Where it All Began

Equipment in the Underground Test Facility proved the effectiveness of  SAGD 

A quarter-century after the first Canadian horizontal well was drilled, the technology is the cornerstone of today's industry.

This article appears in the June issue of Oilweek

By Peter McKenzie-Brown
The world of oil and gas was quite a different place a quarter century ago. Production mostly came straight up out of vertical holes. Though the Texans had drilled the first horizontal well in 1929, in Canada horizontal drilling was still mostly an esoteric, unproved and untested technology.

In 1987, all that began to change – so much so that, during the last 25 years, it simultaneously emerged as a standard production technique and revolutionized production. One result is that many petroleum resources have become technology-driven plays. Another is that reserves are way, way up.

In a sense, the most important uses of horizontal drilling technologies are reverse images of each other. “What makes horizontal drilling for nonconventional resources (like shale gas and tight oil) so attractive to the financial community is the very high initial rate of return. In the beginning, production rates are extremely high, although they quickly taper off. You have to remember that these applications enable you to get highly desirable hydrocarbons out of really poor reservoirs,” according to Dave Russum, who is director of geosciences at AJM Deloitte, a consultancy.

The oilsands represent the mirror image of this situation. “You are drilling into tremendous reservoir rocks – highly porous and very permeable, so there’s plenty of oil in there. But until you process the stuff it isn’t a particularly attractive commodity.”

The Bitumen Story

It’s true that in April 1978 Imperial Oil drilled Canada’s first horizontal well into the Clearwater formation at Cold Lake – a storied well overseen by Dr. Roger Butler in an early test of a system of oilsands production now known as steam-assisted gravity drainage (SAGD). After that test and a less interesting effort by Texaco a couple of years later, in Canada the technique mostly languished until 1987.

Then the advent of improved down-hole drilling motors and the invention of other necessary supporting equipment, materials, and technologies – particularly down-hole telemetry equipment, which enabled rigs to drill straight on target – led to an explosion of new applications for this technology. Producers and the drilling and service firms that support them found endless new uses for directional drilling – especially as it is used for horizontal wells.

Appropriately, in Canada the first horizontal wells drilled after Imperial’s early test were part of the Underground Test Facility (UTF), which celebrated its official opening on June 29^th, 1987. Developed by the Alberta Oil Sands Technology and Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into limestone 15 metres below the reservoir.

Within those tunnels, AOSTRA constructed large well chambers. “Pairs of injection and production wells were drilled upwards from the well chambers at a 17⁰ slant,” according to the mining engineer behind the project, Gerry Stephenson, “and deflected horizontally into the base of the reservoir. The mobilized bitumen drained by gravity from the steam chamber in the reservoir to the well head in the tunnel and all of the production was pumped from a central location.” Those tests proved Butler’s theories about SAGD beyond any possible doubt.

Over its 15-year life, the UTF also evaluated other recovery strategies, but nothing compared to its SAGD results. “AOSTRA’s staff had estimated that the recovery might be somewhere between 30 percent and 45 percent of the bitumen in place” during the Phase A tests, according to Stephenson. “We actually got 65 percent recovery. The steam chambers formed by mobilization of the bitumen spread way beyond the area we’d expected….Over the 10-year life of the well pairs, Phase B got a steam/oil ratio, the most critical figure of all, of 2.3 to one.”

The tests at the UTF forever transformed Canada’s oilsands industry. Today, SAGD is responsible for more than half of Canada’s bitumen production.

Ironically, Sceptre Resources drilled the first horizontal well in Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests. Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive application of a form of SAGD illustrated the kinds of problems horizontal drilling could overcome. With an active aquifer below and a gas cap above, the reservoir’s pay thickness was about 27 metres. The oil was heavy: about 13^o API. Primary production from the field had been meagre (0.6% of the oil in place), and the use of cyclic steam stimulation, which uses vertical production wells, had flopped when they tapped the aquifer and started producing 99% water.

That was when the company decided to try SAGD – not the technique we use today, but the primitive version Imperial had tried out nine years earlier. Sceptre injected steam through four vertical wells near the gas-oil contact, draining the mobilized oil through a horizontal well. At the industry’s leading edge, the company found itself with a technical and economic success.

Fast Production from Tight Reservoirs

More than any other series of innovations, the technology-intensive processes that now surround directional drilling have enabled the industry to get production out of otherwise unproductive rock. In August of that same transformational year, Alberta Energy drilled the first horizontal well into the Glauconitic formation at Suffield. This was the first time a Canadian operator drilled horizontally into a conventional oilfield.

Things then quickly sped up. In February 1998 alone, three significant projects based on horizontal drilling took off. Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at Ansell (Alberta) into the Cardium formation and at Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant to connect isolated small reservoirs or improving contact within heterogeneous rocks to enhance the sweep efficiency.

“In the 1990s the big push was to explore conventional carbonate rocks, especially from the Mississippian in Saskatchewan,” according to AJM Deloitte’s Russum. “The idea was to develop known reservoirs where the rock quality was variable, using horizontal wells to extract more oil from those formations…. Many different companies hopped on to the horizontal drilling band wagon in Saskatchewan with more than 500 wells drilled into the Mississippian in 1997 alone.  In that year more than 1300 horizontal oil wells were drilled across the basin – a tally that was not beaten until 2007.”

Horizontal drilling also began to tap the heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there was a lot of experimentation in other reservoirs. Also, of course, in that decade SAGD began to be developed in its modern form.

