CSUG - Canadian Society for Unconventional Gas May 2011

The changing face of canadian energy supply

Guidebook & directoryVolume ii

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Major Sedimentary Basins containing potential unconventional hydrocarbon resources (excluding gas hydrates)

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 801 TCFSHALE GAS 1111 TCFTIGHT GAS 1311 TCF

IDENTIFIED RESOURCE PLAY TARGETS

ARCTIC ISLANDSNWT CRETACEOUS

CANADA

Lizard Basin

Bowser Basin

Appalachian Basin Sydney

Basin

Anticosti Basin

N

S

› CONTENTS

7 Welcome Letter

9 Welcome Letter—Alberta

11 Welcome Letter—British Columbia

13 Welcome Letter—Saskatchewan

15 Welcome Letter—New Brunswick

SUSTAINABILITY

16 Abridgeorourfuture?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

LIghT TIghT OIL

20 SolvingthepuzzleExplorers are putting together the technologies to optimize light tight oil developments in western Canada

By Darrell Stonehouse

ShALE gAS

24 ShalegaleVast reserves of shale gas redraw the energy picture

By R.P. Stastny

28 Thetechnologyofshalegas

31 TheroadtosuccessCanada’s shale gas producers are paving the way to successful exploitation of a massive resource

By Peter McKenzie-Brown

REgIONAL dEvELOpmENTS

36 Sizeoftheprize

38Firedup

Technology ignites boom in B.C. shale gas production—now the push is on to find markets


40Newlife

Tight oil plays resurrect oil industry across western Canada


42Growingpains

Quebec shale gas drilling results promising, but political worries threaten development


44Inchingahead

Early-stage exploration success creates cautious optimism about emerging New Brunswick and Nova Scotia shale plays


2420

4 // ENERGY EVOLUTION II



SHALE GAS

TIGHT GAS






CANADA

Lizard Basin

Bowser Basin


Basin

Anticosti Basin

N

S

PresidenT & CeOBill Whitelaw

PuBLisherAgnes Zalewski

ediTOrdale Lunan

COnTriBuTOrsJim Bentein, Graham Chandler, Peter McKenzie-Brown, r.P. stastny, darrell stonehouse

ediTOriAL AssisTAnCeLaura Blackwood, Tracey Comeau, samantha Kapler, Marisa Kurlovich

PrOduCTiOn, PrePress & PrinT MAnAGerMichael Gaffney

ArT direCTOrKen Bessie

desiGnerLyuba Kirkova

ACCOunT MAnAGerellen Fraser

MArKeTinGJeannine dryden

CALGArY 2nd Flr., 816 - 55 Avenue neCalgary, AB T2e 6Y4T: 403.209.3500 F: 403.245.8666Toll Free: 1.888.387.2446

edMOnTOn6111–91 street nWedmonton, AB T6e 6V6T: 780.944.9333 F: 780.944.9500Toll Free: 1.800.563.2946

junewarren-nickles.com

PresidenTMike dawson

ViCe PresidenT Kevin heffernan

MAnAGinG ediTOrLisa nicol

Canadian Society for Unconventional Gas

suite 420, 237-8 Ave. seCalgary, AB T2G [email protected]

www.csug.camARkET dEvELOpmENTS

46 Offtomarket

46GastogoldTalisman Energy is pinning its shale gas market strategy on proven gas-to-liquids technology


49Wheretogo?

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


51Asustainablefuture

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


ENvIRONmENT

54 AsmallerfootprintUnconventional resource producers are taking a lead role in improving environmental performance

By Jim Bentein

58 TestingthewatersMassive exploitation of North American shale gas formations puts aquifer protection and water efficiency in the spotlight

By Graham Chandler

63 Directory

68 Glossary

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ENERGY EVOLUTION II // 5

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welcome to energy evolution iithe 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 con-

tinues 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 de-

mands 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 geo-

graphic 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 be-

hind 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 so-

ciety has a wealth of information about the unconventional resource industry and we en-

courage you to visit www.csug.ca for more information.

Mike Dawson

President, Canadian Society for Unconventional Gas


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greetings from the ministry of energy, government of alberta

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 unconven-

tional 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 im-

pact 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

“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.”


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greetings from the ministry of energy and mines, government of british columbia

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 competi-

tive advantages retain long-term confidence in the province’s natural gas sector. Our royalty

programs stimulate growth and maintain production. Industry activity provides jobs, sup-

ports families and strengthens our rural communities.

Liquefied natural gas (LNG) projects are gaining momentum, with global LNG trade ex-

pected 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 re-

place 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 in-

novation 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 in-

dustry 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 re-

sponsible 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

“It is crucial that we continue to work

together to keep British Columbia’s natural

gas sector responsible and competitive.”


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greetings from the ministry of energy and resources, government of saskatchewan

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 pro-

duction 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 chap-

ters 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

“The possibilities are endless in Saskatchewan

for companies developing conventional and

unconventional resources. ”


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greetings from the department of natural resources, government of new brunswick

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 prov-

ince. 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 ex-

ploration 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 ac-

tivity 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

“Support the responsible expansion of the natural

gas sector while ensuring the safety and security of

homeowners and our groundwater supply. ”


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

“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 re-

sources, 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 lim-

ited resource than it’s proving to be; certain technologies weren’t

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 en-

vironment, announced plans to impose new regulations on coal-

fired 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 infra-

structure 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 tech-

nology. 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.”

A bridgeor our future

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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 indus-

trial facilities nearby.”

Egan sees that trend boosting opportunities 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 transporta-

tion, for example, and biomethane, which is a renewable nat-

ural 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 electri-

city—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 ambi-

tious 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 tech-

nologies 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.” ›


SUSTAINABILITY

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 proof-

of-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 op-

tion, 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 expen-

sive, 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 modifica-

tions to refineries.” Ziff’s recent economic analyses of available gas-

to-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 feed-

stock. 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 “spit-

ting 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.

But with all these transport and electrical power generation con-

versions 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 an-

other 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 foun-

dation 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 chil-

dren’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 environ-

mental standards.” ■

“In the short to medium term [natural gas is] really the fuel

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


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Achieve Sustainable Results

Shale Gas

Explorers are putting together the technologies to optimize light tight oil developments in western Canada


Efforts to exploit tight oil resources began in the Bakken formation

in North Dakota and Montana over a decade ago. Explorers ex-

tended 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 as-

sociated technologies have been advanced and adapted to optimize

exploration and production.

PetroBakken Energy Ltd. has been a pioneer in evolving the tech-

nical 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 fol-

lowed by open-hole coiled-tubing fracture treatments, which pro-

duced 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.

Then, about five years ago came the multi-stage fracturing revo-

lution, 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 interest-

ing 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

Solvingthepuzzle

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fracturing technology evolved the company was able to increase fractur-

ing density over longer horizontal legs, yielding increased recoverable re-

serves. 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 conclu-

sion of the reserve auditor,” explains Smith. “If you add a second hori-

zontal 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 evolu-

tion 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 inter-

mediate 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 re-

sulting from milling out the staging tool and wiper plug can lead

to fracking issues. So proper milling procedures must be fol-

lowed. Despite the debris concern, the company plans to con-

tinue use of the monobore design.

Explorers are also testing different completions technologies with

the goal of exposing more rock and increasing production.

Penn West Exploration has become a dominant player in the

Cardium light tight oil play around Drayton Valley, in west-central Alberta.

