The Game-changer

By Peter McKenzie Brown
Every once in a while a computer application comes along that causes fundamental change. A great example can be found in the area of microcredit, which has the potential for transformational change in the developing world.

About five years ago two twenty-somethings founded Kiva Microfunds on a shoestring budget. In its first five years of operation, the online service connected private lenders to nearly half a million entrepreneurs in developing countries. Through Kiva’s global network of micro-finance institutions, those mom-and-pop lenders have already provided $170 million to poor Third World people whose only alternative was the local loan shark.

Kiva has unquestionably been a game-changer for micro-investment in the developing world. Until recently, nothing comparable has been available for corporate community investment.

True, most large corporations use an online grant management system – a place on their websites through which hopeful not-for-profits can request project funding. While TCPL Corporation uses this tool, community investment manager Jamie Niessen cautions that “This is not a primary vehicle for us to use in building relationships, which is what community investment is all about.”

However, he continues, “it’s a useful tool. It automatically generates e-mails. The first one says your application has been received and we will provide you with further updates. During the determination phase, if we haven’t made a decision the system automatically sends an e-mail saying your application is still in process. If we reject your request it automatically generates a rejection letter. If we approve the project, it creates a letter explaining how we will get you the funding.”

Such a function may be bloodless, but it’s practical. It’s an administrative nice-to-have or maybe even an administrative essential. Transformational it is not.

My Goodness!
In fact, according to critic Bryan de Lottinville, “many companies in the oilpatch use that software and have paid a pretty good chunk of change for it. They believe they have a workplace giving program, but they really don’t. These are legacy systems, and it is somewhat of an uphill battle to provide an alternative, even if it’s free.”

Enter software tool Goodness 3.0 – a business application developed by de Lottinville’s company, Benevity Social Ventures. Kiva it isn’t, but this tool nonetheless has the potential to change the way companies handle much of their corporate investment.

“Our approach has been to create a mechanism which enables corporate constituents to give in their own environment,” according to de Lottinville. The online application fits into places “where people and transactions already exist – for example reward programs, an employee deduction plan, a banking interface – any environment where charitable donations may be part of the goal of the transaction.” He adds, “Unlike programs (like grant management tools) that enable not-for-profits to fundraise from destination sites, ours is a business-to-business model.”

Here’s how it works. A company can integrate the Goodness 3.0 tool into a number of pages on its websites – for example, the human resources page on its intranet or the customer rewards page on its website. Users can then go into their accounts and make direct contributions to virtually any certified charity in North America.

They can create a basket of charities they want to donate to – a process that’s a bit like “creating your own personal foundation,” according to de Lottinville. “You can choose one or more charities; allocate percentages among them; set them as one-time or recurring donations. If you choose charities that the company wants to support, they can encourage you to do so by increasing the leverage available for those donations. Matching contributions take place in real-time; the donor employee doesn’t have to wait for their contribution to be matched.” He stresses that the application is inexpensive, quick and (almost) fool proof.

At this point, Randy Findley – cofounder of Provident Energy – picks up the story. An investor in de Lottinville’s company, Findley not surprisingly waxes eloquent about the potential of Goodness 3.0. “Employees are the key to your success” he says; “they can always go somewhere else. So being a better corporate citizen than your competitors is important. It helps to attract and retain employees. A program like (this) enables the company to really focus on the charitable interests of the employees. It eliminates the guesswork in respect to what charities your employees are interested in.”

It “empowers your employees to become directly involved in where their money goes. Today people are much more interested in following their dollars: ‘What are the results of my donations? How have those contributions been working?’” He continues, “If there’s a major cause you want your employees to contribute to, you can leverage your employees’ gifts (through gift-matching) to encourage them to go in that direction.”

Bryan de Lottinville adds that “part of our solution to it is to provide companies with a different way of allocating their funds. Our program enables employees, customers and other stakeholders to say ‘yes’ to many more worthy causes.” Because a company using this system is more likely to be offering matching funds rather than grants, it is an elegant tool for aligning the company’s interests with those of its employees.

The idea doesn’t just work for employees, either. Integrated companies like Husky, Imperial, Shell and Suncor could use it to strengthen their consumer brands. For example, if customers donated reward points to specific charities, they could offer to match them. They could also use these online sites to process charitable gift vouchers their customers may have received.

Where to Go?

Some say transportation should be a market grail for natural gas, while others aren't so sure

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie Brown
In his best-selling 1958 book The Affluent Society, Canadian-born economist John Kenneth Galbraith popularized the concept of conventional wisdom. “It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability,” he wrote. “I shall refer to these ideas henceforth as the conventional wisdom.” The problem with conventional wisdom is that it isn’t always true. Contrarians are often right.

Price Bull
It’s worth keeping that truism in mind as we develop the case for building new natural gas markets in North America. In a recent comment, author and analyst Peter Tertzakian argued that the rapid decline in drilling for natural gas across North America raises the question of whether natural gas is likely to continue to be in a serious state of oversupply. Tertzakian notes that for the first time in 15 years half of the US drilling fleet is drilling for oil, compared to less than 20% of rigs for the last decade. Such a dramatic decline in drilling almost certainly suggests that production levels will decline, he suggests.

