Independence Day

Now that America's presidential race is decided, Canada's need to seek energy markets beyond the U.S. has never been more urgent.

 This article appears in the January, 2013 issue of Oilweek; photo from here

By Peter McKenzie-Brown

The day after America’s presidential election, the Calgary-based Canadian Defence and Foreign Affairs Institute (CDFAI) hosted a panel discussion on the political and economic significance of President Obama’s second term.

Some of the most interesting observations came from Jonathan Baron, an American lobbyist with a primarily Republican clientele. “What you need to know about Republicans and Democrats is that they hear different things when they hear the word energy. Say ‘energy’ to a Republican, and he will think about increasing energy production. Say ‘energy’ to a Democrat, and she will think about mitigating environmental impacts. It’s like another world.”

Now he was on a roll. “When a Republican thinks about Canada’s energy resources,” he added, “they really do think that these resources belong to America. There isn’t a strong sense that they are a sovereign asset for Canadians. For Republicans, the idea of North American energy security is a no-brainer.”

The irony is that the International Energy Agency issued its annual report a few days after this panel discussion – a report which seemed to put the cat among the pigeons. According to the IEA, “The global energy map is changing, with potentially far-reaching consequences for energy markets and trade. It is being redrawn by the resurgence in oil and gas production in the United States and could be further reshaped by a retreat from nuclear power in some countries, continued rapid growth in the use of wind and solar technologies and by the global spread of unconventional gas production.” According to this respected agency, the US will become the world’s top oil producer by 2017, and could be nearing energy self-sufficiency two decades later.

A bearish outlook for Canada’s oil producers, is this report worth long-term worry? Probably not. Since the 1972 publication of The Limits to Growth, a book which forecast shortages of virtually every commodity by the end of the 20^th Century, a good rule of thumb has been that long-term natural resource forecasts are always wrong.

To a large extent, this is because major forecasts are political. IEA member governments and some oil companies vet them before they go public. In the highly likely case that the United States reviewed the IEA forecast before it hit the streets, they would have wanted the agency’s report to justify fracking, Keystone, perhaps, and the West’s embargo of Iranian oil. As one commentator observed, “Forecasters test scenarios – they assess economic and energy trends to produce numbers. Among the enormous range of possibilities, one forecast is chosen for public purposes.” Also, of course, since Adam Smith published The Wealth of Nations in the 18^th century, economies have shown repeatedly that markets eventually equilibrate.

If you focus instead on the near-term implications of the recent US election, there is a lot of good news.

·         Before campaigning began, global warming environmentalists developed traction by opposing Keystone. Notwithstanding their public protests, sources Oilweek spoke to believe the project has a good likelihood of getting State Department approval. An okay would increase the integration of Canadian oil and bitumen production into US markets and provide tidewater access to overseas buyers.

·         On the gas side, this commodity will expand its market for power generation, and Canadians will perhaps gain an advantage in the export of this commodity overseas.

Keystone

President Obama’s re-election was a near-term good news story for Canada’s oil patch. If approved, he Keystone Pipeline will move bitumen to the 7.6 million barrel-per-day Gulf Coast market. It is worth remembering that the Department of State originally deferred its decision on the pipeline as a political gesture, so as not to alienate environmentalists during the election. The reason given was concern about a proposed segment of the pipeline route through environmentally sensitive sand hills in Nebraska.

According to Maryscot (“Scotty”) Greenwood, a left-leaning Democrat, “There is awareness in the United States about the importance of energy from Canada and I believe that awareness was heightened during the campaign. There is a renewed appreciation of the importance of North American energy independence.” She is reasonably confident the project will go ahead, using TCPL’s revised route. In a separate interview, AJM Deloitte’s geoscience director Dave Russum enumerated the reasons the State Department might stand behind Keystone: “Job creation, economy boost in the US, secure supply.”

For Canada, the benefits are different. Keystone would provide Canadian oil sands producers with direct access to America’s single biggest oil market. Thus that pipeline’s throughput would not be subject to the price differentials that have become chronic – especially for the oilsands sector. More importantly, the project would provide Canadian producers with access to tidewater. This would mean overseas markets and international prices. Meanwhile “we are in for a rocky time in the Canadian industry regardless of who is in the White House,” according to Russum. “When oil prices were more than $100, many projects looked pretty attractive, but current prices in the $85 range make the economics much less robust.”

Carbon emissions kept coming up during the CDFAI forum, and Greenwood stressed the political importance of the environmental constituency. “During the second term of the Obama administration (president Obama) has an imperative to deal with some new legislation which covers coal ash, soot and other environment-related questions. This will affect core constituencies. However, there is not necessarily a conflict between these two. You can look after these regulatory issues, and also do Keystone.”

Right-leaning Jonathon Baron disagreed. “The environmental community feels frustrated, so (their protests) have moved down to the state level. The president is going to have to do quite an interesting balancing act to deal with fracturing and Keystone.”

A master of Realpolitik, Baron offered hope for crude oil prices – but hope with a bitter taste. “There’s going to be more instability in the Middle East during an Obama presidency,” he said; after all, the president campaigned on having ended “a decade of war.” If the president is not willing to use American might in response to Iran’s apparent nuclear build-up, Baron argued, there will be mischief in the Middle East. “That volatility means high prices going forward. That has important implications in American markets for Canadian oil sands and natural gas.”