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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 import-

antly, 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 mar-

ket is the pump-down wireline gun and plug system. In this system,

anywhere from three to 10 perforating guns are lowered to the per-

forating 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

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 inter-

vals. Two big advantages of using sand plugs are they work with ce-

mented liners and there is no limit to the number of stages that can

be drilled, said Hawkes. Their downside is they are slower than ball-

drop 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 perfor-

ating 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 flu-

ids being used in light tight oil formations. In the Cardium, produ-

cers 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 per-

formance rather than cost,” said Stark.

Microseismic technology has also played a key role in the ex-

ploitation of tight oil plays, and the tool is evolving as field de-

velopment 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 ac-

tivities created during hydraulic fracturing. From there, the data

is interpreted and mapped, showing the penetration and direc-

tion of the fractures. The information is delivered in real time.

Operators can adjust their fracking stimulation program as it ad-

vances 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 microseis-

mic 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. ■

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.

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The ensuing global recession turned out to be a lot like a trusty com-

puter reboot. It reset the money markets, economic outputs and ener-

gy 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 as-

cent. A relatively low-cost energy source, shale gas currently adds about

10 billion cubic feet per day of production. By 2020, its production is ex-

pected to grow to 24 billion cubic feet a day.

And this has game-changing implications.

ProduCerSThe 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

shales, picking up vast, low-cost contiguous tracks of the most pro-

spective 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 en-

trants 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 consolida-

tions because it’s a scale business. It’s hugely capital intensive and it will

need well-capitalized companies,” he says.

GLoBAL CoNTexTThe 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

Vast reserves of shale gas redraw the energy picture

Shale galeBy R.P. Stastny

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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 under-

stand 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 develop-

ment 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. State-

owned Gazprom’s executive chairman Alexey Miller has been reported saying

shale gas should be regarded only as a “temporary local source” of hydrocar-

bons 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 de-

pendant on Russia’s conventional gas.

redrAWiNG The eNerGy mAPFaced 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 nat-

ural 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 lique-

faction 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 mArkeTSThe oil and gas industry itself admits that commodity prices languish-

ing 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 transporta-

tion fuel largely due to its pollution problems, which have brought in en-

vironmental 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 inter-

est 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

A Trican Well service frac

spread in the duvernay shale

play of western Canada.

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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 pene-

tration 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 gen-

eration. 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 eco-

nomic picture of North America.”

deCLiNiNG exPorTSWhat 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-

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 sec-

tor—conventional gas, shallow gas, tight gas and more recently coalbed

methane, all of which are less economic than the best shale gas plays.

Besa River

Horn River

Montney

Colorado

Bakken Utica Fredericks BrookHorton Blu�

Marcellus

Antrim

Gammon

NiobraraGreen River

Cane Creek

Lewis

Monterey

BarnettWoodford

New Albany

Excello

Haynesville

Conasauga

FayettevillePalo Duro

Pearsall

Duvernay

Miocene

CretaceousJurassic

TriassicPennsylvanian

Mississippian

Devonian

Ordovician

Cambrian

The depth and breadth of shale gas deposits in north America are radically

altering the continent's gas supply picture.

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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-

ment of unconventional resources, Mitchell spent almost a decade

and millions of dollars in research. He cycled through an array of

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 bil-

lion. 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 unconven-

tional reservoirs could be tapped commercially.

Ongoing technical innovations in open-hole and cased-hole

multi-stage completions allowed better fracture stimulation con-

trol 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,

Eagle Ford, Utica, Bakken, Viking, Lower Shaunavon, Cardium and

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.

The National Energy Board expects Alberta’s gas production to dip to 8.5 bil-

lion 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.

oTher imPLiCATioNSDeclining 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 petro-

chemical 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 west-

ern Canadian gas exports, but Steve Clark, TransCanada’s vice-president,

commercial-west, Canada and eastern U.S. pipelines, sees this only as a tem-

porary issue. Speaking at a Vancouver gas conference, he expressed opti-

mism 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.

ChALLeNGeSWater usage and groundwater contamination top the list of challen-

ges facing shale gas development. Some jurisdictions have intro-

duced 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 pro-

viders 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 frack-

ing. 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 man-

ner,” Russum sums up. “All the shale plays are different. The Barnett shale is sig-

nificant 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.” ■

meteoric rise or just reward?Texasoilmanbeganresearchanddevelopment

ofshalegasalmost30yearsago

shale gas in-place resource potential worldwide

• North America: 4,471 trillion cubic feet (tcf)• Former 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

(Canadian natural gas consumption: about 3 tcf/year)sourCe: World energy CounCIl 2010


ShALE gAS

There Are Three key TeChNoLoGiCAL deveLoPmeNTS ThAT hAve uNLoCked The NATurAL GAS PoTeNTiAL of fiNe-GrAiNed roCkS Like ShALe ANd SANdSToNeS:

hOrIzONTALDrILLINGThe 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.

hyDrAuLIcFrAcTurINGHydraulic fracturing is the process of

transmitting pressure by fluid or gas to

create cracks or to open existing cracks

in hydrocarbon-bearing rocks many thou-

sands of feet underground. The purpose

of hydraulic fracturing an oil or gas reser-

voir 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 under-

stood. See Figure 2.

Multi-stage fracturing, the latest evolution

in hydraulic fracturing, involves the segmenta-

tion 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 sur-

face 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.

TheTechNOLOGyOFShALeGAS

Figure 1 Horizontal drilling.

Check out the Csug Videos & animations page at www.csug.ca for more information.

SO

UR

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: CS

UG

PH

OTO

: HA

LLIBU

RTO

NS

OU

RC

E: C

SU

G

reservoir interval

‹ Vertical well “kick-off” point

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.


ShAL

E gA

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Sandstone

Limestone

HYDRAULIC FRACTURING

Shallow groundwater aquiferDeep groundwater aquifer

Protective steel casing:Steel casing and

cement provide wellcontrol and isolate

groundwater zones

Municipal water wellPrivatewell

Surface gas-well lease

Induced shale fractures

Note: Buildings andwell depth not to scale

Surface

1,000 m

1,500 m

2,000 m

2,300 m

Horizontal bore

Gas-rich shale

Sandstone

Limestone

mIcrOSeISmIcmONITOrINGOperators use microseismic technology to

observe the development of vertical and hori-

zontal 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 al-

low for optimal field development. See Figure 5.

Industry will continue to advance tech-

nologies that will broaden unconventional

resource opportunities, improve productiv-

ity and recovery potential, and allow for the

environmentally, socially and economically

responsible development of Canada’s un-

conventional natural resources. ■SO

UR

CE

: ES

G A

ND

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NIL

LUS

TR

AT

ION

: CA

NA

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N N

AT

UR

AL

GA

S

Figure 5 Fracture planes from

microseismic data

Figure 4 schematic of a

horizontal well relative to groundwater

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 associat-

ed with the level of public anxiety, specific-

ally 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 produc-

tion operations. See Figure 4.


ShALE gAS

779522inside education

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779522inside education

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There is now tough competition in North American gas mar-

kets, 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 com-

pany—typifies the situation for little gas producers. With operations

in the northwestern corner of Alberta, the company got its name be-

cause 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 mil-

lion dollars won’t go very far anymore, because the new technolo-

gies 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 mom-

and-pop petroleum companies around.”

Peter Tertzakian of ARC Financial Corp. says two other important

trends favour consolidation and larger companies.

