The changing face of Canadian energy supply
Volume II
Guidebook & Directory
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› CONTENTS ARCTIC ISLANDS NWT CRETACEOUS
Lizard Basin
Bowser Basin
N Major Sedimentary Basins containing potential unconventional hydrocarbon resources (excluding gas hydrates)
S
CANADA
IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC) SHALE GAS TIGHT GAS LIGHT TIGHT OIL (LTO)
Canadian Unconventional Resource Estimates ** **Based upon CSUG 2010 Appraisal of Original Gas in Place (OGIP)
NATURAL GAS FROM COAL SHALE GAS TIGHT GAS
801 TCF 1111 TCF 1311 TCF
20
24
7
Welcome Letter
Shale gas
9
Welcome Letter—Alberta
24
11
Welcome Letter—British Columbia
13
Welcome Letter—Saskatchewan
15
Welcome Letter—New Brunswick
Vast reserves of shale gas redraw the energy picture By R.P. Stastny
28
The technology of shale gas
31
The road to success Canada’s shale gas producers are paving the way to successful exploitation of a massive resource
SUSTAINABILITY
16
A bridge or our future? Natural gas was until recently touted as the perfect bridge to a future world of renewable resources. With today’s low prices and long-term supply, it’s looking more like the future itself.
Shale gale
By Peter McKenzie-Brown
Regional developments
36
Size of the prize 38 Fired up Technology ignites boom in B.C. shale gas production—now the push is on to find markets
By Graham Chandler
Light tight oil
20
Solving the puzzle Explorers are putting together the technologies to optimize light tight oil developments in western Canada By Darrell Stonehouse
By Darrell Stonehouse
40 New life Tight oil plays resurrect oil industry across western Canada
By Darrell Stonehouse
42 Growing pains Quebec shale gas drilling results promising, but political worries threaten development By Darrell Stonehouse
44 Inching ahead Early-stage exploration success creates cautious optimism about emerging New Brunswick and Nova Scotia shale plays By Darrell Stonehouse
4 // ENERGY EVOLUTION II
PRESIDENT Mike Dawson VICE PRESIDENT Kevin Heffernan Managing Editor Lisa Nicol
Anticosti Basin
Appalachian Basin
Sydney Basin
Canadian Society for Unconventional Gas
36
54
Market Developments
46
Suite 420, 237-8 Ave. SE Calgary, AB T2G 5C3 info@csug.ca www.csug.ca
Off to market
46 Gas to gold Talisman Energy is pinning its shale gas market strategy on proven gas-to-liquids technology
President & CEO Bill Whitelaw
By Peter McKenzie-Brown
Publisher Agnes Zalewski
49 Where to go? Some say transportation should be a market grail for natural gas, while others aren’t so sure By Peter McKenzie-Brown
51 A sustainable future Effectively marketing Canada’s vast unconventional gas resources can help ensure global sustainability By Peter McKenzie-Brown
Environment
54
Editorial Assistance Laura Blackwood, Tracey Comeau, Samantha Kapler, Marisa Kurlovich Production, prepress & print manager Michael Gaffney Art Director Ken Bessie
Unconventional resource producers are taking a lead role in improving environmental performance
Designer Lyuba Kirkova
Testing the waters Massive exploitation of North American shale gas formations puts aquifer protection and water efficiency in the spotlight By Graham Chandler
63 Directory 68
Contributors Jim Bentein, Graham Chandler, Peter McKenzie-Brown, R.P. Stastny, Darrell Stonehouse
A smaller footprint By Jim Bentein
58
Editor Dale Lunan
Glossary
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welcome to energy evolution ii the changing face of canadian energy supply
The natural gas industry has undergone dramatic changes over the past few years both globally and within Canada. Unconventional gas has emerged as an abundant low-cost energy source that has the potential to form the foundation upon which North American energy strategies and security can be built. It is estimated that there is greater than 100+ years of potential supply at current consumption levels in North America. Although a market oversupply of natural gas continues to impact prices, interest in unconventional resource development remains significant, specifically where shale gas is involved. Industry continues to show amazing resilience and an unrelenting commitment to evolve and remain competitive. Natural gas is the cleanest-burning fossil fuel with only half the greenhouse gas (GHG) emissions of coal and 25 per cent less GHG emissions than diesel fuel. Increased utilization of natural gas will not only play a key role in meeting Canadian emissions reduction targets, but also ensures that our country has sufficient energy supplies to meet our growing demands while other forms of renewable energy technology are developed. The key to unlocking the unconventional natural gas resources of Canada and North America has been the application of new and emerging technologies. Horizontal drilling, multi-stage hydraulic fracturing and reservoir monitoring technologies are some examples of the technologies that have led to the dramatic growth of natural gas supply and economic production. Unconventional resources development now encompasses numerous geographic regions of the continent and, in many cases, regions that are relatively new to the oil and gas industry. Development of our country’s oil and gas resources continues to drive the economic engine in Canada and provides economic growth and opportunity to many regions from coast to coast. While at times we as Canadians take our energy supply for granted, it is worthwhile to reflect on the positive impact that unconventional resource development is having on our economy. This guidebook and directory furthers the understanding of the technology behind the exploration for and development of unconventional resources, the opportunities for reduction of Canada’s GHG emissions and the important benefits to our energy supply and economy. A comprehensive list of businesses, associations and individuals with interest in unconventional resources is also included. The Canadian Society for Unconventional Gas will continue to play an important role in the transfer of technical unconventional gas knowledge from industry to the public. The society has a wealth of information about the unconventional resource industry and we encourage you to visit www.csug.ca for more information.
Mike Dawson President, Canadian Society for Unconventional Gas
ENERGY EVOLUTION II // 7
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Greetings from the Ministry of Energy, Government of Alberta
“The vast potential of unconventional
gas in Canada and in the United States has created a fundamental shift in North
America’s natural gas industry.
”
I am pleased to have this opportunity to welcome you to Energy Evolution II-The Changing Face of Canadian Energy Supply. This is an exciting and rewarding time in the unconventional resource development industry in Canada. The vast potential of unconventional gas in Canada and in the United States has created a fundamental shift in North America’s natural gas industry. Over the last several years, the North American natural gas market has shifted from one of scarcity to one of abundance. Unconventional gas production in North America has increased significantly as industry has overcome the challenge of unlocking enormous unconventional gas resources using technologies like horizontal drilling and hydraulic fracturing. This has had a significant impact on Alberta and is presenting industry with new opportunities and challenges. These challenges offer the chance to learn and to adapt new techniques and technologies. This guidebook and directory will help add new perspectives and I know you will find it a useful resource. The Honourable Ron Liepert Minister of Energy
ENERGY EVOLUTION II // 9
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Greetings from the Ministry of Energy and Mines, Government of British Columbia
“It is crucial that we continue to work
together to keep British Columbia’s natural gas sector responsible and competitive.
”
Just a few short years ago, British Columbia was on the verge of reaching peak production from natural gas. Now, production of our largest energy commodity could double by the end of the decade. Unconventional gas changed everything, creating an abundant supply of natural gas available to respond to growing market demands. Despite the uncertainty created by low commodity prices, British Columbia’s competitive advantages retain long-term confidence in the province’s natural gas sector. Our royalty programs stimulate growth and maintain production. Industry activity provides jobs, supports families and strengthens our rural communities. Liquefied natural gas (LNG) projects are gaining momentum, with global LNG trade expected to increase by 50 per cent by 2020. With abundant reserves and a close proximity to new markets, British Columbia is in a unique position to take advantage. We recently joined Alberta and Saskatchewan to forge a commitment to target overseas areas looking to replace carbon-intensive technologies. Industry-led projects now in development would give British Columbia the ability to supply our natural gas—the world’s cleanest-burning fossil fuel—to these new markets. At the same time, modernized regulations brought in last year encourage the use of innovation and increase our commitment to responsible development. The province and the BC Oil and Gas Commission will continue to work with First Nations, communities and industry to maintain North American–leading standards for unconventional gas practices. It is crucial that we continue to work together to keep British Columbia’s natural gas sector responsible and competitive. The sector remains an economic engine for our province, and giving it the opportunity to grow and diversify will only strengthen the prospects of the future.
The Honourable Rich Coleman Minister of Energy and Mines and Minister Responsible for Housing
ENERGY EVOLUTION II // 11
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Greetings from the Ministry of Energy and Resources, Government of Saskatchewan
“ The possibilities are endless in Saskatchewan for companies developing conventional and
unconventional resources.
”
In recent years, Saskatchewan has quietly and confidently become a force in Canadian energy supply. Our province accounts for over one-quarter of Canada’s primary energy production and our per capita energy production is the highest in Canada. Our primary energy production comes from coal, oil, natural gas, hydro, uranium, wind and biofuels. We are the only province in Canada that has commercial production from all these sources. Saskatchewan is Canada’s second-largest oil producer and its third-largest producer of natural gas. Oil and gas is now our largest industry, and thus while we are still known as wheat country, we now proudly wear the mantle of oil country as well. Our province has more than 40 billion barrels of conventional oil in place and nearly 13 trillion cubic feet of natural gas in place. While much of this resource wealth is beyond reach for now, new technology continues to unlock our oil and gas plays through leading-edge enhanced oil recovery techniques and through world-renowned CO2 capture and storage methods. Even though natural gas has been produced in the province since the 1930s, new chapters in our gas story are still being written. We have untapped shale gas potential on the west and east sides of the province and are still evaluating the extent of our natural gas in coal resources, which are primarily in the southeast and southwest parts of the province. The oil and gas industry operates in a very favourable business climate in Saskatchewan, with a supportive government and fiscal and regulatory regimes that are appreciated by industry for their certainty and stability. Our government continues to support technological innovation, and last year provided an incentive to encourage horizontal drilling of gas wells. The possibilities are endless in Saskatchewan for companies developing conventional and unconventional resources. We encourage you to explore the energy opportunities in our province and discover for yourself the Saskatchewan advantage.
The Honourable Bill Boyd Minister of Energy and Resources
ENERGY EVOLUTION II // 13
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Greetings from the Department of Natural Resources, Government of New Brunswick
“ Support the responsible expansion of the natural
gas sector while ensuring the safety and security of homeowners and our groundwater supply.
”
New Brunswick has a rich history in the development of oil and natural gas. One of the first oil wells in North America was drilled in New Brunswick in 1859, as four wells were drilled near what is now the city of Moncton. The search for oil and natural gas in this province has been ongoing ever since. The Government of New Brunswick has identified shale gas exploration and development as well as related industrial activity as potentially having significant economic benefits for our province. The government was elected on a commitment to “support the responsible expansion of the natural gas sector while ensuring the safety and security of homeowners and our groundwater supply.’’ Since the year 2000, more than 65 oil and natural gas wells have been drilled in the province. About half of these are currently producing natural gas and four are producing oil. There are another 12 producing oil wells that were drilled prior to 2000. As of April 2011, there are 71 oil and natural gas agreements in place with nine companies that cover approximately 1.4 million hectares. The commissioning of the Maritimes and Northeast Pipeline that runs through southern New Brunswick in 1999 and the discovery of natural gas in Sussex in 2000 sparked an exploration boom. Since then, more than $374 million has been invested in the exploration and development of oil and natural gas in New Brunswick. The oil and gas industry in New Brunswick plans at least an additional $200 million in activity to be completed within the next two years. The continued growth of New Brunswick’s oil and natural gas industry is important to contributing to the province’s economy.
The Honourable Bruce Northrup Minister of Natural Resources
ENERGY EVOLUTION II // 15
SUSTAINABILITY
A bridge
?
or our future
Natural gas was until recently touted as the perfect bridge to a future world of renewable resources. With today’s low prices and long-term supply, it’s looking more like the future itself. By Graham Chandler
Last year, the Pembina Institute published a comprehensive study that found it was possible for Alberta to realize an electrical future in which carbon is greatly reduced: sustainable resources could replace coal within two decades. “Clean, renewable and transitional energy resources in Alberta are more than capable of meeting future demand in the province, even if electricity consumption doubles over the next 20 years,” reads Greening the Grid. The paper’s most ambitious scenario says wind power, natural gas cogeneration and improved efficiencies could lead the way in reducing coal’s contribution—currently 74 per cent—to just seven per cent. Could it happen that fast? “That would be on a war footing,” says Simon Mauger, director of gas services for Ziff Energy Group. “But you could do it in that kind of time frame. I think at least 30 per cent would have to be natural gas.” Importantly, the study demonstrates the prospects for natural gas going forward. The role of natural gas in North America’s energy future has been revolutionized in recent years. From its perception as a fuel to bridge us into a sustainable future powered by renewable resources, it is instead now presenting itself as the foundation fuel of the future. “The language of gas as a bridge was popular a couple of years ago when we hadn’t seen this shale gas revolution,” says Tim Egan, president and chief executive officer of the Canadian Gas Association. “We had higher gas prices and they were much more volatile.” Moreover, the assumption was that natural gas was a more limited resource than it’s proving to be; certain technologies weren’t
16 // ENERGY EVOLUTION II
as affordable with gas. “Gas is part of the energy future that can partner with a number of things,” says Egan. A major driver is of course the looming requirement for all new coal-fired generating plants to meet stringent greenhouse gas emission targets. In June last year, Jim Prentice, then federal minister of the environment, announced plans to impose new regulations on coalfired electricity-generation plants that would eventually force them to match natural gas combined-cycle plant emissions—or shut down. Many of Alberta’s active coal plants are nearing retirement: three-quarters of them were built in the 1970s and 1980s. Much the same goes for coal-fired generation in the United States. “Even before the announcement, gas was capturing a large part of the new electrical-generation market in North America,” says Mauger. “The main reason is they are cheaper to build. And you can build them with all the regulatory approvals sometimes in as little as two years.” Currently the only way any new coal plants will be able to comply with the proposed rules is through carbon capture and storage—never before done on a commercial scale—and the cost of adding that infrastructure will be no match for the price of natural gas plants. “Long term, for coal, it’s not a great development,” says Egan. “It requires an even greater focus on the development of new technology. For gas, it is a good-news story in the long term. We think the more opportunities to use gas, the more appreciation people will have for the fuel.”
SUSTAINABILITY
He adds that, generally speaking, it’s becoming more and more difficult to build big plants and transmission lines, too. “There is a social reaction against very large infrastructure,” he says. “Because we are increasingly an urban society, people are moving more and more into larger centres and don’t want big industrial facilities nearby.” Egan sees that trend boosting oppor tunities for gas. “In a more distributed generation [network], more use of gas as a foundation fuel in integrated domestic systems [can occur],” he says, citing deployment of new technologies in transportation, for example, and biomethane, which is a renewable natural gas from biomass sources. Domestic systems can include “micro-CHP [combined heat and power],” says Egan. “These are very small units where you can use a gas unit in your home that would generate both heat and electricity—they offer incredible efficiencies and environmental benefits, and the affordable delivery of energy services to people.” He says today they are more for small industrial installations and buildings but will ultimately be available for individual homes. A more regionalized, natural gas–powered promise for the future would then shape up as the major source complementing clean renewables. Other technologies, especially renewables like wind and solar, are expensive alternatives that generally need heavy subsidization.
“The cost of wind and solar is significantly higher than other sources that are available today,” says Mauger. “And where we have the wind isn’t necessarily where the people are. We can look at and talk about renewables, however, there are fundamental principles: the sun doesn’t always shine; the wind doesn’t always blow. Consequently, whenever we look at renewable rapid growth, which we include in our forecast, [we have] that as a very small component.” And in the current climate of high government debt and growing public resentment to wind power turbines, chances those will be powering the future are slimming more with time. Witness the recent Ontario government decision to hold off indefinitely from an ambitious Great Lakes wind power program and the United Kingdom’s proposal to cut government financial support for large solar- generation plants. “How practical are they?” asks Mauger. “They’re practical if you’ve got subsidies.” These and other barriers to the penetration of renewable technologies bode well for natural gas. “In the short to medium term, it’s really the fuel of choice,” says Mauger. “We have found a negative correlation between natural gas prices and electrical generation using gas. The reason behind that is natural gas can be used for peak shaving or peak generation; you can spool the plants up very quickly and turn them off very fast. You can do the same to a lesser extent with coal, but you have a lot of waste heat.” ›
ENERGY EVOLUTION II // 17
“ In the short to medium term [natural gas is] really the fuel SUSTAINABILITY
of choice. We have found a negative correlation between natural gas prices and electrical generation using gas. The reason behind that is natural gas can be used for
”
peak shaving or peak generation....
— Simon Mauger, Director of Gas Services, Ziff Energy Group
It’s not just electricity generation that makes natural gas the fuel for the future; liquefied natural gas (LNG) can be used in trucks and buses. “The Port of Los Angeles uses it in their on-site fleet,” says Mauger. “I might be a little dubious on the safety factor, but proofof-concept projects are working out there today.” On the positive side, however, the attraction of LNG is it’s much greater range than compressed natural gas—more potential energy can be packed into a similarly sized fuel tank. Then there’s the refuelling infrastructure needed for the LNG option, which the Canadian Gas Association’s Egan says has been studied thoroughly by the association. “We have been focusing on key heavy transport corridors, for example, from Fort McMurray to Edmonton and Vancouver,” he says. “Where there are significant volumes of trucking you can look at strategic placement of refuelling [stations], so that it is viable for trucking companies.” He notes that it’s already happening: a Quebec-based truck fleet has been partnering with Gaz Métro to develop refuelling stations along busy intercity corridors. As these smaller projects prove up the concept it can expand. Or, trucks’ tanks might be filled with another natural gas product that wouldn’t even require vehicle conversions: diesel. Right now it’s expensive, but as crude prices climb, it approaches competitiveness. “We’ve reached the peak of light sweet crude,” says Mauger. “In general, a barrel is becoming heavier, sourer and needing modifications to refineries.” Ziff’s recent economic analyses of available gasto-liquids technologies suggest capital costs “of maybe $50 or $60 a barrel and feedstock costs of $4 per mcf [thousand cubic feet]. Each barrel takes 10 mcf to produce, so that’s $40 a barrel for feedstock. So, [that’s a] total cost of $90 to $100 a barrel. And what’s oil today? A hundred and change.” So, he reckons, we are within “spitting distance of the economics.” It’s apparently behind the South African firm Sasol’s decision to take a 50 per cent stake in Talisman Energy Inc.’s shale gas assets in British Columbia’s Montney basin. “If they can get the capital cost down, that’s the key issue in terms of economics,” says Mauger.