Gas Prices and Markets

Canada’s gas industry is likely to benefit from President Obama’s next term through the conversion of its power industry to natural gas. According to Scotty Greenwood, who served for two terms as a staffer in the Clinton White House, suggested that he “is looking for ways to regulate more stringently, to pivot to natural gas because it’s a cleaner burning fuel than coal. He does have a desire to build demand for natural gas and to clean up the coal industry.” Since it’s his second term, the president will find America’s powerful coal lobbies less daunting.

“During the election campaign Obama virtually did say ‘I hate coal!’” Baron told the CDFAI audience. “Cheap natural gas has given the president an opportunity that didn’t exist before. Because the United States knows that it is not going to be able to implement a carbon tax, it will instead increase the price of coal through regulation, making coal less competitive.”

North American gas markets are likely to expand at the expense of coal. In itself, this may not be cause for much celebration in Canada, since the United States is nearing self-sufficiency in this commodity, and its production and transportation costs are lower. However, Greenwood noted another area where the US political environment could unwittingly favour Canadian natural gas.

In the American political system, Congressional committees have plenty of muscle, and it matters who serves as the chair. The incoming chair of the Senate’s powerful Energy and Natural Resource Committee is Democrat Ron Wyden. Wyden believes large-scale LNG exports would raise natural gas prices in the US, harming the economy. In the past he has argued that Washington should impose a “timeout” on new LNG export facilities, pending review. “That could be the end politically for (additional) natural gas exports from United States,” said Greenwood.

“There is a gigantic and very legitimate debate about whether we should be exporting natural gas,” she added. “My observation is that in the United States it will be politically very difficult to export (gas to other countries).…This could be a big opportunity for Canada, since the same political challenges do not exist here.” Baron concurred. “There are already a number of LNG export projects in the United States. LNG exports along with hydraulic fracturing will be major issues during the president’s second term.”

While the Americans dither, Canada could approve and construct facilities for overseas markets. Eastern Canada already imports about two billion cubic feet per day of gas from the US, and “this is a cheaper source than Western Canada. We are of course a net exporter to the US, but that role is shrinking. We need alternative exports” said AJM Deloitte’s Russum. He observes that Canada is ‘way behind Australia and other countries in developing or expanding LNG facilities. While the US already has gas export facilities in operation, Canada’s first plant won’t be ready until 2019.

“To me the problem is that Canada can’t compete with gas supplies that are abundant, cheaper, and closer to market in the US – for example, Marcellus, Fayetteville, Barnett and Eagleford,” he added. “Gas is still a fossil fuel, so while it is cleaner and more environmentally friendly than coal, it still has the fossil fuel stigma and the fracking stigma. I’m unclear whether it is a problem or a solution in the US. In any case, if prices rise the US has shown it is able to drill and bring on new volumes of shale gas very quickly, which would in turn dampen prices.” Russum added that “prices for natural gas need to be considerably higher to make the industry profitable here.”

The US/Canada Alliance

Prime Minister Brian Mulroney once famously said that “the relationships (between prime ministers and presidents) are absolutely indispensable. If you don’t have a friendly and constructive personal relationship with the president of the United States, nothing is going to happen.”

According to Greenwood, the Canada/US relationship is “hugely important, writ large. It’s much bigger and more integrated than any personality. It matters who is in the White House, but in the end the relationship will do well because it has to, and because of all the history between the two countries.” She added that “the US government does not want to prevent Canadian development in any way. We have very close relationships, and those relationships are of great value on both sides of the border. I think the United States, as Canada’s most important commercial partner, wants Canada to be commercially successful in every possible way.”

Colin Robinson, a Canadian diplomat who helped broker the Canada-US Free Trade Agreement and NAFTA, stressed the importance of international cooperation to help prevent trade disputes. “The first lumber dispute between Canada and the United States goes back to the time of George Washington,” he reminded the CDFAI audience. “These kinds of things do lead to protectionism. In a lot of cases, we have to put competition aside and think of things as North American.”

“Whenever (a diplomat has) to do something in the United States you have to do it through the White House,” according to Baron. The State Department is critical for international affairs, but other parts of government are in play. Formerly Canada’s ambassador to the US, Frank McKenna once said that “The president can love you to death, but that doesn’t mean you don’t have constant harassment from Congress….The tone at the top helps, but it’s not conclusive.”

As this article went to press, there was optimism that the United States would not fall over the “fiscal cliff.” For the sake of talking about the near-term future, this article assumes a compromise that won’t suffocate North America’s economies. If America remains a house divided, though, Canada needs to declare greater independence from US commodity markets. That truth is self-evident.

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.

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.”

LNG Trumped

Image via Wikipedia

The burst of enthusiasm for shale gas could put LNG on the sidelines of global gas trade

This article appears in the October 2010 issue of Oilweek

By Peter McKenzie-Brown

If you want to understand the performance of global natural gas markets in the next few years, think hockey. On one side the team captain is liquefied natural gas (LNG); on the other natural gas from shale reservoirs (“shale gas”).

The matches are serious, but they are also friendly. Each side is a team of rivals. The squads frequently swap players in and out, but they can play nail-biting games.

Robin Mann’s description of an annual CBM conference in Asia calls the game during two days of play. The first day of the Singapore conference, the president of AJM Petroleum Consultants says, the dominant theme was that “if there is a lot of shale gas development in India, Europe and China, there will be no need for much LNG project development.”

Shale Gas one; LNG zip.

On the second day, however, “the speakers suggested that new LNG projects will be needed no matter how much shale gas is developed in those countries. LNG development might not be as dynamic as people had thought it would be, but the projects now built or on the books to be built will remain viable.”