“Bulking up to get costs down helps you deal with lower prices. It

gives you economies of scale. A related factor is that a lot of com-

panies 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.”

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

tosuccessTheroad

TheShALeGASrevOLuTIONhASTurNeDTheNATurALGASbuSINeSSuPSIDe

DOWNATAPAceNOONecOuLDeverhAveImAGINeD.

›


ShALE gAS

The companies most at risk are those that are heavily lever-

aged and biased to natural gas, but many of the smaller ones

are successfully implementing what he calls “revitalization

strategies: shif ting their focus to l iquids-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 oil-

sands, PetroChina put its money into shale gas. The two compan-

ies 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 ef-

fort 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 up-

ward move in North American gas prices.

One of those ideas is low-cost production. According to Boras,

“In the Montney, where we have done the deal with PetroChina, our

wellhead cost is about $3.15 [per thousand cubic feet].”

The deal will enable the Chinese to “get an early return on their

investment, and then take the technology back to China to use it

there. That certainly is part of what they’re thinking. The Chinese

have recently talked openly about their need to increase domestic

gas use,” 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 ap-

proval 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 ap-

parent, since shale gas has backed Canadian producers out of trad-

itional U.S. markets and driven down prices.

Low prices have made much of Canada’s conventional gas un-

economic 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 restruc-

ture, clouding the outlook. Such legacy assets as Canada’s Arctic

“Thereissomuchwe

candonowtoincrease

demand:fuelswitching,

thePickensPlanin

theunitedStates,

increasinguseofgas

forpowergeneration.

— 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.

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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 conven-

tional 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 import-

ant 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 switch-

ing, 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 con-

tinues to be a positive leading indicator for natural gas price recovery.”

The industry is also responding to low prices with rapid adapta-

tion 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.

GAS To LiquidSThe 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-to-

liquids technology to turn the gas into a desirable liquid fuel. This is

proven technology: Shell, for example, is constructing a $6-billion gas-

to-liquids project in Qatar, the tiny Middle Eastern country with 15 per

cent of the world’s proved natural gas reserves.

Another way to solve the stranded gas problem is to create lique-

faction 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 loca-

tion. I see a lot of objections to a project [there] because of the na-

ture of some communities on the Left Coast.”

STAkehoLder eNGAGemeNTA 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 foot-

age showed a man setting water from his kitchen tap alight—the re-

sult, 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 ›


ShALE gAS

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 hy-

draulic fracturing to sanction its further use. Until his department com-

pleted 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, rhetoric-

ally, then offers his own answer: “Anybody [with an interest in] con-

ventional 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 consul-

tation firm specializing in issues affecting aboriginal communities.

Wells describes effective stakeholder engagement as involving

“thoughtful, non-adversarial and respectful exchanges of informa-

tion. 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 PoLiCyPublic 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.

Senior Democrats in Congress are getting behind the stuff, por-

traying 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 indus-

try, 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 ef-

ficient 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 geol-

ogy—the horizontal potential is huge, but we couldn’t justify [hori-

zontal 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.” ■

“Wearealwayslooking

forwaystomaximize

thevalueofourassets,

andnaturalgas

liquidsextractionisan

importantpartofthat

process.

— Alan Boras, Spokesman, Encana Corp.

A multi-well horizontal drilling location in northeastern British Columbia.

PH

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NU

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Y 2010

”


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SHALE GAS

TIGHT GAS






CANADA

Lizard Basin

Bowser Basin


Basin

Anticosti Basin

N

S

oftheprizeShale gas promises to be a game changer in four key regions across Canada

size




SHALE GAS

TIGHT GAS






CANADA

Lizard Basin

Bowser Basin


Basin

Anticosti Basin

N

S



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Horn River Basin

BRITISH COLUMBIA ALBERTA

CordovaEmbayment

MontneyTrend

Liard Basin


SHALE GAS

TIGHT GAS



BRITISH COLUMBIA UNCONVENTIONAL GAS RESOURCE PLAYS


INcremeNTAL ImPrOvemeNTS INhOrIzONTALDrILLING

ANDmuLTI-STAGeFrAcTurINGTechNOLOGyArequIckLy

DrIvINGDOWNcOSTSANDImPrOvINGrecOveryrATeS

ATThemONTNeyANDhOrNrIverShALePLAySINNOrTh-

eASTerNbrITIShcOLumbIA.

With growing confidence the province’s massive shale resource can

be technically produced, efforts are now under way to build the infra-

structure needed to find premium markets for expanding production.

Encana executive vice-president and president, Canadian div-

ision 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, not-

ing 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 re-

turn 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.”

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 pro-

duction is between 10 [million] and 15 million cubic feet per day with

some wells coming in [at] over 20 million cubic feet per day.”

firedup Technology ignites

boom in B.C. shale

gas production—

now the push is on

to find markets

NOrTheASTerNb.c.


474106halliburton1/2v · hpv

HALLIBURTON

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“In unconventional gas,unlocking the sweetspot, while mitigatingwater concerns, isbusiness as usual.”


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 recov-

eries 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 in-

terest in the planned terminal, located on the west coast of central

British Columbia, and the associated natural gas pipeline, in an ef-

fort 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 offi-

cer, 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 an-

nually. Project construction could begin in 2012, with exports pot-

entially 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 feas-

ibility of constructing a 46,000-barrel-per-day gas to liquids facility

based on Sasol’s technology that is currently being used in three fa-

cilities 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 li-

quids 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 investigat-

ing 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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Emerging Duvernay FmShale Gas Resource Play

Montney Tight Gas Resource Play

Mannville NGCResource Play

Horseshoe Canyon NGCResource Play

Viking Tight Oil Resource Play

Bakken Tight OilResource PlayShaunovan Tight Oil

Resource Play

Calgary

Edmonton

ALBERTA

ALBERTA

SASKATCHEWAN

SASKATCHEWAN

Emerging Exshaw FmTight Oil Resource Play

Cardium FmTight OilResource Play


SHALE GAS

TIGHT GAS



ALBERTA AND SASKATCHEWANUNCONVENTIONAL GAS AND TIGHT OILRESOURCE PLAYSnew

lifeTight oil plays resurrect oil industry across western Canada


exTeNDeD-reAchhOrIzONTALWeLLANDmuLTI-STAGeFrAc-

TurINGTechNOLOGIeShAvereSuLTeDINThebIrThOFAN

eNTIreLyNeWOILANDGASINDuSTryPrODucINGShALeGAS

INcANADA.

The technology has also breathed new life into the moribund con-

ventional 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 com-

pletions 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 west-

ern 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 west-

ern 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 sec-

tions 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.

“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 re-

porting the company’s 2010 results in March, president and chief

operating officer Gregg Smith said the company has plenty of de-

velopment drilling ahead as well, with a focus on drilling long bilat-

eral 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, in-

jecting 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 recov-

ery (EOR) plans using natural gas.