He then moves on to the killer argument: “Let’s say (gas) production starts retreating in earnest this year and natural gas prices rise back to some fictional level like six dollars per MCF. Notionally, the (conventional) wisdom goes that producers will dispatch more rigs to ramp up production and thus clobber prices again. There is a problem with this line of thinking: why would producers do that when more money is to be made elsewhere?” He suggests that as long as oil is valued at more than four times the value of gas (energy equivalency basis), there is little motivation for the industry to shift toward more gas drilling. The result? Declining supply and still higher gas prices until a cost-reward rebalance restores aggressive natural gas drilling.

Supply Bull
Since Tertzakian is such an unusual voice in the wilderness, the balance of this article assumes that the conventional wisdom is true. Gas supplies are likely to continue to be plentiful, and there will continue to be a need to develop new markets. One of the most interesting advocates of greater markets is the legendary oilman T. Boone Pickens, who says he has invested $70 million in developing and promoting The Pickens Plan.

An 83-year-old geologist who received his degree in geology in 1951, as a young man the Texas-born Pickens spent a decade in Calgary. In a broadcast interview, he said he opened an office in Calgary in 1959, and lived in the province with his family in the 1960s. After moving back to the United States, he made a multibillion-dollar fortune in exploration and development and, much more publicly, as a corporate raider. His current passion is to promote the Pickens Plan.

“For 40 years the United States has had no energy plan,” he explained. “We’ve just been drifting. Just drifting means you are just importing more oil from the Middle East, countries that the state department recommends we not visit.”

Pickens is adamant that the United States should reduce its dependency on overseas oil, and he believes that renewables like wind and solar aren’t viable anymore because of cheap gas.

“Natural gas is the only thing we have that can replace non-North American foreign oil. We import 5 million barrels from the Mid East. That’s the oil I want to replace with gas. If you had 8 million 18-wheelers (in the US trucking fleet fuelled with natural gas), that would cut OPEC imports in half.” He added, “If the US administration announced that from now on all new government vehicles would use domestic fuel that would be a powerful message to send to the world.”

“This is a security issue for me. I don’t want to be dependent on the enemy for energy,” he said. Until gas prices cratered, Pickens was a strong advocate of wind energy, and he was leading an effort to finance a multi-billion dollar wind farm in the Texas Panhandle. He uses this fact to support his green credentials. “Natural gas is 30% cleaner than diesel. We have the cleaner, cheaper, abundant fuel here, and it will replace the dirty fuel from the Mid-East.”

Pickens is also an advocate of continental fuel switching – in particular, substituting natural gas for coal in power generation facilities.

For many years most commentators have believed that the United States could never become self-sufficient in energy, Pickens said, but “things have changed. We have so much natural gas – the US has a 100 years supply, and the Canadians have a lot up in Horn River, for example, and the Canadians have a lot of oilsands (oil). Let’s use that to make North America energy self-sufficient.” He added, “When people say to me, ‘Hey, Pickens, I don’t like your plan!’ I say ‘Fine, what’s your plan? If you don’t have a plan your plan is to import more oil from the Middle East.’”

Not many oilmen are as colourful as T. Boone Pickens or as motivated by worries about enemies in the Middle East. However, there are a lot of other natural gas supply bulls.

Exxon-Mobil, for example, demonstrated its belief by plunking down $31 billion for gas-focused XTO Energy a year and a half ago. A company vice president, William Colton, recently told the New York Times that “If there is any kind of major trend, we think it’s going to be a shift toward more natural gas.” He added that “Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

Agency Bull
America’s Energy Information Agency, whose job is to forecast supply and demand based on best-guess current trends, doesn’t appear to see much of a plan to promote greater use of natural gas anywhere in the future. According to the early-bird version of the 2011 forecast, “Non-hydro renewables and natural gas are the fastest growing fuels used to generate electricity, but coal remains the dominant energy source for electricity generation because of continued reliance on existing coal-fired plants” well into the foreseeable future.

According to the EIA, the agency has revised its methodology for gas prices “to better reflect a lessening of the influence of oil prices on natural gas prices, in part because of the increase in shale gas supply and improvements in natural gas extraction technologies.”

Of course, as Peter Tertzakian argues at the beginning of this article, it might be a mug’s game to discount energy equivalency too deeply when you are calculating the relative values of oil and gas.

Whatever methodology the organization uses, the EIA does forecast an increase in North America’s natural gas demand, but its estimates seem paltry compared to the aggressive development that T Boone Pickens, for example, is promoting.

The agency forecasts a strong near-term increasing demand because of a “strong recovery in near-term industrial production, growth in combined heat and power, and relatively low natural gas prices.” Look farther out into the future, however, and the agency’s forecasters are more circumspect than the gas supply bulls. “U.S. natural gas consumption rises 16 percent from 22.7 trillion cubic feet in 2009,” they intone, “to 26.5 trillion cubic feet in 2035.”

Such a small increase in forecast demand – 16% over 25 years – suggests that the EIA’s gas supply bulls aren’t as optimistic as Pickens; he might complain that they “don’t have a plan.” You could equally argue that there are contrarians among them.

