incidentals. As emissions, however, they are technically not considered “wastes.”

The seriousness of upstream waste management did not become clear until the 1980s. An ERCB chairman of the era, the late Vern Millard, once explained, “We used to think Earth could absorb any amount of human waste without a problem. It has now become clear that it can’t.”

In an effort to obviate official regulation, the old Canadian Petroleum Association – the forerunner to today’s Canadian Association of Petroleum Producers – created an industry-wide voluntary code of waste management practices. Although regarded as a good stop-gap measure, the CPA guidelines didn’t last. Governments soon took over the job of regulation.

The ERCB’s role in waste regulation began in the mid-1980s, when the industry began to recognize that oil could be recovered from oily leftover materials in tank bottoms, separator sludge, flare pits and so on. Facilities known as reclaimers began to emerge in active oil- and gas-producing areas. At first, the board’s regulation of these facilities was aimed at making sure volumes of recovered oil were accounted for properly. Spurred by the federal government’s 1986 proclamation of dangerous goods transportation regulations, though, the board became heavily involved in oilfield waste management, regulation and inspection.

In 1990, Alberta began consolidating existing environmental acts and regulations into a comprehensive document that eventually became known as the Environmental Protection and Enhancement Act. This and other environmental measures slice and dice provincial wastes in a number of ways. They can be classified as oilfield wastes or industrial wastes, and those wastes can be hazardous, dangerous or not-dangerous. Alberta Environment regulates hazardous and industrial wastes. The ERCB regulates oilfield wastes.

As waste regulation evolved, it became apparent that reclamation or recycling services could no longer be permitted to operate without regulation. After all, they were reclaiming wastes that were potentially dangerous, and sometimes hazardous. Hazardous oilfield wastes include hydrocarbons with low flashpoints; highly acidic or alkaline chemicals; and such volatile organic compounds as benzene, toluene, ethylbenzene and xylenes, which collectively go by the acronym BTEX.

After these products had been defined as hazardous, the board gave the owners of the province’s reclaimer operations a simple choice. Transform their facilities into high-standard waste management facilities or, in the words of CCS Corporation’s Greg Dickie, “clean them up and shut them down.” Most chose to convert to quality waste management operations.

With oilfield waste facilities not allowed to handle hazardous materials, the province badly needed a large disposal facility. Accordingly, Alberta developed a “special waste treatment center” northwest of Edmonton at Swan Hills to deal with hazardous oilfield wastes and also carcinogenic PCBs, which are primarily a waste product from electric transformers. Owned by the province but operated by the private sector, Swan Hills is primarily a specialized, high-temperature waste incinerator. The oilfield wastes that require incineration there include spent filters, oily rags and specialized high-BTU wastes.

As the 1990s wore on, regulators developed rules covering everything from the construction of landfills to deep well injection of liquid wastes. Those rules and the constant changes to them are available in a glut of guidebooks, information letters, directives and interim directives – all of which have been posted online by the agencies responsible.

Practice Run

H2S re-injection a rehearsal for carbon storage program

This article appears in the May 2009 issue of Alberta Oil Magazine

by Peter McKenzie-Brown

Once an obscure part of waste management, the injection underground of unwanted gases will soon become a huge part of Western Canada’s business. The industry has had plenty of practice at disposing of nastier materials than carbon dioxide.

Oil and gas operations produce two kinds of acid gases – hydrogen sulfide (H2S) and carbon dioxide (CO2). The former is usually stripped from the gas stream and converted into sulfur. Tom Byrnes, a reservoir engineering manager at the Energy Resources Conservation Board, says the sulfurous impurity is sometimes just stripped from the gas and re-injected underground. “It’s usually an economic question. There may be small volumes of H2S in the gas stream, or the infrastructure [to strip out sulfur] may not be in place to make it practical.” In Alberta, the board regulates all disposals through disposal wells and first approved an H2S re-injection project in 1989.

Both of these acid gases are routinely stripped from natural gas for re-injection, as appropriate. “But the smaller the concentration of H2S or CO2 there is in the gas stream, the more expensive it is to get it out. It’s a problem of diminishing returns,” Byrnes says.

If H2S can have commercial value as a source of sulfur, CO2 is frequently injected into operating oilfields to stimulate production. This is not new. Carbon dioxide has long been used for enhanced oil recovery, to urge additional barrels out of elderly oilfields. One such project has been operating in the 50-year-old Weyburn oilfield in southern Saskatchewan for nine years.

The project uses a 330-kilometer pipeline to transport carbon dioxide captured at the Great Plains Coal Gasification plant, which manufactures methane from coal near Beulah, North Dakota. As it keeps oil flowing from this aging field, each year the EnCana-operated project disposes of about 1.5 million tonnes of carbon dioxide emissions. This is environmentally beneficial, since CO2 is both an acid gas that can acidify water and a greenhouse gas that can trap heat within Earth’s ionosphere.