“Using natural gas should look like carbon dioxide without the

corrosion issues,” he explained. “Natural gas is cheaper than car-

bon 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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one million acres of exploration land in southern Alberta targeting mul-

tiple 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 hori-

zontal 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 year-

end 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 high-

productivity 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 rig-

moving 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 bar-

rels 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 produc-

tion 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.” ■


REgI

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Areas of Exploration Activity

Core of Industry Activity

Edge of StructuredPlay Region

Logan’s Line

Shallow Utica Fm Potential

Yamaska Fault

Montreal

Quebec

UNITED STATESOF AMERICA

CANADA


SHALE GAS

TIGHT GAS



QUEBEC UNCONVENTIONAL GASRESOURCE PLAYgrowing

painsQuebec shale gas drilling results promising, but political worries threaten development


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uSINGhOrIzONTALDrILLINGANDmuLTI-STAGeFrAcTurING

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 encour-

aging. Talisman Energy Inc., which has drilled 10 wells in the play

along with partner Questerre Energy Corporation, reported aver-

age 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 deliv-

ering 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 consult-

ing firm SECOR Group to look at the economic benefits shale gas de-

velopment could bring to the province. SECOR found if development of

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 bil-

lion to $5.4 billion per year, depending on the number of wells drilled.

Public worries about air pollution and groundwater contam-

ination, 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 im-

pacts 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 con-

flict 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, vice-

president of North American shale gas operations for Talisman

Energy Inc. Fraser said that going forward, the industry needs to do

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a better job explaining the process involved in drilling and complet-

ing 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 meas-

ures 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 con-

tinue to help provide the technical information needed. Bouchard

said the information gleaned should also help in advancing the eco-

nomic 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 ex-

ploration, 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 produc-

tivity component and varies between five and 35 per cent.

The intention of the new system is for total government take, in-

cluding 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 minis-

ter also announced the introduction of a Gas Development Program

modelled on the Net Profit Royalty Program that is used in north-

eastern British Columbia. The progressive royalty rate starts at two

per cent and varies through a four-tiered scale based on the recov-

ery of capital invested and returns achieved. ■


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MontneyTrend

Maritimes Basin

SydneyBasin

Exploratory Acreage Held by

SWN Canada Ltd

McCully Field

Stoney CreekField


SHALE GAS

TIGHT GAS



MARITIMES UNCONVENTIONALGAS AND OIL RESOURCE PLAYS

inchingaheadEarly-stage exploration

success creates cautious

optimism about emerging

New Brunswick and Nova

Scotia shale plays


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OFAmASSIveShALeGASDIScOvery.

Halifax-based Corridor Resources Inc. reported that its part-

ner 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 approxi-

mately four kilometres north of the village of Elgin in southern New

Brunswick. The first test interval was flowing natural gas at a sta-

bilized 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 com-

pleted 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 pre-

liminary performance of these wells is both unexpected and perplex-

ing,” but cautioned that “it is important to recognize that the evaluation

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 suc-

cessful in showing the resource potential of the play. Based on an es-

timated 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 proxim-

ity to a premium market.”

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MontneyTrend

Maritimes Basin

SydneyBasin

Exploratory Acreage Held by

SWN Canada Ltd

McCully Field

Stoney CreekField


SHALE GAS

TIGHT GAS



MARITIMES UNCONVENTIONALGAS AND OIL RESOURCE PLAYS

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 fo-

cusing on the Bakken light tight oil play in western Canada.

Despite the setbacks, exploration in East Coast shale plays is ex-

pected 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-plus-

probable 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 ven-

ture, 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 includ-

ed 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 south-

ern 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 hori-

zontal 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 target-

ing 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 northeast-

ern United States, has licences totalling 2.52 million acres in New

Brunswick. The company spent around $11 million in 2010 com-

pleting an airborne magnetic and gradiometer survey and plans on

spending another $14 million this year doing core sampling, shoot-

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


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 origin-

ally 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

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 ob-

viously 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 con-

densate per day—“tremendous results,” according to Soares.

WhAT TO dO WITh ShALEY pLAYSAt least part of the significance of Rocor’s efforts was that it illus-

trated 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 re-

source—a hydrocarbon formation halfway between gas from tight

sands (the prospect Scurry Rainbow had originally been investigat-

ing) 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

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eNGINeerWASPreSIDeNTOFThecOmPANyThATDemONSTrATeDTheShALe

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mARkET dEvELOpm

ENTS

ThE UNCONvENTIONAL “BIg ThREE”tight sand, shale and coal reservoirs

whether they are more like tight sand or shale gas they require frac-

king 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 in-

cludes 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-LIqUIdSThis 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 proper-

ties. Talisman’s partner in both ventures is petrochemical giant

Sasol Limited, which honed its expertise in turning coal and nat-

ural 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 de-

cision likely in the second half of next year.”

SHALEYPLAYS

SHALEYSAND

LOW-PERMEABILITYSAND

GAS AD

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ORG

ANIC MATERIAL

GRAIN SIZE

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REASING

ALBERTA/BCMONTNEY/DOIG

TEXASBARNETT

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COALYSAND

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SILTYCOAL

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BCHORN RIVER

BASIN

LOW HIGHSHALE COALQUARTZ OR CLAY RICH? ORGANIC

CONTENT

SHALEGAS

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.

ILLUSTRATION: AJM PETROLEUM CONSULTANTS

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Put another way, a decision on whether to proceed with an engin-

eering 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 re-

sources 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 lar-

gest 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 execu-

tive 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 ac-

quisition 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 WORLdIn a presentation a year ago, the chairman and chief executive of-

ficer 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 conse-

quence…. They seem not to realize that platitudes are not BTUs.”

Citing the environmental advantages of gas, he argued that indus-

try 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 in-

creasingly important role in exploiting nature’s gift. ■


mARkET dEvELOpm

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Where to Go?

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


The problem with conventional wisdom is that it isn’t always true.

Contrarians are often right.

pRICE BULLIt’s worth keeping that truism in mind as we develop the case for build-

ing new natural gas markets in North America. In a recent comment,

author and analyst Peter Tertzakian argued that the rapid decline in drill-

ing 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 de-

cline, he suggests.

He then moves on to the killer argument: “Let’s say [gas] pro-

duction 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 dis-

patch more rigs to ramp up production and thus clobber prices

again. There is a problem with this line of thinking: why would pro-

ducers 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 mo-

tivation for the industry to shift toward more gas drilling. The result?

Declining supply and still higher gas prices until a cost-reward re-

balance restores aggressive natural gas drilling.

SUppLY BULLSince 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 de-

veloping 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 ex-

plained 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 de-

pendency 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 particu-

lar, substituting natural gas for coal in power generation facilities.

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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 mo-

tivated 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 BULLThe 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 fastest-

growing fuels used to generate electricity, but coal remains the dominant

energy source for electricity generation because of continued reliance on

existing coal-fired plants” well into the foreseeable future.

According to the EIA, the agency has revised its methodology

for gas prices “to better reflect a lessening of the influence of

oil prices on natural gas prices, in part because of the increase

in shale gas supply and improvements in natural gas extraction

technologies.”

Of course, as Peter Tertzakian argues, 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 fore-

cast an increase in North America’s natural gas demand, but its es-

timates 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. ■


mARkET dEvELOpm

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A SUStAinAble FUtUre Effectively marketing Canada’s vast

unconventional gas resources can help

ensure global sustainability


According to company spokesman Alan Boras, in 2010 “we re-

placed 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 meth-

ane is also an important part of our production—about 10 per cent.”

Encana’s numbers illustrate the remarkable success of the un-

conventional gas narrative. The big kid on the block is shale gas,

but other sources like coalbed methane and tight gas are also im-

portant 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 num-

ber 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 forma-

tions 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.