As horizontal drilling became more commonplace, the petroleum industry began combining it with innovations in both drilling and well completion technologies and ideas. The result has been like a snowball rolling downhill. Horizontal drilling has been enhanced by geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new bit design, for example. Also, producers can now drill multilateral horizontal wells from a single drilling pad.

Perhaps the important recent development on the drilling side is the monobore. Monobore drilling involves running a casing string, then forcing a steel cone down the well to expand it in the hole. This process is repeated with identical casing strings. Thus, monobore completions have the revolutionary characteristic of installing a string with the same interior diameter from top to bottom. “These are making a huge difference,” said Russum. “In the past you had to drill a vertical well, then run the casing to the bottom and wait for the casing to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.”

Although technologies like microseismic are also making a difference, the most important developments on the completion side have involved the increasing power and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you proceeded to the next one. Today it’s a continuous process.”

These clusters of technological breakthroughs first created the shale gas revolution. Pioneered by an American, George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began yielding highly economic volumes of natural gas – and, not incidentally, drove down the price of gas. Some observers now describe natural gas as a low-value by-product encountered in shale reservoirs in the quest for natural gas liquids.

From a production perspective, the other great outcome from this cluster of technologies has been the development of tight oil from shale – what Russum prefers to call “conventional oil from more shaley, low-permeability reservoirs.” One outcome is that both western Canada and the US are experiencing growing light oil production for the first time in decades – much of it coming from the Bakken play in North Dakota and Montana. After decades of decline in Alberta, for example, light oil production has recently risen to ten year highs.

An Explosion of Uses

These new technologies are changing almost everything about Canada’s petroleum industry. For example, horizontal wells are now a huge part of gas storage. “You can store gas very quickly into those wells,” said Russum, “and you can extract it quickly, too. Then there is the whole area of trying to reduce surface impact. I think we’re going to see more and more of that. Surface owners are more and more reluctant to have pumpjacks and other surface equipment on their land, and horizontal wells are less likely to disturb natural habitat. There is also extended reach, so you can reach under lakes and towns and cities. You can use it to reduce water production in a thin reservoir located over an aquifer.”

The economics of the horizontal well are also greatly improved, especially when you are planning production from a narrow reservoir – ten metres thick, for example. Horizontal wells provide much greater contact with the reservoir per dollar of drilling than do their vertical kin. And when they are drilled in search of unconventional resources like shale gas and tight oil, the producer gets a quick payback because initial production rates are so high.

Still not convinced? Then let the numbers tell the tale. According to an AJM Deloitte study which is complete to late 2011, more than 30,000 horizontal wells have produced conventional oil or gas in Western Canada over the past twenty five years.  Of that tally, 4,300 were completed in 2011.  This set a record for horizontal oil drilling: nearly 3,500 wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly attracted by the high liquids content in the Montney and Middle Mannville. Today, half of Western Canada’s wells are being drilled horizontally.

Is horizontal drilling helping bring about any other changes? Perhaps it is even changing the way corporations work. “Companies that fail to adequately research the geology are putting themselves at considerable risk if they assume all resource plays are alike and that more and larger fracks are the solution to economic production,” according to Russum. Even so, engineers are increasingly replacing geologists in the executive suite.

Traditional geologists who spent entire careers looking for conventional reservoirs are now more interested in minor variations in rock properties, in stress regimes and in proximity to source rock. In terms of traditional petro-geology this is a difficult concept to grasp, but to a large extent it is a response to the revolution spawned by horizontal drilling.

Oilsands companies in particular, but also other companies involved in modern resource plays are basing their business plans on step-by-step, decades-long development of vast and well-defined resources. This means traditional wheeling-and-dealing is at least partly on the decline – to a large extent replaced by courting cash-rich foreign companies with deep pockets and the desire to support these capital-intensive activities.

The Captain Takes a Bow

Suncor Energy starts the long goodbye to Rick George, the man who built it from broken to megaweight

This article appears in the February issue of Oilsands Review; photo from here

By Peter McKenzie-Brown
Bob McClements has had a long association with the oilsands industry. He was construction manager for Sun Oil Company’s (Sunoco) original Great Canadian Oil Sands plant and the first plant manager when it went on stream in 1967. When it commissioned that pioneering plant, Sunoco was one of the largest integrated oil companies in the world. In the 1980s McClements rose to its highest ranks, becoming president and chief executive officer.

When Sunoco was near the top of its game, McClements asked American-born Rick George—who at the time was in charge of Sunoco’s North Sea development and production, and had overseen construction of Europe’s first purpose-built offshore production platform—to take charge of the company’s Canadian subsidiary, Suncor Energy Inc.

“I flew over to London and asked him whether he would give up his position with an established operation in the UK and move to a totally different environment in Canada. After only a day, he agreed,” says McClements. “You have never met a more unassuming, low-key but brilliant executive in your life. He’s quiet and unassuming, but when he speaks you listen. He knows what he’s doing because he came up the ranks. He was given increasing responsibilities and he did well in every one of them.”

Headquartered in Toronto until 1995, George became Suncor’s president and chief operating officer in 1990; the following year the board appointed him chief executive officer. Also in 1991, McClements retired and Sunoco accelerated its policy of divesting upstream assets so it could focus instead on refining and marketing. Accordingly, it spun off Suncor as an independent entity.

