Oil & Gas Inquirer July/August 2013

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New tight gas plays driving natural gas liquids infrastructure boom

Plus: Tracking the oil boom in central Alberta

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CONTENTS

July/august.13

in the news

The coming labour crunch

regional news

British Columbia

Central Alberta

West Coast refinery makes no sense,

Tourmaline Oil pumps up

says Ervin

Deep Basin production

Northwestern Alberta

CNRL builds tight oil production in northwestern Alberta

Northeastern Alberta

Oilsands sulphur production

Southern Alberta

Crew updates Pekisko operations

Saskatchewan

Lightstream Resources expanding Bakken EOR program

creating challenges

features Cover Feature

48 53 58 Wet shale A boom is underway, turning huge natural gas liquids resource from tight rock into reserves

Bright spot Rush of natural gas liquids drilling driving billions in infrastructure spending

Ramping up in central Alberta Cardium pushes oil production in province, but natural gas about to make a comeback

business intelligence

Tax credit can add up to big savings for R&D companies

every issue

8 Stats at a Glance 62 Political Cartoon Cover design: Peter Markiw; Image: Jeremy Seeman

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Editor’s Note Vol. 25 No. 6 editorial Editor

Darrell Stonehouse | dstonehouse@junewarren-nickles.com Contributing writers

Jim Bentein, Godfrey Budd, Lynda Harrison, Carter Haydu, Richard Macedo, James Mahony, Pat Roche, Elsie Ross, Paul Wells

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The rail disaster in Lac-Megantic, Que., will go down as one of the worst manmade calamities in Canadian history, and will stand as a black eye for the oil industry for the foreseeable future. Dozens are dead and a town obliterated after a runaway train carrying oil from North Dakota exploded in the town core. The blame game has begun with most fingers pointing at Montreal, Maine & Atlantic Railway, Ltd., which owned the train. Deservedly so, but there are plenty of others who played a role in this tragedy. The Canadian government shoulders some responsibility. Regulating railways falls under its jurisdiction, and it failed to get the rail companies to reroute trains carrying dangerous goods around populated areas despite a number of close calls leading up to the July 6 disaster. The most famous incident happened in 1979 when 200,000 people had to be evacuated from Mississauga after a train carrying toxic chemicals derailed in the Toronto suburb. Just a week before the Quebec tragedy, Calgary had a close call when a bridge collapsed with tanker cars filled with diluent balanced over the Bow River. U.S. President Barack Obama also shares some blame. His indecision on the Keystone XL Pipeline caused the spike in oil being hauled by rail. Nearly 70 per cent of Bakken oil, or over 500,000 barrels per day, is on the tracks because of pipeline constraints. Obama allowed this situation despite data from his own Department of Transportation showing rail has the worst

GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

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record when it comes to spills, with 651 incidents per billion ton-miles per year. Oil pipelines have the fewest problems, with 0.61 serious incidents per billion ton-miles. A cynic would say Obama delayed Keystone XL because the crude bottleneck at Cushing, Okla., was depressing North American prices and giving the American economy a subsidy estimated at as much as $40 billion annually. Or he was doing a favour for a major donor, billionaire Warren Buffet, who has seen shipments of crude increase on his BNSF Railway Company by almost 7,000 per cent since 2008. And yes, I’m a cynic. The green lobby is also responsible. It targeted the pipeline industry as a backdoor means to attack the oilsands industry. A more realistic leadership in the environmental community would understand the need for energy and work to mitigate the risks rather than taking an all-or-nothing stance. David Suzuki, Greenpeace—this means you. Provincial, state and federal governments in Canada and the United States all share responsibility for not working together to create a regulatory environment allowing for the transportation of oil in an efficient, safe manner. Five years is too long to get a pipeline approved. There’s plenty of blame to go around. The question is who will take responsibility and fix it before the next train leaves the tracks.

N E XT I S S U E September 2013 The new technologies driving in situ oilsands developments, along with a look at tight oil development in southwestern Saskatchewan.

Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.

O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

FAST NUMBERS

13,000

53,000

Number of tankers of oil shipped by Canadian Pacific Railway (CPR) in 2012.

Number of tankers of oil expected to be shipped by CPR in 2013.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Jun 2012

205

254

Jun 2012

376

Jul 2012

348

488

Jul 2012

660

105

873

Aug 2012

380

541

Aug 2012

682

148

986

449

Sep 2012

447

524

Sep 2012

813

908

Oct 2012

588

691

Oct 2012

1,121

105

1,269

Nov 2012

535

137

750

Nov 2012

930

214

1,250

802

164

1,054

Dec 2012

483

105

639

Dec 2012

Jan 2013

313

381

Jan 2013

542

645

Feb 2013

449

124

640

Feb 2013

899

161

1,161

Mar 2013

544

149

119

812

Mar 2013

949

198

127

1,295

Apr 2013

481

129

701

Apr 2013

581

146

127

868

Jun 2013

179

266

Jun 2013

273

405

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

OTHER

TOTAL

Jun 2012

334

Jun 2012

144

154

Jul 2012

401

Jul 2012

232

248

Aug 2012

454

Aug 2012

296

309

Sep 2012

465

Oct 2012

Sep 2012

302

310

493

Oct 2012

453

480

Nov 2012

346

372

Dec 2012

282

317

Jan 2013

174

179

Feb 2013

358

389

Mar 2013

323

342

Apr 2013

Jun 2013

Nov 2012

571

Dec 2012

636

Jan 2013

Feb 2013

Mar 2013

139

Apr 2013

208

Jun 2013

330

*From year-to-date

OTHER

j u ly/a u g u s t 2 0 1 3 â&#x20AC;˘ O I L & G A S I N Q U I R E R

Stats

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, July 10, 2013 Source: Rig Locator

Alberta, June 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E

OIL WELLS

Alberta

GAS WELLS

Jun 13

Jun 12

Jun 13

Jun 12

213

375

588

36%

Northwestern Alberta

British Columbia

73%

Northeastern Alberta

Manitoba

52%

Central Alberta

100

Saskatchewan

134

56%

Southern Alberta

343

460

803

43%

TOTAL

179

205

WC Totals

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, July 10, 2013 Source: Rig Locator

Alberta, June 2013 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada

Alberta

AC T I V E

C OA L B E D M E T H A N E

Alberta

BITUMEN WELLS

Jun 13

Jun 12

Jun 13

Jun 12

370

322

692

53%

Northwestern Alberta

44%

Northeastern Alberta

50%

Central Alberta

Saskatchewan

138

219

63%

Southern Alberta

WC Totals

527

425

952

55%

TOTAL

125

110

British Columbia

Manitoba

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IN THE

NEWS Issues affecting Canada’s E&P industry

crunch

The coming labour crunch By Darrell Stonehouse

The corridors of office towers in downtown Calgary are populated by old geezers a few years away from retirement and there are few young people lining up to take their places, according to the Oil & Gas Global Salary Guide 2013 produced annually by expert recruiters Hays Oil & Gas and leading job site Oil and Gas Job Search. The salary guide found more than half (54 per cent) of Canadian oil and gas employers cite skills shortages as a significant issue, and almost three-quarters (73 per cent) expect to increase hiring in the next 12 months. Furthermore, fewer and fewer young Canadian professionals are entering the oil and gas labour force, a trend that is at odds with the rest of the world. Only 18 per cent of the current Canadian labour force is under 35 years old, while that same age group makes up 33 per cent of the world’s oil and gas labour market. Canada has too many older employees—42 per cent are

between 35 and 49 years old, and another 40 per cent are 50 years old and over. “The Canadian oil and gas industry is watching its talent supply dry up,” said Jim Fearon, regional director for Hays western Canada. “A high volume of oil and gas employees are approaching retirement, and without attracting a younger workforce and addressing skills shortages this sector is facing major challenges to meet its growth potential. Having a robust strategy in place to tap into the global talent pool will be critical in the short term, and working on strategies to increase the level of homegrown entrants into the industry is going to be vital in the medium to long term.” The survey found there isn’t any one company or job type that will be impacted by these challenges more acutely than others—contractors, operators, oilfield services, project managers, drilling engineers and estimators, it will affect them all equally.

The United States is in a similar situation to Canada when it comes to skilled worker shortages. Hays Oil & Gas reported that almost half (43 per cent) of U.S. oil and gas employers cite skills shortages as a significant issue, and two-thirds (66 per cent) expect to increase hiring in the next 12 months. Only 12 per cent of the current American labour force is under 35 years old. The United States is heavily reliant on its older professionals, and almost two-thirds (59 per cent) are 50 years old and over, creating a worker replacement ratio of 0.25. That means that there is only one young professional for every four approaching retirement. “ Wit hout a water shed moment, Americans will miss out on the contributions this sector makes to the overall economy,” said John Faraguna, global managing director for Hays Oil & Gas. “The industry is taking great strides to attract

Oil and gas professionals working in Canada earn on average $125,680 per annum. Over the next 12 months: 38% of employers expect to increase salaries by up to 5% 31% of employers expect to increase salaries between 5–10% 8% of employers expect to increase salaries by more than 10%

Photo: Joey Podlubny

20% of employers expect to keep salaries at the same level Top three benefits offered to Canadian oil and gas employees: 38% receive bonuses 33% receive a health plan 25% receive a pension Around 40 per cent of Canada’s workforce is over 50 years old.

