Just a ‘FRAC’ away

New gas mega-wells threaten to strain contractor fleet

This article appears in the April 2009 issue of Alberta Oil magazine.

The graphic compares natural gas production from a conventional sandstone reservoir to fracced, unconventional production.

By Peter McKenzie-Brown

If unconventional natural gas is a revolution in the making, so are the services required to make it happen. Industry spending patterns are shifting, with much bigger investments now being poured into operations below the ground.

Traditional ways of doing business are changing. Multiple wells are drilled from single sites, known as “pads,” to tap the new gas target. The old oilfield rhythm of busy winters and quiet summers is also changing as work grows in the warm seasons.

Despite the economic downturn, there is even a hint of a gas counterpart to the former oil sands labor shortage in the air. There is a risk that in the near future Western Canada will find itself short of powerful hydraulic equipment needed to make the networks of underground channels that make unconventional gas deposits flow. This would be a blow to exploration and production companies, but possibly a considerable financial boon to service companies with the right stuff to do the rock fracturing, a field known as “fraccing” in the industry.

The specialty is a well stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pushes a mix of water, sand and some soluble chemicals into well bores at high pressure, both to spread cracks across the formation and hold them open for gas and oil to flow.

Originally a simple operation, fraccing has evolved into a high industrial art that uses multi-stage techniques in horizontal wells, reports Dave Russum, geosciences vice-president for AJM Petroleum Consulting. “Between the heel [start] and the toe [end] of a horizontal well, you isolate an interval close to the toe and frac that region,” Russum says. “Then you move back towards the heel, isolate another interval and do another frac.”

The technique is a powerful production tool. “This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability [poorly flowing] rock than you would ever be able to reach with a vertical well,” Russum says.

In the old days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times. A well that requires so much work would likely have a horizontal reach of 3,000 metres or more.

Analyst Kevin Lo of FirstEnergy Capital Corp. estimates that fraccing just one of EnCana Corp.’s Horn River shale gas wells in northeastern British Columbia requires a crew equipped with more than 30,000 horsepower of compression. In Western Canada, there is perhaps 800,000 horsepower available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary” if B.C.’s Horn River and Montney shale gas drilling hot spots grow, Lo says in a research note. He also worries about the heavy lifting required to deliver enough fraccing materials. Fracturing a single horizontal well in the new unconventional gas reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice-president at Trican Well Service Ltd. describes FirstEnergy’s estimates of requirements for the new gas production as conservative. “Some of the Horn River wells require up to 45,000 horsepower of compression,” Dusterhoft reports. “With 10 holes per pad, you may have 40,000 horsepower tied up for 10 weeks.”

The Trican executive predicts, “There will be shortages of equipment when we get up to full development of the shales.” If it happens, the squeeze will be a plus for service companies like his, which will then charge premium day rates, but a worry for the gas producers in the region.

Environmentalists have voiced concern that fraccing chemicals may contaminate groundwater. But Dusterhoft says that, before wells are fracced, the formations are securely sealed away from potential fresh-water reservoirs.

Use of chemicals is also limited in the unconventional wells in northeastern B.C. “We only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand,” Dusterhoft says.

Fraccing’s goal is to create a web of flow channels. When the technique is completely successful, he says, all of the fractures connect with each other to provide maximum production, he says. “We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs in northeastern B.C. require vast logistical support. Each well can require 2,000 to 3,000 tonnes of fine-grained sand. Parades of trucks deliver vast harvests of ancient sand mined from fossil beaches, often from quarries in Saskatchewan. Such a project may require a 40-member crew, operating 20 or more hydraulic compression systems mounted on large fraccing trucks.

High volumes of water are also used. A typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has contributed to the developing seasonal shift in the fraccing business. “Now the industry is drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction,” Dusterhoft reports.

Water is easier to handle in warmer weather. In the longer term, the changing work pattern will require upgrading to all-weather roads to Horn River and Montney. Until those improvements are completed, service companies have to leave equipment in the area during freeze-up.

The shift to unconventional gas occurred much more quickly than anyone expected, Dusterhoft says. Among numerous implications of the switch, an old barometer of industry health –the sheer number of wells drilled – is becoming obsolete.

The production change, while increasing oilfield work, is contributing to a reduction in the total number of Canadian wells being drilled. In 2008, nearly 40 per cent of the wells involved horizontal or directional drilling – twice the level of 10 years ago. For the first time, FirstEnergy Capital said in a recent research note, the number of horizontal wells across reservoirs will soon match the number directionally drilled at angles. Greater proportions of industry spending on wells are going into completion services like fraccing.