LNgEven 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 l ike

[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

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OFNOrThAmerIcA’SPremIerGAS-PrODucINGcOmPANIeS.

The Kitimat LNG project, shown here in an artist’s rendering, is considered a key outlet to Asian markets for Canadian shale gas production.Refuelling a transport truck fuelled by liquefied natural gas.

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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 bub-

ble that’s especially big in Canada. [For conventional gas] it’s worse

than anything we’ve seen in a very long time. That makes LNG

development more important now than ever.” She adds that

“shale gas is basically a technology play. The industry has found

ways to get 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 regula-

tory approvals before the new owners acquired the project.

ThE AThABASCA OIL SANdS STORYIn a rapidly evolving industry, companies are finding imagina-

tive ways to develop natural gas plays. One of the most inter-

esting 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.

Asian markets are logical targets for natural gas from western Canada.

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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 com-

pany 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 sup-

ply heat for production and upgrading operations, to produce hy-

drogen for upgrading and to generate electricity. Companies with

gas production could find themselves well hedged if gas prices rise.

As Svarte puts it, “we expect gas to be almost a free by-product of

our Deep Basin development, so this hedge is well-priced.”

WhATIf?With the help of an Ottawa-based thinktank called whatIf?

Technologies 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 mod-

el 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 gener-

ated using the whatIf? model, he added that the potential ranges of re-

coverable 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 off-

shore 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 un-

conventional gas “can be a contributor to helping the world achieve

nine-billion sustainable lifestyles by 2050.” ■


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ASmALLerFOOTPrINTUnconventional resource producers are taking a lead role in improving environmental performance

By Jim Bentein

“Low natural gas prices don’t present a pretty picture for small-

er companies involved in conventional natural gas produc-

tion 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 oper-

ate within this low-price environment because they have the capital

and cash flow to enter the shale gas and tight gas plays. They rec-

ognize 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 ne-

cessary part of doing business, he says.

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Dawson sees natural gas prices remaining low for at least a

couple of years, if not longer. “There are companies that are com-

petitive 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 de-

mand, but Dawson isn’t optimistic about that occurring anytime soon.

“Natural gas use for compressed natural gas to fuel the transpor-

tation 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, par-

ticularly 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 sec-

tor, 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 al-

low 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 produ-

cers 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 con-

tained 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.

ASmALLer

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ENvI

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This “manufacturing approach” taken by unconventional gas pro-

ducers 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 infra-

structure 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 pro-

tection of “fresh” water aquifers. We’ve been using hydraulic fractur-

ing practices for many years without any impact on groundwater.

We have the technology.”

The potential synergies the CSUG head refers to are well illus-

trated 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 pro-

duces 75 million cubic feet of gas equivalent per day, with plans to

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 ap-

plying 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 conven-

tional 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 drill-

ing multiple wells from one pad. (It can drill up to four wells.)

Encana belongs to the Horn River Basin Producers Group, an or-

ganization representing the 10 developers in the play, who share in-

formation on a regular basis.

“We know we’ll never know everything, so a lot of knowledge-

sharing 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 foot-

print,” says Taylor. “When you do that, you have cost-savings

in capital and equipment. The two [reducing the environmental

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.

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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 rig-

ging 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 magni-

tude,” 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 sub-

stantially 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 de-

velopment, 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 de-

velopment are linked to local and regional impacts—the land im-

pact, 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 off-

hydrocarbon 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 re-

spond 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 con-

tinue 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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ENvI

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ENT

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 drinking-

water 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 con-

ducted. 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 frack-

ing is probably the public’s leading concern surrounding shale gas

exploitation, and the industry’s as well. Concerns are understand-

able; 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.”

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 ac-

complish 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 typ-

ically includes friction reducers to speed the mix, corrosion inhibit-

ors, 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 per-

centages 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

Testing theWATERS

Massive exploitation of North American shale gas formations puts aquifer protection and water efficiency in the spotlight

By Graham Chandler

IT’SNOSurPrISeThATThebIGGeSTcOrPOrATe

merGerSANDAcquISITIONSINTheOILANDGASINDuSTryIN

ThePASTThreeyeArShAveINvOLveDuNcONveNTIONAL

GASreSOurceS,eSPecIALLyShALeGAS.


ENvIRONmENT

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 ex-

cept 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 di-

mensions: 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 de-

mands 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.

Water and Sand 99.51%

Other 0.49%

Modied from: ALL Consulting, based on data from a fracture operation in the Fayetteville Shale, 2008

Friction Reducer 0.088%

Acid 0.123%

Biocide 0.001%

Scale Inhibitor 0.043%

Surfactant 0.085%

KCI 0.06%

Gelling Agent 0.056%

pH Adjusting Agent 0.011%Breaker 0.01%Crosslinker 0.007%Iron Control 0.004%Corrosion Inhibitor 0.002%

Volumetric Composition of a Fracture Fluid

›

Current frac technology is designed with the aim of keeping reservoirs and aquifers separated.

ILLUS

TRATIO

N: P

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PU

BLIC

A.O

RG

PH

OTO

: EN

CA

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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.


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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 treat-

ments 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 stor-

age units, pumping equipment, tubulars, treaters and separators.

“It really is a complex blend of water qualities, types and chemis-

tries,” 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.”

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 con-

sumption—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 con-

tamination is virtually nil,” he says.

Trican also now offers a friction reducer that permits reuse of pro-

duced 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 fric-

tion 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 re-

inject 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 pro-

duced water disposal—using salt or brackish water disposal wells

to place the water in porous rock thousands of metres below fresh-

water aquifers. In between, layers of impermeable rock ensure no

connection can be made with freshwater formations above.

“ 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


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Underground injection of the produced water is not possible in

every play as suitable injection zones may not be available, so treat-

ment 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 tech-

nologies 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 distilla-

tion 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 util-

izes 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 demon-

strated 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 met-

als. Waste generated is restricted to a solid ‘saltcake,’ which is ap-

proved 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 fol-

lowed up with degasification, softening, filtration and reverse osmo-

sis. 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 particu-

late fouling, and eliminating system scaling.

As the number of shale gas wells grows exponentially, research con-

tinues 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 haz-

ard 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 there wil l a lways remain the impor tant underl iner.

“There is an ethical obligation to protect the public and that

is woven in,” says Rieb. “It has to be scientifically based and

researched.” ■


751802Canadian society for unconventional Gas (CsuG)

full page

Canadian Society for Unconventional Gas420, 237 - 8th Avenue SE, Calgary, AB T2G 5C3phone: 403-233-9298 toll free: 1-855-833-9298 fax: 403-233-9267email: [email protected] web: www.csug.ca

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.

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.