Source: Hays Oil & Gas O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

In The News

young professionals and has increased graduate salaries by more than 17 per cent since 2012. However, flexible immigration policy will also be needed to bring in muchneeded imported talent, or U.S. companies may choose to relocate work to where sufficient skills exist.” Some job t y pes are more affected by skills shortages than others south of the border. Experienced professionals with advanced degrees in subsea engineering, reservoir engineering and the geosciences, particularly with nonconventional experience, are in greater demand and can expect higher salaries as a result. Lower-skilled workers, primarily in field positions, can expect salaries to stay flat or decrease. Back in Canada, the oilsands industry remains particularly challenged on the labour front, according to a new report from the Petroleum Human Resources Council of Canada. While Canada’s oilsands sector enjoyed strong growth in 2012, adding 2,100 positions due to stable oil prices and strong

investment, the industry’s optimism is tempered by emerging issues around market access. “The oilsands industry in Canada is changing,” says Cheryl Knight, executive director and chief executive officer of the organization. “To meet the challenge and sustain growth into the future, new approaches to technology, collaboration, transportation, the environment and labour are being developed.” One of the major challenges the sector faces is an ongoing labour shortage that will continue, despite the current operating environment. “Even if expansion plans fall short of expectations, the oilsands still needs over 6,500 workers in the next 10 years just to replace retirees,” says Knight. “And if everything goes according to plan, the oilsands’ workforce will grow by an additional 16,000. Once you throw in turnover, we’re talking about nearly 32,000 job openings over a decade. That’s significant.” Direct operational staff such as power engineers, heavy equipment operators

and petroleum engineers will make up a large part of the demand, according to the council’s findings published in The Decade Ahead: Oil Sands Labour Demand Outlook to 2022. These three occupations could generate nearly 7,500 job openings from industry expansion and age-related attrition alone. The skills shortage even extends to external industries the oilsands operations sector relies on, like support services, manufacturing and construction (indirect operations). The report highlights several current and future workforce strategies that could help meet the labour needs of the oilsands operations sector for the next decade, including working more collaboratively with government and education institutions to provide targeted training, partnering with First Nations, and reaching out more effectively to workers beyond the borders of western Canada. “Finding enough workers will be a challenge,” says Knight. “But the oilsands sector is working to solve its labour issues with some smart Canadian solutions.”

Enhanced recovery

Enhanced recovery could double conventional oil reserves, says new study By Pat Roche

Solvent- and polymer-based floods could increase Alberta conventional oil recovery by as much as 1.89 billion barrels, a study says. To put that in perspective, Alberta’s remaining established reserves of conventional crude are estimated at 1.7 billion barrels. In other words, at the high end of the study’s estimate, miscible and polymerbased flooding could more than double Alberta’s remaining recoverable reserves of conventional oil. Titled Ident if icat ion Of Enhanced Oil Recovery Potential In Alberta Phase 2, t he 629-page st udy was done by Calgary-based engineering firm Sproule Associates Limited for the Alberta Energy Regulator (AER). The study was led by Chris Galas, a partner at Sproule and its manager of reservoir studies. Ga l a s out l i ne d t he f i nd i ng s at GeoConvention 2013, the joint conference 12

j u ly/a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

of the Canadian Society of Exploration Geophysicists, the Canadian Society of Petroleum Geologists and the Canadian Well Logging Society. “First ly— and t his was somewhat surprising to me—there are very many technical successes for enhanced oil recovery in Alberta which have significant increases in recovery,” Galas told the conference. “Vertical miscible floods in Pembina and Rainbow were particularly effective. Polymer and ASP [alkaline surfactant polymer] floods were also successful.” The study screened 11,000 oil pools in Alberta and identified 3,000 pools that have solvent flood potential and 1,400 pools with ASP or polymer potential. It estimates that solvent flooding or miscible f looding—the terms are used synonymously—could increase oil recovery by between 65 million and 224 million cubic metres.

And the report estimates that chemical flooding—polymer and ASP flooding— could increase oil recovery by between 35 million and 75 million cubic metres more than could be produced by conventional waterflooding. So the total additional oil that could be recovered by both processes in Alberta is estimated at between 100 million and roughly 300 million cubic metres. Project goals were to retrieve information on all past and present enhanced oil recovery (EOR) schemes in Alberta, assess the success factors, develop criteria for screening future EOR prospects, apply the screening criteria to all oil pools in Alberta and estimate the potential increase in recoverable oil. The two EOR processes examined in detail were solvent, or miscible, flooding and chemical flooding. Miscible floods inject a solvent such as an enriched gas or CO2 into the reservoir.

In The News

The gas goes into solution with the oil, causing it to swell so more oil is displaced from the pore spaces. The solvent also increases reser voir pressure and reduces viscosity—all of which increase oil recovery. Chemical flooding refers to waterfloods where the sweep efficiency is enhanced by adding a polymer, or thickening agent, to injected water so the viscosity of the injected fluid more closely matches the viscosity of the heavy oil in the reservoir.

Number of pools with potential for enhanced oil recovery in Alberta:

200 734 382 1,701 1,396 935 196 214 196 1,434

pools for vertical solvent floods pools for horizontal solvent floods pools for combination solvent floods pools for sandstone solvent floods pools for ASP floods pools for polymer floods

pools for cyclic steam pools for steam floods

n 2010 Predator was involved in a flash fire testing at a university for FR rated coveralls. A discussion arose about a garment that could not only give the best FR protection, but based on early lab results, reduce the potential and severity of hot fluid transfer burns to the wearer. Intrigued, Predator embarked on a cooperative field test in 2011 and the results were greater than anticipated. Convinced, we worked closely with Westex to create a one and only, unique to our industry, ‘Hybrid’ Coverall. Once again proving that working with industry, we can design a safer workplace for our future.

pools for SAGD pools for in situ combustion Source: The Alberta Energy Regulator

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Alkali and surfactant may also be used with the polymer. Surfactant reduces the interfacial tension between the oil and water. In plain language, it is a detergent that washes the oil off the rock. However, surfactants are relatively expensive. Alkalis such as sodium hydroxide, sodium carbonate and sodium orthosilicate can be used instead of surfactants due to their lower costs. Alkalis are intended to react with acids in the oil, creating in

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In The News

“ A study like this [by the Alberta Energy Regulator] can go into incredible detail, can go through every one of those 11,000 pools and screen them carefully and so on. And what really limits how much detail you can go into is the budget, which was very limited.” — Chris Galas, manager of reservoir studies, Sproule Associates Limited

situ surfactants. However, the report said it is usually difficult to sufficiently lower the interfacial tension with alkalis to significantly reduce the residual oil saturation. Both surfactants and alkalis are often used with polymers for better mobility control. Because the study was funded by the Alberta government, it obviously didn’t look at EOR potential in other provinces. Nor does it include Alberta’s oilsands regions. Also, Galas pointed out the results are based on a preliminary screening. “A study like this can go into incredible detail, can go through every one of those 11,000 pools and screen them carefully and so on. And what really limits how much detail you can go into is the budget, which was very limited,” he said. Hence the study just used readily available information on the 11,000 oil pools. So features that are difficult to obtain from regular databases—for example, bottom water—weren’t included. Also, “permeability for the 11,000 pools would take an enormous amount of time to calculate,” he added.

The study estimated the amount of oil that could be recovered by each process, but didn’t assess the economics. “There’s a certain benefit to that because prices vary so much: trying to put economics in at any particular time means that your results are limited to that time frame,” Galas said. Project goals included identifying all Alberta EOR projects and the range of parameters of successful floods. Based on those ranges, screening criteria were developed. All Alberta oil pools were screened for chemical and miscible flooding potential and a range of recovery factors were estimated. Data sources included the A ER’s reserves report, viscosity and permeability estimates, well location maps, pool production profiles, progress reports and 177 technical papers. Viscosity data—a key parameter for chemical flooding— came from more than 2,000 oil samples with three temperature/viscosity points and gravities ranging from eight to 61 degrees API, and ages ranging from Upper Cretaceous to Devonian.

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BRITISH COLUMBIA WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

JUN/12 JUN/13

Wells spudded

JUN/12

JUN/13

Rigs released

▼

▲

Source: Daily Oil Bulletin

B.C. British Columbia

West Coast refinery makes no sense, says Ervin By Jim Bentein

The 550,000-barrel-per-day Kitimat Refinery would cost $16 billion and would likely be accompanied by an oil pipeline that would cost $6 billion, a $2-billion gas pipeline and tankers that would cost $1 billion. It is being proposed by David Black, the chief executive officer of Black Press Group Ltd., which owns a chain of daily and weekly newspapers. Black is a novice in the oil and gas industry and the project, first announced about a year ago, has been met with skepticism among those in the industry. However, in mid-April he announced the Industrial and Commercial Bank of China, one of the world’s largest financial institutions, had agreed to act as a financial adviser to Kitimat Clean Ltd. as well as providing an equity investment. That level of investment was not disclosed. Ervin thinks the crack spreads, the differential between the price of crude oil and the petroleum products extracted from it,

Photo: Joey Podlubny

The chances of a proposed $25-billion oil refinery being built on Canada’s West Coast are virtually nil, according to one of Canada’s foremost experts on the refining sector and other aspects of the downstream oil and gas industry. Michael Ervin, principal of Calgarybased MJ Ervin & Associates, a division of Ontario-based The Kent Group, said that despite an announcement in mid-April that a Chinese-based bank would provide financing for privately held Kitimat Clean Ltd. to develop the refinery, which would process oilsands crude and other crudes, there is no business case for the project. “It makes no sense to build a refinery of that size on the West Coast, especially when you consider China itself is adding refineries that will be able to process three million barrels a day of crude in the next five years,” said Ervin. “The economics just don’t add up.”