Game tied.

He cautions, though, that “In the end price will be the deciding factor.” Of course, everything from geopolitics to economics can influence price. This is the recurring theme in the competition between LNG and shale gas.
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Three Sources of Gas
From the perspective of North American producers, the future of three gas sources (not two) is of interest. The first is the wild success of shale gas production in the US and Canada. The shale gas revolution, as it is called, is largely the result of rapid innovation in such down-hole technologies as horizontal drilling, better bit design, coil tubing, down-hole motors, geo-steering, microseismic, measurement-while-drilling tools and more powerful fraccing systems. It has truly been a revolutionary development.

The second is the evolution of a global market for liquefied natural gas. This development has been decades in the making, and it has eliminated the need for pipelines to tie stranded gas into the world’s industrial markets. To cite the extreme example, Qatar is developing liquefaction facilities for an offshore reservoir with more than a quadrillion cubic feet of proved reserves, and it will be able to deliver that gas around the world for a century or more.
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The gas industry’s third area of interest lies in the huge conventional gas reserves in Alaska and the Northwest Territories. While companies are proposing expensive pipeline systems to deliver those resources to southern markets, Mann doubts that those proposals will go ahead in the foreseeable future. “Because of the development of shale gas formations like the Montney and Horn River and other with great potential right next to infrastructure and right next to 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?” asks Mann.

“Their costs keep going up and up and up, and economics will trump any national sovereignty argument for the Canadian pipeline. 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 LNG justify building facilities up there? Certainly at the Singapore conference there was no strong feeling that there would be much in the way of LNG exports from North America, apart from a few small projects” like the proposed LNG terminal in Kitimat, BC. The only really positive argument for developing LNG facilities is that the many existing receiver terminals in the world offer a lot of flexibility. Given a Northwest Passage free of ice, you could take Arctic LNG anywhere – if the price were right.
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Arctic Gas Pipelines: benched.
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International sketches
While Robin Mann acknowledges the large potential for shale gas development in Asia, especially in China and India, he is sceptical that this will happen in the near term. “North America’s shale gas sector is advanced, it’s more of a mature industry” he says, sketching out the situation around the world. “Europe is in its infancy. In Asia it isn’t even that far – it’s in its beginning stages. People have barely gone beyond looking at resource potential. The idea of unconventional gas in Australia, China, India and Indonesia is still CBM” (coal bed methane) – a resource the North American industry is not heavily investing in anymore. “Europe is more interested in shale gas because they don’t have much CBM.”

One problem those countries face in developing a shale gas industry is “getting the hardware needed to properly develop the resource – getting the right equipment to the right spot and (having) the expertise and manpower to get things developed. That’s why CBM is still on the books in those regions. To manage in the CBM world you don’t need (heavy-duty) frac equipment or (specialized) manpower.”

Here is the kind of problem he is talking about. Huge fraccing jobs for shale gas development in north-eastern B.C. require a great deal of logistical support. Each horizontal hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. To take on one such project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks. This equipment isn’t widely available outside North America, and there are gas-bearing shales around the world that are remote from the kind of sand quarries needed.

Moreover, a great deal of water is required. While the water commonly comes from deep formations, a typical shale gas fraccing job requires a large water storage pit in addition to a string of high-volume steel tanks. According to Dave Russum, an AJM vice president who also attended the Singapore conference, “in India and Australia they are drilling their first holes into shale just to gather information. They aren’t even into pilot projects yet.” Given those realities, Mann concludes that shale gas will not have a large impact on LNG development – at least not initially
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Geopolitics and the local community
As a domestic source of supply, shale gas is an attractive alternative to imports. For the United States, which has huge trade deficits, it slows down the haemorrhage of US dollars. For Europe it offers a geopolitically smart alternative to Russian supply. Also, governments want this kind of development because it contributes to security of supply
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In recent years Russia has turned off the taps a couple of times because of disputes with Ukraine over payment. As collateral damage, countries in the European Union were temporarily cut off, too. It is therefore ironic that the best shale gas prospects in the European Union are in the north – especially Poland, Ukraine’s neighbour. In northern Europe, according to Mann, “you can get access to enough land to make a viable shale gas project.” In more developed and densely populated southern parts of the union, this is much harder.

As Europe develops shale gas, geopolitics is again likely to enter the fray compliments of the Russian bear. “Are the Russians just going to sit by and let Poland and northern Europe develop natural gas so they can turn off the taps from Russia?” asks Mann. “I don’t think so. They could retaliate with price, and make shale gas uneconomic.”

So could LNG producers. In fact, rather than shale gas driving LNG out of global markets, the exact opposite could take place, with LNG putting the screws to shale gas development irrespective of its geopolitical and trade balance advantages. Qatar, you will recall, has huge reserves that it can liquefy and deliver cheaply, causing international gas prices to crater and rendering some shale gas projects uneconomic.

Yemen and other exporters could do the same. According to Dave Russum, “It wouldn’t take much of a gas surplus on the oceans to really drop the price of gas in many markets. Although (shale gas) reservoirs can be prolific, gas from shale is not cheap, and whether production is sustainable over time is a real question.”

In addition to the prospect of price competition, shale gas development is likely to face environmental and population density issues in Europe and Asia. Environmental concern is likely to be most intense in Europe, and to echo concerns already being expressed in a number of places in the US. Will fraccing contaminate groundwater reservoirs? Are the chemicals used in development safe? Will shale gas production lead to unintended consequences of the undesirable kind?