Big mistake: Suncor had market capitalization of $1 billion when George took over. Today it’s about 48 times bigger, and 12 times larger than Sunoco. Rick George, who recently announced that he will fully retire at the end of July, was the architect of this spectacular business achievement. In his years at the helm of Suncor, McClements said with some understatement, “he has become the number one executive in the oilsands.”

Why did its owners divest Suncor? According to George, “We were actually going through a recession back in 1991-92, both here in North America and in Europe. It was a period of time at which the Government of Ontario [75 per cent owner] was struggling with paying their bills. This was an area they could liquidate. Sun Company had some issues around debt as well. It was just fortunate that both of them actually needed money at the time and decided to sell Suncor to the public.”

When George took over, Suncor’s primary assets included the money-losing oilsands plant, some service stations and a small refinery in Ontario. The oilsands business “really struggled with return on capital well into the mid-1990s [because of] high costs relative to low oil prices,” George said in a recent interview conducted for the Petroleum History Society’s Oil Sands Oral History Project. “There were 20–25 years of real struggle between when this industry got its first plant online and when it actually started to make enough money to make sense.”

Building an oilsands heavyweight
Assisted in the early years by Dee Marcoux, executive vice-president, oilsands, the first items of business during George’s presidency were to restructure the 60,000-barrel-per-day plant, deploy truck-and-shovel technology for mining, make major improvements to the processing plant, and expand capacity to 130,000 barrels per day by 2001.

In 1998 Suncor filed its regulatory application for Project Millennium, comprised of mining capacity increases and a new upgrader. The project was a dramatic expansion designed to increase production to 210,000 barrels per day. George recalls that, “about the time our board approved the Millennium Project, which was 1997, The Economist had a front page view that they expected prices to be at $5.00 a barrel for a long period of time…I think what they lost track of is that this industry moves through cycles and it will continue to roll through cycles as we invest, as we try to figure out where the next investments should be.”

Millennium was a good investment, he added. “We started the project when there were low oil prices. When we got the project done in 2002, oil prices rose and it was obviously a great win for our shareholders. I always think of oil companies as big deployers of capital. And I think the management and leadership of oil companies is really about making right choices at the right time.”

In 2001, Suncor announced its Voyageur growth strategy, a multi-pronged approach targeted to bring oilsands production to 500,000 barrels per day by 2012. The plan included a mine extension, third upgrader, and in situ expansions at the Firebag steam assisted gravity drainage (SAGD) project. The Voyageur strategy was slowed by the global recession, but not derailed. Its most significant piece, the Voyageur upgrader—now a joint venture with Total E&P Canada—is expected to be re-sanctioned in the near-term. George says the upgrader should reduce business volatility. “It should improve reliability. It’s going to be a project that will be online for 50 to 100 years…you’ve got to take a very long-term view of this business.”

And that long-term view rests a lot on in situ development. In addition to undeveloped leases and the MacKay River SAGD project acquired through Suncor’s 2009 merger with Petro-Canada, Suncor considers its Firebag assets to be a key piece of the future. “Firebag is in the middle of a lease we hold that has 9 billion barrels of recoverable oil,” George says. “So this is again an asset base that will be on production for the next hundred years in some form or another.”

Putting assets together
In 2009, George announced a $19.1-billion bid to take over Petro-Canada. With the merger’s success, Suncor suddenly had a much bigger refining and marketing presence in Canada, light oil and gas properties around the world and significant additional oilsands properties.

“If you look at it in a historic sense, we picked Petro-Canada off at the low point of the market, or pretty close to that,” he says. “I’d thought for a period of time about putting the assets together, particularly their downstream with our upgrading and our upstream made a lot of sense. The opportunity to drive synergies, to drive costs out the system—all of that was there in spades. I think it was a great move, made at the right time. And, you know, most mergers actually don’t drive shareholder value. This is one that did.”

George is competitive when it comes to production systems and oilsands technology, but collaborative on environmental issues. As one of the founders of the Oil Sands Leadership Initiative, he believes the industry should share “anything to do with safety, the environment, environmental improvement, anything on reducing our air, land and water footprints. This is important, very important.”

On the future of the oilsands sector
George says that even though he has been at the helm of Suncor for 20 years, the real excitement is yet to come.

“I think the next ten years in this industry are going to be some of its best,” he said, pointing specifically to technology around reducing the environmental footprint of operations. “It is going to astound people how quickly this happens and how well it happens.”

The step-changes will come particularly in the in situ area, he says. “The important thing to remember about SAGD is that is still a very, very young industry. [You’re going to see] a real take-off because of the critical mass of investment in technologies that will rapidly change how we do this. It will reduce water use. It will reduce energy intensity. It will make wells more productive. As wells get to the end of their life, we’ll figure out ways to extend that and recover more.”

George continues, “Listen, industry is looking at all kinds of ways to [improve efficiency], whether it’s use of solvents, surfactants, better downhole pumps, whether you eventually, once you get these caverns, use fire-flood. There are so many technologies out there that are being looked at, being researched, being tried in the field, you’re going to see this thing change rapidly, particularly over the next decade or so. It’s actually quite exciting.”

Suncor’s production has grown significantly under George’s leadership, and will continue as part of his enduring legacy. In the longer term, he notes that the company will “have production coming in from Fort Hills, eventually Joslyn, but also from Firebag, from MacKay River, from our two base mines. And this will feed this large upgrading complex that includes upgrader number one [constructed in 1967], upgrader number two (from the Millennium Project) and upgrader three which is Voyageur. The total capacity of that upgrading facility will be somewhere in the 550,000-barrel-a-day range.”