› dIRECTORY

CSUG MeMberSAdvANCE fLOW TEChNOLOgIES 6135 - 10 St Se calgary, Ab t2H 2Z9 P: (403) 212-2382 | F: (403) 212-2391www.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) 210-5380www.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) 233-8434www.annapoliscapital.ca

ApAChE CANAdA LTd.1000, 700 - 9 Ave SW calgary, Ab t2P 3V4 P: (403) 261-1200 | F: (403) 266-5987www.apachecorp.com

ARC fINANCIAL CORpORATION4300, 400 - 3 Ave SW, canterra tower calgary, Ab t2P 4H2 P: (403) 292-0680 | F: (403) 292-0693www.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) 537-3799www.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) 952-0922www.gov.bc.ca

Bg INTERNATIONAL LTd. 500, 222 - 3 Ave SW calgary, Ab t2P 0b4 P: (403) 538-7400 www.bg-group.com

BIRChCLIff ENERgY LTd. 500, 630 - 4 Ave SW calgary, Ab t2P 0J9 P: (403) 261-6401 | F: (403) 261-6424www.birchcliffenergy.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

BmO CApITAL mARkETS, A&d AdvISORY gROUp (CANAdA) 2200, 333 - 7 Ave SW calgary, Ab t2P 2Z1 P: (403) 515-3674 | F: (403) 515-3654www.bmo.com

BONAvISTA ENERgY 700, 311 - 6 Ave SW calgary, Ab t2P 3H2 P: (403) 213-4300 | F: (403) 262-5184www.bonavistaenergy.com

CALfRAC WELL SERvICES LTd. 411 - 8 Ave SW calgary, Ab t2P 1e3 P: (403) 266-6000 | F: (403) 266-7381www.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) 265-1273www.canadiandiscovery.com

CANAdIAN NATURAL RESOURCES LTd. 2500, 855 - 2 St SW calgary, Ab t2P 4J8 P: (403) 716-6629 | F: (403) 514-7569www.cnrl.com

CANAdIAN SpIRIT RESOURCES INC. 1950, Ford tower 633 - 6 Ave SW calgary, Ab t2P 2y5 P: (403) 539-5005 | F: (403) 262-4177www.csri.ca

CANBRIAm ENERgY INC. 500, 521 - 3 Ave SW calgary, Ab t2P 3t3 P: (403) 269-2874 | F: (403) 269-7637 www.canbriam.com

CANYON TEChNICAL SERvICES 1600, 510 - 5 St SW calgary, Ab t2P 3S2 P: (403) 355-2300 | F: (403) 355-2211www.canyontech.ca

CENOvUS ENERgY INC. 421 - 7 Ave SW calgary, Ab t2P 0m5 P: (403) 766-2000 | F: (403) 766-7600www.cenovus.com

CENTRE fOR mARINE CNg INC. Po box 3, 130 Southside rd St. John’s, Nl A1c 5H5 P: (709) 754-9880 | F: (709) 754-9881www.cmcng.com

CggvERITAS CANAdA 2200, 715 - 5 Ave SW calgary, Ab t2P 5A2 P: (403) 205-6000 | F: (403) 205-6400www.cggveritas.com

ChEvRON CANAdA RESOURCES 500 - 5 Ave SW calgary, Ab t2P 0l7 P: (403) 234-5000 | F: (403) 234-5947www.chevron.com

CITY Of mEdICINE hAT 200, 623 - 4 St Se medicine Hat, Ab t1A 0l1 P: (403) 529-8248 | F: (403) 502-8759www.medicinehat.ca

COmpTON pETROLEUm CORp. 500, bankers crt 850 - 2 St SW calgary, Ab t2P 0r8 P: (403) 237-9400 | F: (403) 237-9410www.comptonpetroleum.com

CONOCOphILLIpS CANAdA LImITEd 401 - 9 Ave SW calgary, Ab t2P 2H7 P: (403) 233-4000 | F: (403) 233-5143www.conocophillips.ca

CORE LABORATORIES CANAdA LTd. 2100, 125 - 9 Ave Se calgary, Ab t2G 0P6 P: (403) 250-4000 | F: (403) 250-5120www.corelab.com

CREW ENERgY INC. 1400, 425 - 1 St SW calgary, Ab t2P 3l8 P: (403) 266-2088 | F: (403) 266-6259www.crewenergy.com

CUmBERLANd OIL & gAS LTd. 2000, 717 - 7 Ave SW calgary, Ab t2P 0Z3 P: (403) 237-0790 | F: (403) 237-7907

CUSTOdIANS Of ThE pEACE COUNTRY SOCIETY Po box 36 Hudson’s Hope, bc V0c 1V0 P: (250) 783-5314

dAR ENERgY INC. 507 Patterson View SW calgary, Ab t3H 3J9 P: (403) 265-7170 | F: (403) 246-6741 www.darenergy.com

dAYLIghT ENERgY TRUST 2100, 144 - 4 Ave SW calgary, Ab t2P 3N4 P: (403) 266-6900 | F: (403) 266-6988www.daylightenergy.com

dEvON CANAdA CORpORATION 2000, 400 - 3 Ave SW calgary, Ab t2P 4H2 P: (403) 232-7337 | F: (403) 232-7337 www.devonenergy.com

dIRECT ENERgY/ CENTRICA CANAdA LTd. 1000, 111 - 5 Ave SW calgary, Ab t2P 3y6 P: (403) 261-9810 | F: (403) 266-6684www.directenergy.com

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) 270-2850www.emberresources.com

ENBRIdgE RESOURCES INC. 3000, 425 - 1 St SW calgary, Ab t2P 3l8 P: (403) 231-3900 | F: (403) 231-4844www.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


ENERpLUS pARTNERShIp 3000, 333 - 7 Ave SW calgary, Ab t2P 2Z1 P: (403) 298-2200 | F: (403) 298-2211www.enerplus.com

ENvIRONmENT CANAdAPo box 5050 burlington, oN l7r 4A6 P: (905) 319-6917 | F: (819) 994-1412www.ec.gc.ca

EOg RESOURCES CANAdA INC. 1300, 700 - 9 Ave SW calgary, Ab t2P 3V4 P: (403) 663-8456 | F: (403) 663-8556www.eogresources.com

EvRAZ 400, 505 - 3 St SW calgary, Ab t2P 3e6P: (403) 663-8456 | F: (403) 663-8556www.evraz.com

fAIRBORNE ENERgY LTd. 3400, 450 - 1 St SW calgary, Ab t2P 5H1 P: (403) 290-7750 | F: (403) 290-7724www.fairborne-energy.com

fARmERS’ AdvOCATE Of ALBERTA 305, 7000 - 113 St edmonton, Ab t6H 5t6 P: (780) 310-3276 | F: (780) 427-3913www.gov.ab.ca

fEkETE ASSOCIATES INC. 2000, 540 - 5 Ave SW calgary, Ab t2P 0m2 P: (403) 213-4200 | F: (403) 213-4298www.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) 262-1855www.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) 215-8644www.huntoil.com

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) 233-0062www.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) 945-1406www.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 2V6P: (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) 263-7599www.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 SWcalgary, Ab t2P 3G6 P: (403) 268-3940 | F: (403) 268-3987 www.psx.ca

dIRECTORY


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) 262-6115www.qrinc.com

REALm ENERgY INTERNATIONAL CORpORATION 15567 marine dr White rock, bc V4b 1c9 P: (604) 637-4974 | F: (604) 630-1351www.realmenergy.ca

RELIANCE INdUSTRIES BUSINESS Atrium building, office 306-308 3rd Floor oud mehta rd dubai 125307 P: 91-22-2278 5000 www.ril.com

ROCk ENERgY INC. 800, 607 - 8 Ave SW calgary, Ab t2P 0A7 P: (403) 218-4380 | F: (403) 234-0598 www.rockenergy.ca

ROkE TEChNOLOgIES LTd. 516 moraine rd Ne calgary, Ab t2A 2P2 P: (403) 247-3778 | F: (403) 247-3482 www.roke.ca

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

SILvERSmITh INC. 1370 milbocker rd Gaylord, mi 49727 P: (989) 732-8988 | F: (989) 732-8996www.silversmithinc.com