While EnCana’s Weyburn project is profitable in its own right, most industrial operators would find it economically prohibitive to strip CO2 from industrial processes for sequestration down disposal wells. Those economics changed profoundly last July when Alberta Premier Ed Stelmach announced a $2-billion commitment of government assistance to advance carbon capture and sequestration (CCS) technologies in the province. Provincial authorities are now sifting through a dozen applications for funding, and will announce the successful projects as decisions are made.

Alberta’s involvement follows a gestation period of deep study, including a provincial policy paper which observed that “Alberta has a unique opportunity to implement carbon capture and storage to substantially reduce our greenhouse gas emissions. CO2 emissions can be captured where they are produced, transported and stored in geological formations (such as depleted oil and gas reservoirs, coal beds and deep saline aquifers) that may be located hundreds of kilometers away.

Ultimately, CO2 capture and storage technologies provide the province with the greatest potential to substantially reduce greenhouse gas emissions while, at the same time, retaining our ability to produce and provide energy to the rest of the world.”

According to that policy paper, Alberta is counting on CCS to meet 70 per cent of its long-term greenhouse reduction targets. If the five provincially subsidized projects – likely to cost a billion dollars each–all go into operation, they would collectively reduce emissions by up to five million tonnes annually. That is likely just the beginning for large-scale underground carbon sequestration projects in the province.

While five million tonnes annually of sequestered CO2 may seem like a large number, it’s barely a whiff of what’s possible. Over four decades, Alberta’s greenhouse gas emissions plan targets a 200-million tonne cut in emissions, but only compared to a do-nothing scenario. That volume is a bare indication of the huge volumes of waste – solids, liquids, effluents and emissions – generated by one of the world’s leading petroleum producers.

Waste to Wealth

Cleaning up after fossil fuels is a thriving enterprise, recession or not.

This article appears in the May 2009 issue of Alberta Oil Magazine

By Peter Mckenzie-Brown

Oil and gas fields, like homes, never stop generating trash. The difference lies in the volume and nature of the rubbish. From exploration through production and eventual abandonment of wells and plants after fossil fuel reservoirs deplete, energy waste management has grown into an industry in its own right.

Common oilfield wastes include oceans of brackish “produced water” that flow to the surface in volumes measured in millions of barrels and have to be separated from oil then put into safe disposal. There are other oil-contaminated materials that can be solid or liquid. The process of completing wells alone generates respectable volumes of drill cuttings and other solids that can no longer be left lying around.

Over the last 25 years, waste regulations have become steadily tougher, encouraging growth of a disposal business that has outlasted boom-and-bust cycles of energy prices and spread across the countryside in tandem with exploration and production operations. Since 1998, the number of producing wells across Western Canada has more than doubled to about 226,000.

Deepwell Energy Services is considered a small newcomer in the field but already has four facilities in Alberta, including a large new waste treatment facility south of Calgary, near Claresholm. Last year, the company acquired a 50 per cent interest in a water disposal facility near Midale, Saskatchewan, as the celebrated Bakken oil drilling play expanded across the southeastern reaches of the province.

Built upon assets that have been around for a while, three-year-old Deepwell organized itself as an income trust and went public just before a federal government decision dubbed by investors as the Halloween Massacre of 2006 to start taxing trusts in 2011. “Everyone in the trust system is now trying to figure out how to reorganize,” says Bob Ritchie, a veteran of more than 25 years in the industry who was Deepwell’s president until March 23.

The biggest players in oilfield waste have already made their moves: Newalta Inc. has reverted to the traditional corporate model. With the help of a large hedge fund sponsored by investors from the United States as well as Canada, CCS Corporation turned itself into a private company in 2007. For its part, Deepwell is using a five-year transition period allowed by the government to decide upon its next move.

Licensed to deal only with “upstream” exploration and production materials, Deepwell typifies the independent specialist in oilfield waste management operations. “It’s up to the producer to characterize and classify their wastes. Our facilities can accept a lot of waste streams, but some materials are not on the list of acceptable materials,” Ritchie explains. Lubricating oil used in exploration and production machinery, for instance, has to go to another specialist as a refined product. Production companies are responsible for tracking and reporting their waste streams to Alberta’s Energy Resources Conservation Board.

The watchdog agency keeps a close watch on waste disposal. “All our Alberta sites are ERCB-approved,” Ritchie says. “We use compacted clay liners, concrete berms, groundwater monitoring, water run-off and run-on systems – it’s all self-contained. The facilities are inspected quite often and very rigorously. It’s completely random. ERCB inspectors are out there at least once a quarter.”

Deepwell vice-president Brian Johnson describes how the company deals with basic waste streams in its Alberta facilities. “We purify produced water as much as we can, then inject the cleaned-up water down our disposal wells,” he says. These are drilled into secure underground formations of porous sedimentary rock capped or surrounded by harder stone, in structures that can be used as natural vaults for permanent storage.