George leaves behind a strategic plan for Suncor to produce 1 million barrels per day by 2020. “We have the reserves to do it, the strategy to do it, and the environmental approvals for the projects. It’s really down to execution.”

On a cautionary note, he noted some worries the industry should think about.

“You’ve got to be very concerned right now about whether we have enough labour in this part of Alberta. The one difficult thing we have is this oilsands resource in a very remote area. You don’t have a nearby port, you have to bring everything in by truck or by rail. You always have to worry about these inflationary cycles, that we have seen and that we’re likely to see on a go-forward basis. So we just came through a big inflationary period, that 2005 and 2008 period. It’s been calm since the market collapsed in 2008 but…”

George’s final year in the company saw record production, record cash flow and earnings, and total debt way down, to $7 billion. Twenty years ago, could he have imagined that Suncor would become the largest oil company in North America?

“No. That would have been the most improbable thing. But you know what? It’s been an exciting ride. What I would say is, the potential to do those kinds of things is still out there. If I were, you know, 20 years or 30 years younger than I am today…. Opportunities still exist to do those kinds of things.”

Rick George will continue to innovate and lead. As he told the press when he announced his retirement, he won’t be leaving the sector. He’ll still be involved with the oilsands and technology development, but through smaller companies.

Selling the Brand

Dene National Chief Bill Erasmus addresses Keystone XL pipeline protesters 

Earning the public trust has become an industry responsibility, not a corporate exercise in public relations

This article appears in the February issue of Oilweek

By Peter McKenzie-Brown

Operating an oil and gas company in western Canada has become a much more complicated endeavour in recent years – in large part traceable back to the rise of the Internet and the age of instant communication. Those living on the periphery of the industry are becoming increasingly vocal about the impact of drilling and pipelines and fracking and trucking are having on the quality of their lives.

In such a fishbowl existence, then, gaining a social license to operate becomes not just a one-off exercise for an operator dealing with a landowner, but an industry-wide commitment requiring coordinated and cooperative efforts by producers, industry associations and regulators to develop cohesive consultation plans with a broad range of stakeholders.

“We are all out there operating in the land base, but we are also in people’s neighbourhoods. Regardless of your company’s size, people see us as the industry,” according to Patsy Vik, who is EnCana’s Group Lead, Community Relations. Collectively, “we are painting a picture that all of us are going to be branded with. If we (in the industry) all work responsibly and respectfully, we will reflect positively on other companies. We should all behave in such a way that we garner respect from our neighbors.”

When the industry fails in matters of common courtesy, terrible things can happen. Consider the Keystone Pipeline, which was constantly in the headlines last fall. In an interview, the University of Alberta’s Andrew Leach suggests that “it’s important not to take this decision (to postpone a ruling on Keystone until after America’s presidential election) as an anti-oilsands measure. At least in part, it’s a reaction to high-profile oil spills in the United States by Canadian pipeline companies.” Also, he suggested, project proponent TransCanada Corporation may have been “a bit high-handed” when it planned the line.

TransCanada spokesman Shawn Howard disagrees. “Across the entire TCPL system, we deal with some 60,000 landowners,” he said. “We understand that we need good stakeholder relations to earn our social license to operate….We have held more than 300 community consultation meetings” as part of stakeholder relations for Keystone, for example.

Howard believes “a well-financed, well-organized group of anti-hydrocarbon environmental groups have taken on the project. The original Keystone pipeline was approved without any problem. For them this is a very important symbolic victory.” Clearly frustrated, he blusters that “A lot of the information (these groups) submitted to the hearings was simply not true and certainly not scientific. They would submit each other’s news releases instead of scientific studies….”

Worst Case Scenario

While Keystone is the most celebrated recent example of a project at risk because of public engagement issues, it has many predecessors. For example, a decade ago Shell was seeking a permit to develop a sour gas field at its Farrier location near Rocky Mountain House.

A consultant specializing in community engagement, Gay Robinson picks up the story. “Shell put in an application to drill this well but in the hearings they began with their emergency plan rather than starting in a positive manner,” she says.

The result was a classic: the locals became frightened and upset and TV personality David Suzuki got wind of the controversy. “He came in and did a documentary called Worst Case Scenario, which aired on CBC-TV. The license was denied and the hearing alone cost Shell many millions.” The mega-corporation also had to forgo the Farrier property’s profit potential, and its reputation suffered.

Robinson continues, “A number of years later, Shell had another significant (sour gas) discovery fairly close to Rocky Mountain House, at Tay River. That time, they realized they had to work in a different way to develop it. They had a different attitude about how to engage the community. They talked to people, asking ‘What do you think we need to do?’” The outcome was a license to operate.

Having focused the last 15 years of her career in public consultation, Robinson is passionate about both the process and the reasons behind it. “There is a need for it. I think there are opportunities for this, and I enjoy sitting down at the kitchen table with people in the community and talking about how we can do things better.”

She adds, “Good stakeholder relations are based on the belief that stakeholders have a right to be involved in decisions that will affect their lives. If companies don’t believe that, we have a basic disconnect from the beginning. People remember the mistakes the industry made in the past, and they don’t want them to see them repeated.”