The Kitimat Refinery would be bigger than existing refineries in Alberta. The proposed refinery would compete with refineries in China, says Ervin.

will never make economic sense at a large new West Coast refinery. Capital costs and operating costs would be too high as well. Black is proposing to export the refined products mostly to Asia, which Ervin says does make sense. But with the Chinese building their refineries, there is no argument that can be made for such a large new refinery in Canada.

Kitimat Refinery by the numbers Capacity:

550,000 barrels per day of diluted bitumen

Products:

100,000 barrels per day of gasoline, 50,000 barrels per day of jet fuel, 250,000 barrels per day of diesel fuel

Projected export revenues: $16 billion per year

Construction jobs: 6,000 for five years

Permanent jobs: 3,000 jobs

Taxes:

Up to $1 billion annually

Ervin said any industry support for such a refinery will quickly fade once western Canadian crude finds its way to more markets, both in the United States and Asia. And he is confident that will happen. For one, he believes that TransCanada Corporation’s controversial Keystone XL Pipeline, which would move about 830,000 barrels per day of mostly western Canadian crude to the U.S. Gulf Coast, will be approved later this year by U.S. President Barack Obama. He also believes the Kinder Morgan’s Trans Mountain pipeline expansion, which would increase capacity on that line to 750,000 barrels daily, has a good chance of going ahead. Despite opposition to that expansion from West Coast politicians and O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

British Columbia

environmentalists, the fact that it is an expansion of an existing pipeline makes it likely to receive regulatory approval, he believes. Even if environmentalists and B.C. politicians manage to stop Enbridge Inc.’s plans to move 525,000 barrels daily of oilsands crude to the West Coast on its proposed Northern Gateway Pipeline, Ervin believes there would be enough options to move oil to markets to render plans for new refineries in Canada suspect. North West Redwater Partnership’s new Sturgeon Refinery, which will upgrade and refine 50,000 barrels per day of oilsands crude, with prospects for two more phases

of 50,000 barrels per day, is a special case, since it will produce diesel (for which there is strong demand in western Canada), diluent for the oilsands (also in great demand) and petrochemical feedstock. A side f rom that and some added upgrading capacity, such as Canadian Natural Resources Limited’s plans to eventually upgrade as much as 500,000 barrels daily at its Horizon oilsands plant, up from a little more than 100,000 barrels daily now, and the possibility of Calgarybased Value Creation Inc. going ahead with the first 77,500-barrel-per-day phase of a long-delayed 260,000-barrel-per-day

upgrader, he said there is little need for additional upgrading or refining of crude within Canada. That’s because U.S. Gulf Coast refineries can upgrade and refine at least three million barrels per day of heavy crude and are eager to process as much as can be sent there by pipeline and rail. “There are refineries there that already have a capacity to handle heavies,” he said. Added to the fact that the new refineries being built in China want western Canadian heavy crude, there should be adequate markets well into the future, he said.

Pressure pumping surplus short term, says Canyon By James Mahony

For a Canadian market oversupplied with pressure pumping equipment, LNG-focused drilling in British Columbia and Alberta will be a light at the end of the tunnel, one of the industry’s contractors said in June. Although drilling in Alberta’s Duvernay and B.C.’s Horn River Basin has a way to go, as it gains pace, it will eventually use up excess pressure pumping hardware in western Canada, Brad Fedora, president and chief executive officer of Canyon Services Group Inc., told investors at the company’s annual meeting in Calgary. For every billion cubic feet of liquefied natural gas (LNG) Canada plans to send abroad, the industry will have to drill 150 wells just to keep production level, and most of those will be drilled in the Montney and Duvernay formations and in the Horn River Basin, he said. “That means you’re going to have an extra 750–1,500 wells incremental to the activity that we see today, just to maintain production,” Fedora told shareholders. “Given the expected activity in those plays and the Deep Basin in general, we feel that in 2014 or early 2015, this basin will be undersupplied with frac equipment,” he said. “We expect 2014 to be a much busier time,” he added, explaining that just a small change in drilling activity causes a disproportionate shift in demand for pressure pumping services. Just a 10 per cent change in drilling, for example, results in a 30 per cent change in demand for pumping, he said. 18

J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

“ We expect 2014 to be a much busier time.” — Brad Fedora, president and chief executive officer, Canyon Services Group Inc.

The equipment surplus in western Canada’s pressure pumping market goes back to 2012 and has affected Canyon’s results, among others. As a consequence, utilization in the industry is down, and pricing has suffered accordingly. Today, Fedora estimated the Canadian sector is working at about 60 per cent utilization. Still, if it’s any consolation to Canyon shareholders, the situation south of the border is worse. Fedora estimated that the U.S. pressure pumping market has roughly seven to eight times the pressure pumping equipment Canada does, and competition is fierce. That’s one reason Canyon has stayed out of the U.S. market, a decision Fedora reiterated. “Our five-year plan is Canada-only,” he said. “From an open-market perspective, Canada is—without a doubt—the best place for us to invest to get good returns on invested capital.”

Apart from industry trends to longer horizontal wells and more frac stages, Fedora said a movement toward 24-hour operations is gaining pace, although it’s also putting a big strain on the people who do the work. Due to a limited supply of workers, operating some crews 24 hours means shutting down other equipment to make crews available, he added. “We’re seeing times when we’ll have 100 per cent of our people utilized but only 50–60 per cent of our equipment utilized. We’ve budgeted...for the remainder of this year to add staff, not only to prepare for more utilization in 2014, but also to better respond on a 24-hour basis.” Over the next six to 12 months, he expects pricing in the Canadian pressure pumping sector to remain stagnant. Despite a roughly $25-million capital program in 2013, Canyon, which currently has a total of about 225,500 hydraulic horsepower in pumping capacity, will add no further pressure pumpers this year. “I think we’ll see rates firm up at the end of this year or early next year, given the activity we expect in the Montney, Duvernay and the greater Deep Basin plays,” he said. Canyon is applying to boost its bor row ing capacit y to t he $80 -m i l l ion-to -$10 0 -m i l l ion ra nge, which would be used for expansion, either through acquisitions or for organic growth, Fedora said.

British Columbia

Costs could derail LNG projects, warns consultant By Elsie Ross

While B.C. LNG projects would spark a resurgence in natural gas drilling in western Canada, a major limiting factor may be rising capital costs, said a U.S.-based consultant. “All this infrastructure is put in place at the same time,” Kevin Petak, vice-president of gas market modelling for ICF International, Inc. in Fairfax, Va., told the Canadian Energy Research Institute Petrochemical Conference. In addition to the LNG infrastructure, the projects will require the construction of major pipelines to transport gas to the coast.

B.C. LNG projects and owners

ICF’s base case calls for about nine billion cubic feet per day of LNG exports from North America by 2025. The figure includes 2.7 billion cubic feet per day out of western Canada and four U.S. projects totalling six to seven billion cubic feet per day. “There’s a window of opportunity for the next 10 years,” he said. In the face of competition from other areas such as Australia and North Africa, the consultant believes that North America will attract 30–40 per cent of the global LNG demand.

Asian demand growth for LNG is one of the drivers for exports and B.C. terminals have an advantage over the United States because they are closer to China while the colder climate makes the liquefaction process more efficient, said Petak. However, regulatory concerns around fracturing regulations and carbon emissions could create uncertainty, he said. Another uncertainty is how LNG will be priced. While ICF believes it will continue to be priced as a function of oil, there’s a question of what percentage of oil it’s priced

Kitimat LNG:  Apache Canada Ltd. and Chevron Canada Limited each own 50 per cent of the

Imperial Oil/Exxon LNG Project: Imperial Oil

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at, the conference heard. “That relationship could begin to breakdown over time, particularly as you start to see Asian development of resources—and certainly shale gas resources in China,” he said. In addition, Canadian LNG exports could face increasing competition from other global players, including the United States, Australia and North Africa. The 2015-25 period will be one of high expansion when sources of market growth come together, Petak suggested. However, cost pressures across the board over that period could be a limiting factor in whether some LNG projects proceed, he predicted. Gas-fired power generation will be an important source of market growth as the economy recovers and coal-fired power plants are retired for environmental reasons. Also contributing to the demand will be petrochemical- and natural gas– fuelled vehicles. ICF is forecasting Henry Hub natural gas prices of US$4 per million British thermal units through to 2015 before they rise to $5–$6 per million British thermal units, driven by market growth. Western