18 // ENERGY EVOLUTION II
But with all these transport and electrical power generation conversions to gas, how will it affect the 100-year supply trumpeted by the natural gas devotees? “Phenomenally,” says Mauger. “Personally, I don’t believe the 100-year number—it’s just the total amount of gas in place divided by today’s consumption. Even if prices were to rise and make some of the marginal fields economic then we are looking at a number, which is substantially lower than that.” His group has modelled what would happen if the “Prentice rules” were applied to the United States. “We would see an incremental 30 [bcf] to 35 bcf [billion cubic feet] a day by 2025 or 2030,” says Mauger. “To put that into perspective, we currently consume in North America around 20 bcf a day for electrical generation, so if you want to replace all the coal plants, you’d have to take today’s 20 bcf up to 50 bcf a day.” On top of that, he adds, Ziff Energy’s analysis assumes growth of electrical demand that would need to be covered by gas to be another 10 billion to 15 billion cubic feet per day by 2025. Egan feels the long-term supply picture still looks good. “The fact is, more gas is being found,” he says. “When I talk to producers I get no sense they feel they have exhausted finds. That’s a good signal for continuing low prices.” Moreover, the infrastructure in North America is robust, which contributes to stable prices in the long term. “And if hydrates can be made economic, that will be incredible— Japan has plans to commercialize hydrates very soon. We’ve got that stuff in extraordinary quantities; it bodes well for gas as a foundation rather than a bridge. The way we talk about it is we do see it as a foundation fuel, and I don’t see that changing in the foreseeable future. I’m not a believer that we will go off hydrocarbons in my children’s lifetimes. Gas is just too effective a fuel source. It’s the right fuel in the right place at the right time.” So from Mauger’s view, is natural gas a bridge to an alternative fuel? “Yes, it has to be,” he says. “The question is, over what time frame?” Is there something on the horizon that could cost-effectively replace natural gas? “No, at least not one that can meet environmental standards.” ■
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LIGHT light TIGHT tight OIL oil
Solving
the puzzle
Explorers are putting together the technologies to optimize light tight oil developments in western Canada By Darrell Stonehouse
Piece by piece, explorers are finding the technologies needed to open up western Canada’s massive light tight oil reservoirs. Think of it as putting together a giant 3-D puzzle. Efforts to exploit tight oil resources began in the Bakken formation in North Dakota and Montana over a decade ago. Explorers extended the effort north to Saskatchewan and it has now moved west into a number of legacy fields across Alberta and Saskatchewan. Along the way, the horizontal drilling, multi-stage fracturing and associated technologies have been advanced and adapted to optimize exploration and production. PetroBakken Energy Ltd. has been a pioneer in evolving the technical know-how to exploit light tight oil. Company president and chief operating officer Gregg Smith outlines how the technology used to produce the Bakken has changed over the years. Smith says the company first used extended reach horizontals in the play to expose as much of the reservoir as possible. Production in the wells came in at 10-30 barrels per day. These wells were followed by open-hole coiled-tubing fracture treatments, which produced at around 100 barrels per day. The problem with this system was fracture heights were difficult to control, which resulted in water incursion from an overlying zone, and saline/brackish water cuts were as high as 75 per cent within five months.
20 // ENERGY EVOLUTION II
Then, about five years ago came the multi-stage fracturing revolution, led by Calgary-based Packers Plus Energy Services Inc. The Packers Plus ball-drop system provided the ability to do multiple fracture stimulations quickly and without multiple coiled-tubing trips used with earlier technologies. Production per well in the Bakken quickly increased. The extended horizontal wells stretched up to 1,400 metres, and early multi-stage treatments averaged seven or eight per well. Wells came on at around 200 barrels per day of initial production. With the ability to effectively control fracture heights, water cuts were also minimized. “We discovered by playing with the technology that more fracs equalled more oil,” Smith says. “But the only way to increase the fracture density at the time was to drill shorter wells. The interesting thing that came out of drilling the shorter wells was that with the same number of fracs that we used on the long wells, the short wells performed initially at exactly the same or slightly higher rates—again taking us to the conclusion that more fracs make more oil.” PetroBakken began drilling 600-metre horizontal legs and placing eight 40-tonne frac stages per well. From there, Smith says as the multi-stage
LIGHT tight TIGHT oil OIL light
Photos: Penn West Resources Ltd.
Penn West Exploration has become a dominant player in the Cardium light tight oil play around Drayton Valley, in west-central Alberta.
fracturing technology evolved the company was able to increase fracturing density over longer horizontal legs, yielding increased recoverable reserves. The company was the first to execute a 20-stage fracture in the play. Well production has increased to up to 250 barrels per day. “We saw some operators starting to drill two long horizontal wells on each quarter-section,” he adds. “We thought if that’s the way the play is going to go, we need a more capital-efficient way to do that.” PetroBakken came up with a scheme to drill bilateral wells off of a single vertical well to cut costs. “In the subsurface, it’s exactly the same impact. That’s the conclusion of the reserve auditor,” explains Smith. “If you add a second horizontal leg the reserve auditor says it results in an increase of 50 per cent of the reserves the original well would have recovered. But with the bilateral wells there are tremendous capital efficiencies. A bilateral costs $2.58 million to drill while it costs $4 million to drill two wells.” While light tight oil is now commercial, the technological evolution of drilling and completions hasn’t stopped. As the Bakken has matured and explorers have moved into new tight oil plays, other technologies are being tested.
Many operators are re-examining their well designs and switching to a monobore design rather than the traditional horizontal layout. Monobore wells maintain the same diameter casing from the intermediate casing through the entire horizontal leg. Albert Stark, vice-president of operations for Spartan Exploration Ltd., told a recent tight oil conference the move to monobore well designs combined with open-hole ball-drop multi-stage fracture completions is part of an ongoing effort to cut drilling costs. Spartan operated 14 wells in the Pembina Cardium in 2010, and all were monobores. Using the design saved Spartan around $160,000 per well, or 10 per cent of drilling costs. Stark said the monobore design combined with the ball-drop system isn’t without its challenges. Debris issues in the wells resulting from milling out the staging tool and wiper plug can lead to fracking issues. So proper milling procedures must be followed. Despite the debris concern, the company plans to continue use of the monobore design. Explorers are also testing different completions technologies with the goal of exposing more rock and increasing production. ›
ENERGY EVOLUTION II // 21
LIGHT TIGHT OIL
Illustration: Encana Corp.
✔ 6 horizontal wells (8 fracs/well) = 48 total fracs per section
✖ Same development would require 48 vertical wells each on a separate 100 m x 100 m pad
Drilling multiple horizontal wells from a single pad disturbs only about five per cent of the surface area as a comparable vertical well scenario.
Robert Hawkes, team leader for reservoir services at BJ Services, told a recent Society of Petroleum Engineers meeting in Calgary the ball-drop system designed by Packers Plus, now used by most major service companies, has proved itself in tight oil plays across western Canada and beyond. Packers Plus has used the system in over 5,200 wells and completed over 45,000 fracture stages. BJ Services has used the ball-drop system on 1,400 wells, completing almost 13,000 stages. Hawkes said the ball-drop system has a number of advantages. It can complete more than 22 stages and allows for continuous pumping. The entire open-hole wellbore has contact with the reservoir. Using the system, crews can isolate out undesirable intervals. And most importantly, the system can complete multiple zones in a single day. The downside of the ball-drop system is it becomes expensive when more than 20 zones need to be fractured. On some occasions, costly cleanouts are needed for the system to function, and the ball sets need to be milled out for well interventions or production work. Still, Hawkes said, “the ball-drop multi-stage fracturing system has proven to be a workhorse system in horizontal completions in Canada.” A competitor technology used in the tight oil completions market is the pump-down wireline gun and plug system. In this system, anywhere from three to 10 perforating guns are lowered to the perforating depth using the frac pumps and fluid. A composite plug is run with the assembly to isolate the lower intervals to be fracked. Then the assembly is moved to the next interval. Hawkes said the advantages to this system are that it is efficient, low-cost and provides for exact depth control. The downsides are the need for extra fluid pumping and the risk of fishing operations if the plugs or perforating guns fail. Annular fracturing techniques are also gaining momentum in light tight oil plays. With annular fracturing, coiled-tubing units are in the
22 // ENERGY EVOLUTION II
wellbore during the fracture treatment. Abrasive perforating is used, rather than charges, with a nozzle spraying a concentrated stream of abrasives into the formation. Sand plugs are used for isolation to fracture the different intervals. Two big advantages of using sand plugs are they work with cemented liners and there is no limit to the number of stages that can be drilled, said Hawkes. Their downside is they are slower than balldrop systems, the annulus is bull-headed on each frac and pressure has to be maintained on the plug to keep it in place. To overcome this, packers can be used to replace the sand plugs. The problem? Exxon Mobil Corporation owns the patent on this technology and there is a six-stage limit in Alberta and a three per cent royalty for using the system. BJ Services has completed over 200 wells using abrasive perforating and has fractured as many as 40 stages in a single trip. “Abrasive perforating and annular fracturing are becoming the method of choice in the Bakken, Viking and Cardium formations,” said Hawkes. Operators are also taking a new look at the type of fracturing fluids being used in light tight oil formations. In the Cardium, producers have been using oil to carry proppant deep into fractures. But Spartan’s Stark says many are now looking at water-based fluids as a means of reducing costs. The two main systems being tested are a nitrified surfactant gel and the slickwater (typically 98+ per cent water and sand) common in tight gas stimulation. Stark said the cost difference between the used oil frac system designed by Trican for the Cardium and water-based fluids is around $94,000 on an average well. Other systems being tested include foamed water fracs, nitrified oil fracs and gas fracs. “The preferred system may ultimately be determined by well performance rather than cost,” said Stark. Microseismic technology has also played a key role in the exploitation of tight oil plays, and the tool is evolving as field development accelerates. Microseismic uses geophones on the surface, buried near the surface, or inserted via wireline into existing wells, where available, to measure the tiny seismic activities created during hydraulic fracturing. From there, the data is interpreted and mapped, showing the penetration and direction of the fractures. The information is delivered in real time. Operators can adjust their fracking stimulation program as it advances stage by stage down the length of the horizontal wellbore, based on the information generated. Microseismic was first used on individual wells to understand how fractures move within the reservoir under stimulation. In the Bakken, the goal is to keep fractures out of the overlying Lodgepole formation, which is saturated with saline/brackish water in many locations. A new technique, pioneered by MicroSeismic, Inc., uses an array of buried geophones to monitor entire oilfields passively. Last March, the company installed a buried array system for Whiting Oil & Gas Corp. covering 150 square miles in the Bakken play in North Dakota. With 1,200 geophone channels in place, the system will enable microseismic monitoring, mapping and analysis of the hydraulic fracturing operations for Whiting’s Sanish Field development program. It will also permit Whiting to monitor the primary, secondary and tertiary activity in a variety of reservoir conditions for its Bakken and Three Forks formation wells on a long-term basis. ■
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SHALE GAS
Shale gale Vast reserves of shale gas redraw the energy picture By R.P. Stastny
In the run-up to the summer of 2008, the global economy was racing like an overworked computer system with too much network traffic and too many program windows open all at the same time. Then the U.S. financial markets melted. The reverberations toppled the world’s economies and the system froze. The ensuing global recession turned out to be a lot like a trusty computer reboot. It reset the money markets, economic outputs and energy supply and demand algorithms. A new cycle began and the fuel of choice for this new, more cautious cycle of economic growth in North America, at least, seems to be clean-burning natural gas from shale. As oil prices, at the bottom of the recession, began their relentless upward march to the current US$100 per barrel mark, natural gas prices have remained flat in the range of US$3 to US$4 per thousand cubic feet. This reflects the disparity between the vast supplies unleashed by shale gas development in North America and the yet-to-be-tapped demand to take advantage of this incredible resource, estimated at 4,471 trillion cubic feet in place just on this continent. To put that in perspective, Canada’s total consumption in one year is about three trillion cubic feet. Decades of innovation and perseverance have succeeded in unlocking natural gas from the world’s most common rock formation and launched a paradigm shift in supply. Natural gas production has been declining for years in Canada and for decades in the United States, but now it’s in ascent. A relatively low-cost energy source, shale gas currently adds about 10 billion cubic feet per day of production. By 2020, its production is expected to grow to 24 billion cubic feet a day. And this has game-changing implications.
Producers The meteoric rise of shale gas opened a new frontier of growth for producers. The technology that unlocked shale gas—horizontal drilling coupled with multi-stage fracture stimulations—emerged in its current incarnation shortly after U.S. independent Devon Energy Corporation entered the Barnett shale in Texas in 2002. Devon Energy showed shale gas was commercial and repeatable. Soon, other companies joined the play and, just as quickly, they found Barnett analogues in other shale basins in the United States and Canada. In British Columbia, companies like Encana Corporation and Apache Corporation secured first-mover advantage in the Horn River
24 // ENERGY EVOLUTION II
shales, picking up vast, low-cost contiguous tracks of the most prospective lands for this production-style resource play development. Producers that waited later paid their way into these plays. There were also some eyebrow-raising attitude shifts along the way. Talisman Energy Inc., for example, displayed a Saul-to-Paul transformation as one top executive, Jim Buckee, who shunned resource plays, retired and was replaced by John Manzoni, who steered Talisman straight into the Montney in British Columbia and the Marcellus shale basin in the United States. But what definitively announced to the world the importance of shale gas was Exxon Mobil Corporation’s purchase of shale gas maverick XTO Energy Inc. for a whopping $41 billion in December 2009. Exxon Mobil, arguably the closest entity to a U.S. national oil company, faced with declining conventional reserves and seemingly limited growth prospects worldwide, sailed into new reserves and growth with its embrace of shale gas. “Today all the major producers are in shales,” says Mike Adams, Talisman’s senior manager of corporate projects and business development. He spoke at the Canadian Institute’s seventh annual Shale Gas Symposium in Calgary last January. “Unlike the oilsands, where some majors are not playing for whatever reason, they’re all there in the shales.” Adams tracked some 97 shale gas transactions worth a total of about $100 billion in the last two years in North America. And new entrants are coming to North America’s shales—the Chinese, the Japanese, the Koreans. Adams notes that the North American shale gas business has also changed hugely over the last two years and continues to reshape itself. “There’s going to be lots of activity. There’s going to be more consolidations because it’s a scale business. It’s hugely capital intensive and it will need well-capitalized companies,” he says.
Global context The natural gas abundance story in North America seems well understood now. Various estimates suggest the continent has more than 100 years of natural gas supply. By 2030, more than half of
its natural gas will come from unconventional sources—mostly shales—according to World Energy Council forecasts. And what works in North America stands a good chance of working in other parts of the world. The biggest producers are now looking to understand the global potential for shale gas. Drawing upon the data collected by U.S.-based Core Laboratories N.V. for its Global Shale Project, Randy Miller, Core’s president of integrated reservoir solutions, says 2011 will see much assessment work and many pilot wells drilled worldwide. The areas that have traditionally seen oil and gas development and benefit from existing infrastructure will be the first in line. “But, right now, Poland is certainly where most of the activity is going on outside of North America,” Miller says. “A lot of acreage has been taken out by various companies. The major players there are ConocoPhillips, Talisman, Chevron [Corporation], Marathon [Oil Corporation], Lane Energy [Holdings plc], BNK [Petroleum Inc.], Exxon Mobil, Shell, Eni and others.” Strangely enough, Russia, which has the world’s largest in-place shale gas potential, according to the World Energy Council, has been throwing cold water on the shale gas revolution. Its top officials have dusted off Cold War– era rhetoric and cast doubt on the significance of foreign shale projects. Stateowned Gazprom’s executive chairman Alexey Miller has been reported saying shale gas should be regarded only as a “temporary local source” of hydrocarbons that will never become a major global energy sector. Then he tipped his hand, adding “shale gas will never compete with traditional gas,” which Russia has plenty of and has a vested interest in continuing to supply to countries like Poland, which currently is entirely dependant on Russia’s conventional gas.
Redrawing the energy map Faced with natural gas declines and growing demand prior to shale gas, the United States started building up its liquefied natural gas (LNG) import capability in the last decade. Many of those projects came to completion just as growing shale gas production hit the market. Shale gas turned out to be cheaper than LNG so the North
African and Middle Eastern LNG producers that were eyeing the United States as a potential market have today largely redirected their marketing efforts back to Egypt, Japan, Europe and Asia. The combination of large U.S. shale gas resources and current low natural gas prices in North America has even prompted discussion around converting some United States. LNG terminals into liquefaction facilities to export natural gas. While some consider that even a small volume of exports could open a window to world-level natural gas pricing and shore up the low North American price environment, the downside is that liquefaction facilities aren’t cheap, they take time to build and, perhaps most importantly, the export idea is at loggerheads with U.S. political objectives of energy security and reducing reliance on foreign energy.
New markets The oil and gas industry itself admits that commodity prices languishing in the doldrums of US$3 to US$4 per thousand cubic feet aren’t sustainable for most shale gas production. Prices need to be closer to $5 and $6 per thousand cubic feet over the long run. So what is the answer to firming up North America’s natural gas price environment? It’s finding new markets for natural gas in North America. Transportation may be a part of this. Transportation represents roughly one-quarter of North America’s energy usage, so expanding natural gas penetration in this market would certainly help the supply and demand balance. California is at the forefront of using natural gas as a transportation fuel largely due to its pollution problems, which have brought in environmental legislation and incentive programs to get more clean-burning natural gas vehicles on the road. In Canada, Encana has taken up the challenge of reigniting interest in natural gas vehicles. (Canada was one of the first countries to develop natural gas vehicle technologies in the 1980s and 1990s and found markets around the world; uptake at home, however, has been slow, to say the least.) So Encana is telling the shale gas abundance story and working with Canada’s NGV association and the NGV ›
ENERGY EVOLUTION II // 25
SHALE GAS
Photo: Trican Well Service
A Trican Well Service frac spread in the Duvernay shale play of western Canada.
Horn River Montney
SHALE GAS
Duvernay Colorado Utica
Bakken Gammon Green River Monterey
Cane Creek
Miocene Cretaceous Jurassic Triassic Pennsylvanian Mississippian Devonian
Antrim Niobrara New Albany
Lewis Palo Duro Woodford Barnett
Excello
Marcellus
Fayetteville Conasauga Haynesville
Pearsall
Ordovician Cambrian
equipment manufacturing industry to promote wider usage of natural gas in transportation. The transportation sector, however, has only limited potential for moving North American natural gas prices. “Even if we had 10 per cent NGV penetration each and every year,” says Simon Mauger, director of gas services for Calgary-based consultancy Ziff Energy Group, “we would end up with one [bcf] or two bcf [billion cubic feet per day of incremental] demand. So natural gas for vehicles really is not the answer. From a pollution perspective, from reducing reliance on external oil, it’s not a bad idea. But going from nothing to next to nothing [in demand] doesn’t make for much of the market.” The real potential for increasing natural gas demand is in power generation. Building coal plants in today’s carbon-wary world is a tough sell. Alternatives such as wind power are growing, but they currently supply only about two per cent of North American energy needs. According to Ziff, this may grow to over six per cent during this decade, but that still isn’t particularly significant. So relatively clean-burning natural gas in power generation has the most potential for growth. “The U.S. fleet of coal plants, which provides 50 per cent of their power generation, is aging, particularly here in the Midwest and the Southeast,” Mauger says. “If we were to replace those coal plants as they end their economic life at the end of this decade or [over] the next 15 years, we would need an incremental 30 [billion cubic feet] a day of natural gas. So this is the real wild card in how shale fits into the economic picture of North America.”