Unconventional gas operations are not cheap. Drilling costs are in the range of $5 million to $7 million per well at Horn River, and $4 million to $5 million at Montney. Fraccing costs are estimated to be $2 million to $3 million per well.

But the production profiles for these wells make them worth their costs. Each may produce 7.5 million cubic feet of gas per day in their first year. Production declines rapidly but typically levels off at around two million cubic feet per day then stays steady for years. When gas prices improve, the new wells will be cash registers.

Productivity Alberta

This article appears in the April 2009 issue of Oilsands Review

By Peter McKenzie-Brown

“It’s really tough to be less productive (than other companies) when times get bad,” according to Jim Rakiewich. “You and your competitors are both scrambling for sales, but prices become compressed. So the companies that aren’t really productive and have too much cost built into their products – they really get killed.” The president and CEO of Edmonton-based McCoy Corporation, Rakiewich was discussing Alberta’s productivity growth – or, more to the point, the lack thereof.

In economics, the definition of “productivity” is bloodless. It is a ratio comparing what is produced to what is required to produce it – usually an average expressing the total output of some category of goods divided by the total input of, say, labour or raw materials. Bloodless the definition may be, but the reality of Alberta’s productivity ranking is downright bloody: Dead last in labour productivity growth among Canadian provinces during the period 1997-2005. Growth was 1 per cent a year – below the national average of 1.4%, and well below growth rates for U.S. and European countries.

The Alberta government is concerned about this problem, and in March launched an agency – Productivity Alberta – to help improve provincial productivity. Rakiewich is one of a group of private sector CEOs who have agreed to serve as advisors to the agency. “If you want to stimulate productivity in Alberta,” he says, “it’s important to have those who are passionate about it on the governing board. That’s why I’m on the board.”

Alberta’s go-to person is Lori Schmidt, a senior director in the Finance and Enterprise bureaucracy. “When this process started,” she said, “companies were working flat out, didn’t have enough people, but despite working at capacity were finding their bottom line continually shrinking. That’s why we started to look at the importance of increasing our productivity. Today, with the economic conditions changing, there’s probably even more need for firms to look at their efficiencies. This doesn’t mean getting rid of people, but utilizing our people to their best ability. Are we utilizing all the inputs and resources and processes that we have so that we can continue to compete?”

Schmidt describes the new agency sees itself as a “path-finding service” which will offer two levels of service to any business that asks for it. “For free, we will offer a preliminary assessment to help them with their operational efficiencies, perhaps by directing clients to online tools. Right now, people may know they have problems but don’t know where to begin. That’s the free part.” Adds the ever-enthusiastic Jim Rakiewich, “You don’t really pay for someone to help you analyse your processes and offer advice. In effect you are getting free consultants, and these are really sharp guys. Where your costs come in is in implementing those ideas.”

“The second part,” continued Lori Schmidt, “is to connect (our clients) to tools and programs and services that are already out there in the marketplace. We want to be the connection point” between organizations that need to become more efficient and resources they can use to achieve that aim. “This is available to any business, but we are really focusing on value-adding businesses – anyone who produces a good. Manufacturers and their supply chains, for example, but also small and medium enterprises. In Alberta, that means businesses with 100 employees or less. Those companies have been doing a lot of work in the oilsands.”

According to the new agency’s slick new brochure, “Productivity Alberta brings together the talents and efforts of people and organizations across the province to tackle productivity challenges and to provide a direct point of access to productivity enhancement offerings. This industry-guided, not-for-profit corporation works in concert with government, industry, academia, associations and communities throughout Alberta to address productivity challenges.”

Jim Rakiewich has bold opinions about the importance of higher productivity and about the reasons why Alberta’s recent record has been so dismal. “Those who are more productive have lower input costs. If you are not really connected (to the importance of increased productivity), you have a lot of waste in your system.”

Alberta’s low productivity growth has had a number of causes – most importantly the tight labour market. There is also a geographical component to Alberta’s poor recent performance. According to Rakievich, “North America is not very competitive compared to the rest of the world, and Canada generally performs worse than the U.S. Alberta just hasn’t been very focused on becoming more competitive” – to a big extent because of the tight labour market. “Rather than finding the right skill sets for jobs on offer, (companies in Alberta) have been hiring warm bodies and trying to bring them up to standard.” He adds that, because manufacturing is such a small part of the provincial economy, there is less experience to draw from than in, say, southern Ontario.

Rakievich’s final comment pertains to the threat of global markets to Alberta business. “Markets are really global in nature, now, and outsiders are coming in to steal market share. This is forcing us to realize someone is going to eat our lunch if we don’t smarten up.” Heed this.