The matter of population density ranges from critical in India and coastal China to highly significant in much of the southern states in the European Union, where the industry can’t get access to enough land to develop a viable shale gas project. Shale gas development requires drilling many wells. Multilateral horizontal drilling and fraccing from a single pad can take weeks and even months to complete. These drilling pads are large and operations can be dirty and noisy. Moreover, in densely populated countries good drilling prospects can be covered over with villages, small farming operations, markets and industrial operations. This inconvenient truth is hard to ignore

Game plans
Mann’s assessment of the situation involves pretty raw political analysis of the situation. “In China the communist government would just do it,” he speculates. The country has almost the same landmass as Canada, yet the population is mostly located along a relatively thin band along the east coast. There are many prospective sedimentary basins within the country, which is geologically more like the United States than Canada. “The ones that are now being looked at for shale gas are out in a desert in the western China, where there is virtually a zero population problem and access is not a problem either. None of these projects are commercial yet, they are just at the stages of looking at resource potential, doing some tests, seeing whether they are viable and then going down the road” to development.

Having said that, he recalls an argument from Singapore that “Even if China developed shale gas at the same rate and volume as North America did over the past ten years they would still require LNG because (in ten years) shale gas would meet only around 15% of their total requirements.” That’s a compelling argument against the notion that shale gas will displace global LNG
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Shale gas development is going to be difficult in most places except northern Europe, potentially China and eventually India. “In India, you do have British law covering land ownership so you do have land issues but you wouldn’t have the same environmental issues as you have in Europe. (Gas producers) could get (to viable projects) if they worked with the local population, most of whom have very low incomes. In much of Europe, where the amount people make on average is much higher and people have a much higher standard of living, it would likely be more difficult to work with local populations.”

Shale gas and LNG can coexist, but as team captains for the gas industry’s two big new hockey clubs there are many ways they can affect price and therefore development. Too much LNG on world markets could hinder development of shale gas in certain parts of the world. A great deal of shale gas development could hinder LNG development in others. But, says Mann, “Either thing could happen. It’s going to depend on geography, on what resources you have, on governments’ want to develop security of supply – a whole bunch of political things can get rolled up into that.”

“North America is a great example,” he concludes. “A few years ago we wanted to have LNG receiver terminals dotting the east coast, the southern coast and the west coast of North America. People didn’t want them. Then all of a sudden by some miracle we ended up with the shale gas revolution and we suddenly found we didn’t need them. So LNG – go away.”

For North America, at least, shale gas was the game changer. Shale Gas five; LNG one.

Unconventional Challenges

There's nothing unconventional about shale gas in western Canada, but the technology to get at it? Now that's a different story

Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide

By Peter McKenzie-Brown

In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.

The most important of these is horizontal drilling. Since the technology became widespread 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.

Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.

Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.

Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.

Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.

Microseismic
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.

Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.

According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.

“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.

What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.

Coil Tubing
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.

The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.

Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.

Fractious
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.

Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.

Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability rock than you would ever be able to reach with a vertical well.”

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

To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” said Kevin Lo of FirstEnergy Capital in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.

Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.

Because so much water is required, a typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “Now (the industry is) drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.

The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.

To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.

Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”

In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”

What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.

If Nobody Hears a Blowout, Did it Really Happen?

Canada’s worst-ever blowout wasn’t a celebrity, and despite the passage of more than a decade the regulator has never formally investigated the event. Is that a good thing?

This article appears in the July issue of Oilweek

By Peter McKenzie-Brown

Klua d-27-J blew out near Fort Nelson BC. No neighbours were under threat, and the blowout took place in the sticks as most Canadians were getting ready for Christmas. No one was injured and, except for an incinerated rig, there was no damage to property. The media didn’t get wind of the disaster, so Klua was relegated to the world of “incidents.”

The blowout began on December 6, 1999 and took 12 days to shut in. But what an incident it was! Chairman Mike Miller of Safety Boss was part of a team of petroleum industry experts who prepared an important paper on Klua for a conference in Texas two years later. “Eyewitnesses reported that the drill string was lowered the last fraction of a meter with no resistance,” the paper says, “as if the bit had entered an underground cavern….” Then all hell broke loose.

According to Miller, at its peak the well spewed an estimated 250 million cubic feet of natural gas per day plus 5,000 barrels of condensate and 45,000 barrels of salt water. After ten days, crews ignited the well, which was flowing mildly sour gas. After pulling the incinerated substructure of the rig from the well, the hole was shut in and a control BOP installed.

When Oilweek recently contacted BC’s Oil and Gas Commission (OGC) for the formal report on this blowout, there was none. The Ministry of Environment would lead clean-up efforts, but otherwise the file is still open.

It’s a Matter of Safety

With oil leaking in the Gulf of Mexico, Canada is well-positioned to deal with the heightened risks - and reap the bountiful rewards - of frontier exploration.

Photo: Chevron Canada, which is drilling the ultra-deepwater Lona O-55 well in the Orphan Basin off Newfoundland with the Stena Carron Drillship, must meet several new requirements stemming from the Deepwater Horizon tragedy.

This article appears in the July issue of Oilweek.

By Peter McKenzie-Brown

As the United States administration and BP plc struggled to deal with what could turn out to be the largest-ever offshore oil spill, the Canadian oil and gas industry could look back in admiration at a frontier drilling history that has been relatively free of stains.