Declining exports What has been good for the United States hasn’t been so good for Canada. Canada produces more gas than it consumes and exports the rest. Largely as a result of shale gas, Canadian natural gas ex-
26 // ENERGY EVOLUTION II
Fredericks Brook Horton Blu
The depth and breadth of shale gas deposits in North America are radically altering the continent's gas supply picture.
ports to the United States have been declining and so has Canada’s overall natural gas production. From a high point of about 15.8 billion cubic feet per day of production in 2008, Canadian production has been losing about a billion cubic feet per day each year. The National Energy Board expects that 2010 production, when the figures finally come in, will have dipped to about 13.04 billion cubic feet per day. AJM Petroleum Consultants’ vice-president of geoscience, Dave Russum, explains some of the economics behind this decline. He says natural gas prices have come down while the Canadian dollar has strengthened. Because many Lower-48 shale plays are on the doorstep of densely populated natural gas consuming regions, they have, in some cases, a competitive advantage over Canadian natural gas exports. That advantage can mean as much as a $1 per thousand cubic feet, according to other analysts. The marvellous Marcellus in Pennsylvania is a case in point. This hugely prolific formation of the Appalachian Basin currently produces 2.5 billion cubic feet a day, has a fairway as large as all the other producing shales in North America and sits next to the massive U.S. Northeast gas market. It also happens to be the most economic play, with sub-$3 per thousand cubic feet costs, according to Ziff Energy. Even Canada’s Montney, a shaley tight reservoir play in north eastern British Columbia that once boasted the best gas economics in North America, lags Marcellus’ prowess. “Then we have the added challenge of [the United States] being able to bring in cheap imports of LNG when it’s available on the import market,” Russum says. It gets worse for Alberta. Historically, 60-70 per cent of Alberta’s activity came from the gas sector—conventional gas, shallow gas, tight gas and more recently coalbed methane, all of which are less economic than the best shale gas plays.
Illustration: AJM Petroleum Consultants
Besa River
Meteoric rise or just reward? Texas oilman began research and development of shale gas almost 30 years ago
A thin stream of shale gas has been produced in the United States in the Appalachian and Illinois basins for almost 100 years. But it wasn’t until George Mitchell turned his attention to the Barnett shale in the early 1980s that the modern era of shale gas development got underway. Aided by a U.S. tax incentive to stimulate exploration and develop-
Other implications
ment of unconventional resources, Mitchell spent almost a decade
Declining conventional gas production in Alberta is making Alberta’s petrochemical industry nervous. For years, it benefited from low gas prices because its natural gas liquids–derived feedstock gave the industry a competitive advantage compared to high–priced crude oil–derived naphtha feedstocks used by other petrochemical hubs. But currently, there is a glut of global petrochemical capacity. And when world demand picks up, it’s unclear whether Alberta’s petrochemical industry will be able to source enough liquids-rich natural gas to drive growth and profitability. Falling Canadian gas exports have also recently prompted TransCanada PipeLines Limited to hike its tolls for moving natural gas across its mainline system to the east. This is a further handicap on the competitiveness of western Canadian gas exports, but Steve Clark, TransCanada’s vice-president, commercial-west, Canada and eastern U.S. pipelines, sees this only as a temporary issue. Speaking at a Vancouver gas conference, he expressed optimism for the prospects of a gradual comeback in conventional natural gas production as gas prices strengthen towards the middle of the decade. The huge potential of shale gas has also pushed frontier gas prospects to the sidelines. Plans for a Mackenzie Valley pipeline have been discussed for more than 50 years. In the years leading up to the financial markets’ collapse, the prospects of finally building the pipeline never looked better, despite the protracted regulatory process around its social and environmental impacts. But then the recession hit and shale gas came on. In March, Ottawa cleared the way to its construction, but analysts don’t expect much to happen on the Mackenzie Valley pipeline until the end of this decade.
and millions of dollars in research. He cycled through an array of
Challenges
Eagle Ford, Utica, Bakken, Viking, Lower Shaunavon, Cardium and
Water usage and groundwater contamination top the list of challenges facing shale gas development. Some jurisdictions have introduced frac fluid chemical disclosure requirements and want the industry to better account for its use and disposal of water. The industry has responded by cleaning up its frac fluids. Some frac providers have replaced diesel carrier frac fluids with food-grade mineral oils to reduce potential impacts. Others are reducing or even trying to eliminate oil carriers altogether. Some are looking to non-potable water sources in fracking. And mechanical processes are replacing chemicals where possible—for example, in the treatment of frac water to control microbial growth. “The challenge is economically extracting shale gas in an environmental manner,” Russum sums up. “All the shale plays are different. The Barnett shale is significant for being the first and providing guidance for other shale opportunities. The Haynesville is the deepest. The Marcellus, a game changer in terms of price. The Horn River, quite possibly the biggest of the shale plays. But even in some of the best [shale] plays in North America, producers are not guaranteed to make money. We have to encourage science and experimentation to find the optimal solutions in specific plays. Perseverance and patience are to be vital.” ■
drilling and completions techniques, all the while ignoring a chorus of industry veterans who told him he was wasting his time. Challenging conventional wisdom that shale can’t be fractured by water, Mitchell and his team eventually met with success in the early 1990s using a high-volume “slickwater” fracture stimulation, which drastically reduced fracking costs by eliminating the frac gel component and reducing sand. But it would still be more than a decade before the floodgates on Barnett shale gas burst open in 2002 when U.S. independent Devon Energy bought Mitchell Energy & Development for $3.5 billion. Devon Energy paired slickwater fracs with horizontal drilling and shifted shale gas development into high gear. The Barnett would become one of the largest natural gas fields in the United States. More importantly, it showed the world that the vast natural gas resource locked in shale and tight unconventional reservoirs could be tapped commercially. Ongoing technical innovations in open-hole and cased-hole multi-stage completions allowed better fracture stimulation control across the length of a horizontal well and continued to improve shale gas economics. Producers also migrated this technology to other unconventional reservoirs, both gas and oil bearing, finding commercial production across the continent. Today, the list of shale plays runs long. Some of the high-flyers are the Haynesville, Fayetteville, Marcellus, Horn River, Montney, Niobrara. Others are in the making. But all of them can be traced back to the determination and perseverance of George Mitchell, who, at 92 years of age, still remains active in the industry, both as a driller and the largest shareholder in Devon Energy.
Shale gas in-place resource potential worldwide North America: 4,471 trillion cubic feet (tcf) USSR: 5,402 tcf • Western Europe: 559 tcf • Eastern and Central Europe: 559 tcf • Middle East and North Africa: 1,305 tcf • Latin America: 373 tcf • Sub-Saharan: 1,017 tcf • Central Asia and China: 372 tcf • Pacific: 745 tcf •
• Former
(Canadian natural gas consumption: about 3 tcf/year) Source: World Energy Council 2010
ENERGY EVOLUTION II // 27
SHALE GAS
The National Energy Board expects Alberta’s gas production to dip to 8.5 billion cubic feet per day in the next two or three years from 12.7 billion cubic feet per day in 2009. British Columbia may pick up some of this contraction, growing to 3.7 billion cubic feet per day from the current 2.7 billion cubic feet per day. What this means for Alberta is fewer natural gas jobs and perhaps tighter government budgets since it remains to be seen whether Alberta’s growth in oilsands and the current boom in light oil drilling using the same technology that unlocked shale gas will make up the slack in workforce and government revenues.
SHALE GAS
The technology of shale gas There are three key technological developments that have unlocked the natural gas potential of fine-grained rocks like shale and sandstones:
Horizontal drilling
Hydraulic fracturing
Figure 2 First commercial hydraulic fracturing job in Velma, Okla., in 1949
Figure 3 Multi-stage hydraulic fracture stimulation. From the CSUG Videos & Animations page at www.csug.ca.
SOURCE: CSUG
28 // ENERGY EVOLUTION II
Reservoir interval
PHOTO: Halliburton
Hydraulic fracturing is the process of transmitting pressure by fluid or gas to create cracks or to open existing cracks in hydrocarbon-bearing rocks many thousands of feet underground. The purpose of hydraulic fracturing an oil or gas reservoir is to enable the oil or gas to flow more easily from the formation to the wellbore. Hydraulic fracturing is not a new process and engineering principles are well understood. See Figure 2. Multi-stage fracturing, the latest evolution in hydraulic fracturing, involves the segmentation of fracturing operations in the horizontal leg of the wellbore. Each stage is isolated using either plugs or packers so that fracture energy, applied to the wellbore from the surface fracturing equipment, is concentrated within each stage. The result is the creation of extensive fracture patterns that allow the oil or gas to flow more easily to the wellbore. Stimulation procedures are applied to each stage individually. See Figure 3.
‹ Vertical well “kick-off” point
SOURCE: CSUG
The first stage involves drilling a vertical well to a predetermined point above the shale gas reservoir. The well is then drilled (kicked off) at an increasing angle until it meets the reservoir interval in a horizontal plane. See Figure 1. Once horizontal, the well is then drilled to a selected distance, which could extend as much as 2,500 metres. This portion of the well, called the horizontal leg or lateral, allows significantly increased contact of the wellbore with the reservoir compared to a vertical well.
Figure 1 Horizontal drilling. Check out the CSUG Videos & Animations page at www.csug.ca for more information.
SHALE GAS
Figure 4 Schematic of a horizontal well relative to groundwater Surface
Municipal water well
Private well
Shallow groundwater aquifer Deep groundwater aquifer
Surface gas-well lease
Protective steel casing: Steel casing and cement provide well control and isolate groundwater zones
1,000 m
Lim esto ne Limestone
HYDRAULIC FRACTURING
ILLUSTRATION: CANADIAN NATURAL GAS
1,500 m
2,000 m
Induced shale fractures
Sandstone San dsto ne
2,300 m
Gas-rich shale
Microseismic monitoring
Horizontal bore Note: Buildings and well depth not to scale
Figure 5 Fracture planes from microseismic data
SOURCE: ESG and Nexen
Industry has a strong track record of safe development, demonstrated in hundreds of thousands of wells drilled throughout North America during the last 50 years. Still, the reality is that there are challenges associated with the level of public anxiety, specifically where hydraulic fracturing is concerned. Canadian regulators and the natural gas industry are focused on the protection of surface and groundwater. A key element of successful hydraulic fracturing is proper well construction, which will ensure that groundwater is isolated from the wellbore and protected from completion and production operations. See Figure 4.
Operators use microseismic technology to observe the development of vertical and horizontal fractures in the rock formation in real time. Measurement of microseismic events that are occurring as the fracture stimulation takes place is important because adjustments can be made during the operation to ensure that the fractures created stay within the zone that has production potential. Once completed, the microseismic model can be used to define the limit and reach of fracture stimulations in each wellbore and allow for optimal field development. See Figure 5. Industry will continue to advance technologies that will broaden unconventional resource opportunities, improve productivity and recovery potential, and allow for the environmentally, socially and economically responsible development of Canada’s unconventional natural resources. â–
ENERGY EVOLUTION II // 29
779522 Inside Education full page 路 fp
SHALE GAS
The road to success Canada’s shale gas producers are paving the way to successful exploitation of a massive resource 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 Nor th 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 any more, because they now generally require a lot of start-up capital. Crashing gas prices have put some junior oil companies into receivership, forced many to merge and forced all to change. Perhaps Winter Petroleum Ltd.—a small, privately held company—typifies the situation for little gas producers. With operations in the northwestern corner of Alberta, the company got its name because its properties can be drilled only 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 Ltd., which was a neighbour to his own gas company. “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 fracking. 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 [million] to $70 million and then putting an experienced management team in charge. There are fewer momand-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.” ›
ENERGY EVOLUTION II // 31
Photo: Nexen
“ There is so much we SHALE GAS
can do now to increase demand: fuel switching, the Pickens Plan in the United States, increasing use of gas for power generation.” — Danielle Smith, Leader, Wildrose Alliance
Frac operations on Nexen’s B-18-I/94-O-8 pad (8 wells, 144 fracs) in Horn River in Summer 2010. Nexen set an industry record frac pace of 3.5 fracs per day with a 100 per cent success rate with this program.
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: shif ting 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 Company Limited made a huge counterintuitive deal with Encana Corporation. While other major Asian investments in the Canadian petroleum industry have mostly gone into the oilsands, PetroChina 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 Company’s stake in Syncrude Canada Ltd. 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.
32 // ENERGY EVOLUTION II
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,” says Boras. 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 Corporation’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 to liquids The gas-to-liquids concept is most evident in the billion-dollar deal Talisman Energy Inc. 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-toliquids technology to turn the gas into a desirable liquid fuel. This is proven technology: Shell, for example, is constructing a $6-billion gasto-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 liquefied natural gas (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, Inc. 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 [West Texas Intermediate]. 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 Group, 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 British Columbia’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 skeptical. While he acknowledges that the consumption of large amounts of water for fracking can be an environmental problem in areas where water is in short supply, he’s not sure the environmental concerns expressed in Gasland really hold much credence. “Shale gas and groundwater 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 that 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 1,500 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 ›
ENERGY EVOLUTION II // 33
SHALE GAS
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 Consultants, “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 policy-makers 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.
Photo: Nexen, JANUaRY 2010
“ We are always looking SHALE GAS
for ways to maximize the value of our assets, and natural gas liquids extraction is an important part of that process.” — Alan Boras, Spokesman, Encana Corp.
A multi-well horizontal drilling location in northeastern British Columbia.
that conversation, they have to come to the conclusion that there is no problem here.” Well, not entirely. In March, Québec 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 would halt new drilling in Québec’s promising Utica shales. Ziff’s Gwozd has a kind of conspiracy theory into 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 specializing in issues affecting 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 ever more important in other ways, too. The Obama administration, for example, 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.
34 // ENERGY EVOLUTION II
Senior Democrats in Congress are getting behind the stuff, portraying it as an alternative fuel for transportation that can serve as a stop gap 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 that 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 United States 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 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.” ■
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REGIONAL DEVELOPMENTS
size
of the prize Shale gas promises to be a game changer in four key regions across Canada
N Major Sedimentary Basins containing potential unconventional hydrocarbon resources (excluding gas hydrates)
S
IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC) SHALE GAS TIGHT GAS LIGHT TIGHT OIL (LTO)
Canadian Unconventional Resource Estimates ** **Based upon CSUG 2010 Appraisal of Original Gas in Place (OGIP)
NATURAL GAS FROM COAL SHALE GAS TIGHT GAS
36 // ENERGY EVOLUTION II
801 TCF 1111 TCF 1311 TCF
REGIONAL DEVELOPMENTS
ARCTIC ISLANDS NWT CRETACEOUS
Lizard Basin
Bowser Basin
CANADA
Anticosti Basin
Appalachian Basin
Sydney Basin
ENERGY EVOLUTION II // 37
REGIONAL DEVELOPMENTS
Northeastern B.C.
fired up
Technology ignites boom in B.C. shale gas production— now the push is on to find markets
Liard Basin
Incremental improvements in horizontal drilling and multi-stage fracturing technology are quickly driving down costs and improving recovery rates at the Montney and Horn River shale plays in northeastern British Columbia. With growing confidence the province’s massive shale resource can be technically produced, efforts are now under way to build the infrastructure needed to find premium markets for expanding production. Encana executive vice-president and president, Canadian division Mike Graham told a BMO Capital Markets conference earlier this year that Encana is making great strides in driving down costs in its B.C. shale plays, making them among the best on the continent. “Technology has moved very, very quickly there,” said Graham. “And there’s still a lot more to come.” In the Montney, Graham said wells have gone from 1,000-metre to 2,000-metre horizontal legs, and the latest wells are extending out to 2,500 metres. Six to eight wells are being drilled per pad. The company is now fracking up to 14 intervals per horizontal leg. “Average wells are now initially producing over five million cubic feet per day and up to 10 million cubic feet per day,” he added, noting the company’s cost per interval completed has declined from $500,000 to $350,000. “We may get as much as 0.5-0.8 billion cubic feet in reserves per frac stage. Our finding and development costs are getting below $1 per thousand cubic feet, and our supply costs are down from $5 to $6 to $3 and are probably going to be sub-$3 this year. So even at today’s prices, we still make a really good return on the Montney.” Encana’s next hurdle at the Montney is stripping liquids out of the gas stream, in an effort to improve the economics of the play further. “Right now we’re selling the liquids in the gas stream without stripping them out,” he explained. “But we’re going to take our NGL [natural gas liquids] from 10,000 barrels per day in Canada right up to 30,000-35,000 barrels per day over the next few years.” 38 // ENERGY EVOLUTION II
Horn River Basin
BRITISH COLUMBIA
ALBERTA
BRITISH COLUMBIA UNCONVENTIONAL GAS RESOURCE PLAYS IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC) SHALE GAS TIGHT GAS
By Darrell Stonehouse
Cordova Embayment
LIGHT TIGHT OIL (LTO)
Montney Trend
The increase will come from the Montney, along with Encana’s other resource plays in the liquids-rich areas surrounding the Deep Basin. Talisman Energy Inc. is also making major progress on its Montney tight gas and shale play at Farrell. Talisman has eight rigs operating in the play in 2011, and expects production to reach 50-60 million cubic feet per day net to the company. “At Farrell, we have over 1,400 well locations,” Talisman executive vice-president, conventional, Jonathan Wright told a First Energy conference in March. “Wells to date have had initial production averaging six million cubic feet per day and are expected to recover seven billion cubic feet of gas.” Further north in the Horn River, Encana’s Graham said gains from technological advancements continue driving down costs. A key factor in this is the pad drilling, or gas factory, concept pioneered by the company. “We’re now drilling as many as 16 wells off of one pad. It gives us a lot of economies of scale and it’s what’s driving down our costs,” he explained. “We do this in an enormous way in the Horn River. We’re getting very good at it.” Graham said the goal at Horn River is to maximize everything— the number of wells per pad, the length of the horizontal legs, the number of fracs per well and the size of the fracs themselves. On its latest wells, horizontal legs are now stretching as far as 3,000 metres, and Encana is averaging 27.5 fracs per well. The size of the fracture treatments have grown from 4,000 cubic metres of water per frac to 5,000 cubic metres and pumping costs have declined from $176 per cubic metre to around $119 per cubic metre. The company is now putting in around 75 fracs per section. “Costs have continued to come down to around $500,000 per frac,” said Graham. “Finding and development costs are getting down to the 80- to 90-cent range. What we’re finding is the more fracs we put into these, the bigger the wells are. On our 63K pad, the average initial production is between 10 [million] and 15 million cubic feet per day with some wells coming in [at] over 20 million cubic feet per day.”