Canadian prices are likely to be 50 cents to $1 per million British thermal units lower. At the same time, North American shale gas production is forecast to nearly double to 65 billion cubic feet per day by 2025, up from today’s 33 billion cubic feet per day. By 2035, Marcellus shale gas production is forecast to grow to 20 billion cubic feet per day—about 25 per cent of total production of 80 billion cubic feet per day. In Canada, ICF’s middle-of-the-road estimate indicates 526.6 trillion cubic feet of resources from the Montney, Horn River, Cordova Embayment and other resource plays, said Petak. The company, though, hasn’t fully evaluated some of the newer plays so, if anything, those numbers could actually increase, he said. “There’s a lot of molecules that are cost effective in that $5–$6-permillion-British-thermal-units ballpark.” The North American LNG trade would also result in a modest increase in natural gas prices, the conference heard. An ICF study commissioned by the American Petroleum Institute to look at the impact of LNG on the price of natural gas calculated that the price would increase

by eight to 11 cents per billion cubic feet of LNG exports, he said. For a 15-billioncubic-foot increase in exports, that would amount to a pricing impact of $1.20–$1.50 per million British thermal units. The study also found that 80 per cent of the volume needed to accommodate the LNG exports would come from production increases, while the remaining 20 per cent would be from reduced demand due to the price increase, he said. “The drilling is the most important for western Canada because it provides certainty for gas production, and right now there’s a lot of uncertainty,” according to Petak. “Without the LNG exports, Western Canadian Sedimentary Basin natural gas production would probably be much flatter over time. You wouldn’t get as much growth in the shale gas production or you would get a bigger decline.” Western Canadian LNG exports could also have an impact on natural gas liquids production, making more liquids available for the petrochemical industry or, possibly more likely, going into the LNG stream itself as the Japanese market uses a richer stream, said Petak.

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J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

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NORTHWESTERN ALBERTA WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

197

187

JUN/12 JUN/13

Wells spudded

114

JUN/12

JUN/13

Rigs released

▼

Northwestern Alberta

▼

Source: Daily Oil Bulletin

CNRL builds tight oil production in northwestern Alberta By Pat Roche

Canadian Natural Resources Limited (CNRL) says its tight oil drilling results in northwestern Alberta compare favourably with those reported in the Permian Basin. Drilling in the Permian Basin of western Texas has been contributing to the boom in U.S. domestic light oil production. Since acquiring a large gas-weighted asset in the Grande Prairie, Alta., area in 2010, CNRL has grown the property’s oil

CNRL Grande Prairie tight oil by the numbers • 1.4 million net acres

• Average horizontal initial production: 448 boe/d

• 14 tight crude oil horizontal targets

•A verage horizontal expected ultimate

• Five-year plan to drill 300–500 wells

CNRL Grande Prairie Drilling Results Project Montney Dunvegan

Photo: Joey Podlubny

Halfway

CNRL has grown oil production in the northwest by 90 per cent in the last two years.

recovery: 417,000 boe

Wells drilled

One-Month IP (boe/d)

Average EUR (mboe)

Drilling and completion ($,000s)

Identified drilling locations

455

423

4,572

285

294

3,900

450

460

5,250

output by roughly 90 per cent and expects to exit 2013 at 23,000 barrels per day, said Jeff Wilson, senior vice-president of exploration. During the past two years, CNRL has been testing several tight oil plays in the area, which boasts 14 formations with horizontal initial-production rates exceeding 100 barrels per day. So far, the company has concentrated on the Montney, the Halfway and the Dunvegan formations in the region, where it owns 1.4 million net acres. “Since 2011, we have drilled 56 successful wells and have first-month average IPs [initial production rates] that range from 285 to 455 barrels per day, and average EURs [estimated ultimate recoveries] that range from 294,000 to 460,000 barrels per well,” said Wilson. He commented, “The high-ranked Permian Basin has achieved similar average results and at a high level provides a benchmark and compares favourably with the results we have achieved.”

His presentation included a slide quoting Permian Basin horizontal initial production rates of 448 barrels per day and estimated ultimate recoveries of 337,000 barrels per well. CNRL says its Grande Prairie tight oil drilling and completion costs range between $3.9 million and $5.25 million per well. “Based on the level of success we have experienced, we are preparing to ramp up the pace in this area,” Wilson said. “We currently have 136 locations in the hopper. And with continuing success and increased technical focus, the activity contained in our five-year plan will range from 300 to 500 wells.” He attributed the production growth to drilling success, field optimizations and well workovers. Wilson said the Grande Prairie team reduced drilling and completion costs by using pad drilling as much as possible, by changing drilling fluids and by increasing the proportion of saline source water used for completions. O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Northwestern Alberta

“We have made improvements in our completion technology and optimized our frac fluids. By drilling longer laterals, optimizing frac sizes and using tighter frac spacing, we have achieved higher production,” he said. Besides northwestern Alberta, CNRL concentrated on four other tight oil or natural gas liquids areas last year—the Bakken (Exshaw) Formation in southern Alberta, the Jurassic in southwestern

Saskatchewan, the Viking in Dodsland and the Devonian in central Alberta, Wilson said. This year, the company plans to spend $490 million across all its light oil and natural gas liquid (NGL) plays, down from $570 million last year. It plans to drill 114 net producers, down from 124 last year. But despite the lower planned spending and well counts, the company expects

its light oil and NGL production to average 65,000–69,000 barrels per day this year, up slightly from 64,000 barrels per day last year. Light oil and NGL output averaged 67,000 barrels per day in the first quarter, up six per cent from the same period last year. As well, the company’s light oil division expects to manage about 100 existing waterfloods and two enhanced oil recovery projects this year.

Strong first-quarter results drive Birchcliff Energy to up 2013 budget Birchcliff Energy Ltd. was firing on all cylinders in the first quarter of 2013, with a major increase in production, along with lower operating costs compared with the same period last year. The company’s success has resulted in a planned increase in 2013 spending. Production averaged 26,108 barrels equivalent per day, a 24 per cent increase from 21,016 barrels per day in the first quarter of 2012.

Operating costs were driven downward as a result of the bringing the Pouce Coupe South gas plant on stream, which had costs of approximately $0.28 per thousand cubic feet or $1.68 per barrels equivalent. Birchcliff processed 68 per cent of its natural gas production at the plant. On a corporate basis, operating costs declined to $5.77 per barrel equivalent, a decrease of 6 per cent from the first quarter of 2012. Total cash costs per barrel decreased 19 per cent to $15.43.

As a result of its first-quarter success, Birchcliff increased its capital budget to $246.6 million from $184.6 million. The new money is primarily directed toward the drilling of five (five net) additional Montney/Doig horizontal natural gas wells and $21.3 million for a recent land acquisition in the Pouce Coupe area on the Montney/Doig natural gas resource play. Birchcliff now has 2,032 horizontal drilling locations in the play, up from 1,929 net locations last year.

Long Run Exploration begins cranking up production Successful development drilling for Montney oil in the northwest and Viking oil at Redwater resulted in 3,000 barrels equivalent per day of incremental production for Long Run Exploration Ltd. in the first quarter of 2013. The majority of production additions in the first quarter were crude oil volumes, a trend that Long Run expects to continue through 2013. Total first-quarter 2013 exit production was approximately 26,300 barrels equivalent per day, ahead of budget forecast. Continued operational improvements in the Montney at Girouxville/Normandville and in the Viking at Redwater were responsible for increased exit production volumes. Long Run continues to be on track to meet its 2013 full-year average production guidance of 25,000 barrels equivalent per day. 26

J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

Long Run drilled 18 net wells in the Montney oil play, all of which were completed, equipped and on stream before the end of the quarter. At Redwater, Long Run drilled 30 (28.6 net) light oil wells. Capital expenditures totalled $103.9 million, with the Montney and Viking constituting the bulk of development spending. Production in the Peace River area averaged 9,453 barrels equivalent per day in the first quarter, an increase of 41 per cent over the 6,691-barrel-per-day average in the fourth quarter of 2012. The Peace River–area Montney contributed 40 per cent of Long Run’s first-quarter 2013 production volumes. T he company credits t he use of cemented liner completion design for yielding improved completion reliability in the Montney. Long Run believes operational

and engineering improvements in this play realized over the past several months will lead to an increased inventory of drilling locations and higher booked reserves in the longer term. Enhanced oil recovery (EOR) work in the Montney at Normandville is progressing on schedule, the company also reported. Water injection began on Apr. 1, 2013, on this project, with a response anticipated in 2014. Long Run believes this pressure maintenance program will improve recoveries, lower natural gas/oil ratios and enhance overall project economics. In the first quarter of 2013, Redwater production averaged approximately 5,195 barrels equivalent per day, more than 22 per cent of Long Run’s total production. Thirty (28.6 net) wells were drilled in this play during the first quarter, with 26 gross

Northwestern Alberta

Production by Long Run in the Peace River area averaged 9,453 barrels equivalent per day in the first quarter.

wells tied in. Higher production volumes have been achieved through modifications of drilling technique and completion technology. These improved results are driving strong project economics, Long Run reported. On-stream well costs remain at $1.2 million. Plans continue to advance EOR work in this play. To ensure that maximum value from this property is achieved, Long Run is moving forward with the initial stages of a pilot water injection scheme and plans to implement injectivity before the end of 2013 to further test this concept. Long Run anticipates initial results from the early stages of this project to be available in 2014. Also during the first quarter of 2013, Long Run recompleted a 100 per cent working interest vertical well into the Duvernay located in the Smoky Heights area at 03-26-072-02W6. Initial testing recovered light oil and associated natural gas volumes. Additional analysis will be available in coming months when further testing is completed.