Gas to Gold

Talisman Energy is pinning its shale gas market strategy on proven gas-to-liquids technology

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown
It’s hard to match Colin Soares’ bragging rights. The Calgary-based engineer was president of the company that demonstrated the shale gas potential of the Montney formation.

The way he tells the story, “from some work we’d done (with Home Oil subsidiary Scurry Rainbow) in the late 1980s. We originally thought it was the source rock, a number of us believed that the Montney formation contained an abundance of hydrocarbons to deliver, and we set out to prove it up.”

He led the formation of a private company, Rocor Inc., with initial funding of $2 million, although during the company’s brief life it raised an additional $15 million.

“Our mandate was to prove this idea, then to hand over the keys to a company with deep pockets, as it takes an awful lot of capital to develop these plays with horizontal wells. To do a job like this and become a producing company you would probably need $50 million to $100 million.”

Rocor demonstrated the existence of wet shale gas with vertical wells only. “As we were drilling we had a lot of condensate coming in and killing the well.”

The company’s thinking was strategic in several ways. “We bought 14 sections of land between two rivers,” says Soares. “Whoever owned that land could control things when they started planning facilities. When word got out about what we’d done, land prices all around us really started to go up – like in any real estate boom. We were the first in the area drilling for this resource, but obviously people with deeper pockets soon overtook us.”

In October 2008, Rocor sold out for $50 million to PetroBank, which promptly drilled a horizontal well that produced 8.5 million cubic feet of gas plus 350 barrels of condensate per day – “tremendous results,” according to Soares.

What to Do with Shaley Plays
At least part of the significance of Rocor’s efforts was that it illustrated the tie between tight gas and shale gas. According to Dave Russum, AJM Petroleum Consulting’s geoscience vice president, the Montney is a case study in a kind of “hybrid” natural gas resource – a hydrocarbon formation halfway between gas from tight sands (the prospect Scurry Rainbow had originally been investigating) and shale gas pure and simple. In fact, according to Russum, these prospects are best described as “shaley plays”. They contain shale and sand in relatively larger and smaller percentages, but whether they are more like tight sand or shale gas they require fraccing to yield economic production.

In a real sense, the shaley gas plays are an extension of Canadian Hunter Exploration’s Deep Basin tight gas developments of the 1970s. Montney occupies one end of the shaley gas spectrum, and partly includes old-fashioned tight gas. Horn River, which taps the Muskwa shales in a basin just south of the Northwest Territories and just west of Alberta, is a picture-perfect shale gas play. According to Russum, it may prove to be the biggest shale gas play in North America.

Of course, in an environment of rapidly expanding gas supply the key issue is what to do with the stuff. In recent months, Talisman Energy has placed two major bets on the use of GTL (gas-to-liquid) technology, which transforms natural gas into a combination of high-quality liquid fuels and petrochemical feedstock.

Gas-to-Liquids
This effort began last December, when Talisman announced a billion-dollar joint venture on its Farrell Creek property in the Montney. In March, the company announced a similar deal in respect to its Montney area Cypress A properties. On behalf of the partnership, the Calgary-based oil company will operate the Cypress A and Farrell Creek projects as integrated development projects.

Talisman’s partner in both ventures is petrochemical giant Sasol, which honed its expertise in turning coal and natural gas into liquid fuels during an international oil boycott imposed upon South Africa during Apartheid. Che company’s two South Africa coal-to-liquids (CTL) facilities represent the largest and most profitable asset in Sasol’s portfolio.

Sasol and Talisman are investigating the economics of building North America’s first gas-to-liquids plant. In cautious news release language, the companies agreed to undertake feasibility studies “to examine a world scale gas-to-liquids (GTL) facility in Western Canada, with Talisman having the option to participate as a 50% partner in the facility. This could provide a strategic alternative to traditional North America pipeline or LNG markets. The GTL process produces premium, clean liquids fuel. Sasol is leading this study with a front-end engineering design decision likely in the second half of next year.”

Put another way, a decision on whether to proceed with an engineering design for the Canadian project is expected in 2012.

The Talisman/Sasol plant would turn Western Canadian gas into value-added liquid fuels and petrochemical feedstocks. Converting natural gas into liquid fuels is particularly attractive now, given the prospect of an extended period of low natural gas prices in a high oil price environment. This solution could create diesel and other fuels that are used in automotive transport.

GTL, which will become increasingly significant as crude oil resources are depleted, is operational already in a number of Sasol plants around the world. In addition, super major Royal Dutch Shell produces diesel from natural gas in a factory in Malaysia. When finished, its Pearl GTL plant in Qatar, will be the world’s largest GTL facility.

Until recently, GTL only made sense in gas-producing regions which could not build pipelines to major markets. The reason it has suddenly become economical Western Canada, of course, is that despite ample pipeline capacity to American markets, British Columbia’s shaley gas projects have created huge supply surpluses at the end of one of the world’s longest gas pipeline systems. The plant, according to the two partners, could provide “a strategic alternative to traditional North America pipeline or LNG markets.”

In a corporate statement, Talisman CEO John Manzoni put it like this: “This transaction allows Talisman and Sasol to unlock additional value in the world-class Montney shale play and potentially accelerate development of the resources in the area. The Cypress A assets are very similar to Farrell Creek and, with our partner, we will now build an integrated long-term development plan for the area.”