REGIONAL DEVELOPMENTS
With wells on production for a number of years, the company is also getting a better understanding of decline rates in the field. Graham said wells are declining around 55 per cent the first year, 35 per cent the second and 20 per cent the third. “So after two years they are still producing over five million cubic feet per day. We think we are going to get estimated ultimate recoveries based on existing declines of 20 billion cubic feet per well,” he added, while cautioning that it is still “early days” in the play. Infrastructure to process the gas is taking shape with the 400-million-cubic-feet-per-day Cabin gas plant operated by Encana, Spectra Energy Corp.’s reworking of its Fort Nelson plant to bring capacity back up to one billion cubic feet per day and a new take-away pipeline being built by TransCanada Corporation in the works. But the bottom line when it comes to driving further growth in B.C. shale plays is finding new markets for the gas. With U.S. shale plays growing quickly, finding a home for increasing Canadian production is paramount. According to industry studies, recent B.C. discoveries indicate the province will have the resource capacity to more than double current production of about 2.8 billion cubic feet per day to more than seven billion cubic feet per day in the next seven to 10 years. Producers in the Horn River are working to build an export line and liquefied natural gas terminal in Kitimat in one effort to relieve the pressure. In mid-March 2011, Encana acquired a 30 per cent interest in the planned terminal, located on the west coast of central British Columbia, and the associated natural gas pipeline, in an effort to move gas to Asia-Pacific markets. Apache Canada Ltd. and EOG Resources Canada Inc. own the remainder of the facility. “We expect that this project will help advance North America’s natural gas economy across the Pacific to markets where demand is growing and natural gas prices are more closely tied to oil prices,” said Randy Eresman, Encana’s president and chief executive officer, in announcing the purchase. The facility has a planned initial capacity of 700 million cubic feet per day, and will produce about five million metric tons of LNG annually. Project construction could begin in 2012, with exports potentially starting in 2015. The project is operated by Apache Canada, which will own 40 per cent, with Encana and EOG Resources Canada each owning 30 per cent. Talisman is also moving to find new markets and better pricing for its Montney production. In December 2010, it announced a joint venture with South African chemical giant Sasol Limited, with Sasol paying $1 billion for 50 per cent of Talisman’s Farrell Creek play. At the time, the companies said they would also investigate the feasibility of constructing a 46,000-barrel-per-day gas to liquids facility based on Sasol’s technology that is currently being used in three facilities around the world. In March 2011, a second joint venture was announced on Talisman’s Cypress properties. Sasol’s global general manager, Leon Strauss, says a gas to liquids plant makes sense because of what the company views as “a long-term structural shortfall in the dynamics between prices of natural gas and crude that makes gas to liquids an even stronger value proposition.” With the second joint venture, the two companies are investigating whether a 96,000-barrel-per-day facility is possible. While the study is just beginning, Strauss says, “overall we are optimistic about its outcome.” ■
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ENERGY EVOLUTION II // 39
REGIONAL DEVELOPMENTS
Alberta/Saskatchewan
new life
Tight oil plays resurrect oil industry across western Canada By Darrell Stonehouse
ALBERTA AND SASKATCHEWAN UNCONVENTIONAL GAS AND TIGHT OIL RESOURCE PLAYS IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC) SHALE GAS TIGHT GAS
ALBERTA Montney Tight Gas Resource Play
LIGHT TIGHT OIL (LTO)
Mannville NGC Resource Play Edmonton
SASKATCHEWAN Horseshoe Canyon NGC Resource Play
ALBERTA
Cardium Fm Calgary Tight Oil Resource Play SASKATCHEWAN
Extended-reach horizontal well and multi-stage fracturing technologies have resulted in the birth of an entirely new oil and gas industry producing shale gas in Canada. The technology has also breathed new life into the moribund conventional oil industry, and is expected to slow the long decline in production that began in 1973 as a number of tight oil plays take off. The Bakken/Three Forks play in southeastern Saskatchewan is where the tight oil revolution began in western Canada. In the past five years, over 2,000 horizontal wells with multi-stage fracture completions have been drilled into the play, with production reaching over 65,000 barrels per day in 2011. “The Bakken pool is now the largest producing oilfield in western Canada,” Greg Tisdale, chief financial officer of Crescent Point Energy Corp., told a BMO Capital Markets conference in 2010. “With an estimated four [billion] or five billion barrels in place, the Bakken light oil resource play is the largest pool discovery in western Canada in the last 50 years.” Crescent Point is the most significant producer in the Bakken, with 32,000 barrels of oil equivalent per day of production and 930 net sections of land. The company has 3,800 drilling locations in inventory. But even with a decade of development drilling ahead, Crescent Point is piloting four waterflood tests in the hopes of capturing more resource. The first pilot began in 2001, and the results have been encouraging. Crescent Point estimates it will increase the recovery factor from the three-well pattern from 19 per cent to 30 per cent. The company drilled 13 injection wells in 2010 and plans for up to 40 injection wells by the end of 2011. Tisdale says Crescent Point expects the waterflood scheme will allow the company to increase recovery by around 307,000 barrels per well, and that this will transfer into increased economic value for the company. 40 // ENERGY EVOLUTION II
Emerging Duvernay Fm Shale Gas Resource Play
Viking Tight Oil Resource Play
Bakken Tight Oil Shaunovan Tight Oil Resource Play Emerging Exshaw Fm Resource Play Tight Oil Resource Play
“Three wells under primary production would be worth around $18 million,” he says. “Under waterflood, the value of those wells would be $24.6 million. PetroBakken Energy Ltd. is the second-largest producer. In reporting the company’s 2010 results in March, president and chief operating officer Gregg Smith said the company has plenty of development drilling ahead as well, with a focus on drilling long bilateral horizontal wells with more than 20 fracture intervals per well. PetroBakken has drilled 121 bilateral wells into the Bakken since 2009, and plans for another 75 bilaterals into the play in 2011. It has 900 potential targets in its Bakken inventory. PetroBakken is also advancing enhanced recovery plans, injecting gas rather than water to force more oil out of the rock. “We did a carbon dioxide injection on a well early in 2010,” said Smith. “We started a well in February, and injected carbon dioxide over two days. We wanted to use natural gas but it is more difficult to do, so we chose carbon dioxide for the test case. The offset wells adjacent to the injector more than doubled in production and 10 months after the injection they’re still producing 50 per cent higher than what they were producing before we did the injection, so we think continuous injection will have quite a positive impact on the play.” Smith said the next step is to further develop enhanced oil recovery (EOR) plans using natural gas. “Using natural gas should look like carbon dioxide without the corrosion issues,” he explained. “Natural gas is cheaper than carbon dioxide, and at the end of the day we will recover most of the gas back, so it ends up acting as a physical hedge and hopefully the price will be higher as well.” PetroBakken plans on spending $20 million on its EOR plans in 2011. With the Saskatchewan Bakken in the development stage, Crescent Point is now looking to expand its resource inventory further through targeting the Alberta Bakken play. The company has accumulated over
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ENERGY EVOLUTION II // 41
REGIONAL DEVELOPMENTS
one million acres of exploration land in southern Alberta targeting multiple zones, including the Bakken/Three Forks formations. Tisdale said to date the company has drilled one well into the play and has plans to drill 19 wells in 2011. “It’s early days, but we plan on applying what we learned in the Bakken and Lower Shaunavon to the play,” he said. Outside the Bakken, the Cardium in Alberta is the busiest of the new tight oil plays. There are between 10.5 billion and 12.5 billion barrels remaining in the Cardium play, and a number of companies believe the multi-stage fracturing revolution can be used to exploit some of that resource. Penn West Exploration (the operating entity of Penn West Petroleum Ltd.) is the most active player in the Cardium and the most active oil driller overall across western Canada. It has over 650,000 acres in the Cardium play and has identified over 2,500 drilling locations. The company is drilling monobore wells with horizontal legs averaging 1,000-1,400 metres. Each well has an average of 17 fracture stages. In March 2011, Penn West president and chief operating officer Murray Nunns reported to shareholders during the company’s yearend conference call that after spending 2010 appraising its various tight oil plays, the company is ready to start development in earnest this year. And its major target will be the Cardium. “We have the appraisal of significant areas of the play done and that has allowed us to prioritize our 2011 capital spending,” said Nunns. “The bulk of our efforts will be concentrated in the highproductivity areas of West Pembina and Willesden Green as well as some other selected areas along the play trend.” Nunns said Penn West has eight rigs currently working the Cardium and has drilled 16 wells so far this year. It plans to drill 80 or 90 wells into the play. Penn West’s current focus is on reducing the costs of drilling and completions in the Cardium. Pad drilling is being used as one means to reduce costs. Penn West estimates that by drilling four horizontals per pad it can reduce lease construction costs from $600,000 per well to $250,000. Drilling times are reduced from 18 days to 12 days, and rigmoving costs are reduced from $200,000 per well to $40,000. The company is also refining its fracturing fluids to improve reliability and optimize production. Nunns said they have been testing slickwater fracs and hydrocarbon based fluids side-by-side in well pairs. “The slick water fracs are not there yet,” he noted. “Right now things slightly favour hydrocarbons but that could shift in the next few months.” Penn West is also extremely active in another of the emerging tight oil plays, the Viking play near Dodsland, Sask. The Viking had four billion barrels of oil in place, with only around 12 per cent currently recovered. At Dodsland, Penn West drilled 52 out of the 121 wells industry drilled in the Viking play in 2010, reporting initial average production of 55 barrels of oil equivalent per day per well. The company is drilling monobore wells with 660-metre horizontal legs, and using 18 fracture stages per well. Fracture sizes are 12 tonnes, compared to 20 tonnes in the Cardium. Total well costs in the Viking are $1.18 million, and Penn West would like to see that drop to $1.05 million in the upcoming year. “We are currently appraising the Viking to the north and west, and now west into central Alberta,” said Nunns. “It provides solid returns and significant running room for Penn West.” ■
REGIONAL DEVELOPMENTS
Quebec/Utica shale
growing pains
QUEBEC UNCONVENTIONAL GAS RESOURCE PLAY
CANADA
IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC) SHALE GAS
Logan’s Line
TIGHT GAS LIGHT TIGHT OIL (LTO)
Quebec
Shallow Utica Fm Potential
Quebec shale gas drilling results promising, but political worries threaten development By Darrell Stonehouse
Edge of Structured Play Region Core of Industry Activity Montreal
Areas of Exploration Activity
Yamaska Fault
UNITED STATES OF AMERICA
The good news is that there appears to be a massive gas resource in the Utica shale underlying the Quebec Lowlands that can be economically accessed using horizontal drilling and multi-stage fracturing technologies. The bad news? Public concern about the environmental impacts of fracturing on groundwater have led to a political firestorm in the province and a halt to shale gas exploration and development until studies can be completed on the potential associated environmental effects. The studies are expected to take up to 30 months, slowing momentum in what was one of the hottest exploration plays underway in Canada. By year-end 2010, industry had drilled 29 wells in the Utica play, with 18 wells receiving fracture treatments. Early results are encouraging. Talisman Energy Inc., which has drilled 10 wells in the play along with partner Questerre Energy Corporation, reported average production from vertical wells of 600,000 cubic feet per day, and production from its first horizontal well drilled in 2010 came on stream at around 10 million cubic feet per day and averaged 5.3 million cubic feet over its first 30 days. Two other horizontals are still under evaluation. Forest Oil Corporation and partner Junex Inc. have also reported strong results with two early vertical wells delivering around one million cubic feet per day of initial production. Early estimates put the original gas in place in the Utica shale as high as 116 billion cubic feet per section. Overall, there could be as much as 60 trillion cubic feet of potential recoverable shale gas in Quebec. In 2009, the Quebec Oil and Gas Association (QOGA) hired consulting firm SECOR Group to look at the economic benefits shale gas development could bring to the province. SECOR found if development of 42 // ENERGY EVOLUTION II
shale gas goes ahead, baseline studies indicate $1 billion to $3 billion in capital investment per year over the next 15 years. SECOR examined two scenarios, involving multi-well pad drilling of 150 wells per year and 600 wells per year, with six wells drilled from each pad. The study calculated the creation of 5,000-19,000 jobs per year. The study also predicted government revenue would be $1.4 billion to $5.4 billion per year, depending on the number of wells drilled. Public worries about air pollution and groundwater contamination, however, have put the potential economic windfall at risk. Pressure has been building against shale gas exploration since it began in earnest in 2008. In late 2010, Talisman and Questerre announced they were delaying further fieldwork until a government-led hearing was completed on the impacts of development. In March, the results of the hearing were released, calling for restricted hydraulic fracturing activity until its effects could be better understood. Industry now waits for the results of planned studies. QOGA president and former Quebec premier Lucien Bouchard told a press conference following the announcement that the conflict over shale gas development is because the industry failed to do due diligence in explaining itself to the public. Bouchard said a lack of expertise in the province that has caused a number of wells to leak is also to blame for the problem. “We all forgot that there is absolutely no culture, no experience of gas and oil development in Quebec—that we were starting afresh,” he explained. “We all forgot that it was something new. It was a shock in Quebec because of that.” Also speaking at the press conference was Jim Fraser, vicepresident of North American shale gas operations for Talisman Energy Inc. Fraser said that going forward, the industry needs to do
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ENERGY EVOLUTION II // 43
REGIONAL DEVELOPMENTS
a better job explaining the process involved in drilling and completing shale gas wells to get the public on board with development. “We need to educate the people of Quebec to those practices to earn their trust,” said Fraser. Fraser said the decision to limit hydraulic fracturing could have an impact on his company’s operations this year, but it’s too soon to say what that impact would be. Bouchard said the Quebec industry would back the government study on shale gas and help in any way it can to make it run smoothly. “The government has our support to quickly put in place the measures required to conduct a thorough study and promote an informed debate regarding the collective decisions to be made,” he said. “Association members wish to make it clear that they will take an active role. Together with all Quebecers, they believe that development of gas resources is not possible unless it serves the public interest.” During the study’s duration, some exploration drilling may continue to help provide the technical information needed. Bouchard said the information gleaned should also help in advancing the economic case for furthering shale gas development. “The economic value of gas resources is not yet proven, and the only way to know if Quebec has viable gas resources is through field testing,” he noted. Other petroleum industry associations, including the Canadian Energy Pipeline Association (CEPA), the Canadian Gas Association, the Canadian Natural Gas Vehicle Alliance, the Canadian Association of Petroleum Producers, and the Canadian Society for Unconventional Gas, have launched a public relations campaign to encourage Canada, both federally and provincially, to make natural gas, including shale gas, an integral part of the energy mix. “We are confident, based on experience in other jurisdictions, that shale gas can be developed safely in Quebec,” CEPA president Brenda Kenny said in describing the effort, called the Canadian Natural Gas Initiative. While the Quebec environment department studies shale gas exploration, its finance department is continuing to move forward in laying the fiscal groundwork for the industry. In its 2011-12 budget, the government laid out its plans for its future royalty structure in a new report. “Our action is focused on shale gas. It is now reasonable to believe that Quebec’s subsoil holds substantial shale gas potential,” said Finance Minister Raymond Bachand in announcing Quebec’s royalty plans. The report states that the new royalty regime will come into effect once the strategic environmental assessment has been completed and the legal and regulatory framework has been adapted to its conclusions. This regime includes a commodity price and productivity component and varies between five and 35 per cent. The intention of the new system is for total government take, including corporate taxes, to be 50 per cent in mature development as compared to their estimate of 33 per cent under the current system. It has been modelled on the royalty regimes in Alberta and British Columbia for conventional production. In recognition that the Utica shale is not yet mature, the minister also announced the introduction of a Gas Development Program modelled on the Net Profit Royalty Program that is used in northeastern British Columbia. The progressive royalty rate starts at two per cent and varies through a four-tiered scale based on the recovery of capital invested and returns achieved. ■
REGIONAL DEVELOPMENTS
Maritimes basin
inching ahead
MARITIMES UNCONVENTIONAL GAS AND OIL RESOURCE PLAYS IDENTIFIED RESOURCE PLAY TARGETS NATURAL GAS FROM COAL (NGC)
Early-stage exploration success creates cautious
SHALE GAS TIGHT GAS LIGHT TIGHT OIL (LTO)
optimism about emerging New Brunswick and Nova Scotia shale plays By Darrell Stonehouse
Last January, New Brunswick was buzzing with news of a massive shale gas discovery. Halifax-based Corridor Resources Inc. reported that its partner Apache Corporation had completed segregated testing of two intervals in the Frederick Brook formation that had been fractured with propane at the vertical Green Road G-41 well, located approximately four kilometres north of the village of Elgin in southern New Brunswick. The first test interval was flowing natural gas at a stabilized rate of 430,000 cubic feet per day. The second test interval flowed at a peak rate of 11.7 million cubic feet per day and a final stabilized rate of three million cubic feet per day. With an estimated 67 trillion cubic feet in place, it looked like the province’s shale gas industry was on its way. But a year later, things don’t look quite so clear. In December, Corridor announced Apache Canada Ltd. had completed two follow-up horizontal wells. Strong gas shows were encountered in the horizontal section of both wells during drilling. Five slickwater fracture stimulations were completed in each of the wells, including one frac completed in the highly productive zone of the G-41 well. Unfortunately, after the plugs were drilled out in both horizontal wells, negligible gas flows were reported. Corridor said “The preliminary performance of these wells is both unexpected and perplexing,” but cautioned that “it is important to recognize that the evaluation 44 // ENERGY EVOLUTION II
Maritimes Basin Exploratory Acreage Held by SWN Canada Ltd McCully Field
Stoney Creek Field
Sydney Basin
Montney Trend
of the development potential of the Elgin shale gas resource play is in its early stages.” One step forward, two steps back. Nova Scotia’s early-stage shale gas exploration play has experienced a similar up and down start. In 2007, Triangle Petroleum Corporation subsidiary Elmworth Energy Corporation and its partners drilled two vertical wells in the Windsor Block to test the Horton shale. Both test wells proved successful in showing the resource potential of the play. Based on an estimated resource of 89 billion to 109 billion cubic feet per section from Schlumberger Limited’s log analysis, the company reported the project had the gas in place to drive the company’s exploration program. That same year Triangle reported that Ryder Scott Company, L.P., its independent reserves-evaluation engineering firm, estimated the resource potential for the Horton Bluff Shale to be 69 trillion cubic feet of original gas in place. “The identification of 69 trillion cubic feet of resource potential by Ryder Scott is a major step in our development of the Horton Bluff Shale resource in Nova Scotia,” Triangle president Howard Anderson said. “Although this resource assessment only covers 40 per cent of Triangle’s land block that is delineated by seismic, this is an extraordinarily large accumulation of natural gas in close proximity to a premium market.”