Crude oil waste that has value is also scoured out of industry equipment. The material comes “from such sources as tank bottoms we clean up and dry up and either credit back to our customers, keep for our own account, or do a bit of both,” Johnson reports. The recovered oil must satisfy standard quality specifications before it can be put into pipelines. Cleaned-up solids like sand used in well “fraccing” or fracturing operations are shipped off to sanitary landfill sites.

While Deepwell is a small player in the sector, CCS Corporation is big. It has 48 facilities across Canada, from northeastern British Columbia to Manitoba, plus operations in Louisiana and Texas. Greg Dickie, a senior manager, reports that CCS deals primarily with dangerous materials.

“Wastes coming into our facility are called dangerous because they have a flashpoint, and they have a flashpoint because they contain hydrocarbons. The ERCB defines oilfield wastes, and there’s a clear line between hazardous wastes and dangerous wastes, and between dangerous wastes and not-dangerous wastes, and they fall within different jurisdictions,” Dickie says.

Hazco, a CCS subsidiary, operates a network of industrial landfills, bioremediation facilities and hazardous waste transfer stations. Hazardous wastes are regulated by Alberta Environment and mostly treated at the special treatment facility near Swan Hills. “Our business is to recover hydrocarbons from the wastes and then deal with the byproducts,” Dickie says. “The solids go to landfill, while the liquids go to deepwater disposal. We separate oil from water at our sites.” CCS also has terminals. “We are connected to a pipeline. We receive a producer’s oil, clean it up and send it through the pipeline.”

As economic recession slows down drilling and development across Western Canada until energy prices and bank credit make comebacks, is waste still a growing business? The consensus among the specialists is yes. At Deepwell, Ritchie says: “Last quarter we saw a downturn in exploration activity, and that is not likely to be good for the industry. Having said that, we do get a significant portion of our business from production, and production tends to continue even in a low commodity price environment.”

At CCS, Dickie says: “Up until most recently business was growing – right through 2008, in fact. We believe our industry will continue to grow even as the conventional industry begins to deplete. The types of services we offer through our operations are services that assist people in cleaning up, remediating and managing depleting assets. We believe our business will continue to grow even if the oil industry has the occasional decline.”

In the long run, conventional oil and gas production are in decline in Western Canada as geological reservoirs deplete naturally. Does that mean there will be less oilfield waste?

At Deepwell, Johnson isn’t so sure. “The lines between conventional and nonconventional production are beginning to disappear,” he says. “More and more effort is being put into making unconventional wells produce economically. As we use more unconventional resources, there will be greater volumes of waste. It is a growth sector.” He adds that as fields age, they tend to produce more water, and the need for water disposal will continue to grow.

Dickie sees additional opportunity within areas where there is still some infill drilling to be done. “As the percentage of oil in production goes down, the percentage of water and other materials, including emulsions and some solids like silts, goes up. That’s where our facilities become valuable to producers,” the CCS executive says. Emulsions or streams of mixed liquids and solids need to be treated as oilfield wastes.

Much water is also produced with some of the newer oil discoveries including Saskatchewan’s Bakken formation. Sometimes the water is used to maintain reservoir pressure. Sometimes it’s simply re-injected into a deep rock formation, to prevent surface- and groundwater contamination. Whatever the case, the volumes are increasing, and the job of getting rid of the stuff is requiring more effort.

At the ERCB, regulatory manager Susan Halla flags another reason the waste management business is going to continue to grow. Reading from the regulations, she describes oilfield waste as “an unwanted substance or mixture of substances that results from the construction, operation, abandonment or reclamation of a facility, wellsite or pipeline.”

Based on that definition, the industry creates wastes at all stages of operation – from construction to decontamination and reclamation. So there will be wastes to manage whether an operation is in the stage of development, oilfield decline, closure, abandonment or surface land reclamation.

Environmentalism is a growth force, says Ritchie, who saw the effects of public demand for cleaner industry first-hand as a project manager for TransCanada Corp. as well as during his tenure at the helm of Deepwell. “The movement to be environmentally responsible has continued to advance. Over time it’s likely to become more stringent, and that is actually likely to help us.”

It is a widespread industry consensus that western Canadian waste management regulations are among the most stringent in the world. “Over the last 15 years Alberta has been at the forefront of waste management, even compared to Louisiana and Texas. I don’t know of another regulator that has taken the same initiative as Alberta in developing waste management regulations,” says Dickie. Where CCS operates, “the ERCB is the leader. Saskatchewan and British Columbia are close behind, and Western Canada is at the front of the pack.”

At the ERCB, Halla stresses that Canadian regulators work with each other to make sure their regulations march in step. “We work with Alberta Environment to harmonize waste management practices within the province. We also have committees to harmonize practices in Western Canada, and also we are involved in national harmonization.”

Ritchie says there is momentum for improvements within the private sector. Annual inspections of facilities became routine at Deepwell, he recalls. “I think the whole industry has a heightened awareness of the need to meet or exceed regulations. Everyone is conscious of environmental stewardship. I see the whole industry trying to advance their performance.”