Sasol chief executive Pat Davies added that “this additional acquisition of another high quality natural gas asset will accelerate our upstream growth while also potentially advancing Sasol’s already strong GTL value proposition utilizing our proprietary technology.” That pretty much sums it up.

Nature’s Gift to the World
In a presentation a year ago the boss of ConocoPhillips, James Mulva, called natural gas “Nature’s gift to the world.” Taking a shot at the unbendable greens – he called them “hydrocarbon deniers” – Mulva complained that “They support renewables at any cost, and oppose hydrocarbons at any consequence….They seem not to realize that platitudes are not BTUs.” Citing the environmental advantages of gas, he argued that industry and government should ensure that the world’s gas supplies are used to their full potential.

If they do, he argued, by 2050 natural gas will have potentially helped meet four great energy challenges: achieving US and world energy supply security; providing consumers with affordable energy; driving economic prosperity and job creation; and reducing greenhouse gas emissions. He argued that vast conventional and unconventional gas resources – more than 38,000 TCF globally, by some estimates – will ensure stable supplies and reduce the risk of long-term price volatility.

Within that context, much needs to be done to develop supplies and to develop markets for natural gas. Surely GTL will play an increasingly important role in exploiting nature’s gift.

The Road to Success

Canada's shale gas producers are paving the way to successful exploitation of a massive resource

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown

The shale gas revolution has turned the natural gas business upside down at a pace no one could ever have imagined. There is now tough competition in North American gas markets and the legendary successes of junior oil companies in the province—a crowning achievement of western Canada’s way of doing business –is in decline. Juniors can’t be really small anymore because they now generally require a lot of start-up capital. Crashing gas prices have put some into receivership, forced many to merge and forced all to change.

Perhaps Winter Petroleum—a small, privately held company—typifies the situation for little gas producers. With operations in the northwest corner of Alberta, the company got its name because its properties can only be drilled during the winter, according to president Duncan McCowan, a geologist.

“Winter drilling requires a lot of equipment and it’s expensive,” he says, “and our production is remote from major markets. Because of cost structure and transportation, we’re finding it tough to compete in U.S. markets.”

His company hasn’t let any employees go, however. “We are still slightly profitable, but we can’t grow. We’ve cut back our capital spending completely and many of our operational items too. (Dry gas) activity in that part of the province is at a standstill.”

McCowan points to a decline in the number of junior companies, partly through bankruptcies like that of Drake Energy, which was a neighbour to his own gas company, Winter Pete.

“Today you need pretty serious money for a start-up. A few million dollars won’t go very far anymore, because the new technologies we’re using involve horizontal wells and multi-stage fraccing. It used to be you could drill a well for a couple hundred thousand dollars. Today it takes millions, and financing groups are putting together a fund of, say, $35 to $70 million and then putting an experienced management team in charge. There are fewer mom and pop petroleum companies around.”

Peter Tertzakian of ARC Financial Corp. says two other important trends favour consolidation and larger companies.

“Bulking up to get costs down helps you deal with lower prices. It gives you economies of scale. A related factor is that a lot of companies are migrating to horizontal drilling and completion strategies, but that’s very expensive.”

On average those wells cost $4.5 million, and there have been many wells that cost $8 million or more. “By drilling fewer wells that are more expensive each, you need more backbone – you need to be a bigger company.”

The companies most at risk are those that are heavily leveraged and biased to natural gas, but many of the smaller ones are successfully implementing what he calls “revitalization strategies: shifting their focus to liquids-rich gas, or even prospecting for oil. A small amount of liquids in the gas stream can make a big difference” since it often has a greater market value than oil.

Compare that situation to the one announced in February, when PetroChina made a huge counter-intuitive deal with EnCana Corp. While other major Asian investments in the Canadian petroleum industry have mostly gone into the oilsands, Petro-China put its money into shale gas. The two companies announced that they had inked a $5.4 billion deal by which they would become equal partners in EnCana’s Cutbank Ridge gas field in British Columbia. This investment, which surpasses Sinopec Corp.’s $4.65 billion acquisition of ConocoPhillips’ stake in Syncrude last year, is Asia’s largest single bet on North America’s energy sector.

According to EnCana spokesman Alan Boras, the focus of this effort is natural gas, not the associated gas liquids.

“We are always looking for ways to maximize the value of our assets, and natural gas liquids extraction is an important part of that process,” he says. “However, that is not our major focus.”

Since the company does not see natural gas prices above $6.63 per thousand cubic feet in the foreseeable future (2021), EnCana clearly is basing its business plan on something other than an upward move in North American gas prices.

One of those ideas is low-cost production. According to Boras, “In the Montney, where we have done the deal with PetroChina, our wellhead cost is about $3.15 (per thousand cubic feet).”

The deal will enable the Chinese to “get an early return on their investment, and then take the technology back to China to use it there. That certainly is part of what they’re thinking. The Chinese have recently talked openly about their need to increase domestic gas use.”

In addition to low-cost production, new pipe in a region already riddled with infrastructure could lower future transportation costs. This is the significance of the National Energy Board’s recent approval of TransCanada Corp.’s plan to build a $310 million pipeline to connect British Columbia’s Horn River shale gas region to its Alberta mainline system.