REGIONAL DEVELOPMENTS
In 2009, Elmworth signed a production lease covering 10 years for its Nova Scotia shale play. Since then, however, activity in the area has stalled with the crash in gas prices resulting in Triangle focusing on the Bakken light tight oil play in western Canada. Despite the setbacks, exploration in East Coast shale plays is expected to continue in the years ahead. Corridor already has tight gas production at its McCully field in New Brunswick. The field contains 138 billion cubic feet of proved-plusprobable reserves and produces 18 million cubic feet per day from 30 wells in the Hiram Brook tight gas sand reservoir. The Frederick Brook shale play directly underlies the Hiram Brook tight gas sands. In December 2009, Corridor signed the partnership deal with Apache to explore the Frederick Brook. The first part of the joint venture, completed late last year, called for Apache to spend $25 million to drill at least two 1,000-metre-long horizontal wells and use multi-stage hydraulic fracturing technology to complete the wells. This work included the successful G-41 well and the two follow-up wells. Apache now has until June to decide whether it wants to spend another $100 million over the next two years to earn a 50 per cent interest in 116,000 gross acres of Corridor-controlled lands in southern New Brunswick. If it decides to move forward, Apache would drill and test six to eight more wells in three or four areas within the play by March 31, 2013. “Though plans are not certain, Phase 2 would probably consist of three pairs of horizontal wells in three different locations,” says the company. “Each pair would be one tight gas siltstone well and one shale gas well. We anticipate these horizontal wells would be at depths greater than 2,000 metres, have approximately 2,000 metres of horizontal length and we would use 10 to 20 fracture stages per well.” Full-scale development in New Brunswick would likely mean drilling of one to two pads a year for up to 30 years. Each well pad would have eight to 16 horizontals. Water for the massive slickwater fracs would likely come from the Atlantic Ocean. Apache isn’t the only large U.S.-based independent targeting Maritime shale deposits. Unconventional gas specialist Southwestern Energy Company, which is focused on the Fayetteville shale play in Arkansas and the Marcellus play in the northeastern United States, has licences totalling 2.52 million acres in New Brunswick. The company spent around $11 million in 2010 completing an airborne magnetic and gradiometer survey and plans on spending another $14 million this year doing core sampling, shooting between 1,000 and 1,300 kilometres of 2-D seismic and other early exploration work before spudding its first well in 2012. Southwestern Energy’s land is north of the Corridor acreage, in an area that’s essentially unexplored. It plans on testing both the tight sandstones currently being produced by Corridor, along with the Frederick Brook shale. Junior producer Contact Exploration Inc. currently has light tight oil production in the Stoney Creek field in New Brunswick. In 2010, the company drilled two horizontal wells with multi-stage fractures with one well initially producing 135 barrels a day and the other 60 barrels a day. Contact Exploration plans three to five additional wells this year, and a total of between 12 and 15 wells in the future. The company also has an estimated 11 trillion cubic feet of shale gas resource in place on its New Brunswick lands. Going forward, Contact Exploration says it may drill vertical wells to test the play, or find a joint-venture partner. ■
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ENERGY EVOLUTION II // 45
MARKET DEVELOPMENTS
Gas to gold
Talisman Energy is pinning its shale gas market strategy on proven gas-to-liquids technology By Peter McKenzie-Brown
It’s hard to match Colin Soares’ bragging rights. The Calgary-based engineer was president of the company that demonstrated the shale gas potential of the Montney formation. The way he tells the story, “from some work we’d done [with Home Oil subsidiary Scurry Rainbow Oil Ltd.] in the late 1980s, we originally thought it was the source rock. A number of us believed that the Montney formation contained an abundance of hydrocarbons to deliver, and we set out to prove it up.” He led the formation of a private company, Rocor Resources Inc., with initial funding of $2 million, although during the company’s brief life it raised an additional $15 million. “Our mandate was to prove this idea, then to hand over the keys to a company with deep pockets, as it takes an awful lot of capital to develop these plays with horizontal wells. To do a job like this and become a producing company you would probably need $50 million to $100 million.” Rocor demonstrated the existence of wet shale gas with vertical wells only. “As we were drilling, we had a lot of condensate coming in and killing the well.” The company’s thinking was strategic in several ways. “We bought 14 sections of land between two rivers,” says Soares. “Whoever owned that land could control things when they started 46 // ENERGY EVOLUTION II
planning facilities. When word got out about what we’d done, land prices all around us really started to go up—like in any real estate boom. We were the first in the area drilling for this resource, but obviously people with deeper pockets soon overtook us.” In October 2008, Rocor sold out for $50 million to Petrobank Energy and Resources Ltd., which promptly drilled a horizontal well that produced 8.5 million cubic feet of gas plus 350 barrels of condensate per day—“tremendous results,” according to Soares.
What to do with shaley plays At least part of the significance of Rocor’s efforts was that it illustrated the tie between tight gas and shale gas. According to Dave Russum, AJM Petroleum Consultants’s geoscience vice-president, the Montney is a case study in a kind of “hybrid” natural gas resource—a hydrocarbon formation halfway between gas from tight sands (the prospect Scurry Rainbow had originally been investigating) and shale gas pure and simple. In fact, according to Russum, these prospects are best described as “shaley plays.” They contain shale and sand in relatively larger and smaller percentages, but
THE UNCONVENTIONAL “BIG THREE”
LOW-PERMEABILITY SAND
ALBERTA/BC MONTNEY/DOIG G DE RAIN CR S EA IZE SIN G
TEXAS BARNETT
TIGHT GAS
BC HORN RIVER BASIN
SHALE QUARTZ OR CLAY RICH?
SHALEY SAND
COALY SAND
SILT
SHALEY SILTY PLAYS
SHALE
SHALE GAS
COALY SILT
SILTY COAL
INTERBEDDED OR MIXED ORGANIC SHALE
TO L ED IA RB TER SO A AD M S NIC GA RGA O
Certain shale gas plays in Canada, like the Montney in British Columbia, are actually hybrid plays that share characteristics of true shale plays and tight sand gas plays of the kind that proliferate in the Deep Basin.
MARKET DEVELOPMENTS
Tight sand, shale and coal reservoirs
SHALEY COAL
LOW
C.B.M.
HIGH
COAL
ORGANIC CONTENT Illustration: AJM Petroleum Consultants
whether they are more like tight sand or shale gas they require fracking to yield economic production. In a real sense, the shaley gas plays are an extension of Canadian Hunter Exploration Ltd.’s Deep Basin tight gas developments of the 1970s. Montney occupies one end of the shaley gas spectrum, and partly includes old-fashioned tight gas. Horn River, which taps the Muskwa shales in a basin just south of the Northwest Territories and just west of Alberta, is a picture-perfect shale gas play. According to Russum, it may prove to be the biggest shale gas play in North America. Of course, in an environment of rapidly expanding gas supply, the key issue is what to do with the stuff. In recent months, Talisman Energy Inc. has placed two major bets on the use of gas-to-liquid (GTL) technology, which transforms natural gas into a combination of high-quality liquid fuels and petrochemical feedstock.
Gas-to-liquids This effort began last December, when Talisman announced a billion- dollar joint venture on its Farrell Creek property in the Montney play in northeastern British Columbia. In March, the company announced
a similar deal with respect to its Montney-area Cypress A properties. Talisman’s partner in both ventures is petrochemical giant Sasol Limited, which honed its expertise in turning coal and natural gas into liquid fuels during an international oil boycott imposed upon South Africa during apartheid. The company’s two South African coal-to-liquids facilities represent the largest and most profitable assets in Sasol’s portfolio. On behalf of the partnership, the Calgary-based company will operate the Cypress A and Farrell Creek projects as integrated development projects. Sasol and Talisman are investigating the economics of building North America’s first gas-to-liquids plant. In cautious news release language, the companies agreed to undertake feasibility studies “to examine a world-scale gas-to-liquids [GTL] facility in western Canada, with Talisman having the option to participate as a 50 per cent partner in the facility. This could provide a strategic alternative to traditional North American pipeline or LNG [liquefied natural gas] markets. The GTL process produces premium, clean liquids fuel. Sasol is leading this study with a front-end engineering design decision likely in the second half of next year.” › ENERGY EVOLUTION II // 47
MARKET DEVELOPMENTS
Put another way, a decision on whether to proceed with an engineering design for the Canadian project is expected in 2012. The Talisman/Sasol plant would turn western Canadian gas into value-added liquid fuels and petrochemical feedstocks. Converting natural gas into liquid fuels is particularly attractive now, given the prospect of an extended period of low natural gas prices in a high oil price environment. This solution could create diesel and other fuels that are used in automotive transport. GTL, which will become increasingly significant as crude oil resources are depleted, is operational already in a number of Sasol plants around the world. In addition, supermajor Royal Dutch Shell produces diesel from natural gas in a factory in Malaysia. When finished, its Pearl GTL plant in Qatar will be the world’s largest GTL facility. Until recently, GTL only made sense in gas-producing regions that could not build pipelines to major markets. The reason it has suddenly become economical in western Canada, of course, is that despite ample pipeline capacity to North American markets, British Columbia’s shaley gas projects have created huge supply surpluses at the end of one of the world’s longest gas pipeline systems. In a corporate statement, Talisman president and chief executive officer, John Manzoni, put it like this: “This transaction allows Talisman and Sasol to unlock additional value in the world-class Montney shale play and potentially accelerate development of the resources in the area. The Cypress A assets are very similar to Farrell Creek and, with our partner, we will now build an integrated long-term development plan for the area.”
Sasol chief executive Pat Davies added that “this additional acquisition of another high-quality natural gas asset will accelerate our upstream growth while also potentially advancing Sasol’s already strong GTL value proposition utilizing our proprietary technology.” That pretty much sums it up.
Nature’s gift to the world In a presentation a year ago, the chairman and chief executive officer of ConocoPhillips, James Mulva, called natural gas “nature’s gift to the world.” Taking a shot at the unbendable greens—he called them “hydrocarbon deniers”—Mulva complained that “they support renewables at any cost and oppose hydrocarbons at any consequence…. They seem not to realize that platitudes are not BTUs.” Citing the environmental advantages of gas, he argued that industry and government should ensure that the world’s gas supplies are used to their full potential. If they do, he argued, by 2050 natural gas will have potentially helped meet four great energy challenges: achieving U.S. and world energy supply security; providing consumers with affordable energy; driving economic prosperity and job creation; and reducing greenhouse gas emissions. He argued that vast conventional and unconventional gas resources—more than 38,000 trillion cubic feet globally, by some estimates—will ensure stable supplies and reduce the risk of long-term price volatility. Within that context, much needs to be done to develop supplies and to develop markets for natural gas. Surely GTL will play an increasingly important role in exploiting nature’s gift. ■
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48 // ENERGY EVOLUTION II
MARKET DEVELOPMENTS
Where to go?
Some say transportation should be a market grail for natural gas, while others aren’t so sure By Peter McKenzie-Brown
In his best-selling 1958 book The Affluent Society, Canadian-born economist John Kenneth Galbraith popularized the concept of conventional wisdom. “It will be convenient to have a name for the ideas which are esteemed at any time for their acceptability, and it should be a term that emphasizes this predictability,” he wrote. “I shall refer to these ideas henceforth as the conventional wisdom.” The problem with conventional wisdom is that it isn’t always true. Contrarians are often right.
Price bull It’s worth keeping that truism in mind as we develop the case for building new natural gas markets in North America. In a recent comment, author and analyst Peter Tertzakian argued that the rapid decline in drilling for natural gas across North America raises the question of whether natural gas is likely to continue to be in a serious state of oversupply. Tertzakian notes that for the first time in 15 years, half of the United States’ drilling fleet is drilling for oil, compared to less than 20 per cent of the rigs for the last decade. Such a dramatic decline in drilling almost certainly suggests that production levels will decline, he suggests. He then moves on to the killer argument: “Let’s say [gas] production starts retreating in earnest this year and natural gas prices rise back to some fictional level like $6 per thousand cubic feet. Notionally, the [conventional] wisdom goes that producers will dispatch more rigs to ramp up production and thus clobber prices again. There is a problem with this line of thinking: why would producers do that when more money is to be made elsewhere?” He suggests that as long as oil is valued at more than four times the value of gas (on an energy-equivalency basis), there is little motivation for the industry to shift toward more gas drilling. The result? Declining supply and still higher gas prices until a cost-reward rebalance restores aggressive natural gas drilling.
Supply bull Since Tertzakian is such an unusual voice in the wilderness, the balance of this article assumes that the conventional wisdom is true. Gas supplies are likely to continue to be plentiful, and there will continue to be a need to develop new markets. One of the most interesting advocates of greater markets is the legendary oilman T. Boone Pickens, who says he has invested $70 million in developing and promoting the Pickens Plan.
Now an 83-year-old geologist who received his degree in geology in 1951, as a young man, the Texas-born Pickens spent a decade in Calgary. In a broadcast interview, he said he opened an office in Calgary in 1959 and lived in the province with his family in the 1960s. After moving back to the United States, he made a multi- billion dollar fortune in exploration and development and, much more publicly, as a corporate raider. His current passion is promoting the Pickens Plan. “For 40 years, the United States has had no energy plan,” he explained in a recent radio interview. “We’ve just been drifting. Just drifting means you are just importing more oil from the Middle East, countries that the state department recommends we not visit.” Pickens is adamant that the United States should reduce its dependency on overseas oil, and he believes that renewables like wind and solar energy aren’t viable anymore because of cheap gas. “Natural gas is the only thing we have that can replace non– North American foreign oil. We import five million barrels from the Mideast. That’s the oil I want to replace with gas. If you had eight million 18-wheelers [in the U.S. trucking fleet fuelled with natural gas], that would cut OPEC [Organization of the Petroleum Exporting Countries] imports in half.” He added, “If the U.S. administration announced that from now on all new government vehicles would use domestic fuel, that would be a powerful message to send to the world. “This is a security issue for me. I don’t want to be dependent on the enemy for energy,” he said. Until gas prices cratered, Pickens was a strong advocate of wind energy, and he was leading an effort to finance a multi-billion dollar wind farm in the Texas Panhandle. He uses this fact to support his green credentials. “Natural gas is 30 per cent cleaner than diesel. We have the cleaner, cheaper, abundant fuel here, and it will replace the dirty fuel from the Mideast.” Pickens is also an advocate of continental fuel switching—in particular, substituting natural gas for coal in power generation facilities. › ENERGY EVOLUTION II // 49
MARKET DEVELOPMENTS
For many years, most commentators have believed that the United States could never become self-sufficient in energy, Pickens said, but “things have changed. We have so much natural gas— the U.S. has a 100-year supply, and the Canadians have a lot up in Horn River, for example, and the Canadians have a lot of oilsands [oil]. Let’s use that to make North America energy self-sufficient.” He added, “When people say to me, ‘Hey, Pickens, I don’t like your plan!’ I say, ‘Fine, what’s your plan? If you don’t have a plan, your plan is to import more oil from the Middle East.’” Not many oilmen are as colourful as T. Boone Pickens or as motivated by worries about enemies in the Middle East. However, there are a lot of other natural gas supply bulls. ExxonMobil Corporation, for example, demonstrated its belief by plunking down US$31 billion for gas-focused XTO Energy Inc. a year and a half ago. Company vice-president, William Colton, recently told The New York Times that “if there is any kind of major trend, we think it’s going to be a shift toward more natural gas.” He added that “Natural gas is available. It’s the most efficient way to generate massive power. It’s affordable. We already have gas infrastructure in place. From a CO2 emissions standpoint, it’s 60 per cent cleaner than coal, and [the United States has] 100 years of supply.”
Agency bull The U.S. Energy Information Administration (EIA), whose job it is to forecast supply and demand based on best-guess current trends, doesn’t appear to see much of a plan to promote greater use of natural gas anywhere in the future. According to the early bird version of its
2011 forecast, “non-hydro renewables and natural gas are the fastestgrowing fuels used to generate electricity, but coal remains the dominant energy source for electricity generation because of continued reliance on existing coal-fired plants” well into the foreseeable future. According to the EIA, the agency has revised its methodology for gas prices “to better reflect a lessening of the influence of oil prices on natural gas prices, in part because of the increase in shale gas supply and improvements in natural gas extraction technologies.” Of course, as Peter Tertzakian argues, it might be a mug’s game to discount energy equivalency too deeply when you are calculating the relative values of oil and gas. Whatever methodology the organization uses, the EIA does forecast an increase in North America’s natural gas demand, but its estimates seem paltry compared to the aggressive development that Pickens, for example, is promoting. The agency forecasts a strong near-term increasing demand because of a “strong recovery in near-term industrial production, growth in combined heat and power, and relatively low natural gas prices.” Look farther out into the future, however, and the agency’s forecasters are more circumspect than the gas supply bulls. “U.S. natural gas consumption rises 16 per cent from 22.7 trillion cubic feet in 2009,” the agency intones, “to 26.5 trillion cubic feet in 2035.” Such a small increase in forecast demand—16 per cent over 25 years—suggests that the EIA’s gas supply bulls aren’t as optimistic as Pickens; he might complain that they “don’t have a plan.” You could equally argue that there are contrarians among them. ■
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MARKET DEVELOPMENTS
A sustainable future Effectively marketing Canada’s vast unconventional gas resources can help ensure global sustainability
By Peter McKenzie-Brown
Illustration: KitimatLNG
Photo: Westport Power/Canadian Natural Gas Vehicle Alliance
Refuelling a transport truck fuelled by liquefied natural gas.
The Kitimat LNG project, shown here in an artist’s rendering, is considered a key outlet to Asian markets for Canadian shale gas production.
If you want to understand how important unconventional gas has become, consider a couple of facts from Encana Corporation—one of North America’s premier gas-producing companies. According to company spokesman Alan Boras, in 2010 “we replaced 250 per cent of our production. We [now] have 14.3 [trillion cubic feet] 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 per cent.” 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 coalbed 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 market opportunities. The first is the development of liquefied natural gas (LNG) capacity. The second is to use the fuel as a cheap input for oilsands development. The third is to go into shaley formations in the quest for natural gas liquids (NGL) 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. Robin Mann, chairman and chief executive officer of AJM Petroleum Consultants, puts the issues in a complex question. “Because of the development of shale gas formations like [British Columbia’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 B.C.?” 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 Group, 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 to develop overseas exports now, however. In fact, three big and successful companies—Apache › ENERGY EVOLUTION II // 51
Illustration: KitimatLNG
MARKET DEVELOPMENTS
development more impor tant now than ever.” She adds that “shale gas is basically a technology play. The industry has found ways to get at gas that we knew was there before, but couldn’t develop. And the better companies are finding ways to produce 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 Asian markets are logical targets for natural gas from western Canada.
Corporation, EOG Resources Inc. 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. “Worldwide, LNG is maybe 10 per cent of supply. There’s plenty of room to grow it.” According to Kitimat LNG Inc.’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
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 been well known for several years as a wannabe oilsands producer. Through a series of summertime raids at Alberta land sales, in 2006-07 the company became the single biggest landowner in the oilsands sector—a position it held until Suncor Energy Inc. gobbled up Petro-Canada Limited a few years back. But oilsands development is a long-term proposal, and after farming out some of its land to PetroChina Company Limited, the company had cash in the bank but no cash flow in prospect until its first in situ project comes to life next year.
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52 // ENERGY EVOLUTION II
whatIf? With the help of an Ottawa-based thinktank called whatIf? Technologies Inc., Alberta’s former assistant deputy minister 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 636 trillion cubic feet to an optimistic case of about 1,400 trillion cubic feet. 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,” Taylor says. “For that reason I recommend joint government- industry efforts.” For political reasons and because of local worries, he adds, it “may not be recoverable in places like eastern Quebec and offshore British Columbia.” 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 nine-billion sustainable lifestyles by 2050.” ■
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ENERGY EVOLUTION II // 53
MARKET DEVELOPMENTS
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 oilsands development,” says president and chief executive officer Sveinung Svarte. “This area offers the potential for a very short pay-back time and we plan to re-invest 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 liquid-rich natural gas is 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, diversification 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.”
ENVIRONMENT
A smaller footprint Unconventional resource producers are taking a lead role in improving environmental performance By Jim Bentein
A funny thing happened on the way to decades-low natural gas prices: as producers, those in the service sector and other industries turned to “resource plays” to produce unconventional gas, the environmental impact of gas development shrunk to a shadow of its former self.