In the Centre of the Storm

This article on SEPAC chairman Stan Odut appears in the April 2009 issue of Oilweek magazine; graphic from here.

By Peter McKenzie-Brown

Toward the end of a long and thoughtful interview, a smile flickers across Stan Odut’s face. The topic of his grandchildren has come up, and he brings out a photo of the four who are aged seven and older. Wearing Ukrainian dress, they are dancing at a multi-cultural festival in Calgary. A Chinese dragon dance takes place in the margin of the picture, suggesting the great diversity of today’s Alberta. His pride is palpable and infectious, and he’s probably thinking back on a life well lived.

Odut’s story is exactly contemporaneous with that of Canada’s modern energy era. Born in Germany just as Imperial’s Leduc #1 well ushered in Alberta’s post-war conventional oil age, his family migrated to “a very poor farm” near Dauphin, Manitoba, where he grew up. The new chairman of the Small Explorer’s and Producers Association of Canada (SEPAC) moved to Calgary after earning an engineering degree from the University of Manitoba in 1969. Forty years on, no one is prouder of his city or his province than Stan Odut.

As SEPAC chair he is the voice of junior oil, and he urges small companies to join the trade association. “Membership isn’t expensive, and SEPAC can help you get your voice heard by provincial and federal politicians.” With more than 450 members, the organization describes itself as representing “Canada’s oil and gas entrepreneurs” – a tag line the association has actually trademarked.

According to Odut, the small companies need to “press for revised regulations, cutbacks in bureaucracy and a more efficient industry.” He has strong views on the changes needed to return health to the juniors.

Background: His early career included stints with Hudson’s Bay Oil and Gas, Texas Gulf and Canterra Energy – larger companies that were eventually absorbed by acquisitors. After finding himself at Husky after its 1991 takeover of Canterra, he left that corporation and began working with smaller companies.

He was one of the founders of Del Roca Energy, which eventually sold out to Tusk Energy. Five years ago he formed privately-held Sifton Energy, which he serves as president and chief executive officer. Sifton has 80 shareholders, ten employees and daily production of 950 barrels of oil equivalent. Odut’s original exit strategy was to sell out to a trust “but now with the downturn, we’re struggling a bit to keep on going. There would be no advantage in going public, though. Public companies are so badly discounted that there would be a real disadvantage to doing that.”

Now he begins to address his key messages. “The sources of capital for the junior sector are equity, debt and cash flow,” he begins. But in today’s environment, “many companies are already mired in debt and credit lines are being pulled. You can’t get additional debt coverage. You can’t raise any equity because there is no reason for investors to put money into the energy business right now. And governments (provincially in particular) have strangled cash flow. So help me with the equation: you’ve got to get one of those factors to change to get the business going again.”

Odut describes the economic situation as “dire”, and observes that it has built up over several years. The treatment of trusts has been a major contributor. Another has been the loss of the Alberta royalty tax credit. “Actions by provincial and federal government have debilitated our industry”, which is mostly headquartered in Alberta. The economic environment is becoming similar to that of the 1980s, when exploration and development collapsed, layoffs replaced hectic hiring, and Alberta’s rural areas found themselves with little work on the rigs or in oilfield construction. In both periods, the junior sector was hit particularly hard.

Just as westerners with long memories generally finger the National Energy Program as an important cause of decline in that earlier period, Odut places blame for the deteriorating situation on Alberta’s new royalty regime. “It has resulted in fewer jobs, less activity and less money in government coffers.” He acknowledges that it has been “more than the royalty regime that has killed activity…. It’s also been oil and gas prices – but those prices are the same in Saskatchewan and British Columbia” where activity is still relatively strong. In Odut’s view, Alberta’s new regime helped drive activity into the other western provinces.

“The Alberta advantage seems to have disappeared,” he laments. “You can see it in municipalities increasing taxes on infrastructure, the cost of obtaining surface leases or the new royalty system. Alberta’s bureaucracy now seems to be anti-development.” While he acknowledges that “there are land bargains out there,” he stresses that “you need cash to take advantage of them. And if I put on my Alberta resident’s hat, should I be happy that provincial (mineral rights) are being sold for a song?”

As this article goes to press, the Alberta government has promised measures that will provide relief for the juniors, and the government has agreed to consult with SEPAC and other trade associations. “My advice on help is the sooner the better,” says Odut. “We have already lost the winter drilling season. Now we have to concentrate on (getting activity going during) the summer drilling season.”