Ascendancy?
While the gas industry isn’t exactly in the ascendant, some trends suggest that ascendancy might not be far off. This isn’t readily apparent, since shale gas has backed Canadian producers out of traditional U.S. markets and driven down prices.

Low prices have made much of Canada’s conventional gas uneconomic in distant U.S. markets, and many producers are in trouble. In recent years the only major commodity to decline in price and stay there, natural gas has mostly defied winter demand for heat and summer demand for air conditioning.

The price collapse is forcing the industry to dramatically restructure, clouding the outlook. Such legacy assets as Canada’s Arctic gas fields look increasingly like white elephants: the likelihood of a pipeline from north to south is slipping ever farther into the future.

According to Robin Mann, president of AJM Petroleum Consulting, “Because of the development of shale gas formations like Montney and Horn River and others with great potential right next to infrastructure and pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and B.C.?”

Consumers are happy with lower prices. Companies are not, however, and neither is the government of Alberta—now into its fifth consecutive year of deficit budgets.

One Alberta politician with ideas on the issue is Wildrose Alliance leader Danielle Smith, who doesn’t have to worry about balancing this year’s provincial budget. She sees the collapse in gas prices as an opportunity.

“There is so much we can do now to increase demand: fuel switching, the Pickens Plan (to increase gas use in automotive transport) in the United States, increasing use of gas for power generation.”

She even talks about installing modern-day gas-fired Stirling engines in our homes, to generate both heat and power. “If we do these things, consumers win. So does the environment and so do gas producers.”

In a way, those simple ideas describe a path that could bring the industry out of its funk. They are also consistent with much of what the industry is already doing in response to a rapidly changing business environment.

One industry response has been to reduce natural gas drilling--at this writing, at a one-year low. Companies are focusing instead on drilling for oil. According to ARC Financial’s Tertzakian, “this capital migration continues to be a positive leading indicator for natural gas price recovery.”

The industry is also responding to low prices with rapid adaptation of technology. It is cutting costs, seeking profitable niches and developing better markets. In addition, consumers are responding to the attractive price of natural gas, and policymakers are seeing it as a low-carbon alternative to other fuels.

And North America’s dominance in shale gas development makes it for the first time a potential large-scale manufacturer of liquids made from natural gas.

Gas-to-liquids
The gas-to-liquids concept is most evident in the billion-dollar deal Talisman Energy struck late last year with Sasol, the South African petrochemicals giant. The deal involved selling a 50 per cent interest in Talisman’s Farrell Creek shale gas properties in British Columbia. Eventually, the partnership could develop a plant using Sasol’s gas-to-liquids technology to turn the gas into a desirable liquid fuel. This is proven technology: Shell, for example, is constructing a $6 billion gas-to-liquids project in Qatar, the tiny Middle Eastern country with 15 per cent of the world’s proved natural gas reserves.

Another way to solve the stranded gas problem is to create liquefaction facilities for natural gas exports. When finished, the $3 billion Kitimat LNG project will become another face in the global LNG market—competing with, for example, Qatar.

According to Rosemary Boulton, the founding president of Kitimat LNG, “we’re experiencing a bigger gas bubble than we have seen in western Canada for 20 years, and this makes (LNG exports) a particularly viable proposition. We need to develop LNG to meet the needs of gas markets other than those in the U.S.”

Apache Corporation and EOG Resources obviously agree, since in December they bought out her start-up company—after it had received development approvals—and Canadian gas giant Encana Corp. came onboard with a 30 per cent interest this past March.

Countries like India and China will eventually begin developing their own shale gas resources but at present “Japan and Korea are the world’s biggest importers of natural gas,” says Boulton, “and they have no indigenous supply.”

She adds that “there are a number of ways you can write a price contract, and one of them is based on the price of WTI. That’s a pretty good price for exporters. For importers, it’s a lot better than a contract based on the price of Brent (North Sea) oil. Markets in Asia price natural gas relative to the price of oil, so that could be very attractive.”

Bill Gwozd, a vice president of Calgary-based Ziff Energy Services, agrees. “If you have an Asian market that’s prepared to pay (an LNG) price that’s linked to oil, we think (shale gas production) can surge.”

Boulton sees room for expansion of Canada’s international LNG business. “The Kitimat project is approved for five metric tonnes or 700 million cubic feet per day. The pipeline will be capable of supporting a much bigger project—doubling (project capacity) is certainly viable.”

She doesn’t see a lot of LNG shipments leaving from B.C.’s Lower Mainland, however. “Projects are all about location. I see a lot of objections to a project (there) because of the nature of some communities on the Left Coast.”

Stakeholder engagement
A year ago, American filmmaker Josh Fox released a film called Gasland, which purported to document the dangers of hydraulic fracturing for shale gas. One landowner after another talked about the dangers of shale gas to their health, and some spectacular footage showed a man setting water from his kitchen tap alight – the result, he said, of shale gas polluting his water well.

Ziff Energy’s Bill Gwozd is sceptical. While he acknowledges that the consumption of large amounts of water for fraccing can be an environmental problem in areas where water is in short supply, he’s sceptical about the rest. “Shale gas and ground water are peanut butter and oil,” he says. “They don’t touch each other.