Illustration: © iStock.con/ Dave Stevens
“Low natural gas prices don’t present a pretty picture for smaller companies involved in conventional natural gas production in the Western Canadian Sedimentary Basin,” says Mike Dawson, president of the Calgary-based Canadian Society for Unconventional Gas (CSUG). “But the bigger companies can operate within this low-price environment because they have the capital and cash flow to enter the shale gas and tight gas plays. They recognize that, with these unconventional plays, operations are under intense scrutiny and only exemplary environmental performance will sustain their social licence to operate.” Adopting practices that minimize the impact of their operations on the environment, on landowners and other stakeholders is a necessary part of doing business, he says. 54 // ENERGY EVOLUTION II
ENVIRONMENT
Dawson sees natural gas prices remaining low for at least a couple of years, if not longer. “There are companies that are competitive at today’s prices,” he says. “They use a manufacturing-type approach and they have thousands of locations to develop.” The low-price world will likely exist for many years, thanks to the huge new finds of shale gas and tight gas in North America, he says. The longer-term solution to the price squeeze is to increase gas demand, but Dawson isn’t optimistic about that occurring anytime soon. “Natural gas use for compressed natural gas to fuel the transportation and power plants might be the salvation of the industry,” but he says that won’t happen quickly, because there is a lack of natural gas transportation infrastructure in Canada and the United States. Natural Resources Canada released a report in mid-January titled Natural Gas Use in the Canadian Transportation Sector: Deployment Roadmap, in which the federal department said wider use of gas, particularly by Canada’s trucking fleet and other commercial vehicles, could reduce greenhouse gas emissions from those sources by 25 per cent and reduce their fuel costs by as much as 30 per cent. Gas will also eventually gain more market share in the electricity sector, where it is used as a fuel source for power plants, Dawson says.
It burns about 50 per cent cleaner than coal, and is responsible for about half of the power production in the United States and about 15 per cent in Canada. But it will take many years until it starts to replace phased-out coal-fired power plants in the United States, where gas now is used for about 21.5 per cent of that country’s power, and in Canada, where it charges about 15 per cent of the country’s electricity plants. Gas producers have “shifted to what industry giant Encana [Corporation] calls resource plays,” says Dawson, which allow larger producers to operate in a low-price world. They have moved to shale gas plays like Horn River and tight gas plays in the Rockies. The same change has taken place in the oil sector, where producers have moved to the oilsands and shale oil plays. In both cases, it’s the larger firms that dominate—and those larger firms are able to manage operations so that costs are contained and the environmental footprint is minimized. In the gas sector, this is done through the use of pad drilling and multilateral horizontal wells (with a similar approach taken in the oil shale). The resource can be recovered from four or five sections of land utilizing only one pad. › ENERGY EVOLUTION II // 55
ENVIRONMENT
Illustration: Encana Corp.
This illustration shows an example of a shale gas development with several well pad sites. Each well pad has six producing wells. Multiple horizontal wells per pad limit footprint and impact on the surface.
This “manufacturing approach” taken by unconventional gas producers also allows for better planning of roads, pipelines and other infrastructure, limiting the total footprint of their operations. “It means the surface disturbance will be smaller overall,” says Dawson. “Instead of myriad roads, pipelines and electrical infrastructure crossing the surface, the facilities are more concentrated.” These economies of scale are even extended beyond one operator. “Operators may find there are more synergies, where, perhaps, two operators might drill from a common pad,” says the CSUG head. “There are opportunities to pool resources, although this type of opportunity would not come without a spectrum of liability issues, including equipment, production, environmental and personnel considerations.” And Dawson says concerns about the environmental impact of hydraulic fracturing, the technology used extensively to unlock shale gas reserves, are simply not based on fact. Critics, particularly in the United States, claim the technology threatens to contaminate groundwater sources. “We need to be very clear about the groundwater issue,” he says. “It [concerns about groundwater contamination] is not an issue of hydraulic fracturing, but, instead, of well construction. Protection of potable groundwater sources is a priority for everyone, including industry. Proper wellbore construction will ensure isolation and protection of “fresh” water aquifers. We’ve been using hydraulic fracturing practices for many years without any impact on groundwater. We have the technology.” The potential synergies the CSUG head refers to are well illustrated by development in the Horn River Basin of British Columbia, a huge source of unconventional gas in Canada. But with opportunity comes challenge—a challenge the industry has responded to. Encana and Apache Corporation’s Horn River development produces 75 million cubic feet of gas equivalent per day, with plans to 56 // ENERGY EVOLUTION II
reach average net production of 110 million cubic feet per day by year end. The development of the play in this manner makes this partnership a poster child for the companies’ smaller footprint manufacturing approach. Mark Taylor, Encana’s team leader for Horn River development, says the company is taking lessons learned from its Cutbank, Montney, Cadomin, Doig and Horn River resource plays in Canada, Haynesville in the United States, and others continent-wide and applying them to each of the developments. “The footprint differs at our different resource plays,” says Taylor. “We’ve talked about the gas factory approach or the hub approach. The knowledge flows to our CBM [coalbed methane] and conventional projects, too. It’s all about using a repetitive process. When you multiply it across thousands of wells, it takes costs out.” The company can’t deploy the long horizontal wells it does in Horn River in its CBM plays, of course, but it can use the same basic approach of drilling multiple wells from one pad. (It can drill up to four wells.) Encana belongs to the Horn River Basin Producers Group, an organization representing the 10 developers in the play, who share information on a regular basis. “We know we’ll never know everything, so a lot of knowledgesharing goes on,” says Taylor. The company, North America’s largest gas producer, strives for continuous improvement and to always find ways of cutting costs, says spokesman Alan Boras, “because the low-cost producer wins.” At Horn River, the company “draws from a huge reservoir” from a single pad, with 14-16 wells, says Taylor. “For every acre on the surface, we access 160 acres of the lease.” That isn’t possible in some resource plays (in the mountainous terrain of Colorado, for instance), but the same principles apply. “The overall philosophy is to minimize the environmental footprint,” says Taylor. “When you do that, you have cost-savings in capital and equipment. The two [reducing the environmental
ENVIRONMENT
footprint and reducing costs] are not mutually exclusive. You can do both at the same time.” Because up to 16 wells can be drilled from a single pad, there are also improvements in safety. “We’ll spend 12 months in one location, so, aside from the capital efficiencies of that, you’re not hauling equipment on roads and rigging up, so it improves the overall safety of the industry,” he says. Cost savings have been ongoing. “We thought we were cutting edge in 2009, when we were drilling four wells from a single pad,” Taylor says. “Now we’re drilling 16 from a single pad. We spend less on fracs and have cut our costs by 50 per cent.” While he doubts further cost savings will be “of that order of magnitude,” Taylor thinks annual savings of five to 15 per cent are possible. The Encana manager, who has been with the company since 1986, says he and his staff are eager to work on resource plays like Horn River. “It’s exciting. People want to work on resource plays.” About 90 per cent of the company’s gas production, which hit 1.4 billion cubic feet daily in 2010, up from 1.32 billion cubic feet a day in 2009, came from resource plays. The centralized planning approach led to an investment that substantially reduces water consumption at Horn River. The Debolt water plant, which taps brackish water for fracking operations, has cut the use of fresh water there by 95 per cent. “Two years ago, we were using 100 per cent fresh water,” he says. That not only cuts water use at the project, but also reduces the company’s water costs. These and other environmental improvements will continue to be made because of the company’s approach to resource play development, he says. Encana executives say it is developing what Jeff Wojahn, executive vice-president and president, USA division, recently called “long-term strategic partnerships” with its service providers, something that also helps it reduce costs, advances its continuous improvement agenda and limits the environmental footprint of its operations. The industry’s growing concentration on its environmental and social performance is vital, according to the industry body the Canadian Association of Petroleum Producers (CAPP). David Collyer, head of CAPP, warned gas producers last November that they face the same scrutiny as oilsands producers. “Fundamentally, the concerns of those that oppose oilsands development are linked to local and regional impacts—the land impact, the water impact, for example. This is equally true for natural gas,” he said. ”They are linked to climate change and they are linked to the offhydrocarbon agenda. It’s as relevant, I think, to natural gas as it is to other parts of the oil and gas sector. We need, therefore, to respond to that as an industry, as a province and I think, frankly, as a country, in terms of making sure our perspective on those issues is well-represented.” He went on to say that those who believe that “if we fixed oilsands mining,” the opposition to hydrocarbon development “would just go away” are misguided, arguing that that opposition is fundamentally directed at the whole industry. “We have to perform as an industry,” he said. “We have to continue to raise the bar on performance and we have to communicate better…and I think that applies to the natural gas industry as it does to the oilsands business.” ■
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ENERGY EVOLUTION II // 57
ENVIRONMENT
Testing the
WATERS
Massive exploitation of North American shale gas formations puts aquifer protection and water efficiency in the spotlight By Graham Chandler
It’s no surprise that the biggest corporate mergers and acquisitions in the oil and gas industry IN the past three years have involved unconventional gas resources, especially shale gas. From ExxonMobil Corporation’s US$41-billion purchase of XTO Energy Inc. on down, it speaks volumes that the energy of the future is natural gas. The future of natural gas is shale gas; and the future of shale gas is the technology of multi-stage fracking. And multi-stage fracking often demands copious amounts of water. So it’s no surprise either that public concerns about drinkingwater protection are on the rise, especially in regions unfamiliar with the oil and gas industry and the techniques of multi-stage fracking. In March, for example, Quebec put all licences and exploration on hold for 30 months so a full environmental impact study can be conducted. Across the border last summer, the New York state senate approved a moratorium on new drilling permits in that state’s part of the Marcellus shale pending further environmental studies to ensure that fracking chemicals won’t contaminate drinking water. The potential for aquifer contamination caused by hydraulic fracking is probably the public’s leading concern surrounding shale gas exploitation, and the industry’s as well. Concerns are understandable; it’s all about everyone’s quality of life. “It can’t be brushed under the carpet,” says Brad Rieb, region technical manager for Baker Hughes Canada’s pressure pumping division in Calgary. “The onus of responsibility of environmental stewardship is co-owned. We tell all our customers what we think is right, wrong or dangerous. Protection of the public is paramount; that overrides everything we do.”
58 // ENERGY EVOLUTION II
Multi-stage hydraulic fracturing indeed often demands massive volumes of water. In some places, today’s horizontal shale gas wells routinely employ 15 frac stages per wellbore and each stage needs 2,000-3,000 cubic metres of high-pressure injected fluid. And that’s growing: with the latest in isolation technologies, teams can now accomplish as many as 30 stages per wellbore. Injected frac fluid is typically greater than 99 per cent water and sand, with the remaining one per cent selected off a menu that typically includes friction reducers to speed the mix, corrosion inhibitors, biocides to prevent biological growth from clogging equipment and fissures, surfactants to keep the sand in suspension, and scale inhibitors such as hydrochloric acid or ethylene glycol. Small percentages yes, but clearly it’s critical that the injected mixture not be allowed anywhere near aquifers, especially those that are potable. Industry’s first priority is to maintain isolation of the frac—both from freshwater aquifers and from expanding outside its intended zone. Rieb points out that the vast majority of shale gas fracs his company does—excepting perhaps some in the Bakken shale—are in formations considerably deeper than freshwater aquifers, so risk of contamination is close to nil. Secondly, technological advances in drilling and tools can effectively isolate a fracking operation within its desired zone. “The science of wellbore construction has never been better than it is today,” he says. “Drilling the well, the mud quality, cementing the well, ensuring adequate and robust cement bonds, the testing
Volumetric Composition of a Fracture Fluid
ENVIRONMENT
Friction Reducer 0.088%
Acid 0.123%
Water and Sand 99.51%
Biocide 0.001% Corrosion Inhibitor 0.002% Iron Control 0.004% Crosslinker 0.007% Breaker 0.01% pH Adjusting Agent 0.011% Scale Inhibitor 0.043%
Other 0.49%
Gelling Agent 0.056% KCI 0.06% Surfactant 0.085%
Modified from: ALL Consulting, based on data from a fracture operation in the Fayetteville Shale, 2008
Current frac technology is designed with the aim of keeping reservoirs and aquifers separated. Illustration: ProPublica.org Photo: Encana
of those bonds, the science of understanding what these hydraulic fracs do in the formation—the science and the knowledge behind it has never been higher.” But it’s not just a matter of isolating the well itself. On top of that, the sophistication of modern microseismic techniques allows an operator to pinpoint with a high degree of accuracy where the fracs are and, together with knowledge of the geology, whether they will grow out of the intended frac zone. Microseismic doesn’t generate energy in the traditional sense except for the initial setup; it only ‘listens’ to the frac. With sensors downhole or on the surface, operators can ‘hear’ the breaks as they happen—technology now can identify where the frac is in three dimensions: azimuth, length and height; as well as its magnitude and whether it has stayed open or resealed. The majority of tight gas fracking operations in western Canada use fresh water as source water, but that’s changing as water demands increase. Towns like Kindersley, Sask., are growing averse to selling potable water for the purpose. Moreover, other regions aren’t so lucky to have such a volume of fresh supply. As has been common in areas such as the Barnett shale of Texas, where use of recycled water is rapidly becoming the norm. To use recycled water for fracking, operators start with the produced water coming out of the fractured well and either treat it on site or truck it to a remote treatment facility. ›
Tripping tower (left) and three reactor towers at Encana Corp.’s Debolt water plant, which supplies water for the company’s Horn River frac operations.
ENERGY EVOLUTION II // 59
ENVIRONMENT
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Produced water is a mixture that can be of three different sources: frac water of varying chemistry, flowback water from previous treatments and actual formation water. Frac water chemistry can vary immensely across a formation. “This is what makes the chemistry challenge so interesting,” says Rieb. “The ratios keep changing. For example, the ratio of produced water to actual flowback material changes all the time.” In addition, there are often iron compounds introduced by new storage units, pumping equipment, tubulars, treaters and separators. “It really is a complex blend of water qualities, types and chemistries,” says Rieb. “We insist on getting representative samples from all these different sources so we can develop systems that serve a purpose on this used water.”
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“ There is an ethical obligation to protect the public and that is woven in. It has to be scientifically based and researched.” — Brad Rieb, Region Technical Manager, Baker Hughes Canada
Several manufacturers provide chemicals especially designed for use with recycled waters. For example, Trican Well Service’s EcoClean products are formulated to be non-toxic, biodegradable and non-bioaccumulating, protecting the environment and handlers in case of surface spill. David Browne, Trican’s corporate director of technology, says they pass the strict Microtox testing—meaning safe for human consumption—and so would not harm an aquifer even if there were communication between the product and the water. “Whichever fluid the producers choose to use, whether our EcoClean line or any of our fluid products, the risk of aquifer contamination is virtually nil,” he says. Trican also now offers a friction reducer that permits reuse of produced water even when it contains high levels of salt. “It enables use of produced water instead of fresh water,” says Browne. He is speaking of Trican’s FR-8 and FR-9 salt-tolerant friction reducers, which have been designed for use in water-based fracturing fluids and specifically for high-salt brines. Where not recycled, operators typically separate the water from any oil, treat the water to reduce scale chemical emulsions, and reinject it into waterfloods or deep aquifers. Where suitable underground injection sites aren’t handy, disposal can be expensive, as it requires trucking or pipelining. Underground injection has traditionally been considered the best solution for produced water disposal—using salt or brackish water disposal wells to place the water in porous rock thousands of metres below freshwater aquifers. In between, layers of impermeable rock ensure no connection can be made with freshwater formations above.
Engineering | Geology | Geophysics
ENVIRONMENT
Underground injection of the produced water is not possible in every play as suitable injection zones may not be available, so treatment and reuse is becoming the more popular option. “If we can reduce those costs, reuse that water to complete wells without damage to the formation, that’s where the economics are,” says Rieb. In support of that, several new produced-water treatment technologies and new applications of existing technologies are under development. Some of the treated water can be reused as frac water for certain, but in some regions of the United States it can be sold as irrigation water or even drinking water. Such recycling or reusing of produced water can serve to alleviate demands on traditional sources, offering new resources for drought-stricken or more arid areas—making produced water a potential resource in its own right. But shale drilling activity doesn’t always stay in one place long enough to justify a fixed-treatment facility, and transporting it may not be cost-effective either. Thus, on-site units are appearing on the market, particularly in the Barnett shale where regulatory-approved mobile recycling units are becoming ever more popular. For example, Fountain Quail Water Management, LLC provides a unit that recycles 80 per cent of flowback water. On-site distillation units apply heat to separate out and concentrate the salt water, which is sent to a disposal well, and the remaining distilled water is reused for fracking. On-site produced natural gas is used to fire the distilling units. Another firm, VWS Oil & Gas, offers different treatments. One utilizes thermal evaporation and crystallization technology as primary treatment for both flowback and produced waters. Such zero-liquid discharge (ZLD) solutions, as they are known, have been demonstrated in treating waters containing both high and low levels of total dissolved solids. The company claims effective removal of several compounds: sodium and calcium chlorides and heavy metals. Waste generated is restricted to a solid ‘saltcake,’ which is approved for most landfill disposals. Its ZLD systems generally recover over 95 per cent of the effluent. Other on-site treatments start with free oil removal, which is followed up with degasification, softening, filtration and reverse osmosis. The sequence reduces water hardness, metals and suspended solids. And because they’re designed to operate at a high pH level, they are also effective for controlling biological, organic and particulate fouling, and eliminating system scaling. As the number of shale gas wells grows exponentially, research continues into ways of keeping it environmentally sound and more efficient. A case in point is the challenges inherent in the use of biocides. Produced water and stored water need to be treated, but with biocides in them, they can’t be placed down a reservoir or disposed of in natural areas. If not properly disposed of, they become a hazard to living things. So new strains are being studied. “The food industry has products that are edible,” says Rieb, “but you can’t just change things overnight.” Other research is aimed at finding minimum standards for safe acceptability in water quality, perhaps additives that will allow water with higher total dissolved solids content to be used. But the re will always re main the impor tant unde rline r. “There is an ethical obligation to protect the public and that is woven in,” says Rieb. “It has to be scientifically based and researched.” ■
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ENERGY EVOLUTION II // 61
Who is CSUG? Since its inception in 2002, the Canadian Society for Unconventional Gas (CSUG) has had a significant impact on the evolution of the unconventional gas industry in Canada. With a strong focus on technology transfer between industry, government, public stakeholders and First Nations, CSUG’s major role is to provide this information to enable resource development in an environmentally, socially and economically sensitive manner. In 2010, we recognized that the industry is changing as companies increase their unconventional exploration efforts to regions outside of Western Canada and also to emerging resource plays such as liquids rich natural gas and light tight oil.
751802 Canadian Society for Unconventional Gas (CSUG) full page While natural gas from unconventional sources continues to play an important role in filling the gap between energy demands and declining conventional gas production the growth of this resource throughout North American has provided an opportunity for energy supply assurance for many decades to come. CSUG representatives have been instrumental in educating the public and industry about unconventional gas and will continue to work collaboratively with a wide cross-section of organizations to ensure the responsible and sustainable development of our unconventional resources. Benefits of Membership • Opportunity for members to make a direct contribution to the development of unconventional resources in Canada by volunteering for a committee (technical, regulatory and communications) or the board of directors. • Access to the members-only section of the CSUG website at www.csug.ca. • Attend technical conferences and workshops at a discounted rate; and members only field trips and technical luncheons. • CSUG is recognized as a significant voice of the natural gas industry and currently has a number of advocacy initiatives that are targeting the regulatory issues in a number of jurisdictions across Canada. As well the Society is an active participant with the Canadian Natural Gas Initiative which works to influence energy policies and strategies at a federal and provincial government level.