Oil and gas continues to be pumped from fields off the East Coast. Crude oil has been produced and shipped from the Arctic Islands. And natural gas from the Mackenzie Delta region is poised to supply southern markets, pending completion of a long-awaited natural gas pipeline from Inuvik. And in the Queen Charlotte basin, off the coast of British Columbia, where a moratorium has barred drilling since 1971, there lies a “new, rich petroleum province waiting to be explored,” says widely-respected petroleum geologist Henry Lyatsky.

He has been actively promoting lifting the moratorium even while the media were buzzing about the Gulf of Mexico blowout, believes there are excellent prospects in Canada’s west coast basins. Opening them up for drilling would reward the industry for decades of nearly incident-free frontier exploration.

Those sentiments would alarm most people outside the oilpatch, and they would alarm Canadian environmental activists to the point of apoplexy. That, however, is exactly the point: There is widespread concern around Canada that rapid growth in the petroleum sector would pose environment, health and safety (EHS) dangers. Those concerns illustrate how profoundly EHS has become part of our national DNA. And that is a very good thing.

The Three-legged Stool
The EHS stool has three legs: customs and social attitudes; regulatory and industrial codes; technical skills and operating environments. If the legs aren’t the same length, the stool wobbles. Since the three legs of the Canadian stool are level and strong, there are good reasons to encourage the industry to reach out to new operating environments.

Consider reality in much of the developing world, for example. “We do a lot of work out of Third World countries where clearly life is cheaper,” says Mike Miller, the chairman of Calgary-based Safety Boss Inc. “We were doing safety management on a huge construction project in Iran, and we just had a hell of a time to get people on board with it. One of the comments we heard was that if they killed someone it would just cost fifteen hundred bucks. You’d take $1500 to the family and that would be the end of it. So how much money are you going to spend on safety? Our contract was about enforcing Canadian safety standards, and we found so much resistance that at the end of the day we just said ‘This isn’t going to work, guys, because you aren’t going to stand behind us.’” In the end, Safety Boss got out of its contract.

Miller’s example illustrates the social attitude leg of the stool in much of the Third World. By contrast, in Canada the legal resources applied to safety and safe working environments are huge. Apart from representing personal tragedy, injury and loss of life are expensive propositions.

On the matter of the second leg of the stool, regulation, rich countries like Canada are increasingly focused on stringent EHS rules. The Canadian experience illustrates how regulation has saturated public opinion so deeply that environment, health and safety have become essential parts of the social fabric. According to Dale Dusterhoft, the chief executive officer of well service company Trican, there is a “continued focus on safety, environment and hazard issues and it comes from all levels, it comes from government, it comes from our customers who are the oil companies, it comes from the public at large and it comes internally from within the service industry. It now affects everything we do, and it is helping us make real progress.”

Operating environments represent the third leg of the stool, and they reflect the industry’s collective experience. The sector has a wealth of experience in the Western Canada Basin and is increasingly knowledgeable about the frontiers. The industry’s technical knowledge and skill-sets are formidable.

Safety Costs
Although serious industrial incidents have become rare, as long as there is an oil industry there will probably be kicks and blowouts. The story of Canada’s oil patch is full of these events, some of which have become legend: Royalite #4 at Turner Valley (1924); Atlantic Leduc #3 (1948); Amoco’s second sour gas blowout at Lodgepole (1982-83). The most blowout-prone exploration program in Canadian history was probably Panarctic’s 1969-70 effort in the High Arctic. Of 17 holes, two were spectacular gas blowouts and three were relief wells drilled to bring those blowouts under control.

To some extent because of the disasters of its cowboy years, Canada’s safety record is now excellent– especially since the high-profile Lodgepole event. In years of high drilling activity the industry now sinks three times as many wells as it did in ’82 and drills four times as many metres, yet blowout rates have substantially declined. In 2008, for example, the ERCB recorded 0.118 blowouts per 1,000 non-abandoned wells.

This partly reflects technological advance. “Almost all blowouts occur because of human error,” says Mike Miller of Safety Boss. “Fewer than 5% occur because of corrosion. It’s almost always when there’s a rig over the hole – whether it’s a drilling rig, a service rig or a snubbing unit. That’s where the human error takes place. Today we can put holes down in half to a quarter of the time it used to take so there’s less exposure of time to risk. That’s one reason we have fewer blowouts: we can drill wells so much faster.”

Miller also commends the ERCB’s strict regulations for sour gas drilling. “We now classify wells with significant sour gas content as critical wells, for which a whole new set of rules apply, including the requirement for emergency response plans. That’s made a huge difference.” So big, reports the Energy Resources Conservation Board’s Bob Cullan, that “there hasn’t been a single sour gas blowout since Lodgepole. That’s because we have the toughest sour gas drilling regulations in the world.”

The cost of safety is huge, and it has meant big changes in operating procedures. Mike Miller describes dramatic changes in the safety business since his father founded the company. “People (doing safety turnarounds at gas plants) now have fall-arrest equipment. They don’t do anything without fire protection and breathing air equipment. A friend of mine tells me that at the plant he works at, the safety bill used to be $20,000. Now it’s like $300,000 to $400,000. Every time someone goes into a vessel someone has to be there to watch. They may need to have specialized safety equipment or even specially trained personnel to watch that person in the vessel.”

He adds, “I appreciate the safer work environment, but the paperwork can be simply overwhelming. Now on blowouts we have to take a safety certified officer, and their job is simply to do the safety recording – to record every detail of the safety meetings we have. ‘We met at such-and-such a time, these are the hazards we discussed, people have to wear such-and-such protection equipment, here’s what we said and did.’”