There are a lot of people who want to talk about shale gas polluting groundwater but it just isn’t going to happen.”

He points out that the geological zones which hold groundwater and shale gas can be literally thousands of feet apart, and that dirt and rock under pressure are anything but porous. “So how could deep zones of shale gas pollute groundwater, which is maybe 1500 metres up?”

“You’ve got to believe that the answer is in the details,” he says. “A lot of people complain about shale gas development without bothering to understand the technical issue. When you get into that conversation, they have to come to the conclusion that there is no problem here.”

Well, not entirely. In March Québec’s environment minister, Pierre Arcand, said the government didn’t have enough scientific information about hydraulic fracturing to sanction its further use. Until his department completed its research into what had become a heated public issue, the government imposed a drilling moratorium on Québec’s promising Utica shales.

Ziff’s Gwozd has a kind of conspiracy theory respecting public concern about shale gas. “Who’s driving the environmental objections?” he asks, rhetorically, then offers his own answer: “Anybody (with an interest in) conventional gas, in LNG, in coal, in energy alternatives. If you complain about it, you make it an issue. (To say these worries are based on science) is like the fox telling the bird he doesn’t want to cook it for turkey day.”

Enter Lane Wells, the principal at head•stock, a public consultation firm which specializes in aboriginal communities. Wells describes effective stakeholder engagement as involving “thoughtful, non-adversarial and respectful exchanges of information. Listening to stakeholders is important. Responding to what you have heard is critical.” Stakeholder engagement is becoming increasingly crucial if you want public policies that give you the right just to develop shale gas.

Changing Policy
Public policy is becoming increasingly important in other ways, too. For example, the Obama administration is now behind a drive to make natural gas the fuel of choice in as many energy-consuming applications as possible, with an emphasis on switching coal-fired power plants to gas.

Senior Democrats in Congress are getting behind the stuff, portraying it as an alternative fuel for transportation that can serve as a stopgap until renewable sources of energy, like solar and wind power, become economical on a broad scale.

Reflecting this policy, last year Rahm Emanuel—a congressman and formerly President Barack Obama’s chief of staff—introduced legislation which would have offered tax credits to both gas producers and consumers. The legislation died with last fall’s election, which unceremoniously turfed Emanuel and other Democrats from the House.

The promotion of natural gas as a fuel is popular within the industry also. The New York Times cites William M. Colton, ExxonMobil’s vice president for corporate strategic planning, as a serious natural gas enthusiast.

“If there is any kind of major trend, we think it’s going to be a shift toward more natural gas. Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and (the U.S. has) 100 years of supply.”

As these issues get resolved, a leaner and meaner industry using advanced technologies and far more capital is emerging. The industry is opening its collective eyes to a brave new world of natural gas—one in which surplus supplies are convulsing the sector in many ways.

“Our intent is to tough it out,” says Winter Petroleum’s Duncan McCowan. “So we’re doing creative things to cut costs—jointly handling gas with our neighbours, for example. We’re optimistic about our geology—the horizontal potential is huge, but we couldn’t justify (horizontal drilling) in this price environment. Sure, we’re pessimistic about gas prices, but we know they’re going to turn. We don’t know when, but when they do we think it’s going to be pretty quick.”

A sustainable future

Effectively marketing Canada's vast unconventional gas resources can help ensure global sustainability

This article appears in the second volume of CSUG's Energy Evolution Guidebook & Directory

By Peter McKenzie-Brown
If you want to understand how important unconventional gas has become, consider a couple of facts from EnCana – one of North America’s premier gas-producing companies.

According to company spokesman Alan Boras, in 2010 “we replaced 250 percent of our production. We (now) have14.3 tcf of proved reserves.” Of course, much of the company’s new reserves have come from its aggressive shale gas development. But consider this: “Coalbed methane is also an important part of our production – about 10 percent.”

EnCana’s numbers illustrate the remarkable success of the unconventional gas narrative. The big kid on the block is shale gas, but other sources like coal bed methane and tight gas are also important parts of the mix. Unless market conditions somehow kill the development of new supply, gas will remain plentiful and affordable for a long time to come.

This prospect provides Canada’s petroleum sector with a number of opportunities. One is the development of LNG capacity. Another is to use the fuel as a cheap input for oilsands development. A third is to go into shaley formations in the quest for NGLs and other valuable light liquids. The fourth is for oilsands producers to develop both gas and NGLs for financial hedging. Let’s look at these in turn.

LNG
Even though the federal government has given Cabinet approval for Arctic pipeline development, many people in the oilpatch are skeptical that development will begin soon. Put another way, such legacy assets as Canada’s arctic gas fields look increasingly like white elephants.
For example, Robin Mann, president of AJM petroleum consultants puts the issues in a complex question. “Because of the development of shale gas formations like (BC’s) Montney and Horn River and others with great potential right next to infrastructure and pipelines, and with our existing conventional gas and our exports to the United States going down daily, we have more than enough (gas) for our own (use) so why is it important to build these pipelines? Why are we worrying about anything north of Alberta and BC?”

He adds that the costs of the northern pipeline keep going up. “Maybe the best way is to develop LNG facilities in the north, but what will the economics of that kind of project be? Will the price of (Arctic) LNG justify building facilities up there?”