Red Earth program builds Pinecrest Energy production Pinecrest Energy Inc. achieved record first-quarter average production of 4,315 barrels per day (99 per cent light oil), an increase of 28 per cent from 3,358 barrels per day in 2012. Production growth was driven by the Red Earth play, where Pinecrest completed its first-quarter capital program in mid-March, having drilled and completed 12 wells (11.3 net). Subsequent to the quarter-end, the company was successful in bringing on stream all of the wells drilled in the first quarter. Pinecrest continues to refine its well design and, as a result, has seen its most recent well costs decrease to below $3.8 million, representing a savings of over $1.2 million (24 per cent) per well as compared to the same period in 2012. With drilling shutdown for spring breakup, Pinecrest is now focused on the implementation of its seven operated 2013 waterflood schemes. Results to date from the companyâ&#x20AC;&#x2122;s first two waterflood projects have been positive, with offset wells experiencing an increase in oil rates and reservoir pressures. To be prudent during the evaluation phase of the waterfloods, Pinecrest has chosen to truck the injection water to each new scheme. Consequently, these additional water hauling costs have contributed to higher operating costs during the first quarter. The responses experienced to date are similar to other analogous waterfloods in the greater O I L & G A S I N Q U I R E R â&#x20AC;˘ J Ul y / a u g u s t 2 0 1 3

Northwestern Alberta

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Red Earth area and provide additional support for the upside potential associated with waterflooding. In late March, the company began injection on its third waterflood project. The results of this project will be provided in the following quarterly reporting periods. Temporary increased regulatory approval times have caused minor delays in the implementation of the remaining projects. Two additional projects are now ready to be implemented, and injection on these two schemes will begin in the third quarter. Water injection on the final three projects located in the Evi field is scheduled to commence during the fourth quarter of 2013. Since inception, Pinecrest has established itself as one of the dominant interest holders in the high-quality Slave Point light oil resource play in the greater Red Earth area. The company has over 400 net risked drilling locations on its lands, which contain an estimated 580 million barrels of discovered oil initially in place, with very low recovery to date. Sproule Associates Limited conducted an assessment effective as of Jan. 31, 2012, of Pinecrest’s contingent Slave Point oil resources and has assigned the company a contingent resource best estimate of 67.5 million barrels using a 13 per cent recovery factor and based on a drilling density of four wells per section. The company believes that significant upside potential, over and above the contingent resource assignment, can be achieved through further infill drilling and waterflooding. This resource capture is consistent with the company’s stated strategy of focusing its capital and resources on large light oil accumulations with high netback production, long-term upside and the ability to increase recovery factors through the application of horizontal infill wells, multistage fracture stimulations and implementing waterflood recovery schemes. Analogous Slave Point waterfloods in the immediate area have proven to be very effective and have been assigned incremental recovery factors ranging between 50 and 100 per cent over primary recovery. For the balance of 2013, Pinecrest will execute an integrated capital program that will include drilling wells for primary production (five wells per section) and initial injection on an additional five operated waterflood schemes.

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NORTHEASTERN ALBERTA WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

JUN/12 JUN/13

Wells spudded

108

124

JUN/12

JUN/13

Rigs released

104

129

▼

▲

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Oilsands sulphur production creating challenges By Carter Haydu

Photo: Joey Podlubny

12,800 A mountain of sulphur at Syncrude. Nearly 9.5 million tonnes is stockpiled at the mine.

All living things need sulphur, and as it’s crucial to the growth of plants, it is a major component of fertilizer. A growing stockpile of sulphur in the oilsands region of northern Alberta has resulted in researchers and the industry faced with trying to figure out what to do with the yellow stuff. Com merc ia l bloc k i ng sta r ted at Syncrude Canada Ltd. in 1992, and by last year the sulphur block inventory had risen to 9.5 million tonnes, said Gerald d’Aquin, president of Con-Sul, Inc. As sulphur produced in northern Alberta is isolated from international markets, a major area of research is storage when it comes to dealing with sulphur production, said Paul Davis, general manager of Alberta Sulphur Research Ltd. A current project involves studying different coverings for block storage of sulphur. These in essence are barriers that protect the mineral from weathering and the environment from the mineral

when it has to be stored for long periods of time. According to d’Aquin, the Canadian sulphur industry is challenged by a shift in production to the oilsands accompanied by declining reser ves and drilling in regions where sour gas has provided a source of sulphur. In 2000, 6.5 million metric tonnes of sulphur were produced at sour gas plants, mainly in the Alberta foothills but, by 2009, production had collapsed to only 3.5 million tonnes and slipped further to 2.4 million tonnes of sulphur in 2012. At the same time, the foothills’ solid inventory—which had been as high as 16 million tonnes within the last decade—is now almost exhausted. “As a counterpoint, sulphur extracted from oilsands finally reached two million metric tonnes in 2012, thus total Alberta sulphur output for 2012 was 30 per cent lower than in 2000,” he said. In British Columbia, about 900,000 metric

tonnes per year of sulphur is extracted f rom sour gas, wh i le Sask atc hewa n heavy oil upgraders contribute perhaps 300,000 tonnes. In its year- end f inancial repor t, Santonia Energy Inc. noted its average realized sulphur price in 2012 was $120.35 per tonne, a decrease from $131.07 per tonne in 2011 as sulphur prices declined throughout last year. D’Aquin, whose company publishes a North American quarterly review in addition to undertaking normal consulting projects, said sulphur pricing is dependent on whether it is sold as a liquid for U.S. and domestic sales, or as a solid for export abroad, generally through Vancouver. “The point of production significantly affects plant value, especially as it pertains to more distant oilsands-derived sulphur,” he said. “It also does not benefit from the historical infrastructure found in the foothills, where sulphur has been produced since the 1950s.” O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Northeastern Alberta

Sulphur production from bitumen upgrading 1,000

1,102

800

882

600

661

400

441

200

220

0 2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

Source: Alberta Energy

Generally speaking, d’Aquin said, there are two indexes affecting Canadian sulphur prices—a “Tampa/Central Florida” index for molten products, which currently sits at $US150 per long ton in Tampa (plus or minus); and a “Vancouver” price in the case of solidified sulphur, which currently sits at $150 per metric tonne (with a wider plusor-minus range). Although individual gas plant netbacks are affected by location and infrastructure, most plants in Alberta should be selling sulphur for a positive return. “A decline of $30 per tonne may eliminate that return and send it to block storage, where possible. Much of the pricing outcome will depend on U.S. phosphate fertilizer manufacturing activity during the second half of 2013.” According to Statistics Canada figures, in 2012 Canada exported about

3.64 million metric tonnes of sulphur for a total value of $545.82 million, compared to 4.09 million metric tonnes for a total value of $686.26 million in 2011. The big year for the nation’s sulphur industry was 2008, when exports totalled 5.17 million metric tonnes and earned nearly $2 billion. Nexen Inc. is one of the oilsands producers with a sulphur component to its business. Davis Sheremata, company spokesman, said the CNOOC Limited subsidiary produces approximately 330 metric tonnes per day of liquid sulphur from operations at its Long Lake project near Fort McMurray. The company freights its sulphur to market via rail. According to Davis, sulphur from either sour gas or oilsands operations is produced by processing hydrogen sulphide and the resulting end product is

very similar. However, he said, a major difference is location because while there are transportation networks in place to move sour gas sulphur, oilsands sulphur is produced in a remote area, separated from the rest of the world by the Athabasca River. “It’s the same sulphur, but one is far away from export tidewater and the other not so much.” D’Aquin says that historically, Canadian sulphur has been removed from bitumen as part of the upgrading process. However, he believes shipping diluted bitumen to China would enable that country to process it and extract the petroleum coke and sulphur. “If you [process] it before you go over there, you’ll end up with sulphur and petroleum coke in northern Alberta with little that can be done with it except for stockpiling it, whereas if you ship it to China, they will be able to utilize the full amount.”

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J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

Northeastern Alberta

New funding model for oilsands monitoring created “ Scientifically credible, transparent monitoring in the oilsands area is important to ensure the public has confidence....” — David Pryce, vice-president of operations, Canadian Association of Petroleum Producers

Photo: Joey Podlubny

Industry will pay for monitoring under the new model.

The Alberta legislature has approved legislation that establishes a funding mechanism for Alberta’s enhanced oilsands monitoring program. T he f unding ar rangement established under Bill 21: the Environmental Protection and Enhancement Amendment Act, 2013 will enable Alberta to collect, hold and disburse funds from the oilsands industry to continue to implement the joint oilsands-monitoring program. The funding proposal was developed in collaboration with the industry and the federal government. The oilsands industry has committed to providing up

to $50 million per year for three years to support the joint oilsands-monitoring program. Funds will be disbursed to various parties to support environmental monitoring activities approved by the Alberta and federal governments under the joint plan. “Albertans expect continued excellence in the way this government manages resource development in the province,” Diana McQueen, minister of environment and sustainable resource development, said in a news release. “A clear and sustainable funding mechanism is the next step in ensuring on-going success of environmental monitoring of our oilsands in an open and transparent manner.”