What they see is a truck

Whether companies are large or small, “they face exactly the same problems,” according to Terry Bachynski, a vice president of emerging oilsands producer Athabasca Oil Sands Corp. (AOSC). “When local people see a truck driving by, they don’t know or care who the truck belongs to. What they see as a truck. If any company is unresponsive to the needs of the people, then we as the industry can all be affected.”

While in one sense stakeholder relations is fundamentally the same for every company, local factors to make a difference. “We have a wide network of stakeholders we have to deal with,” according to EnCana’s Patsy Vik.” These include the media, community leaders, organizations we provide community investment support to, synergy groups, different industry groups and interested environmental groups. Our contractors are another really important stakeholder. They are out there representing us on a daily basis.” EnCana’s interests stretch across the continent.

By contrast, Bachynski works primarily with aboriginal groups. “Because we are up in northeastern Alberta, most of the stakeholders we have to deal with are aboriginal communities. They have deep concerns: how will oilsands development affect their land treaty rights? Will it interfere with their use and enjoyment of their traditional lands? When we talk to them, one of the areas we talk about is how they can benefit from our efforts – for example, through employment and business development. “There are some cases where it’s really important for all the operators to work together – road building, for example. People in those areas really don’t want a lot of roads going through their traditional territory. What’s important is for the industry to work as one on these projects, making sure they meet the needs of local communities.

“New operators do have particular challenges in some ways,” he concedes. “The companies that are already established have a reputation among the local people. If it’s a good reputation, they do have an advantage. New operators have to go in and prove themselves.”

Unlike Bachynski’s AOSC, gas giant EnCana mostly produces from more populated parts of the Western Canada Basin – thus, different constituents with different issues. According to Patsy Vik, “A lot of the issues are related to dust, noise and traffic. We try to identify the impacts of our developments on our neighbours so we can be proactive and manage them. We need to talk to people and listen to people and create some kind of awareness and understanding around what we’re doing. It depends on the scope and scale of the project. We have different groups in our company that address different parts of the issues. A lot of people work with landowners on issues like gathering lines, for example, that might affect them.”

Vik stresses that public engagement is mostly about communities and neighbourhoods. “People are protective about their homes – that’s the one domain that they want to have influence and control over. That’s why we developed our signature Courtesy Matters program, which specifically addresses those things that affect people when they’re driving to their homes and through their neighbourhoods. Some of the things we do can make it less appealing for them to enjoy their homes and enjoy their space. We know that. We try to mitigate those impacts” through Courtesy Matters, which she describes as a policy focused on “working with the community to understand our impacts and working to resolve, mitigate and minimize them.”

She adds, “One of the things we really stress is how people utilize natural gas in their daily lives. We want it to be personally relevant to people. We also communicate with people around the different stages of our activities, and what it will mean to them.”

Moving On

Returning to Gay Robinson’s Tay River case study, “the community recommended that the partners form a synergy group. I helped them do that.” She adds that global best practices “show that public acceptance of the decision-making process is the key to implementing a public engagement program.” A strong advocate of synergy groups, she describes this relatively new approach to public consultation as a public consultation best practice.

The purpose of these groups “is to bring people together to resolve issues, lessen impacts and encourage the use of best practices in the areas of health, safety and the environment,” according to Synergy Alberta, a not-for-profit organization which promotes this form of conflict resolution. “They connect people and organizations to a particular project, facility or neighbourhood. With relevant people at the same table, true information sharing happens and projects or facilities can be tailored to meet the needs of all stakeholders including industry, residents and landowners and regulators.”

According to the organization’s website, synergy groups “form for a variety of reasons. Sometimes it’s community-driven to seek more information, provide information or rally against something the community opposes. Other times, groups are created by industry looking to proactively share information on proposed projects and gather input from the community and others with a stake in the project or area.”

Those working in the area are adamant that good stakeholder engagement is critical if you want a controversial project to move on – be it sour or shale gas, bitumen or an environmentally contentious pipeline.

According to Robinson, “There is actually a solid business case for meaningful stakeholder relations. It’s not something you do just to avoid grief. You do it to get a social license to operate.” Quoting a colleague, she says “‘the government grants the permits but the community grants the permission.’ The idea is that if the community is not in support, and you don’t have the social license to operate, you will have a lot of trouble getting the project off the ground.”

To a very large extent, those decisions reflect changes in the law. In 2004, for example, a Supreme Court decision articulated the notion that governments and industry have a “duty-to-consult.” Alberta’s recent Aboriginal Policy, Water for Life, Land Use Framework, Biodiversity Monitoring Institute and other policy-related pronouncements incorporate this notion. The same now applies in one way or another across the country.

The duty of government, public agencies and industry has simply become good practice.

The Granddaddy of them All

The granddaddy of Canada’s public consultation regulations probably comes from Alberta’s Energy Resources Conservation Board (ERCB). The Board has required public consultation for decades, thus making Alberta a leader in public engagement. According to ERCB historian Gordon Jaremko, the board’s first major public hearing involved Imperial’s proposed Cold Lake project in 1978-79, although it had done hearings on sour gas development earlier in that decade.

The ERCB and its much younger sibling, the Natural Resources Conservation Board (NRCB), have broad discretion and little legislative guidance on what “the public interest” actually means.  In practice, these organizations consider social, environmental and economic effects of development when they determine whether a project is in the public interest.