Bill Gwozd, a vice president of Ziff Energy, is much more sanguine about arctic gas. His firm’s model suggests there will be a North American market for Arctic gas beginning in the 2020s, “so it’s important to get ready now to activate those pipelines,” which will take a long time to build and commission.

The need for Arctic gas in North America 15 years from now doesn’t exclude the prospect of beginning now to develop overseas exports, however. In fact, three big and successful companies – Apache, EOG and EnCana – are betting good money that they can make a serious buck out of the Kitimat LNG Project. According to Gwozd, the chances of winning that bet are pretty good. “World-wide, LNG is maybe 10 percent of supply. There’s plenty of room to grow it.”

According to the Kitimat LNG Project’s founding president Rosemary Boulton, “the development of shale gas has developed a gas bubble that’s especially big in Canada. (For conventional gas) it’s worse than anything we’ve seen in a very long time. That makes LNG development more important now than ever.” She adds that “Shale gas is basically a technology play. The industry has found ways to get it gas that we knew was there before, but couldn’t develop. And the better companies are finding ways to producing more efficiently. Efficiency and technology translate in a fairly linear way to a decrease in cost.”

“These projects are all about location,” she adds. “You really have to have a supportive community to make them happen. First Nations and other communities along the pipeline route and around Kitimat were very supportive of the idea of having this project there.” Because the company was able to develop this support under her leadership, both the pipeline and the terminal had received regulatory approvals before the new owners acquired the project.

The Athabasca Oil Sands Story
In a rapidly evolving industry, companies are finding imaginative ways to develop natural gas plays. One of the most interesting examples is Athabasca oil Sands Corp., which has become well known for several years as an oilsands producer wannabee. Through a series of summertime raids at Alberta land sales, in 2006-2007 the company became the single biggest landowner in the oilsands sector – a position it held until the Suncor/PetroCanada merger. But oilsands development is a long-term proposal, and after farming out some of its land to PetroChina, the company had cash in the bank but no cash flow in prospect until its first in situ project comes to life next year.

So what did the company do? Still holding a very large oilsands land position, the company acquired more than a million acres in northwestern Alberta’s gassy Deep Basin. “This is an excellent way for Athabasca to use its cash until needed for our oil sands development,” according to president and CEO Sveinung Svarte. “This area offers the potential for a very short pay-back time and we plan to reinvest that quick return in the oilsands.”

Athabasca’s exploration strategy is to look for liquids and light oil in a gas-prone basin. The company will do this by drilling into Deep Basin formations, where it believes liquids are likely to be found and easily developed. The Athabasca story is almost a reverse image of the breakup of EnCana into pure play companies. According to Svarte, within his company the synergies of diversifying its land position are great. His geoscience and drilling teams can work in oilsands or tight sands with equal dexterity.

More importantly, perhaps, iversification will hedge the company as its oilsands projects begin coming on stream. If diluent prices are high and bitumen prices low, having diluent production of its own will help make that problem right. Of course, the sector in general uses a lot of natural gas – to supply heat for production and upgrading operations, to produce hydrogen for upgrading, and to generate electricity. Companies with gas production could find themselves well hedged if gas prices rise. As Svarte puts it, “we expect gas to be almost a free by-product of our Deep Basin development, so this hedge is well-priced.”

whatIf?
With the help of an Ottawa-based thinktank called whatIf? Technologies, Alberta’s former ADM for Oil, Bob Taylor, thinks a forecasting tool he helped develop could enable policy-makers to better feel, touch and imagine Canada’s possible energy futures. According to Taylor, the recent surge in gas supply reflects a pattern that has been continually recurring in Canada for a century: “Too much gas; too little price.”

Part of his solution to the dilemma this creates was a computer model that could deal with supply and demand without factoring in price. Economists would call that heresy; Taylor calls it “dynamic and robust.” Using numbers the Canadian Society for Unconventional Gas generated using the whatIf? model, he added that the potential ranges of recoverable resource range from a conservative case of 636tcf to an optimistic case of about 1400 tcf.

Those are extraordinary numbers, but such energy wealth won’t be developed without trials. “My worry is that much of this unconventional gas potential remains unproved. For that reason I recommend joint government-industry efforts,” according to Taylor. For political reasons and because of local worries, he adds, it “may not be recoverable in places like Eastern Quebec and offshore BC.” While these are serious concerns, he believes they can be resolved – “but it will require leadership and action.”

A lot is riding on the outcome. If the technical and environmental issues are solved, Taylor thinks Canada’s plentiful supplies of unconventional gas “can be a contributor to helping the world achieve 9 billion sustainable lifestyles by 2050.”

Genetics and Thermal Oil

Niel Edmunds and the next generation of reservoir engineering

This article appears in the June issue of Oilsands Review

By Peter McKenzie-Brown
Neil Edmunds is a serial innovator. Now the vice-president of enhanced oil recovery for Laricina Energy, in the past he’s worked in a variety of technical and executive positions with other companies. For example, at EnCana he provided reservoir and operations direction for Foster Creek’s Vapex and SAGD pilots. At CS Resources he was responsible for the Senlac thermal project in Saskatchewan. Later, as the CS vice president responsible for recovery technologies, he focused on enhanced recovery research.