“Scientifically credible, transparent monitoring in the oilsands area is important to ensure the public has confidence in the responsible development of this provincial and Canadian resource,” said David Pryce, vice-president, operations, Canadian Association of Petroleum Producers. “Bill 21 provides the mechanism to establish sustained funding, through an arms-length industry levy.” Significant steps have already been taken on the joint-monitoring program, including the addition of new water-quality sites on the Athabasca River and on the Muskeg River system, increased hydrocarbon air monitoring through the addition of more sampling sites, and enhanced biodiversity monitoring that includes all oilsands producing areas in the province. Additionally, Bill 21 removes the requirement for personal information numbers for hazardous waste management to ensure alignment, consistency and full integration of hazardous waste management practices across the province. — DAILY OIL BULLETIN

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CENTRAL ALBERTA WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

329

153

JUN/12 JUN/13

Wells spudded

172

116

JUN/12

JUN/13

Rigs released

164

▼

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Tourmaline Oil pumps up Deep Basin production

Photo: Joey Podlubny

By Darrell Stonehouse

Winter drilling success raised Tourmaline firstquarter production by almost 50 per cent over the previous year.

Tourmaline Oil Corp. reported a year-over-year production increase of almost 50 per cent in the first quarter of 2013 as the Deep Basin explorer continued to profitably exploit its huge land base on the Alberta border with British Columbia. Production for the first quarter of 2013 averaged 68,636 barrels equivalent per day, a 47 per cent increase over the first quarter of 2012 and a 20 per cent increase over the previous quarter. Tourmaline reported record after-tax earnings of $52.2 million in the quarter, up from $3 million the previous year. Tourmaline exited the first quarter with production of 75,000 barrels equivalent per day, without the contribution of ongoing major facility projects at Sunrise-Dawson and Spirit River. April production averaged approximately 74,350 barrels equivalent per day despite unscheduled downtime (third-party facility disruptions in northeastern British Columbia and at Edson, Alta.), representing eight per cent further growth over the first-quarter 2013 average. The new gas plant at Dawson-Sunrise and the gas-handling facility expansion at Spirit River were expected to bring an additional 12,000–13,000 barrels equivalent per day of shut-in production on stream during the month of June, bringing corporate production levels to approximately 86,000–88,000 barrels of oil equivalent per day entering the third quarter. Second-half facility expansions at Wild River and Minehead-Banshee in the Deep Basin, and pipeline debottlenecking at Spirit River will add substantial additional production volumes during the second half of 2013, continuing the strong quarterly growth trend. The company remains on track to meet or exceed the upward revised 2013 average

production target of 80,000 barrels equivalent per day. Tourmaline expects to exit 2013 producing natural gas volumes in excess of 500 million cubic feet per day in a period of improving natural gas prices. The company also expects to exceed the 15,000-barrel-perday, oil-and-liquids target by year-end. During the first quarter of 2013, Tourmaline drilled 20 new gas wells (18.2 net) and seven new oil wells and no dry holes. The company will operate 13 drilling rigs after breakup, an increase from the originally planned second half of 2013 11-rig program. Eight rigs will be employed in the Alberta Deep Basin: one pursuing multiobjective, seismically defined frontal foothills vertical targets; one rig will be testing Cretaceous Notikewin horizontal targets; and six rigs will be exploiting Cretaceous Wilrich horizontal targets. Major Wilrich development projects will be pursued at Minehead-Banshee, Lovett River, SmokyResthaven and Wild River during the second half of 2013. Of the 35 Wilrich horizontals drilled thus far in the 2012-13 time frame, 30 have initial production rates in excess of 10 million cubic feet per day. The company expects to drill and complete a total of 50 Wilrich horizontals during 2013, with the majority of these wells tied in by year-end. Two drilling rigs will be employed in northeastern British Columbia pursuing horizontal Montney gas-condensate targets, one at Sunrise-Dawson executing the ongoing development and the second exploiting multiple new opportunities at Sundown and Groundbirch. Two drilling rigs will be active in the Greater Spirit River area of Alberta, pursuing horizontal Triassic Charlie Lake oil and gas objectives. The final rig will be testing large reserve Paleozoic exploration opportunities in Alberta and northeastern British Columbia, beneath Tourmaline’s existing production complexes. Full-year 2013 capital spending of $770 million is currently anticipated. O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Central Alberta

Bellatrix in waiting mode on Duvernay Bellatrix Exploration Ltd. said it will for now watch the activity happening around it in the Duvernay and will let larger companies with more capital drill in the emerging play to improve drilling costs and well productivity. The company owns 53 gross sections, 52.6 net, in the wet gas fairway. The 09-24 well recorded a 90-day initial production of 3.7 million cubic feet per day with cumulative 0.57 billion cubic feet to date. It’s currently producing at 1.4 million cubic feet per day. Two step-out locations to the 9-24 well have been identified. “We have a good position in the Duvernay—we think we’re in a liquids-rich

area, albeit our first well stayed dry because we drilled right on top of a thrust fault,” Raymond Smith, president and chief executive officer, told the company’s annual meeting. “The wells around us have produced a lot of liquids.” But, he said, at current gas prices, the play is still borderline economic. “We’re allowing the larger companies, which have a lot more capital to invest, to continue to drill up the play and bring down the cost of drilling and bring up the results of the drilling to a higher-productivity level to entice us to get out and start drilling,” he said. “Certainly, the economics don’t

compare anywhere near the economics we have on the remainder of the plays in our portfolio.” The company recently reported a strong first quarter benchmarked by burgeoning production that averaged 19,343 barrels equivalent per day, compared to 15,900 barrels per day in the same period last year, while exiting the period at 23,000 barrels per day. The increase in volume was primarily a result of an increased capital program year-over-year and the associated drilling success achieved in the Cardium and Notikewin resource plays.

Angle increases use of slickwater fracs By Lynda Harrison

Angle Energy Inc. is in the top quartile among producers in the Cardium play in Harmattan partly because it learned from its peers to use slickwater fracturing, the company’s annual meeting heard. With oil at $90 and a cost of about $3 million per well, Angle is generating rates of return of more than 50 per cent on the project as a whole, said Heather Christie-Burns, president and chief operating officer. T he project compr ises about half of the company’s budget and has been a t wo -r i g f o c u s y e a r- to - d ate , s a id Christie-Burns.

Gregg Fischbuch, Angle’s chief executive officer, mapped out the change in technology that has occurred over the past three or four years in the Cardium. Initially a lot of drilling in the Cardium was done with oil or propane fracs on wells that typically ended up with break-even economics, said Fischbuch. But a big change occurred when slickwater fracs “started to take over,” he said. “People developed the containment tanks for the water; you didn’t have the big environmental impact surface, so we started to do it in the Cardium and all of a sudden you go from zero [net present

value] or break-even to something that’s making $2 million to $5 million per well in terms of net future discounted profit.” Angle has now drilled close to 30 wells in the Harmattan area and eight in the Viking using slickwater fracs, and has continued the practice in the Mannville. Slickwater frac liquids are commonly used in shale, tight sands and other lowpermeability formations. Friction reducers are added to make the water more slippery. “ T he sl ic k water i s subst a nt ia l ly better,” Fischbuch told the meeting. “We’re seeing this occurring consistently across our asset base.... We’re finding that

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J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

Central Alberta

we’re not getting the damage and so on that occurs from water, which was the dogma that engineers and geologists had worked with for the past number of decades.” Angle has four core operating areas: Harmattan, Ferrier, Edson and Lone Pine Creek, all in Alberta. The company is focusing on Cardium light oil, Viking light oil and Mannville liquids-rich natural gas and light oil. Cardium light oil is now Angle’s dominant asset and has become so in only one year. The company is the fifth-largest Cardium land holder in Canada, and in its Dec. 31, 2012, reserves report only 20 per cent of its undrilled inventory was booked. Angle’s Cardium project had finding and development costs of $18.09 per barrel in 2012. The company decided about two years ago to boost its cash flow by transitioning from natural gas to light oil. That transition is on track with a 113 per cent increase in 2012 light oil reserves. Reserve additions in 2012 are substantially all from Cardium projects.

“ The slickwater frac is substantially better. We’re seeing this occurring consistently across our asset base.... We’re finding that we’re not getting the damage and so on that occurs from water, which was the dogma that engineers and geologists had worked with for the past number of decades.” — Gregg Fischbuch, chief executive officer, Angle Energy Inc.