SmITh, RANdY 1400 - 800 5 Ave SW calgary, Ab t2P 3t6 P: (403) 263-0449

SOURCE-EvAL LTd. 167 cardiff dr NW calgary, Ab t2k 1S1 P: (403) 607-6565

SOUThWESTERN ENERgY 125 - 2350 N. Houston Pkwy e Houston, tX 77032 P: (281) 618-4700 | F: (281) 618-4818www.swn.com

SpROULE ASSOCIATES LImITEd 900, 140 - 4 Ave SW calgary, Ab t2P 3N3 P: (403) 294-5519 | F: (403) 294-5570 www.sproule.com

STEALTh vENTURES LTd. 3300, bow Valley Sq ii, 205 - 5 Ave SWcalgary, Ab t2P 2V7 P: (403) 514-9998 | F: (403) 514-9995 www.stealthventures.ca

STONE mOUNTAIN RESOURCES LTd. 2800, 144 - 4 Ave SW calgary, Ab t2P 3N4 P: (403) 261-3399 | F: (403) 261-3377

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

TRIdENT ExpLORATION CORp. 1000, 444 - 7 Ave SW calgary, Ab t2P 0X8 P: (403) 770-0333 | F: (403) 668-5805 www.tridentexploration.ca

TURCATO, fRANk 2927 lindsay dr SW calgary, Ab t3e 6A9 P: (403) 807-9431

UNCONvENTIONAL gAS RESOURCES CANAdA 700, 736 - 8 Ave SW calgary, Ab t2P 1H4 P: (403) 269-1690 | F: (403) 269-1680 www.ugresources.com

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) 476-8100www.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/ orGAnizAtionSALBERTA ASSOCIATION Of SURfACE LANd AgENTS140, 21 - 10405 Jasper Ave NWedmonton, Ab t5J 3S2P: (780) 413-3185 | F: (780) 421-0204www.aasla.com

ASSOCIATION Of pROfESSIONAL ENgINEERS, gEOLOgISTS ANd gEOphYSICISTS Of ALBERTA1500, Scotia one – 10060 Jasper Ave NWedmonton, Ab t5J 4A2P: (780) 426-3990 | F: (780) 426-1877www.apegga.org

CANAdIAN ASSOCIATION Of pETROLEUm LANdmEN350, 500 - 5 Ave SWcalgary, Ab t2P 3l5P: (403) 237-6635 | F: (403) 263-1620www.capl.ca

CANAdIAN ASSOCIATION Of pETROLEUm pROdUCERS2100, 350 - 7 Ave SWcalgary, Ab t2P 3N9P: (403) 267-1100 | F: (403) 261-4622www.capp.ca

CANAdIAN ENERgY RESEARCh INSTITUTE150, 3512 - 33 St NWcalgary, Ab t2l 2A6P: (403) 282-1231 | F: (403) 284-4181www.ceri.ca

CANAdIAN NATURAL gAS809, 350 Sparks St ottawa, oN k1r 7S8P: (613) 748-0057 ext. 341 F: (613) 748-9078www.canadiannaturalgas.ca

CANAdIAN pETROLEUm pROdUCTS INSTITUTEbow Valley Square 11010, 202 - 6 Ave SWcalgary, Ab t2P 2r9P: (403) 266-7565 | F: (403) 269-9367www.cppi.ca

CANAdIAN SOCIETY Of ExpLORATION gEOphYSICISTS600, 640 - 8 Ave SWcalgary, Ab t2P 1G7P: (403) 262-0015 | F: (403) 262-7383www.cseg.ca

CANAdIAN SOCIETY Of pETROLEUm gEOLOgISTS600, 640 - 8 Ave SWcalgary, Ab t2P 0m2P: (403) 264-5610 | F: (403) 264-5898www.cspg.org

CANAdIAN SOCIETY fOR UNCONvENTIONAL gAS420, 237 - 8 Ave Secalgary, Ab t2G 5c3P: (403) 233-9298 | F: (403) 233-9267www.csug.ca


CLEAN AIR STRATEgIC ALLIANCE1000, 10035 - 108 St NWedmonton, Ab t5J 3e1P: (780) 427-9793 | F: (780) 422-3127www.casahome.org

fARmERS’ AdvOCATE305, 7000 - 113 St NWedmonton, Ab t6H 5t6P: 310-FArm (3276) | F: (780) 427-3913www1.agric.gov.ab.ca/$department/dept-docs.nsf/all/ofa2621

fREEhOLd OWNERS ASSOCIATION1403 - 12 St SWcalgary, Ab t3c 1b3P: (403) 245-4438 | F: (403) 245-4420www.fhoa.ca

pETROLEUm SERvICES ASSOCIATION Of CANAdA1150, 800 - 6 Ave SWcalgary, Ab t2P 3G3P: (403) 264-4195 | F: (403) 263-7174www.psac.ca

pETROLEUm TEChNOLOgY ALLIANCE Of CANAdA400, 500 - 5 Ave SWcalgary, Ab t2P 3l5P: (403) 218-7700 | F: (403) 920-0054www.ptac.org

SASkATChEWAN RESEARCh COUNCIL125, 15 innovation blvdSaskatoon, Sk S7N 2X8P: (306) 933-5400 | F: (306) 933-7446www.src.sk.ca

SmALL ExpLORERS ANd pROdUCERS ASSOCIATION Of CANAdA1060, 717 - 7 Ave SWcalgary, Ab t2P 0Z3P: (403) 269-3454 | F: (403) 269-3636www.sepac.ca

SOCIETY Of pETROLEUm ENgINEERS425, 500 - 5 Ave SWcalgary, Ab t2P 3l5P: (403) 237-5112 | F: (403) 262-4792www.spe.org

edUCAtionAl inStitUteSINSTITUTE fOR SUSTAINABLE ENERgY, ENvIRONmENT ANd ECONOmY university of calgary earth Sciences building, room 1040, 2500 university dr NWcalgary, Ab t2N 1N4P: (403) 220-6100 | F: (403) 220-2400www.iseee.ca

mOUNT ROYAL UNIvERSITY4825 mount royal Gate SWcalgary, Ab t3e 6k6P: (403) 440-6111www.mtroyal.ca

NORThERN ALBERTA INSTITUTE Of TEChNOLOgY11762 - 106 St NWedmonton, Ab t5G 2r1P: (877) 333-NAit (6248) | F: (780) 471-8490www.nait.ca

SOUThERN ALBERTA INSTITUTE Of TEChNOLOgY1301 - 16 Ave NWcalgary, Ab t2m 0l4P: (877) 284-7248 | F: (403) 284-7112www.sait.ca

UNIvERSITY Of ALBERTA114 St - 89 Ave edmonton, Ab t6G 2e1P: (780) 492-3111www.ualberta.ca

UNIvERSITY Of CALgARY2500, university dr NWcalgary, Ab t2N 1N4P: (403) 220-5110 | F: (403) 282-8406www.ucalgary.ca

UNIvERSITY Of LEThBRIdgE4401 university drlethbridge, Ab t1k 3m4P: (403) 329-2111www.uleth.ca

UNIvERSITY Of REgINA (fACULTY Of ENgINEERINg)3737 Wascana Parkwayregina, Sk S4S 0A2P: (306) 585-4111www.uregina.ca