To put costs in perspective it is worth noting that, according to an ERCB report, the direct costs of the 1982 Lodgepole disaster (lost production, lost drilling rig, operations and remediation) totalled $200 million. In a technical presentation nearly ten years ago, Mike Miller estimated that indirect costs – more stringent critical sour gas well procedures, equipment and emergency response planning, which can amount to a quarter to a half million dollars for a deep test – had been in the order of $1 billion. The cost of EHS is high, but Canadians are clearly prepared to pay it.

So is Canadian business. Chief executive officer Dale Dusterhoft of Trican, which is a key player in hydraulic well fraccing, describes the safety issues his employees face as long-distance driving (often over rough terrain); controlling high-pressures and chemicals; and working with moving parts and equipment. “Whenever you have those elements, you have safety issues,” he says. While he acknowledges that there is more paperwork than ten years ago, he says “It’s just part of the process. It doesn’t hinder our operations. We have a safety meeting prior to each job, and we have to document every one. What’s more, every individual there has to sign off that they were in attendance and heard it and understood it. But these are just good business practices. They take a bit more time, but they save money in the long run because you don’t have as many incidents.”

High Arctic
Canada’s early experience in the High Arctic – a 17-well drilling program that included three relief wells to control two major blowouts – illustrates how bad things can be when you don’t properly prepare for drilling in new exploration territory. The stool becomes wobbly, and the risk of an uncontrolled release of hydrocarbons – the fancy phrase for blowout – becomes greater.

In that context consider that the EHS stool is shaky in most Third World countries, yet there are big increases in deep water drilling off the shores of Africa, Brazil, China and India. “Aside from the oil sands,” ARC Energy’s Peter Tertzakian pointed out in a recent research note, “offshore drilling is where most of the world’s incremental oil barrels now come from, and it’s those higher-cost marginal barrels that set price. Indeed, a large fraction of the world’s growing oil needs since the early 1990s has come from the discovery of new, deep offshore reservoirs.” In North America, much of that oil has come from the American sector of the Gulf of Mexico.

Notwithstanding the BP-operated Macondo well disaster, it is rich-world companies that are best suited to drilling the world’s offshore petroleum basins. Because of our national attitudes and far-flung technical expertise, environment, health and safety are well served when Canada-based companies drill offshore fields. This reality applies as much to basins in Canada as to those in the Third World.

The Beaufort Sea and the East Coast Offshore
In Canada’s Beaufort and East Coast basins there have been important EHS developments in recent months.

Going to the ends of the earth is nothing new for the Canadian oil and gas industry. Beginning in 1976, drilling expeditions in the Beaufort Sea were innovative and daring and continued for nearly a decade. The wells were in shallow water, however – often using equipment that sat on the sea floor.

Last fall the National Energy Board began a safety inquiry in anticipation of a revival of drilling in the Beaufort Sea. The review was triggered by a proposal from Imperial and Exxon Mobil to start deeper Beaufort drilling, using a new vessel built on the scale of a battleship. The Board is investigating serious concerns about opening up deeper northern waters for drilling. The previous generation of regulations assumed that in the event of a blowout the operator could drill a relief well in the same season.

The Board began developing its new regulatory approach because the Arctic work season is too short to follow the old rules for the next wave of bigger wells. After the Macondo disaster began, the Board announced that it would review Arctic drilling requirements in light of findings from the American inquiries into that event. “We need to learn from what happened in the Gulf,” NEB Chair Gaétan Caron said in a statement. “The information taken from this unfortunate situation will enhance our safety and environmental oversight.” The regulator is making sure all three legs of the EHS stool are the right size for deep Beaufort drilling.

Off the east coast, the Gulf debacle created consternation for a different reason: a new, deep well was being spudded. In May, Chevron began drilling Canada’s deepest offshore oil well 430 kilometres northeast of St. John’s in the offshore Orphan Basin in the North Atlantic. Lona 0-55 was spudded in 2,500 metres of water (compared to Macondo’s 1,500 metres). Despite political calls for postponement because of the risk of an ultra-deep-water blowout, Newfoundland defended the project as critical to its economic development. The gist of the government’s argument was that oil is too crucial to the economy to call off exploration. That sounds quite a bit like damning with faint praise.

In response to public criticism, the government of Newfoundland appointed master mariner Mark Turner, an expert in marine safety and environmental management, to review the province’s ability to prevent and respond to an offshore oil spill.

It isn’t surprising that environmentalists and the political opposition sounded their respective horns on the remote prospect of a North Atlantic blowout. Serious offshore oil blowouts always attract attention, and rightly so. Injuries and fatalities are more common. They pollute, they’re hard to clean up and contamination can last for years. When dispersants are appropriate at all, they are the least bad of the available tools. And offshore oil blowouts have a disproportionate impact on wildlife: a deer can walk past a puddle of oil, but fish, whales and seals have nowhere else to go.

However, crucial facts were lost in the conversation about Lona O-55. One is that there has never been a crude oil blowout offshore Canada. Another is that only hundreds of wells have been drilled in Canada’s vast east coast, compared to tens of thousands in the much smaller US segment of the Gulf. Also lost in the debate is that all Canadian offshore wells have recently become governed by a more robust regulatory regime – one which offers greater EHS flexibility as a carrot, but bigger sticks for those who fail to perform. That means better safety and environmental protection rather than less, as the knee-jerk critics protest.

The new rules governing offshore drilling were posted in the Canada Gazette last December, and took effect at the beginning of this year. They are performance-based rather than prescriptive regulations, and the industry certainly believes that is a good thing.