Angle has a large land block in Edson where it may or may not re-enter and test one of its wells next year, Fischbuch said. The company is in no hurry to go after the Duvernay shale, where Angle has 110.5 net sections, preferring to learn from other producers first, he added. The company spent about $10 million in the first quarter of 2013 building a battery to gather all its Harmattan oil. In addition to providing access to processing, it has reduced operating costs by about $1.50 per barrel and provided more options for where it can truck its product, thereby improving its netback and transportation costs, Duane Thompson, vice-president of production, told the meeting. The gathering system and central treating facility will also reduce wellsite equipment costs by cutting down on the amount of tanks needed as well as measuring equipment at individual wells. It will also reduce emissions of solution gas, which had been vented and is now being captured, increasing revenue, he said. O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Central Alberta

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Tamarack cuts Cardium, Viking drilling costs During 2012, Tamarack Valley Energy Ltd. cut capital costs on the drilling Cardium and Viking programs by 34 and 26 per cent, respectively, increased drilling inventory to 108 locations from 47, grew oil production 196 per cent (70 per cent on a pershare basis) and almost doubled reserves. “This is what we set out to do,” Brian Schmidt, president and chief executive officer, told the company’s annual general meeting. Initially spending about $4.2 million on its Cardium wells in the Garrington area, Tamarack cut that to about $2.85 million, thereby shortening its payback periods. “It’s not a fluke,” said Schmidt. “We drilled two separate programs, two wells each on that and so we expect that to continue in 2013.” Whereas the previous operator of its Redwater wells was spending $1.3 million per well, Tamarack’s first Redwater program cost about $1.2 million, and the four-well program it is soon embarking on is expected to cost a little under $1 million. “Very significant if you want to grow in an area to make sure your costs structure is in place,” said Schmidt, adding that it also helps with tuck-in acquisitions. Tamarack’s office walls bear a small plaque announcing the shortest drilling time the company has accomplished in the Cardium, the best in the basin, and last month it won an award for drilling in the Viking, he told the meeting. The company is currently drilling a well that has clocked 100 metres an hour. “It drives down your costs quite a bit when you can get through the rock that fast,” said Schmidt. Cardium and Viking wells were taking about 18 months to pay out, and subtracting $1.2 million and $400,000 in costs, respectively, brings payback period to 12 months or less, he said. A Garrington well last year took only eight months to pay out while a Lochend well took only 10 months, shareholders heard. Cutting well costs to about $1 million gets them to about a one-year payback, he said.

Central Alberta

“It’s our belief this was very important for the company to achieve because now we can build production. If you’ve got one-year payback, you build production without taking on debt,” said Schmidt, adding that it also provides some predictability for its 2013 drilling program. Tamarack has had the best 30-day initial production rates among its peers, based on barrels of oil equivalent per day, with net asset values of more than two to three times the average, said Schmidt. Most producers are spending about $4 million to get 170 barrels per day for a 25 per cent rate of return or $1.2 million, but Tamarack has achieved $1.2 million in cost cuts in the Cardium alone, he said. It is now spending $3.3 million on its wells and has a rate of return of about 120 per cent and a net asset value of about 3.6, he said. During the first quarter of 2013, Tamarack completed, equipped and tied in two (1.03 net) horizontal Garrington Cardium oil wells. It drilled, completed and equipped five (4.7 net) horizontal Redwater Viking oil wells, equipped and tied in two (one net) Lochend non-operated wells and equipped and tied in one (one net) Westlock Viking well. A lso during the first quarter, the company expanded its oil facilities in Garrington and participated in a nonoperated facility expansion in Lochend. In April 2012, Tamarack increased its exposure to the Redwater Viking oil trend by acquiring Echoex Ltd. Production expenses for the three months ended Mar. 31, 2013, increased by 186 per cent to $3.12 million, compared to $1.09 million in the same period in 2012. The increase in total production costs resulted from a 117 per cent increase in production and the increase in higher-cost oil production weighting, along with the Echoex acquisition of higher per-unit cost properties. On a per-un it basis, produc t ion expenses for the first quarter of 2013 were up 33 per cent to $12.84 from $9.67 per barrel during the first quarter of 2012. The company acquired a mineral royalty interest for $1.2 million on a section of land in its Redwater property with the intent of reducing royalties on a go-forward basis. Tamarack also acquired 15,071 net acres of oil-prone lands at a cost of $516,727, bringing the company’s undeveloped acreage to 144,368 acres at the end of the quarter.

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SOUTHERN ALBERTA WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

106

JUN/12 JUN/13

Wells spudded

JUN/12

JUN/13

Rigs released

▼

▲

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

Crew updates Pekisko operations By Pat Roche

Crew Energy Inc. had built production from its Pekisko light oil play at Princess in southern Alberta to 10,000 barrrels per day. But heading into last year, output plunged precipitously to 8,000 barrels per day. The company’s original wells were coming on production at about 600–700 barrels per day. Then the new downspaced wells came on at strong initial rates of about 400–500 barrels per day. But a month or two later, Crew saw some very steep declines in both the original and the newer wells. What happened, Crew president and chief executive officer Dale Shwed told the company’s annual meeting last week, was the wells were in communication with each other, draining the same reserves at a very high rate. But why? This hadn’t been an issue as presumably analogous lands were developed over the previous 60 years. “Obviously something was different here,” Shwed said. “What was different in this area was the fact that the permeability and porosity of the rock was so much better....

So because of it, we saw that communication. As a result, the wells declined.” Crew knew waterflooding was needed to restore pressure in the affected reservoir as well as the other pools it had been producing. “So we had a number of studies done that indicated to us that we should increase our recovery factors roughly from about 10 per cent to 20–30 per cent with waterflooding,” the chief executive officer recalled. For that reason, the company is doing waterfloods in those reservoirs to stabilize the declines, reduce the gas/oil ratio (GOR) and get better ultimate recoveries. Thirtysix per cent of Crew’s developed Pekisko oil reserves are now under waterflood. So far, results have exceeded expectations. A lesson learned from the experience, Shwed said, is to “take your time.... Take six to 12 months to get better ideas of what the pressures are, and then you can go in and develop further once you have a better understanding of that.” He displayed a chart showing the GOR dropping sharply and oil output climbing

after water injection began a year ago at the Bantry Pekisko HH pool. “So that’s a very, very good result,” Shwed said. “Ideally we want to see the GORs coming down, like they have, but if production stayed flat, we’d be happy. To have an increase in production—that’s a real plus.” Another chart showed a similar response in the Princess Pekisko K pool, although its recent results were muted because some wells were down for workover. Crew’s waterfloods are more for pressure maintenance than sweep efficiency. “We just have to get water in that reservoir and keep pumping the oil/water/gas to surface, separating it out and putting the water back,” Shwed said. Sproule Associates Limited estimated Crew’s waterflooding should increase ultimate recoveries to about 20 per cent from roughly 10 per cent, he said. “I know the original models we did said we should get 20–30 per cent.... So I hope there’s still some room left to get to that 30 per cent number.” But his punchline is the cost of adding those reserves. Due to waterflooding on six pools last year alone, Crew was able to book an extra 14.09 million barrels of oil at a half-cycle finding and development cost

Crew Energy Princess Pekisko tight oil play Total (net acres): 315,700 Developed (net): 43,528 Undeveloped (net): 272,172 86 per cent undeveloped 11 waterfloods underway

Photo: Joey Podlubny

waterflood expansions in 2013 2 (DD & N pools) ignificant exposure to emerging S Mannville oil play 6 per cent of Pekisko developed 3 resource is under waterflood Crew is one of a number of companies targeting the emerging Mannville oil play in southern Alberta.

O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Southern Alberta

of $1.04 per barrel. The full-cycle finding and developing cost for the Princess field waterflood is expected to be about $5 per barrel. “There’s not many places we can put capital for $1–$5 [finding and developing].... So that’s why we’re busy waterflooding this area,” Shwed told shareholders. Eleven waterfloods are underway and two waterflood expansions—in the DD and N pools—are slated for this year.

C r e w h a s 315,70 0 net ac r e s at Princess and 86 per cent of this acreage is undeveloped. While the original target was Pekisko oil, the company is now starting to explore overlying Mannville sands for oil. “Cenovus is drilling on the same playtype and having some pretty good results,” Shwed said. “We just drilled a vertical well here we haven’t fractured as of yet. It’s doing

about 30 barrels a day after a month or two and it’s low water cuts, which is critical. “We can see that Mannville sand deposit over most of our land,” he said, indicating the company plans to drill about three horizontal wells to test how the horizontals will work in the prospective Mannville oil play. “We’ll know more about that once we drill a few more wells into it.”

DeeThree Exploration reports best Bakken well yet DeeThree Exploration Ltd. continues finding success in the Alberta Bakken play, reporting its best well to date in early spring. DeeThree has been ver y active on the Ferguson Alberta Bakken property since quarter-end and currently has two rigs drilling on the property. Subsequent to the end of the first quarter, the company has drilled, completed and tested t wo Ba k ken wel l s h igh l ighted by a

significant step-out well that flow tested at the highest rate experienced to date from wells drilled on the property. After fracture stimulation, the well continued to flow for five days up the 4.5-inch frac string at an average rate of 1,560 barrels per day of 29 degrees API reservoir oil with a final rate of approximately 1,360 barrels per day of oil (on a three-quarterinch choke at a wellhead pressure of 150 pounds per square inch). Final water

cuts at the end of the test were approximately four per cent. The well was drilled to a planned total depth with a horizontal lateral of approximately 3,200 metres. The horizontal lateral was successfully fracture stimulated, placing 400 tonnes of sand over 22 stages using an energized water-based system. The well was also significant in that it extended the edge of the company’s existing Bakken pool by another two miles.