UNIvERSITY Of SASkATChEWAN501 - 121 research drSaskatoon, Sk S7N 1k2P: (306) 966-6607 | F: (306) 966-6815www.usask.ca

GovernMentALBERTA dEpARTmENT Of ENERgY700, 9945 - 108 St NWedmonton, Ab t5k 2G6P: (780) 427-8050 | F: (780) 422-0698www.energy.gov.ab.ca

ALBERTA dEpARTmENT Of SUSTAINABLE RESOURCE dEvELOpmENT9920 - 108 Stedmonton, Ab t5k 2m4P: (780) 944-0313 | F: (780) 427-4407www.srd.gov.ab.ca

ALBERTA ECONOmIC dEvELOpmENT AUThORITYmcdougall centre 455 - 6 St SWcalgary, Ab t2P 4e8P: (403) 297-3022 | F: (403) 297-6435aeda.alberta.ca

ALBERTA ENvIRONmENT10th Floor, Petroleum Plaza South tower9915 - 108 Stedmonton, Ab t5k 2G8P: (780) 427-2700 | F: (780) 422-4086www.environment.gov.ab.ca

ALBERTA gEOLOgICAL SURvEY4th Floor, twin Atria4999 - 98 Aveedmonton, Ab t6b 2X3P: (780) 422-1927 | F: (780) 422-1918www.ags.gov.ab.ca

ALBERTA INNOvATES ENERgY ANd ENvIRONmENT SOLUTIONS2540, Amec Place801 - 6 Ave SWcalgary, Ab t2P 3W2P: (403) 297-7089www.albertainnovates.ca

ALBERTA INNOvATES TEChNOLOgY fUTURES250 karl clark rdedmonton, Ab t6N 1e4P: (780) 450-5111 | F: (780) 450-5333www.albertainnovates.ca

BC OIL & gAS COmmISSION300, 398 Harbour rdVictoria, bc V9A 0b7P: (250) 419-4400www.bcogc.ca

BRITISh COLUmBIA mINISTRY Of ENERgY ANd mINESPo box 9318, Stn Prov GovtVictoria, bc V8W 9N3P: (250) 952-0241 | F: (250) 356-2965www.gov.bc.ca/empr

CLImATE ChANgE CENTRAL600, 110 - 9 Ave SWcalgary, Ab t2P 0t1P: (866) 609-2700 | F: (403) 517-2727www.climatechangecentral.com

CRA CANAdA REvENUE AgENCY66 Stapon rdWinnipeg, mb r3c 3m2 P: (204) 984-5164www.cra-arc.gc.ca

ENERgY RESOURCES CONSERvATION BOARd1000, 250 - 5 St SWcalgary, Ab t2P 0r4P: (403) 297-8311www.ercb.ca

ENvIRONmENT CANAdA INqUIRY CENTER351 St. Joseph blvd8th Floor, Place Vincent masseyGatineau, PQ k1A 0H3P: (800) 668-6767 | F: (819) 994-1412www.ec.gc.ca

gEOLOgICAL SURvEY Of CANAdA3303 - 33 St NWcalgary, Ab t2l 2A7P: (403) 292-7000 | F: (403) 292-5377www.gsc.nrcan.gc.ca

mINISTèRE dES RESSOURCES NATURELLES ET dE LA fAUNE5700, 4 Ave ouest, A 401 Québec, Qc G1H 6r1 P: (418) 627-6385www.mrnf.gouv.qc.ca

NATIONAL ENERgY BOARd444 - 7 Ave SWcalgary, Ab t2P 0X8P: (403) 292-4800 | F: (403) 292-5503www.neb-one.gc.ca

NATURAL RESOURCES CANAdA (NRCAN)14th Floor, 580 booth Stottawa, oN k1A 0e4P: (613) 995-0947www.nrcan-rncan.gc.ca

NEW BRUNSWICk mINISTRY Of NATURAL RESOURCESbrunswick Square1 Germain StSaint John, Nb e2l 4V1www.gnb.ca

NOvA SCOTIA dEpARTmENT Of ENERgY400, 5151 George St, bank of montreal buildingPo box 2664Halifax, NS b3J 3P7P: (902) 424-4575 | F: (902) 424-0528www.gov.ns.ca/energy

SASkATChEWAN mINISTRY Of ENERgY ANd RESOURCES200, 2101 Scarth Stregina, Sk S4P 2H9P: (306) 787-1155www.er.gov.sk.ca

SURfACE RIghTS BOARd1229 - 91 St SWedmonton, Ab t6X 1e9P: (780) 427-2444 | F: (780) 427-5798www.surfacerights.gov.ab.ca

inForMAtion reSoUrCeSALBERTA OIL mAgAZINE800, 550 - 11 Ave SWcalgary, Ab t2r 1m7P: (403) 663-0083 | F: (403) 663-0086www.albertaoil.net

CANAdIAN CENTRE fOR ENERgY1600, 800 - 6 Ave SWcalgary, Ab t2P 3G3P: (403) 263-7722 | F: (403) 237-6286www.centreforenergy.com

JUNEWARREN-NICkLE’S ENERgY gROUp2nd Floor, 816 - 55 Ave Necalgary, Ab t2e 6y4P: (403) 209-3500 | F: (403) 245-8666www.junewarren-nickles.com

OIL & gAS NETWORk300, 840 - 6 Ave SWcalgary, Ab t2P 3e5P: (403) 539-1165 | F: (403) 206-7753www.oilgas.net

OILWEEk mAgAZINE2nd Floor, 816 - 55 Ave Necalgary, Ab t2e 6y4P: (403) 209-3500 | F: (403) 245-8666www.oilweek.com

dIRECTORY


832535roke Technologies

1/2h · hp

470129GLJ Petroleum Consultants

1/2h · hp


483674Alberta rig Mats

1/4h · tqc5250 Centre Street

New Sarepta, Alberta

Canada T0B 3M0

tel: (780) 941.3555

fax: (780) 941.3530

www.albertarigmats.com

1.866.941.3555

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.

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.

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 fol-

lowing 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 meth-

ane 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.

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.

desorption/desorbed

Removal of an adsorbed or absorbed substance from its ad-

sorbed state.

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 indus-

try is commonly referred to as the downstream sector.

drilling mud

A mixture of clay, water and other ingredients that is pumped down-

hole 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.

› gLOSSARY


829432Perpetual energy inc

1/4h · tqcSTOCK EXCHANGE LISTING | TSX | PMT

BOLD IDEAS FOR ENERGYPerpetual Energy explores for, produces and markets oil and gas based energy,

targeting to be the energy investment of choice, generating sustainable, premium

after-tax returns. Through resource style plays and new ventures with high-impact

potential, we are exposed to opportunities that can dramatically reshape the

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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 resour-

ces 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 pump-

ing fluids such as water, CO2, 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

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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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 occasion-

ally in the darcy range. Unconventional or tight reservoirs usually

have permeabilities in the micro- to nano-darcy range (one-

millionth of a millidarcy).

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.

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.

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 be-

coming less clear, but unconventional gas is more dif ficult to

produce. It requires specialized drilling, completion and produc-

tion techniques. The actual composition is usually the same as

conventional natural gas—predominantly methane.

upstream

The exploration, development and production sector of the petrol-

eum industry.

Wellbore

A hole drilled into the earth, usually cased with metal pipe, for the

production of gas or oil.

gLOSSARY


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Documents

CSUG - Canadian Society for Unconventional Gas May 2011