Since regulatory agencies have so much latitude, they can be very responsive to well-organized campaigns opposing a particular project. For the proponent, therefore, it is better to over-consult than to do too little.

“Companies should recognize that the regulations are just the starting point. They are the minimum requirement,” Gay Robinson stresses. “The ERCB has a document called Directive 56 which outlines the application process. It specifies that in some cases the public may require greater consultation (than the directive specifies). Unfortunately, some companies only perform to those minimums. They need to develop a principled approach to stakeholder engagement rather than just use the one that is prescribed – the regulatory minimum, as it were.”

Patsy Vik puts the matter into a continental context. In her view, EnCana’s stakeholder relations emerge out of “a reputation we have that we’re proud of, and (that reputation) is based on standard values we hold across the company. They are values that are dear and near to us, and they don’t stop at the border.”

How Public Money Saved Syncrude

This article appears in the August issue of Oilsands Review. 

A quarter-century after Peter Lougheed retired as Alberta’s first Progressive Conservative premier, he is sitting in Calgary’s historic Lougheed House (a mansion built by his grandfather a century ago), reflecting on his government’s impact on the oil sands.

By Peter McKenzie-Brown
Lougheed won a seat in Alberta’s Legislature in 1967, the year the doors opened on the Great Canadian Oil Sands (now Suncor) mine and upgrader; he became premier four years later. During 14 years at the helm, he took an active role in oilsands development. “It was obvious that the oil sands were owned by the people of Alberta,” he says. “We consistently and constantly made sure that the industry understood that the Government of Alberta was the owner and we weren’t just there in a supervisory or regulatory way. We were extensively involved because we were the owners.”

Fast-forward to 1974, when the province’s resource ownership and its commitment to play an active role in development helped revive Syncrude during a near-death experience.

The project had received regulatory approval in 1968, but by 1974 the projected cost of the plant had more than doubled to $2 billion. At year-end Atlantic Richfield Corporation, which was developing its Prudhoe Bay assets, sent its partners a telegram saying that effective January 1st they were pulling out. The remaining participants – Cities Service Canada, Imperial Oil and Gulf Canada – were paying $666 per minute for an increasingly dicey-looking project.

Energy Shock and Energy War
The world’s first energy shock was in high gear. During the previous three years, global oil prices had more than tripled to $11.50 per barrel. While this should have created an energy boom, in Canada it didn’t.

The environment in 1973 was one of high inflation and rising oil prices, and in September Prime Minister Pierre Trudeau asked the western provinces to agree to a voluntary freeze on domestic prices. Nine days later, his government imposed a $0.40 tax on every barrel of exported oil. The tax equalled the difference between domestic and international prices, and the revenues were used to subsidize imports for refiners in eastern Canada.

Outraged that Ottawa would tax a provincial resource, Alberta retaliated in early October. The province cancelled the Alberta Oil Revenue and Royalty Plan effective at yearend, eliminated maximum royalty provisions in all leases and introduced a price-related royalty system. Days later came the Arab/Israeli Yom Kippur War and an embargo by Arab states on oil deliveries to the US and Western Europe. As international prices skyrocketed, so did Ottawa’s export tax. For the rest of the 1970s, OPEC sat in the oil price driver’s seat.

In December Trudeau announced a National Oil Policy “designed to reach Canadian self-sufficiency in oil and oil products before the end of this decade.” Among other measures, this policy added fuel to the crude oil firestorm by making royalties a non-deductible expense for corporate income tax calculations and putting price caps – euphemistically called “made-in-Canada prices” – on oil production for domestic use. Alberta responded with plans to implement a 65% surroyalty on oil. The 1974 Liberal budget made some concessions but retained in principle the right of the federal government to tax provincial royalties.

As Canadians worried about the country “running out of oil,” the producing provinces felt hoodwinked and betrayed. In effect, they argued, the feds were arrogating the fiscal benefits of rising oil prices unto themselves and encroaching on provincial resource ownership. These moves precipitated the bitterest intergovernmental conflicts in Canadian history. The first of two political wars had begun, and battles would rage for a decade.

The political environment was toxic, and it remained so during the Syncrude crisis. According to Hans Maciej, who at the time was the Canadian Petroleum Association’s technical director, “The first energy war did not end until the end of 1975 after the federal government introduced price increases for crude oil and natural gas and, most importantly, recognized the role of royalties paid prior to the price upheaval as a legitimate business expense.”

An Early Thaw
At the beginning of the Syncrude crisis, the consortium created two management teams – one team of executives to plan ways to deep-six the project; another to find ways to keep it alive. In addition to two top executives from each of the three partners, the life-support team included an executive vice president from Cities Services, Calgary-based Bill Mooney. According to Lougheed, “Everybody knew Bill and he just had a way with him of getting people involved and he’s one of the funniest guys I’ve ever met. Mooney played a major behind-the-scenes role in getting people together.”

Though the political environment was toxic, these men had the task of getting government participation in the Syncrude project. Absent other industry partners, public money was the only alternative to a shutdown. The team of seven made a dozen cross-country trips in 17 days. One breakthrough came toward the end of January, when Mooney walked unannounced into Minister of Energy, Mines and Resources Donald Macdonald’s office suite. Hearing that Macdonald was too busy to see him (meetings all day), Mooney decided to wait him out.

When Macdonald returned from Cabinet, Mooney accosted him: “I’ve got to see you.” During a brief meeting the minister outlined the concessions the federal government was willing to make. As Mooney was leaving, Macdonald said “If you tell anyone about this I’ll call you a goddamned liar.”