According to Patrick Delaney of the Petroleum Services Association of Canada, the trend in regulation is undergoing a fundamental shift to performance-based regulation from prescriptive rules. As he explains, under the new approach the regulator essentially says, “The journey is from A to Z” – Z being a plan which meets the regulator’s EH&S goals. “We aren’t going to tell you how to get there. But before you start it’s up to you to prove that you can do it safely. This is a safer approach.”

For offshore operators, the days are now over when agencies of government specify the safety equipment the industry should use. “A lot of governments are making this shift,” adds Delaney. “Alberta recently announced that it is doing a complete review of its regulations, and that it will move away from prescriptive to performance-based regulation.”

Paul Barnes, who is Atlantic Canada manager for the Canadian Association of Petroleum Producers, is another advocate of performance-based regulation. It’s more “modern,” he says. Britain, Norway, Australia – all the advanced countries with offshore petroleum operations are adopting it. “It is part of a robust regulatory system in Canada,” he adds. “We have a strong track record of safety and environmental performance. Canada needs energy and the world needs energy, and oil’s going to be a big part of the energy mix for a long time to come. Let’s get on with it.”

Team of Rivals

As executive director of the Small Explorers and Producers Association of Canada, Gary Leach leads Canada's "Silicon Valley of oil"

This article appears in the February 2010 issue of Oilweek.

By Peter McKenzie-Brown

A year ago, Stan Odut was chairman of the Small Explorers and Producers Association of Canada (SEPAC), and he was deeply worried about the industry’s immediate future. “The sources of capital for the junior sector are equity, debt and cash flow,” he said, “but many companies are already mired in debt and credit lines are being pulled. You can’t get additional debt coverage. You can’t raise any equity because there is no reason for investors to put money into the energy business right now (because of collapsing commodity prices). And governments (provincially in particular) have strangled cash flow. So help me with the equation: you’ve got to get one of those factors to change to get the business going again.”

In the last year, what has changed? I put the question to Gary Leach, SEPAC’s executive director. He describes a cautious sense of optimism within the junior sector of Canada’s petroleum industry. There’s been a strong recovery in oil prices, for example, although gas prices are still languishing. “In recent months equity markets have been more supportive of the industry,” he adds, although they have been “selective”. They are targeting companies with “strong management, in certain commodity niches. But there is no tide that is lifting all boats.” Bank credit is still a problem for some companies; many are carrying a lot of debt, and lower commodity prices have reduced the value of their assets in the ground. Technically, this is known as a double-whammy.

On the positive side, “Banks have tried to be nimble and flexible. They don’t want to cause a lot of financial wreckage in the junior and midcap sector. A lot of the equity raised in recent months has been used to reduce debt, so things are improving.” However, he cautions, “If we don’t see a sustained rebound in gas prices in 2010, that may change.”

The Gas Story
Gary Leach describes himself as a “pure prairie product”. He was born in Manitoba, raised in Alberta and received post-secondary education (including a law degree) at the University of Saskatchewan. He spent much of his strictly legal career putting together international joint ventures, petroleum production sharing agreements, and international financing loans with multilateral institutions such as the World Bank and the European Bank for Reconstruction and Development.

He joined Calgary-based Canadian Fracmaster in 1995 and stayed with the business after it was acquired by BJ Services Company, the Houston-based petroleum equipment and services giant. His background in down-hole completions is a notable asset for a spokesman in an industry being transformed by horizontal drilling and new fraccing technologies. Soft-spoken and articulate, Leach joined SEPAC – the trade association for 350 small oil companies – in 2006.

We began our discussion with the natural gas story. At time of writing, gas prices are sitting well below their ten-year average. Where are those prices headed? “I think right now there’s possibly a larger gap in opinions about where gas prices are going than any time I can remember,” Leach says. “There are people who say the potential international demand (for gas) has barely been touched, so prices should go up. Others talk about the huge international supply potential, and they see things the other way.” Perhaps remembering the adage that predictions are especially perilous when they pertain to the future, he says “We are never going to get out of these swings in gas prices. I think there are going to continue to be big swings in the gas market. I don’t think anyone can accurately forecast gas prices beyond a couple of quarters.”

“For companies carrying a lot of gas assets on their balance sheets, it’s not a great time to be selling. “There are going to be a lot of assets put on the market. A lot of big companies” – he mentions Talisman, EnCana and Suncor – “are talking about moving conventional gas reserves off their balance sheets. The lowest cost gas resources are the ones they are going to pursue, and those resources are now shale gas resources.”

Since gas-price volatility is a fact of life, he says, “The low-cost suppliers are the ones that are going to do best. Companies have to learn how to drive down their costs.” For the junior sector, which has a lot of conventional gas on the books, the outlook is particularly uncertain. “The leading shale gas resource in western Canada is in a place that’s so remote and so expensive that mostly big players can participate. However, as the technologies and the infrastructure are developed, the smaller players will get in.”

Behind the Curve
When you ask Leach about Alberta’s place in western Canada’s industry, he is oddly ambivalent. For example, on the matter of shale gas he says, “If we were further along the curve in Alberta in developing shale gas resources, the smaller players would be developing them. But Alberta’s industry is behind the curve.”

He notes that both British Columbia and Saskatchewan long ago introduced important incentives for the industry, but that those policy environments didn’t spur high levels of petroleum sector growth until the technological environment changed in recent years. For example, Saskatchewan’s “Bakken field has been known for years. We used to just drill right through it. However, it is only recent that the technologies of horizontal well completions and multistage fracturing” – the technologies that led to the shale gas revolution – “made that reservoir viable.”