Canadian Society for Unconventional Gas 420, 237 - 8th Avenue SE, Calgary, AB T2G 5C3 phone: 403-233-9298 toll free: 1-855-833-9298 fax: 403-233-9267 email: info@csug.ca web: www.csug.ca
› DIRECTORY CSUG MEMBERS Advance Flow Technologies 6135 - 10 St SE Calgary, AB T2H 2Z9 P: (403) 212-2382 | F: (403) 212-2391 www.afti.ca AJM Petroleum Consultants 600, 425 - 1 St SW Calgary, AB T2P 3L8 P: (403) 648-320 | F: (403) 265-0862 www.ajmpc.com Alberta Geological Survey 4999 - 98 Ave Edmonton, AB T6B 2X3 P: (780) 427-1980 | F: (780) 422-1459 www.ags.gov.ab.ca Alberta Innovates Technology Futures 3608 - 33 St NW Calgary, AB T2L 2A6 P: (403) 210-5222 | F:(403) 210-5380 www.albertatechfutures.ca Altius Solutions Inc. 401 - 51 Ave SW Calgary, AB T2V 0A2 P: (403) 216-8515 Annapolis Capital Limited 1515, 800 - 5 Ave SW Calgary, AB T2P 3T6 P: (403) 231-4430 | F: (403) 233-8434 www.annapoliscapital.ca Apache Canada Ltd. 1000, 700 - 9 Ave SW Calgary, AB T2P 3V4 P: (403) 261-1200 | F: (403) 266-5987 www.apachecorp.com ARC Financial Corporation 4300, 400 - 3 Ave SW, Canterra Tower Calgary, AB T2P 4H2 P: (403) 292-0680 | F: (403) 292-0693 www.arcfinancial.com ARC Resources Ltd. 1200, 308 - 4 Ave SW Calgary, AB T2P 0H7 P: (403) 503-8600 | F: (403) 509-6427 www.arcresources.com ATCO Group 1300, 909 - 11 Ave SW Calgary, AB T2R 1L8 P: (403) 292-7500 | F: (403) 292-7532 www.atco.com Baker Hughes Canada Company 1000, 401 - 9 Ave SW Calgary, AB T2P 3C5 P: (877) 285-9910 | F: (403) 537-3799 www.bakerhughes.com BC Ministry of Energy, Mines, and Petroleum PO Box 9318 Stn Prov Govt Victoria, BC V8W 9N3 P: (250) 952-0241 | F: (250) 952-0922 www.gov.bc.ca
BG International Ltd. 500, 222 - 3 Ave SW Calgary, AB T2P 0B4 P: (403) 538-7400 www.bg-group.com
Canbriam Energy Inc. 500, 521 - 3 Ave SW Calgary, AB T2P 3T3 P: (403) 269-2874 | F: (403) 269-7637 www.canbriam.com
Custodians of the Peace Country Society PO Box 36 Hudson’s Hope, BC V0C 1V0 P: (250) 783-5314
Birchcliff Energy Ltd. 500, 630 - 4 Ave SW Calgary, AB T2P 0J9 P: (403) 261-6401 | F: (403) 261-6424 www.birchcliffenergy.com
Canyon Technical Services 1600, 510 - 5 St SW Calgary, AB T2P 3S2 P: (403) 355-2300 | F: (403) 355-2211 www.canyontech.ca
Dar Energy Inc. 507 Patterson View SW Calgary, AB T3H 3J9 P: (403) 265-7170 | F: (403) 246-6741 www.darenergy.com
BJ Services Company Canada 1020, 903 - 8 Ave SW Calgary, AB T2P 0P7 P: (403) 531-5151 | F: (403) 296-1550 www.bjservices.ca
Cenovus Energy Inc. 421 - 7 Ave SW Calgary, AB T2P 0M5 P: (403) 766-2000 | F: (403) 766-7600 www.cenovus.com
Daylight Energy Trust 2100, 144 - 4 Ave SW Calgary, AB T2P 3N4 P: (403) 266-6900 | F: (403) 266-6988 www.daylightenergy.com
BMO Capital Markets, A&D Advisory Group (Canada) 2200, 333 - 7 Ave SW Calgary, AB T2P 2Z1 P: (403) 515-3674 | F: (403) 515-3654 www.bmo.com
Centre for Marine CNG Inc. PO Box 3, 130 Southside Rd St. John’s, NL A1C 5H5 P: (709) 754-9880 | F: (709) 754-9881 www.cmcng.com
Devon Canada Corporation 2000, 400 - 3 Ave SW Calgary, AB T2P 4H2 P: (403) 232-7337 | F: (403) 232-7337 www.devonenergy.com
CGGVeritas Canada 2200, 715 - 5 Ave SW Calgary, AB T2P 5A2 P: (403) 205-6000 | F: (403) 205-6400 www.cggveritas.com
Direct Energy/ Centrica Canada Ltd. 1000, 111 - 5 Ave SW Calgary, AB T2P 3Y6 P: (403) 261-9810 | F: (403) 266-6684 www.directenergy.com
Bonavista Energy 700, 311 - 6 Ave SW Calgary, AB T2P 3H2 P: (403) 213-4300 | F: (403) 262-5184 www.bonavistaenergy.com Calfrac Well Services Ltd. 411 - 8 Ave SW Calgary, AB T2P 1E3 P: (403) 266-6000 | F: (403) 266-7381 www.calfrac.com Canada Energy Partners Inc. 1500, 885 West Georgia St Vancouver, BC V6C 3E8 P: (604) 909-1154 | F: (604) 488-0319 www.canadaenergypartners.com Canada Revenue Agency 130, 220 - 4 Ave SE Calgary, AB T2G 0L1 www.cra-arc.gc.ca Canadian Consulate General Buffalo NY 3000 HSBC Center Buffalo, NY 14203-2830 P: (716) 858-9557 Canadian Discovery Ltd. 300, 706 - 7 Ave SW Calgary, AB T2P 0Z1 P: (403) 269-3644 | F: (403) 265-1273 www.canadiandiscovery.com Canadian Natural Resources Ltd. 2500, 855 - 2 St SW Calgary, AB T2P 4J8 P: (403) 716-6629 | F: (403) 514-7569 www.cnrl.com Canadian Spirit Resources Inc. 1950, Ford Tower 633 - 6 Ave SW Calgary, AB T2P 2Y5 P: (403) 539-5005 | F: (403) 262-4177 www.csri.ca
Chevron Canada Resources 500 - 5 Ave SW Calgary, AB T2P 0L7 P: (403) 234-5000 | F: (403) 234-5947 www.chevron.com City of Medicine Hat 200, 623 - 4 St SE Medicine Hat, AB T1A 0L1 P: (403) 529-8248 | F: (403) 502-8759 www.medicinehat.ca Compton Petroleum Corp. 500, Bankers Crt 850 - 2 St SW Calgary, AB T2P 0R8 P: (403) 237-9400 | F: (403) 237-9410 www.comptonpetroleum.com ConocoPhillips Canada Limited 401 - 9 Ave SW Calgary, AB T2P 2H7 P: (403) 233-4000 | F: (403) 233-5143 www.conocophillips.ca Core Laboratories Canada Ltd. 2100, 125 - 9 Ave SE Calgary, AB T2G 0P6 P: (403) 250-4000 | F: (403) 250-5120 www.corelab.com Crew Energy Inc. 1400, 425 - 1 St SW Calgary, AB T2P 3L8 P: (403) 266-2088 | F: (403) 266-6259 www.crewenergy.com Cumberland Oil & Gas Ltd. 2000, 717 - 7 Ave SW Calgary, AB T2P 0Z3 P: (403) 237-0790 | F: (403) 237-7907
Dixon, Bob PO Box 36079 Lakeview PO Calgary, AB T3E 7C6 P: (403) 261-1019 Dragon Energy Consulting Inc. 184 Camden Crt Strathmore, AB T1P 1Y1 P: (403) 816-7587 | F: (403) 945-1748 East Coast Energy Inc. 276 Foord St PO Box 940 Stellarton, NS B0K 1S0 P: (902) 755-5384 | F: (902) 755-9406 www.eastcoastenergy.ca Ember Resources 2400, 300 - 5 Ave SW Calgary, AB T2P 3C4 P: (403) 698-8996 | F: (403) 270-2850 www.emberresources.com Enbridge Resources Inc. 3000, 425 - 1 St SW Calgary, AB T2P 3L8 P: (403) 231-3900 | F: (403) 231-4844 www.enbridge.com Encana Corporation 150 - 9 Ave SW, PO Box 2850 Calgary, AB T2P 2S5 P: (403) 645-6718 | F: (403) 716-2488 www.encana.com Energy Resources Conservation Board 640 - 5 Ave SW Calgary, AB T2P 3G4 P: (403) 297-8311 | F: (403) 297-7336 www.ercb.ca
ENERGY EVOLUTION II // 63
DIRECTORY Enerplus Partnership 3000, 333 - 7 Ave SW Calgary, AB T2P 2Z1 P: (403) 298-2200 | F: (403) 298-2211 www.enerplus.com Environment Canada PO Box 5050 Burlington, ON L7R 4A6 P: (905) 319-6917 | F: (819) 994-1412 www.ec.gc.ca EOG Resources Canada Inc. 1300, 700 - 9 Ave SW Calgary, AB T2P 3V4 P: (403) 663-8456 | F: (403) 663-8556 www.eogresources.com EVRAZ 400, 505 - 3 St SW Calgary, AB T2P 3E6 P: (403) 663-8456 | F: (403) 663-8556 www.evraz.com Fairborne Energy Ltd. 3400, 450 - 1 St SW Calgary, AB T2P 5H1 P: (403) 290-7750 | F: (403) 290-7724 www.fairborne-energy.com Farmers’ Advocate of Alberta 305, 7000 - 113 St Edmonton, AB T6H 5T6 P: (780) 310-3276 | F: (780) 427-3913 www.gov.ab.ca Fekete Associates Inc. 2000, 540 - 5 Ave SW Calgary, AB T2P 0M2 P: (403) 213-4200 | F: (403) 213-4298 www.fekete.com Fracturing Horizontal Well Completions Inc. 146 Coverton Heights NE Calgary, AB T3K 5B2 P: (403) 464-1741 www.fracknowledge.com Gastem Inc. 1215, 1155 University Montreal, QC H3B 3A7 P: (514) 875-9034 | F: (514) 878-3041 www.gastem.ca GLJ Petroleum Consultants Ltd. 4100, 400 - 3 Ave SW Calgary, AB T2P 4H2 P: (403) 266-9500 | F: (403) 262-1855 www.gljpc.com Halliburton Energy Services 1600, 645 - 7 Ave SW Calgary, AB T2P 4G8 P: (403) 290-7966 | F: (403) 231-9366 www.halliburton.com Hatch Ltd. 700, 840 - 7 Ave SW Calgary, AB T2P 3G2 P: (403) 269-9555 | F: (403) 266-5736 www.hatch.ca Hunt Oil Company of Canada, Inc. 3100, 450 - 1 St SW Calgary, AB T2P 5H1 P: (403) 215-8636 | F: (403) 215-8644 www.huntoil.com
64 // ENERGY EVOLUTION II
Huron Energy Corporation 1000, 202 - 6 Ave SW Calgary, AB T2P 2R9 P: (403) 264-1200 | F: (403) 264-2200 Imperial Oil 237 - 4 Ave SW, PO Box 2480 Stn M Calgary, AB T2P 3M9 P: (403) 237-4052 | F: (403) 237-2907 www.imperialoil.ca Insite Petroleum Consultants 2000, 801 - 6 Ave SW Calgary, AB T2P 3W2 P: (403) 262-2499 | F: (403) 233-0062 www.insitepc.com JL McNichol Consulting Inc. 81 Valley Creek Rd NW Calgary, AB T3B 5V1 P: (403) 998-0844 Junex Inc. 200 - 2795 Blvd Laurier Bureau Quebec City, QC G1V 4M7 P: (418) 654-9661 | F: (418) 654-9662 www.junex.ca Kern Partners Ltd. Centennial Pl E 3110, 520 - 3 Ave SW Calgary, AB T2P 0R3 P: (403) 517-1501 | F: (403) 517-1515 www.kernpartners.com LxData Inc. 520 McCaffrey St St Laurent, QC H4T 1N1 P: (514) 599-5714 | F: (514) 599-5729 www.lxdata.com Mancal Energy Inc. 1600, 530 - 8 Ave SW Calgary, AB T2P 3S8 P: (403) 231-7680 | F: (403) 231-7679 www.mancal.com Manitoba Geological Survey 360 - 1395 Ellice Ave Winnipeg, MB R3G 3P2 P: (204) 945-3744 | F: (204) 945-1406 www.gov.mb.ca Marble, Jesse 308, 420 - 3 Ave NE Calgary, AB T2E 0H6 P: (403) 690-6311 Martin Teitz Geoconsulting Inc. 24 Grandview Rise Calgary, AB T3Z 0A8 P: (403) 850-3689 McDaniel & Associates Consultants Ltd. 2200, 255 - 5 Ave SW Calgary, AB T2P 3G6 P: (403) 218-1384 | F: (403) 233-2744 www.mcdan.com ME Energy 905, 500 - 4 Ave SW Calgary, AB T2P 2V6 P: (403) 454-0887 | F: (403) 452-7479 www.marier-energy.com
Murphy Oil Company Ltd. Centennial Pl - East Tower 4000, 520 - 3 Ave SW Calgary, AB T2P 0R3 P: (403) 294-8000 | F: (403) 294-8819 www.murphyoilcorp.com MWM Canada Inc. 210 Willmott St, PO Box 1120 Cobourg, ON K9A 4W5 P: (716) 238-4417 | F: (905) 248-3168 www.power-technology.com NAL Resources Management Limited 600, 550 - 6 Ave SW Calgary, AB T2P 0S2 P: (403) 294-3600 | F: (403) 294-3601 www.nalenergy.com National Energy Board 444 - 7 Ave SW Calgary, AB T2P 0X8 P: (403) 777-2542 | F: (403) 777-2699 www.neb-one.gc.ca Natural Resources Canada (NRCan) 3303 - 33 St NW Calgary, AB T2L 2A7 P: (403) 292-7000 | F: (403) 292-7049 www.nrcan-rncan.gc.ca New Brunswick Department of Natural Resources PO Box 6000 Fredericton, NB E3B 5H1 P: (506) 453-2206 | F: (506) 453-3671 www.gnb.ca Nexen Inc. 2900, 801 - 7 Ave SW Calgary, AB T2P 3P7 P: (403) 699-4245 | F: (403) 513-6329 www.nexeninc.com Northern Cross (Yukon) Ltd. 840, 700 - 4 Ave SW Calgary, AB T2P 3J4 P: (403) 237-0055 | F: (403) 237-6255 www.northerncrossyukon.ca Norwest Corporation 2700, 411 - 1 St SE Calgary, AB T2G 4Y5 P: (403) 232-4109 | F: (403) 263-4086 www.norwestcorp.com Nova Scotia Department of Energy Bank of Montreal Building 400, 5151 George St Halifax, NS B3J 3P7 P: (902) 424-4575 | F: (902) 424-0528 www.gov.ns.ca/energy NuVista Energy Ltd. 3500, 720 - 2 St SW Calgary, AB T2P 2W2 P: (403) 538-8500 | F: (403) 538-8505 www.nuvistaenergy.com Object Reservoir 2137 - 33 Ave SW, PO Box 327 Calgary, AB T2T 1Z7 P: (403) 615-2501 www.objectreservoir.com
Pace Oil & Gas 1700, 250 - 2 St SW Calgary, AB T2P 0C1 P: (403) 303-8500 | F: (403) 264-0085 www.paceoil.ca Packers Plus Energy Services Inc. 2200, 205 - 5 Ave SW Calgary, AB T2P 2V7 P: (403) 263-7587 | F: (403) 263-7599 www.packersplus.com Peace Environment & Safety Trustees PO Box 7 Farmington, BC V0C 1N0 P: (250) 843-7072 | F: (250) 843-7072 www.peacenews.ca Pengrowth Corporation 2100, 222 - 3 Ave SW Calgary, AB T2P 0B4 P: (403) 233-0224 | F: (403) 265-6251 www.pengrowth.com Penn West Petroleum Ltd. 2200, 425 - 1 St SW Calgary, AB T2P 3L8 P: (403) 777-2500 | F: (403) 777-2699 www.pennwest.com Perpetual Energy Inc. 3200, 605 - 5 Ave SW Calgary, AB T2P 3H5 P: (403) 269-4400 | F: (403) 269-4444 www.perpetualenergyinc.com Petrel Robertson Consulting Ltd. 500, 736 - 8 Ave SW Calgary, AB T2P 1H4 P: (403) 218-1618 | F: (403) 262-9135 www.petrelrob.com PetroBakken Energy Ltd. 800, 425 - 1 St SW Calgary, AB T2P 3L8 P: (403) 268-7800 | F: (403) 218-6075 www.petrobakken.com Petroleum Services Association of Canada 1150, 800 - 6 Ave SW Calgary, AB T2P 3G3 P: (403) 264-4195 | F: (403) 263-7174 www.psac.ca Petro-Logic Services 439 - 11A St NW Calgary, AB T2N 1Y2 P: (403) 270-8517 | F: (403) 670-0811 www.petrologic-cbm.com Potter, Bob J201, 500 Eau Claire Ave SW Calgary, AB T2P 3R8 P: (403) 863-9738 Progress Energy Ltd. 1200, 205 - 5 Ave SW Calgary, AB T2P 2V7 P: (403) 216-2510 | F: (403) 216-2514 www.progressenergy.com ProspEx Resources Ltd. 2500 Bow Valley Sq III, 255 - 5 Ave SW Calgary, AB T2P 3G6 P: (403) 268-3940 | F: (403) 268-3987 www.psx.ca
Questerre Energy Corporation 1650, 801 - 6 Ave SW Calgary, AB T2P 3W2 P: (403) 777-1185 | F: (403) 777-1578 www.questerre.com Quicksilver Resources Canada Inc. 2000, 125 - 9 Ave SE One Palliser Square Calgary, AB T2G 0P8 P: (403) 537-2478 | F: (403) 262-6115 www.qrinc.com Realm Energy International Corporation 15567 Marine Dr White Rock, BC V4B 1C9 P: (604) 637-4974 | F: (604) 630-1351 www.realmenergy.ca
Silversmith Inc. 1370 Milbocker Rd Gaylord, MI 49727 P: (989) 732-8988 | F: (989) 732-8996 www.silversmithinc.com
Trident Exploration Corp. 1000, 444 - 7 Ave SW Calgary, AB T2P 0X8 P: (403) 770-0333 | F: (403) 668-5805 www.tridentexploration.ca
Smith, Randy 1400 - 800 5 Ave SW Calgary, AB T2P 3T6 P: (403) 263-0449
Turcato, Frank 2927 Lindsay Dr SW Calgary, AB T3E 6A9 P: (403) 807-9431
Source-Eval Ltd. 167 Cardiff Dr NW Calgary, AB T2K 1S1 P: (403) 607-6565
Unconventional Gas Resources Canada 700, 736 - 8 Ave SW Calgary, AB T2P 1H4 P: (403) 269-1690 | F: (403) 269-1680 www.ugresources.com
Southwestern Energy 125 - 2350 N. Houston Pkwy E Houston, TX 77032 P: (281) 618-4700 | F: (281) 618-4818 www.swn.com
Reliance Industries Business Atrium Building, Office 306-308 3rd Floor Oud Mehta Rd Dubai 125307 P: 91-22-2278 5000 www.ril.com
Sproule Associates Limited 900, 140 - 4 Ave SW Calgary, AB T2P 3N3 P: (403) 294-5519 | F: (403) 294-5570 www.sproule.com
Rock Energy Inc. 800, 607 - 8 Ave SW Calgary, AB T2P 0A7 P: (403) 218-4380 | F: (403) 234-0598 www.rockenergy.ca
Stealth Ventures Ltd. 3300, Bow Valley Sq II, 205 - 5 Ave SW Calgary, AB T2P 2V7 P: (403) 514-9998 | F: (403) 514-9995 www.stealthventures.ca
Roke Technologies Ltd. 516 Moraine Rd NE Calgary, AB T2A 2P2 P: (403) 247-3778 | F: (403) 247-3482 www.roke.ca
Stone Mountain Resources Ltd. 2800, 144 - 4 Ave SW Calgary, AB T2P 3N4 P: (403) 261-3399 | F: (403) 261-3377
Ryder Scott Company (Canada) 1200, 530 - 8 Ave SW Calgary, AB T2P 3S8 P: (403) 262-2799 | F: (403) 262-2790 www.ryderscott.com SAIT Polytechnic 1301 - 16 Ave NW Calgary, AB T2M 0L4 P: (403) 284-7248 | F: (403) 284-7119 www.sait.ca Savanna Energy 1800, 311 - 6 Ave SW Calgary, AB T2P 3H2 P: (403) 580-1899 | F: (403) 580-2671 www.savannaenergy.com Schlumberger of Canada 525 - 3 Ave SW Calgary, AB T2P 0G4 P: (403) 509-4000 | F: (403) 509-4023 www.slb.com Seven Generations Energy Ltd. 2500, 300 - 5 Ave SW Calgary, AB T2P 3C4 P: (403) 718-0700 | F: (406) 532-8020 Shell Canada Limited 355 - 4 Ave SW, PO Box 100, Station M Calgary, AB T2P 2H5 P: (403) 691-4542 | F: (403) 691-2828 www.shell.ca