In the 1980s he was lead engineer on AOSTRA’s underground test facility (UTF), which provided the definitive demonstration of the viability of SAGD. The UTF proved the process beyond question in 1992, when it briefly achieved positive cash flow at a production rate of about 2,000 barrels per day from three horizontal pairs. Edmunds stresses that the use of horizontal well pairs was not his idea, but was suggested by his predecessors at AOSTRA. However, SAGD pioneer “Roger Butler wanted to try a vertical fracture, but none of us wanted that, so we designed the horizontal well idea and tested it at the UTF.” The rest is history.

Just as SAGD was constructed upon the physics of Roger Butler, the original idea for what Edmunds calls his “favourite claim to fame” is partly an adaptation of work begun by nuclear engineer Terry Stone of the Alberta Research Council. Stone’s PhD thesis included a mathematical model to calculate fluid flows at reactor accidents.

At AOSTRA, Edmunds began applying this idea to heavy oil production, and sold the idea to CS Resources when he joined that company in 1995. Eventually acquired by Cenovus through a merger, the simulator “gives a detailed model of what happens in the wellbore in terms of heat transfer and fluid flow,” according to Edmunds. “This gives Cenovus quite an advantage in terms of engineering the wellbores themselves. Think about it: you’ve got a 7-inch pipe and it’s maybe 800 metres long; to make it efficient you have to figure out how to circulate the fluids to heat the reservoir uniformly.” He deadpans, “that involves some real plumbing challenges.”
Replacing engineers with computers

So what is Edmunds up to today? “I like to say we’ve replaced reservoir engineers with computers, but what we’ve really done is up the level at which engineers can operate. Instead of being drones who try to optimize stuff every day, we can now do rapid searches through classes of variables to find the best approach to any given reservoir.”

The first company to attempt to develop commercial production from Alberta’s bitumen carbonates, Laricina’s bitumen carbonates project is now steaming up, and the company will follow this with a program in the Grand Rapids formation, which is essentially the same as the McMurray. Both projects will use thermal solvent programs.

To illustrate the nature of the reservoir engineering problems he faces, Edmunds describes the chore as like finding the highest peak in a mountain range – in the fog. The surface to be optimized can’t be seen, only sampled at specific points. The problem exists in many dimensions, and it’s non-linear – especially when you consider the economics involved. Most frustrating of all, the same action can generate different, even opposite, effects when applied in different situations. Given those realities, he set out to develop an algorithm that could help the company select the most economically efficient way to produce from these difficult and largely unexplored strata.

The project – he says it began as a hobby before he helped create Laricina – now involves an algorithm of about 20 lines, and it could conceivably transform in situ oilsands production. “We use a lot of machinery to run the input files, but the basic algorithm is simple.” He adds, “This is pretty new in the oil business.”

“What we have done is to program a genetic algorithm. We encode the possible processes so the algorithm generates digital chromosomes out of 0s and 1s. Once you’ve run each file you need a fitness score. Ours is dollars per barrel. We create a class of possible processes with a fair number of variables. Our computer may take a couple of weeks, but it can run a huge number of possibilities. The computer takes the winners from each trial, recombines their strings of 0s and 1s – the same thing biology does with DNA. We use some from the mother and some from the father,” Edmunds explains, “and we presumably end up with a better organism. You never know if you have the best possible answer, but in the 5,000 trials the computer ran for us it does seem to have ended up with a very good answer.”

Dumb code
Your reporter’s skill in mathematics is limited, so to pursue Edmunds’ ideas I referred to a paper he and co-authors Behdad Moini and Jeff Peterson prepared for the 2009 Canadian Petroleum Conference. Titled “Advanced Solvent-Additive Processes via Genetic Optimization,” the paper is a partly whimsical, somewhat over-written but unquestionably accessible description of the project. It seems to deliberately raise more questions than it answers.

As the authors explain, the industry has long known that adding light hydrocarbon solvents to steam can improve well performance, but the optimum choice of additives involves evaluating vast numbers of alternatives. The genetic approach may allow computers to quickly come up with solutions tailor-made for each production system.

The authors describe the application of advanced mathematics to complex factors in reservoir engineering and find that the results tally with findings from trial and error. The convergence verifies the usefulness of applying mathematics in this way to real-world problems. The computer run takes a couple of weeks, while trial and error can take many years, so the authors argue that employing mathematics in this way can save time and money, big-time. While they admit that the model is greatly simplified, their general conclusion is that an industry that devoted major effort to similar projects could find itself spending months in the lab instead of decades in the field. The argument is compelling.

After running the algorithm, Edmunds’ team used engineering models to crack the code of the computer output and then applied an economics package to the whole. “In this, we are trying to do an economics calculation. The key thing for me was that working on these solvent processes involves too many variables. When you think you’ve solved a problem, it can be hard to look at the raw output and decide whether what you have come up with is good or not. So we have an automatic economics package which looks at each of the simulations. This permits computers to identify solvents and timetables that will maximize profit.”

With a sense of pride that only the mathematically gifted can appreciate, Edmunds observes that “our algorithm reproduced some of the best mathematical ideas that people have written up in the last 15 years or so.” Not bad for what he calls “a dumb piece of code.”