Alberta, of course, is quite different from either of those provinces. “The (Western Canada Sedimentary) Basin covers the province from north to south. We have every conceivable hydrocarbon opportunity here. There’s a lot of excitement about using those technologies to improve production from formations in Alberta that are well past their glory days – the Viking formation, the Cardium formation. A lot of companies are looking at targeting oil in these formations, but using horizontal wells and multistage fractures.” Leach thinks the industry will soon successfully use these methods to increase oil recovery in Alberta.

What is SEPAC’s single biggest challenge? Here his message is particularly striking. “We have to help policy makers and politicians understand what a tremendously exciting, dynamic, vibrant group of junior and mid-cap companies we have in Canada. Almost half the world’s publically traded oil companies are here in Calgary. It’s a remarkable statistic. It’s the closest thing to a Silicon Valley type business culture and industry cluster we in Canada have ever developed. It’s emerged on its own without government help. But over the years, we have had all these companies competing with each other. Hundreds and hundreds of companies are competing with each other for land, for resources, for capital. They have a tremendous publically accessible database that puts small companies on an equal footing with big players. It’s the most unique oil industry in the world, and Canada’s most successful business story. We need policy-makers to understand that story, so they don’t see the industry as just eight or ten companies. Let’s see the big picture, and not do things to harm it. This industry is amazing. We don’t want to lose it. We want to nurture it. It’s a great incubator of new ideas.”

Leach sees the Alberta government’s recent adjustments to the royalty changes of two years ago as a SEPAC success. “Both times (Premier) Stelmach came out with revisions to the royalty regime, he specifically mentioned that he wanted to help Alberta’s junior petroleum sector. The Alberta incentives brought additional cash flow, reduced costs, drew some investment into Alberta that would. They helped, but they were not the complete answer. They couldn’t help everybody.”

SEPAC is now working with other industry associations, the financial sector and others in developing a study of investment competitiveness within the province, which will be complete in the New Year. The idea is to answer the question, “Compared to other investment places, how does Alberta rate?” The provincial government will then have to take all that information and decide on new policies. We think if the province can set itself up as one of the world’s best places to invest, its future will be bright.” Citing a report from a large bank, he points out that about 60 per cent of the world’s investible oil resources are here in Alberta. Big international oil companies have been boxed into smaller and smaller bits of the world. This is one of the few places in the world where companies can book meaningful reserves additions.”

Moving Ahead
I’m always interested in the responses of senior people in the patch to the issue of peak oil, so I put the question to Gary Leach. His response is forceful and direct. “I think we’re near peak cheap oil. I think we’re near peak easily accessible oil. But the amount of oil in the world is enormous. The biggest problem to developing oil has to do with policy restrictions – off-limits restrictions on resource development. The US has huge oil shale resources, for example, but they are politically inaccessible.” Working with their client national oil companies, oil-rich countries have put resource development off limits to private sector oil companies. He mentions Venezuela’s Orinoco ultra heavy oil belt, Alberta’s oilsands, the vast heavy oil deposits in Russia, then cites the old gag that the Stone Age didn’t end because we ran out of stones.

He’s now just warming up. “The petroleum age won’t end because we run out of petroleum. Western European countries are consuming less oil than they did 30 years ago, and the United States is consuming less than it did in 2007. The petroleum age may end in a gentle decline because some of the advanced countries begin to move away from (oil). I don’t think it will end with apocalyptic change. Price signals will put a limit on demand.”

I mention the often-cited rapid demand growth in China and India among developing countries and the rapid growth in OPEC countries like Venezuela, where consumer prices are greatly subsidized. “Rapidly growing countries like India and China are still poor countries,” he counters. “They can live with a price around today’s price (US$77 per barrel) but they cannot afford oil at $150-$200 per barrel. (If prices rise to those levels) there will have to be some kind of market response. Before 500 million Chinese own a car, they will be driving something that doesn’t rely on oil: Maybe electricity-fuelled vehicles charged from nuclear reactors.” Whatever those vehicles are, Leach has no doubt “there are going to be other factors on the demand side, the technology side, that will temper those straight-line graphs that say oil demand will outstrip oil supply and prices will skyrocket.”

Of course, a basic principle of free-market economics is that supply and demand must always be in balance. Neither does a world with global economic growth constrained by energy shortages sound reassuring. Indeed, the situation he is describing seems compatible with mainstream peak oil theory, so I wonder whether his arguments against worldwide economic destabilization have settled the issue. All the same, I have thoroughly enjoyed the discussion. We shift gears, moving to lighter topics.

Has he read any good books lately? Yes, he says. He reads a lot, and is now reading Team of Rivals: The Political Genius of Abraham Lincoln by Pulitzer Prize-winning historian Doris Kearns Goodwin. This thick book describes Abraham Lincoln’s leadership skills by focusing on his war cabinet, which included three of the political rivals he beat in the 1859 presidential campaign. According to Leach, “it was amazing how he turned these diverse people into a team during the most cataclysmic period of American history.”

For a guy with responsibility for managing SEPAC’s affairs and representing its views to government, the news media and the public, political genius may be just what the doctor ordered. Bear in mind that “nearly half of the world’s public oil companies are here in Calgary.” Within the modern petroleum age, those hundreds of companies have become a team of rivals for the global oil industry to reckon with.

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