The Winnipeg Agreement of February 3, 1975 was the outcome of the Syncrude rescue team’s countless phone calls and meetings, and it represented an early thaw in the political climate. The participants in the 12-hour session convened to reach consensus included many of Canada’s key decision-makers. The chairmen of Cities Service, Imperial, Gulf and Shell were there, along with other executives from their companies. Three provincial ministers accompanied premier Lougheed: energy minister Bill Dickie, intergovernmental affairs minister Don Getty and attorney general Merv Leitch. Ontario Premier Bill Davis also brought key ministers to the negotiations. Federal players included Macdonald and Jean Chretien, president of the Treasury Board.

There was give-and-take from everyone except the Shell delegation, which stormed out of the meetings after an hour. They would have considered taking an equity stake in the project, but CEO Bill Daniel first wanted a government-guaranteed base price for production. His team went home empty-handed.

Many people remember the Winnipeg Agreement as a successful effort to replace with government money the 30% equity vacuum created by the departure of Atlantic Richfield: Ottawa took 15%, Alberta 10% and Ontario 5%. The private partners agreed to take a $1.4 billion interest in the project, but Cities Service and Gulf gave Alberta the option to convert a $200 million loan into equity. The province also agreed to construct a pipeline and a power plant, which were risk-free.

Particularly innovative was a royalty structure reflecting technological risks. “When Syncrude came along and we got into the negotiations,” according to Lougheed, “it was clear we could not approach (royalties) from a gross-revenue point of view. It wasn’t really fair because of the risk element involved in such a new process.”

It took eighteen months to prepare legal documentation for the Winnipeg Agreement, and signing took two days. The second day of signing, for dignitaries, was planned for the Saskatchewan Room in Edmonton’s Westin Plaza hotel. For the occasion, Bill Mooney used a pair of table knives to pry off the room’s nameplate. He replaced it with the one that said The Alberta Room.

This article is the first in a series which reflect information from the Petroleum History Society’s current Oil Sands Oral History Project, which is recording the stories of oilsands pioneers in their own words. As with the society’s previous oral history projects, transcripts and recordings will reside in Calgary’s Glenbow Archives. Peter McKenzie-Brown is a member of the team of researchers/writers behind the project.

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.”

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.”

Tell Your Banker to Buzz Off!

As lines of bank credit grow increasingly restrictive, royalty financing offers new options for operators. This article appears in the February issue of Oilweek

By Peter McKenzie-Brown and Richard Graham

Especially if you’re a natural gas producer, it can be tough to get credit these days. What are you going to do?

One possibility is to do what Compton Petroleum did last spring. Primarily a gas producer, the company sold a 5% royalty interest in 19,000 barrels of oil equivalent (BOEs) production per day, plus a 5% interest in 600,000 undeveloped acres to Caledonian Royalty Corporation, a company founded and managed by oil and gas financier Jim Kinnear.

In a way, royalty financing is filling a gap created by the elimination of energy trusts – at least, that’s what conventional wisdom would like you to think. However, as we researched this story, it became increasingly clear that royalty financing not only meets the needs of investors (especially heavy hitters), but it is also an excellent tool to meet the industry’s needs – natural gas companies like Compton Petroleum, for example, but other companies as well. While the industry traditionally associates the idea of royalties with government take, the new players in this area are promoting it as an effective alternative financing tool. While the jury is still out on whether it will be a preferred form of funding during the next boom, right now it has a lot of merit.

The Olden Days
Royalty funding is not new in Canada’s oil and gas sector, but the industry has to a large extent lost its collective memory of royalty financing. The founder of royalty financing in Canada was R.A. (Bob) Brown who, with his son – also named Bob Brown – later turned Home Oil into a major independent oil company.

During the Great Depression royalty financing played a critical role in the development of Turner Valley – at the time “the biggest oilfield in the British Empire.” On June 16, 1936, Brown senior’s Turner Valley Royalties #1 well began flowing 850 barrels of crude oil per day. Funded by royalty financing which guaranteed investors a percentage production from successful wells, Royalties #1 found Turner Valley’s oil formation two decades after earlier producers began stripping naphtha from wet gas discoveries there. This meant the first generation of producers had wasted much of the pressure needed to produce light oil from the reservoir.

Royalties financed 69 other wells in Turner Valley in the two years following Brown’s discovery. Since only two of those wells were dry, the primary constraint on new investment was the rapid saturation of local crude oil markets.

Royalties financing didn’t last, however. In 1938 the federal government decreed that income from oil production was taxable as profits in the hands of the producing company. In the investor’s hands it was taxed again as income, rather than return of capital. Although a producing company appealed this decision successfully, the incident shook confidence in the system. Indeed, in 1942 Ottawa amended the Income Tax Act to tax oil income from royalty trusts at wartime rates. Although the federal government repealed this provision in 1950, it was 70 years before petroleum royalties again became a significant alternative to traditional debt and equity.

Teams at Play
In recent years, at least four teams have suited up for the royalty game. Each team has its own style of play and a strategy that sounds like a winner. Brickburn Asset Management has the most passive style of play. Range Royalty Management is the brainchild of Clayton Woitas, founder of Renaissance Energy, and effectively combines royalty financing with E&P. Caledonian, founded and controlled by Jim Kinnear, is new while the fourth, Freehold Royalties Ltd. has roots going back to the creation of Canada.