Incentives: Only two years ago, when oil prices dropped to $50 per barrel, there was no let-up in investment in Alberta. Yet last year, when average oil prices hit their all-time high, that changed. Why? Because investors no longer feel they can count on a stable regime in Alberta.

“Large companies are still going around the world and investing,” says Odut. “They know that one pass through (countries with immature petroleum basins) can give them a good short-term return. They are less concerned if the regime changes. (But Alberta) is not a one-pass-through basin. You need to know there will be a stable return over time.” After the recent changes in royalties, that certainty is no longer there.

Although Alberta is a mature basin, Odut is optimistic about its future. “Better than 35 per cent of the conventional oil resources are still there waiting to be recovered,” he says. Odut’s optimism about Alberta’s productive potential is qualified by deep skepticism about its exploratory potential. “Right now, only one (exploratory) well in seven is a decent well. I think there are still a lot of good opportunities in the conventional sector. The opportunities are in technology, because of improved recovery methods. We aren’t going to find a lot of great new fields, but we can get a lot of left-over barrels of oil using new technologies. We need incentives to do that.”

“The present regime,” he says, “penalizes you if you come up with a good well by increasing royalty rates from 35 percent max to 50 percent max”. While acknowledging that at present prices oil royalties are “at the bottom of the scale,” he stresses that the present system “penalizes horizontal wells, which reduce the industry’s environmental footprint. If you are successful, instead of having four 10-barrel-per-day wells, you could have a single horizontal well producing 100 barrels per day.” However, because the present regulations impose lower royalties on less-productive wells, “you shoot yourself in the foot by drilling (horizontally) under the existing regulations.”

At the end of last year, the Alberta government announced a 5-year window in which companies could apply the old royalty system to new wells. Stan Odut wasn’t impressed. “It doesn’t address the basic question of what you are going to drill with. You need debt, equity or cash flow to drill, and it really didn’t address any of those issues. Equity I can’t raise any, credit there isn’t any and governments are strangling cash flow.” The royalty regimes are better in BC and Saskatchewan, he says, “and BC is tweaking its system to make it even better. The biggest problem is here in Alberta.”

The outcome is that large companies have taken their cash flow and vacated the province, leaving it to the junior sector. Yet the junior companies have little to work with. To turn this around, he says, “You have to acknowledge that capital will flow to where it will get the best return. Our fiscal regime does not encourage the flow of capital into Alberta.”

What’s a government to do? Provincially, he suggests incentives for horizontal wells. Federally, he argues for changes in flow-through tax rules.

If Edmonton encouraged small companies to use horizontal wells, production would go up and the environmental footprint would go down. “You need to encourage investment in horizontal wells, as Saskatchewan does. They have a royalty holiday for horizontal wells – you pay a very small royalty on the first 100,000 barrels or so. That way the investor is able to recover his money before the government begins receiving its take.”

Ottawa, on the other hand, should take steps to expand flow-through investment. Under the present flow-through rules, companies can pass tax breaks associated with exploration directly to individual investors. The focus of that program, however, is exploration, the success of which is in decline. “Flow-through rules should (be changed to) enable companies to put flow-through money into development wells, where the risk is lower. (The federal government should) make larger sums available, so slightly larger companies could take advantage of it. This would encourage investment, and that investment would be used for drilling. Companies could choose whether they wanted to put money into exploratory drilling or development. It would give you much more cash flow.”

Peak Oil: Stan Odut is one of a growing contingent of oilmen now subscribing to the concept of peak oil – the notion that the planet’s maximum rate of oil extraction is at hand. After that point arrives, the rate of production will enter terminal decline. “I believe we probably aren’t going to see an increase on the supply side globally,” he says. “With the global economic situation there has been (crude oil) demand destruction, but I would add that there has also been supply destruction because drilling has been declining, producers are shutting in supply” and many large projects, world-wide, have gone on hold.

Prices are low because “right now oil is overbalanced on the supply side,” he says. “When things do recover, I think we are going to be in a really tight situation. The horizon might be shorter than many people predict. I think within the next five years – certainly within the next ten – we will meet a supply crunch probably like we have never seen before.”

“There’s a huge disconnect between developing world and developed world consumption,” he says. “Either we have to tap some alternative resources which we don’t really know about today, or many of us in the developed world are going to have to really cut down on our oil consumption. The developed world has to contract its consumption a lot.” This sounds ominous, and Stan Odut quickly adds that he doesn’t want to be a scare-monger.

“I’m getting a bit long in the tooth and I have an eye for what my grandchildren are going to face as we go down the road. I think they are going to be facing a different world from the one we are in today.”