Suncor Energy Inc. 112 - 4 Ave SW Calgary, AB T2P 2V5 P: (403) 269-8638 | F: (403) 269-6258 www.suncor.com Talisman Energy Inc. 2000, 888 - 3 St SW Calgary, AB T2P 5C5 P: (403) 237-1496 | F: (403) 693-2454 www.talisman-energy.com TAQA North Ltd. PetroCanada Tower 5100, 150 - 6 Ave SW Calgary, AB T2P 3Y7 P: (403) 724-5000 | F: (403) 724-5001 www.taqa.ae Thomas, Stephen PO Box 198, West Perth P: 61893226955 Total E & P Canada Ltd. 2900, 240 - 4 Ave SW Calgary, AB T2P 3C4 P: (403) 537-2372 | F: (403) 571-7595 www.total-ep-canada.com TransCanada Pipelines Ltd. PO Box 1000, Station M 450 - 1 St SW Calgary, AB T2P 5H1 P: (403) 537-2372 | F: (403) 571-7595 www.transcanada.com Trican Well Service Ltd. 2900, 645 - 7 Ave SW Calgary, AB T2P 4G8 P: (403) 266-0202 | F: (403) 237-7716 www.trican.ca
University of Alberta 1-26 Earth Sciences Building Edmonton, AB T6G 2E3 P: (780) 492-9660 | F: (780) 492-0249 www.ualberta.ca University of Calgary 2500 University Dr NW Calgary, AB T2N 1N4 P: (403) 210-9784 | F: (403) 220-2400 www.ucalgary.ca University of Lethbridge 4401 University Dr Lethbridge, AB T1K 3M4 P: (403) 329-2111 | F: (403) 239-2016 www.uleth.ca Vermilion Energy Ltd. 3500, 520 - 3 Ave SW Calgary, AB T2P 0R3 P: (403) 269-4884 | F: (403) 476-8100 www.vermilionenergy.com Vero Energy Inc. 1400, 333 - 5th Avenue SW Calgary, AB T2P 3B6 P: (403) 875-0505 | F: (403) 218-2064 www.veroenergy.ca Weatherford Canada Partnership 1100, 333 - 5 Ave SW Calgary, AB T2P 3B6 P: (403) 693-7838 | F: (403) 693-5611 www.weatherford.com Weimer, David 1400 Ravello Drive Katy, TX 77449 P: (281) 660-1065 Weir, Bob 274 Palace Brier Park SW Calgary, AB T2V 5H7 P: (403) 650-6777 Zargon Oil & Gas Ltd. 700, 333 - 5 Avenue SW Calgary, AB T2P 3B6 P: (403) 264-9992 | F: (403) 265-3026 www.zargon.ca
Associations/ Organizations Alberta Association of Surface Land Agents 140, 21 - 10405 Jasper Ave NW Edmonton, AB T5J 3S2 P: (780) 413-3185 | F: (780) 421-0204 www.aasla.com Association of Professional Engineers, Geologists and Geophysicists of Alberta 1500, Scotia One – 10060 Jasper Ave NW Edmonton, AB T5J 4A2 P: (780) 426-3990 | F: (780) 426-1877 www.apegga.org Canadian Association of Petroleum Landmen 350, 500 - 5 Ave SW Calgary, AB T2P 3L5 P: (403) 237-6635 | F: (403) 263-1620 www.capl.ca Canadian Association of Petroleum Producers 2100, 350 - 7 Ave SW Calgary, AB T2P 3N9 P: (403) 267-1100 | F: (403) 261-4622 www.capp.ca Canadian Energy Research Institute 150, 3512 - 33 St NW Calgary, AB T2L 2A6 P: (403) 282-1231 | F: (403) 284-4181 www.ceri.ca Canadian Natural Gas 809, 350 Sparks St Ottawa, ON K1R 7S8 P: (613) 748-0057 ext. 341 F: (613) 748-9078 www.canadiannaturalgas.ca Canadian Petroleum Products Institute Bow Valley Square 1 1010, 202 - 6 Ave SW Calgary, AB T2P 2R9 P: (403) 266-7565 | F: (403) 269-9367 www.cppi.ca Canadian Society of Exploration Geophysicists 600, 640 - 8 Ave SW Calgary, AB T2P 1G7 P: (403) 262-0015 | F: (403) 262-7383 www.cseg.ca Canadian Society of Petroleum Geologists 600, 640 - 8 Ave SW Calgary, AB T2P 0M2 P: (403) 264-5610 | F: (403) 264-5898 www.cspg.org Canadian Society for Unconventional Gas 420, 237 - 8 Ave SE Calgary, AB T2G 5C3 P: (403) 233-9298 | F: (403) 233-9267 www.csug.ca
ENERGY EVOLUTION II // 65
DIRECTORY Clean Air Strategic Alliance 1000, 10035 - 108 St NW Edmonton, AB T5J 3E1 P: (780) 427-9793 | F: (780) 422-3127 www.casahome.org Farmers’ Advocate 305, 7000 - 113 St NW Edmonton, AB T6H 5T6 P: 310-FARM (3276) | F: (780) 427-3913 www1.agric.gov.ab.ca/$department/deptdocs.nsf/all/ofa2621
Southern Alberta Institute of Technology 1301 - 16 Ave NW Calgary, AB T2M 0L4 P: (877) 284-7248 | F: (403) 284-7112 www.sait.ca University of Alberta 114 St - 89 Ave Edmonton, AB T6G 2E1 P: (780) 492-3111 www.ualberta.ca
Freehold Owners Association 1403 - 12 St SW Calgary, AB T3C 1B3 P: (403) 245-4438 | F: (403) 245-4420 www.fhoa.ca
University of Calgary 2500, University Dr NW Calgary, AB T2N 1N4 P: (403) 220-5110 | F: (403) 282-8406 www.ucalgary.ca
Petroleum Services Association of Canada 1150, 800 - 6 Ave SW Calgary, AB T2P 3G3 P: (403) 264-4195 | F: (403) 263-7174 www.psac.ca
University of Lethbridge 4401 University Dr Lethbridge, AB T1K 3M4 P: (403) 329-2111 www.uleth.ca
Petroleum Technology Alliance of Canada 400, 500 - 5 Ave SW Calgary, AB T2P 3L5 P: (403) 218-7700 | F: (403) 920-0054 www.ptac.org Saskatchewan Research Council 125, 15 Innovation Blvd Saskatoon, SK S7N 2X8 P: (306) 933-5400 | F: (306) 933-7446 www.src.sk.ca Small Explorers and Producers Association of Canada 1060, 717 - 7 Ave SW Calgary, AB T2P 0Z3 P: (403) 269-3454 | F: (403) 269-3636 www.sepac.ca Society of Petroleum Engineers 425, 500 - 5 Ave SW Calgary, AB T2P 3L5 P: (403) 237-5112 | F: (403) 262-4792 www.spe.org
Educational Institutes Institute for Sustainable Energy, Environment and Economy University of Calgary Earth Sciences Building, Room 1040, 2500 University Dr NW Calgary, AB T2N 1N4 P: (403) 220-6100 | F: (403) 220-2400 www.iseee.ca Mount Royal University 4825 Mount Royal Gate SW Calgary, AB T3E 6K6 P: (403) 440-6111 www.mtroyal.ca Northern Alberta Institute of Technology 11762 - 106 St NW Edmonton, AB T5G 2R1 P: (877) 333-NAIT (6248) | F: (780) 471-8490 www.nait.ca
66 // ENERGY EVOLUTION II
University of Regina (Faculty of Engineering) 3737 Wascana Parkway Regina, SK S4S 0A2 P: (306) 585-4111 www.uregina.ca University of Saskatchewan 501 - 121 Research Dr Saskatoon, SK S7N 1K2 P: (306) 966-6607 | F: (306) 966-6815 www.usask.ca
Government Alberta Department of Energy 700, 9945 - 108 St NW Edmonton, AB T5K 2G6 P: (780) 427-8050 | F: (780) 422-0698 www.energy.gov.ab.ca Alberta Department of Sustainable Resource Development 9920 - 108 St Edmonton, AB T5K 2M4 P: (780) 944-0313 | F: (780) 427-4407 www.srd.gov.ab.ca Alberta Economic Development Authority McDougall Centre 455 - 6 St SW Calgary, AB T2P 4E8 P: (403) 297-3022 | F: (403) 297-6435 aeda.alberta.ca Alberta Environment 10th Floor, Petroleum Plaza South Tower 9915 - 108 St Edmonton, AB T5K 2G8 P: (780) 427-2700 | F: (780) 422-4086 www.environment.gov.ab.ca Alberta Geological Survey 4th Floor, Twin Atria 4999 - 98 Ave Edmonton, AB T6B 2X3 P: (780) 422-1927 | F: (780) 422-1918 www.ags.gov.ab.ca
Alberta Innovates Energy and Environment Solutions 2540, AMEC Place 801 - 6 Ave SW Calgary, AB T2P 3W2 P: (403) 297-7089 www.albertainnovates.ca Alberta Innovates Technology Futures 250 Karl Clark Rd Edmonton, AB T6N 1E4 P: (780) 450-5111 | F: (780) 450-5333 www.albertainnovates.ca BC Oil & Gas Commission 300, 398 Harbour Rd Victoria, BC V9A 0B7 P: (250) 419-4400 www.bcogc.ca British Columbia Ministry of Energy and Mines PO Box 9318, Stn Prov Govt Victoria, BC V8W 9N3 P: (250) 952-0241 | F: (250) 356-2965 www.gov.bc.ca/empr Climate Change Central 600, 110 - 9 Ave SW Calgary, AB T2P 0T1 P: (866) 609-2700 | F: (403) 517-2727 www.climatechangecentral.com CRA Canada Revenue Agency 66 Stapon Rd Winnipeg, MB R3C 3M2 P: (204) 984-5164 www.cra-arc.gc.ca Energy Resources Conservation Board 1000, 250 - 5 St SW Calgary, AB T2P 0R4 P: (403) 297-8311 www.ercb.ca Environment Canada Inquiry Center 351 St. Joseph Blvd 8th Floor, Place Vincent Massey Gatineau, PQ K1A 0H3 P: (800) 668-6767 | F: (819) 994-1412 www.ec.gc.ca Geological Survey of Canada 3303 - 33 St NW Calgary, AB T2L 2A7 P: (403) 292-7000 | F: (403) 292-5377 www.gsc.nrcan.gc.ca Ministère des Ressources naturelles et de la Faune 5700, 4 Ave Ouest, A 401 Québec, QC G1H 6R1 P: (418) 627-6385 www.mrnf.gouv.qc.ca National Energy Board 444 - 7 Ave SW Calgary, AB T2P 0X8 P: (403) 292-4800 | F: (403) 292-5503 www.neb-one.gc.ca
Natural Resources Canada (NRCan) 14th Floor, 580 Booth St Ottawa, ON K1A 0E4 P: (613) 995-0947 www.nrcan-rncan.gc.ca New Brunswick Ministry of Natural Resources Brunswick Square 1 Germain St Saint John, NB E2L 4V1 www.gnb.ca Nova Scotia Department of Energy 400, 5151 George St, Bank of Montreal Building PO Box 2664 Halifax, NS B3J 3P7 P: (902) 424-4575 | F: (902) 424-0528 www.gov.ns.ca/energy Saskatchewan Ministry of Energy and Resources 200, 2101 Scarth St Regina, SK S4P 2H9 P: (306) 787-1155 www.er.gov.sk.ca Surface Rights Board 1229 - 91 St SW Edmonton, AB T6X 1E9 P: (780) 427-2444 | F: (780) 427-5798 www.surfacerights.gov.ab.ca
Information Resources Alberta Oil Magazine 800, 550 - 11 Ave SW Calgary, AB T2R 1M7 P: (403) 663-0083 | F: (403) 663-0086 www.albertaoil.net Canadian Centre for Energy 1600, 800 - 6 Ave SW Calgary, AB T2P 3G3 P: (403) 263-7722 | F: (403) 237-6286 www.centreforenergy.com JuneWarren-Nickle’s Energy Group 2nd Floor, 816 - 55 Ave NE Calgary, AB T2E 6Y4 P: (403) 209-3500 | F: (403) 245-8666 www.junewarren-nickles.com Oil & Gas Network 300, 840 - 6 Ave SW Calgary, AB T2P 3E5 P: (403) 539-1165 | F: (403) 206-7753 www.oilgas.net Oilweek Magazine 2nd Floor, 816 - 55 Ave NE Calgary, AB T2E 6Y4 P: (403) 209-3500 | F: (403) 245-8666 www.oilweek.com
470129 GLJ Petroleum Consultants 1/2h 路 hp
832535 Roke Technologies 1/2h 路 hp
ENERGY EVOLUTION II // 67
› GLOSSARY Adsorption/Adsorbed Refers to the molecular bonding of a gas to the surface of a solid. In the case of shale, natural gas is adsorbed or bonded to the organic material in the shale.
Damage (Formation Damage) Changes to a reservoir rock that have a negative impact on the ability of the reservoir to produce gas or liquids; commonly considered to be a reduction in permeability caused by drilling operations.
Aquifer The subsurface layer of rock or unconsolidated material that allows water to flow within it. Aquifers can act as sources for groundwater, both usable fresh water and unusable salty water.
Desorption/Desorbed Removal of an adsorbed or absorbed substance from its adsorbed state.
Casing Steel pipe placed in a well and cemented in place to isolate water, gas and oil from other formations and to maintain hole stability. Completion The activities and methods to prepare a well for production following the drilling of the wellbore. This includes the installation of equipment for production from a gas well. Conventional Natural Gas Conventional natural gas is typically made up of 80-90 per cent methane and consists of a mixture of hydrocarbon compounds and small quantities of various non-hydrocarbon substances. Conventional gas is generally defined as gas that is produced using more traditionally established drilling and completion methods.
Disposal Well A well that injects produced water into a regulated and approved deep underground formation for disposal. Downstream The refining, marketing and end-use sector of the oil and gas industry is commonly referred to as the downstream sector. Drilling Mud A mixture of clay, water and other ingredients that is pumped downhole through the drill pipe and drill bit that enables the removal of the drill cuttings from the wellbore and also stabilizes the penetrated rock formations before casing is installed in the borehole. Fault A fracture surface in rocks along which movement of rock on one side has occurred relative to rock on the other side.
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Flowback The flow of fracture fluid back to the wellbore after the treatment is completed. Formation (geologic) A rock body distinguishable from other rock bodies and useful for mapping or description. Formations may be combined into groups or subdivided into members. Gas in Place (GIP) The hypothetical amount of gas contained in a formation or rock unit. Gas in place always represents a value that is more than what is economically recoverable and refers to the total resources that are possible. Horizontal Drilling A drilling procedure in which the wellbore is drilled vertically to a kickoff depth above the target formation and then angled through a wide 90-degree arc such that the producing portion of the well extends horizontally through the target formation. Hydraulic Fracturing (aka ‘Fracking’) A method of improving the permeability of a reservoir by pumping fluids such as water, CO 2, nitrogen or propane into the reservoir at sufficient pressure to crack or fracture the rock. The opening of natural fractures or the creation of artificial fractures
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to create pathways by which the hydrocarbons can flow to the wellbore. Lithification The process of converting sediment to rock. Methane The principal ingredient in natural gas.
Microseismic The methods by which fracturing of the reservoir can be observed by geophysical techniques to determine where fracturing occurred within the reservoir. Midstream The processing, storage and transportation sector of the oil and gas industry. Multi-stage Fracturing The process of undertaking multiple fracture stimulations in the reservoir section where parts of the reservoir are isolated and fractured separately.
Permeability The ability of the rock to pass fluids or gas through it. The higher the permeability number, the greater the amount of fluid or gas
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GLOSSARY that can flow through the rock over a fixed time period. Permeability is measured in a unit called darcies. Conventional reservoirs may have permeabilities in the 10s to 100s of millidarcies or occasionally in the darcy range. Unconventional or tight reservoirs usually have permeabilities in the micro- to nano-darcy range (onemillionth of a millidarcy).
Shale Gas Natural gas stored in low-permeability shale formations. Stimulation Any of several processes used to enhance reservoir permeability. Thermogenic gas Natural gas generated from petroleum or other organic matter in a high-temperature and high-pressure environment.
Porosity The free space within the fine-grained rock that can store hydrocarbons. Produced Water Water produced from oil and gas wells. Propping Agents/Proppants Non-compressible material, usually sand or ceramic beads, that is added to the fracture fluid and pumped into the open fractures to prop them open once the fracturing pressures are removed. Reserves The estimated volume of gas economically recoverable from single or multiple reservoirs. Reserve estimates are based on strict site-specific engineering criteria. Reservoir The rock that contains potentially economic amounts of hydrocarbons.
Unconventional Gas Unconventional gas sources are generally categorized as tight sands and carbonates, shale gas or natural gas from coal. The distinction between unconventional and conventional is becoming less clear, but unconventional gas is more difficult to produce. It requires specialized drilling, completion and production techniques. The actual composition is usually the same as conventional natural gas—predominantly methane. Upstream The exploration, development and production sector of the petroleum industry. Wellbore A hole drilled into the earth, usually cased with metal pipe, for the production of gas or oil.
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