Until it converted to a dividend-paying corporation at the beginning of 2011, Freehold was a publicly listed trust that issued distributions based on a large number of diverse royalty-generating properties (mineral rights and gross overriding royalties) and working interest properties. Its income comes from oil, gas, liquids and potash. Many of its properties are legacy assets – royalty rights which Ottawa granted to railroads and the Hudson’s Bay Company as part of the national effort to secure Western Canada. Freehold has interests in more than two million gross acres of land and 23,000 wells.

In a statement, the company’s president and chief executive officer, Bill Ingram, said that most “of our oil and gas production comes from mineral title lands and gross overriding royalties, which have no associated capital or operating costs; thus we have relatively low capital expenditure requirements. The strength of our royalties has allowed us to preserve a high payout ratio historically and should allow us to maintain a high dividend payout.”

The newest team is that of financier Jim Kinnear, who sees royalty financing as an extension of a common practice in Canada’s mining sector. When he started out in the securities business, says Kinnear, “we invested in small mining syndicates that had acquired claims – money returned plus a carried interest. I learned about returning capital to investors. People liked to see a return of cash or cash flow, and they still do.”

Last year, after retiring from Pengrowth Energy Trust – a business he founded and managed for over 20 years – Kinnear began applying this lesson in finance to oil and gas in an innovative way. So far he and his investors have placed $100 million in Caledonian Royalty Corporation. Their royalty investments – which represent registered interests in land and rank ahead of banks and other creditors – allow qualified investors to participate in cash flow based on production. Caledonian’s royalty interests include current production and potential future production from a large undeveloped land base in Alberta. At present, those assets are heavily weighted towards natural gas.

Range Royalty Management operates rather more like a traditional oil company, but also does financing through the issuance of royalties. The company was not willing to be interviewed for this story, but a source who asked to remain anonymous describes the firm as having “a great technical team. While they always want an overriding royalty, they get at it in a different way. They begin at the grassroots level” – by going to land sales, drilling and frequently operating oil and gas properties. Issuing royalties effectively gives the company financing that bears no interest, doesn’t need to be repaid and is free of commodity price risk.

The Problem with PUDs
Another newcomer to royalty financing is Bill Bonner, president of Brickburn Asset Management. Brickburn manages four partnership funds that invest in royalty interests under the WCSB brand name.

Although he has had a long career in oil and gas financing, Bonner only added royalty financing to his company’s portfolio in 2008. His system is both conservative and traditional. “We raise capital through prospectus,” he explains, “then make that capital available to experienced operators for the completion of development wells. In return, we earn a gross overriding royalty. One way to think about this is that we rent the operator’s wellbores. We are not concerned with any of the traditional costs, including the well’s ultimate abandonment.” He adds, “The sanctity of the royalty position is a very special place to get to.”

Bonner is adamant that royalty financing in its own right is an effective and robust form of finance rather than a replacement for the energy trust. When the oil industry goes into boom mode again, “we think there will still be opportunities for this kind of instrument, although candidly we don’t know for sure.”

He adds that “the main link between us and income trusts is that we pay out capital as we receive it. We provide a stream of income which the investor really likes. We are very much a distribution model as opposed to a model where you retain capital and grow. One of the advantages we have is that our investors get a tax write-off – a 30% Canadian Development Expense, which enables them to write off all of the money they have invested. It just takes time.”

He adds, “We have completed five partnerships totalling $82 million. We only take the money for three years. At that point our prospectuses say we will offer a ‘liquidity event’ to return the capital investment back to the investor. Our game plan is to somehow monetize the property after our investments have gone through a period of flush production – either by selling it outright or by somehow putting it into a going-concern business.”

Brickburn’s first royalty partnership came about in 2008. After the 2006 Halloween Massacre imposed a new tax on energy trusts, he says “it became increasingly difficult for smaller energy businesses to finance growth because for them the liquidation opportunity (selling their assets to energy trusts) had disappeared. So we moved in with this royalty instrument.” Complicating the tax problem was the financial crisis. Traditional sources of equity and debt financing for junior oil and gas companies seemed to have disappeared. Part of the solution was royalty financing.

Brickburn royalty partnerships have participated in more than 70 wells, 95% of which used horizontal multi-frac technology. “One of the reasons operators like us,” according to Bonner, “is that we extend their budgets. If we provide one and a half million dollars for a horizontal well, it frees up that much money for them to go do something else.” Royalties can add to the companies’ bottom lines in other ways, too. One of the main reasons is that operators tend to carry inventories of “proven undeveloped reserves,” or PUDs.

“The problem with PUDs,” says Bonner, “is that you get credit on your balance sheet for them as a proven resource, but now you have to throw a lot of money at them to turn them into developed resource. What we did was to come along and offer operators the opportunity to develop those PUDs in a way that was not dilutive to equity” since royalty interest investments equate to non-repayable loans. “Even though interest rates for the last couple of years have been close to zero, royalty financing is attractive because you don’t have to pay back the principle. When operators began to see this, they quickly realized that taking our capital was very accretive to the capital they had to spend themselves.”

Through its family of funds, Brickburn has acquired royalty interests through 11 operating companies, but is bound by agreement not to mention names. However, Delphi Energy and Bellatrix Exploration have both publically acknowledged that they use royalty financing from Brickburn.

Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.