Marquee Energy works to plan at Michichi liquids play Marquee Energy Ltd. did a technical evaluation of its Michichi liquids play in late 2012, and that evaluation is now bearing fruit as new wells are proving more productive, the company reported in June. Early in the final quarter of 2012, Marquee initiated a detailed geologic and seismic mapping evaluation of the Michichi area. At the same time, a review of the drilling, completion and production practices of the first seven horizontal wells drilled by Marquee at Michichi was undertaken. The four wells drilled at Michichi in late 2012 and early 2013 incorporated the results of this work and have been completed as Banff or Detrital oil wells. All of these wells are now on production and, based on testing and early production, are expected to meet or exceed type-curve expectations for Michichi. In particular, initial production for the second well of this four-well program drilled at 13-29 is significantly better than the best horizontal well drilled to date by industry at Michichi. This well was completed as a 42

J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

110 Horizontal locations Marquee has at Michichi

dual zone Banff and Detrital oil well and has averaged 280 barrels equivalent per day (67 per cent oil and natural gas liquids) over the first 78 days. Production over the last 30 days for the first three wells of this program has averaged 185 barrels equivalent per day (75 per cent oil natural gas liquids). The fourth well has less than 30 days of production with the associated gas production being flared until tie-in operations are completed. Optimization of production from all four wells continues. Marquee’s undeveloped land in the area now exceeds 110 net sections of primarily

100 per cent owned and operated Crown lands. Integration of geologic mapping with 2-D and 3-D seismic has contributed to better definition of well locations and ultimate production results. In excess of 110 horizontal locations (400-metre inter-well spacing) have been identified on Marquee lands. The Michichi gas plant expansion and upgrade was completed in early 2013 and became operational in February. The plant now handles over half of Marquee’s natural gas and natural gas liquids production in the Michichi area. Approximately twothirds of the production from the company’s remaining 2013 capital program at Michichi is expected to be tied into this facility. Ownership of this facility is expected to continue to produce significant operating cost savings and production efficiencies. The company expects to drill an additional six horizontal wells in 2013 as part of a continuous drilling program at Michichi. Marquee will continue to focus on reducing capital costs on a per-well basis and operating costs in 2013.

SASKATCHEWAN WELL ACTIVITY

JUN/12 JUN/13

Wells licensed

368

313

JUN/12 JUN/13

Wells spudded

221

176

JUN/12

JUN/13

Rigs released

218

171

▼

Source: Daily Oil Bulletin

S.K. Saskatchewan

Lightstream Resources expanding Bakken EOR program By Pat Roche

potential prize. Lightstream says it has more than 900 future drilling locations in its Bakken business unit, where it has an estimated 1.69 billion barrels of light oil in place. But only five per cent of that oil in place had been booked or produced by year-end 2012. The company expects to ultimately recover about 15 per cent using primary recovery methods and as much as 25 per cent through EOR. Lightstream is operating two pilots injecting natural gas into the Bakken tight oil formation at its Creelman property. The first pilot began injecting between 500,000 and one million cubic feet per day of dry natural gas in January 2012. (Natural gas liquids are stripped out at the gas plant and sold.) The toe to heel injector well runs down the lease line between two opposing sets of horizontal wells. “And so essentially what we’re doing with that horizontal injector is flooding two sections,” LaPrade said.

Photo: Joey Podlubny

Lightstream Resources Ltd. plans to expand its natural gas–based enhanced oil recovery (EOR) in the Bakken to a nine-section flood. Lightstream is the former PetroBakken Energy Ltd., which was renamed at its annual meeting in Calgary in May. “To date, we’ve had some early success w it h our Bak ken nat ural gas – flooding enhanced oil recovery scheme,” Rene LaPrade, senior vice-president and chief operating officer, told shareholders. At the start of last year, the company started injecting natural gas into its 16-34 horizontal injector well at its Creelman Bakken property in southeastern Saskatchewan. By mid-year, there was a significant increase in oil output from offsetting producing wells, LaPrade said. “With these successes, we plan to expand the Creelman Bakken EOR project in 2014 to a commercial size,” the chief operating officer told the meeting. EOR success has significant positive implications because of the size of the

The Bakken play is moving into secondary recovery, with Lightstream focused on using natural gas to extract more oil.

That 16-34 injection well has increased light oil production by about 100 barrels per day, LaPrade told the Daily Oil Bulletin after the annual meeting. “We were seeing a significant response six months after the injection had begun, so we’re pretty pleased with the results,” he said. Oil output could increase further as gas injection continues to re-pressure the reservoir. But perhaps more importantly, the company expects to see a flattening of production declines over the longer term. Steep decline rates are a downside of the multi-frac horizontal wells that have enabled the industry to tap ultra-tight formations. Competing Bakken producer Crescent Point Energy Corp. has successfully tested waterflooding as a way of levelling out its decline curves. A second Lightstream pilot, also in the Creelman Bakken, has been using a parallel injector well to inject 300,000– 400,000 cubic feet per day of natural gas since mid-2012. “We are seeing some response on offsets, but it’s early time on that particular pilot,” LaPrade said. The company has said its early-stage EOR success resulted in the booking of proved-plus-probable reser ves related to the natural gas f looding it piloted in the Bakken. Lightstream plans to expand to a more commercial-scale nine-section natural gas–flood at Creelman. Pending regulatory approval, the company hopes to have at least another two wells ready to start gas injection in the first quarter of 2014, LaPrade told the Daily Oil Bulletin. Regulatory hurdles include securing landholder approvals. A cost estimate for the proposed gas flood expansion wasn’t immediately available, but LaPrade said it should be relatively modest because the required compressors and pipelines are already in place. In fact, the relatively modest capital and operating costs, the ability to use O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Saskatchewan

Lightstream Resources Bakken EOR potential Lands (net): 359 net sections stimated discovered petroleum E initially in place (DPIIP): 1.69 billion barrels Recovery factor: 5 per cent* xpected primary recovery factor: E 15 per cent otential EOR recovery factor: P 15–26 per cent cale of existing EOR opportunity: S 290 net sections at 100 per cent WI I dentified toe to heel patterns: 23 patterns (approx. two sections per pattern) ossible future EOR greater than P 130 (69 net) sections at less than 100 per cent WI or the Bakken each one per cent F (of DPIIP) change in recovery factor represents 17 million boe in incremental reserves to Lightstream

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existing infrastructure and the readily available feedstock are part of the appeal of natural gas–based EOR. While injecting CO2 may achieve better miscibility—and hence better ultimate recoveries in amenable reservoirs—CO2 is expensive, unavailable in many areas and operationally complex due to its corrosiveness. However, natural gas is also a miscible fluid—as demonstrated by the existence of solution gas. It is widely available— Lightstream is using its own solution gas— and cheap because soaring U.S. shale gas production has glutted North American gas markets. Also, gas injected for EOR can be recovered and sold after oil production ends and gas prices are higher. As it moved to expand its natural gas EOR in the Bakken in Saskatchewan, Lightstream has been screening for natural gas–flooding opportunities in the Cardium formation in Alberta. “We are looking at some piloting of natural gas in the West Pembina area. It’s in its infancy right now, but we’re going to leverage our experience out of the Bakken into the Cardium,” LaPrade said. “They’re similar [formations], and we feel that the Cardium can be natural gas flooded—it’s just a matter of finding the right place to implement a pilot.”

Saskatchewan

Petrobank Kerrobert project still challenged

Photo: Joey Podlubny

By Paul Wells

Petrobank Energy and Resources Ltd.’s chief executive officer said the company is continuing to try to work out the kinks at its Kerrobert toe to heel air injection (THAI) project as it travels the slow road to commerciality. “There’s lots of upside built into this technology, there’s lots of potential cash flow generating capacity built into this technology—we’ve got to crack the code on commerciality to get it there,” John Wright told the company’s annual general meeting. Wright noted that the break-even production mark for Kerrobert is about 1,000 barrels per day, a level he said would allow the company to generate about $5 million in net operating income annually. “We’re not targeting that, we’re not proud of that, but that’s kind of an indication of when we’ve finally sort of hit the cusp point and gone from the red into the black,” he said. Petrobank remains well off that mark, however. Average production at the Kerrobert THAI project was 205 barrels of oil per day in the first quarter, a decrease from 307 barrels per day in the fourth quarter of 2012 and a small increase over 193 barrels in the first quarter of 2012. Kerrobert THAI production averaged about 200 barrels per day in April. Although the project has encountered numerous setbacks, Wright is confident that the company will crack the nut and move Kerrobert forward. “We are constantly injecting air into the reservoir and getting upgraded heavy oil out of the reservoir. The THAI process is performing as we would expect, and we’re working through a lot of challenge s — seem i ng ly nu merou s c ha llenges—that we have in beating the odds around the physical and engineering problems that we’ve encountered getting oil out of the ground at commercial rates,” he said. “I would assure you that we’re happy with the technical results of THAI, but we’re just catching up on some of the challenges associated with the by-products, t he temperat ure of t he f luids we’re

Petrobank’s Kerrobert project is one of a number using thermal technology to recover heavy oil resources.

dealing with and the rates we can get out of these wells.” The company’s recent operating focus has been to continue to significantly increase air injection and optimize operations for higher production at lower perbarrel costs. Since beginning to increase air injection in the fourth quarter of 2012, the Petrobank has increased the fieldair injection rate to up to 25 per cent of design capacity. “The whole key to making THAI commercial is to maximize the amount of energy we put into the reservoir, which maximizes the amount of oil we mobilize to the reservoir and [maximizes] the amount of oil we can produce back out of the reservoir,” Wright said. “What we’re looking at is ramping up our air injection...long term; the more air we put in, the more oil we get out. And that’s what we’re moving to.” Since the beginning of the year, the company has also converted two wells from pumps to gas lift, which reduces workover costs, allows for more gas production and

results in less downtime. Petrobank is assessing other wells for conversion to gas lift as conditions dictate. In addition, the company is conducting a wet combustion test in its east injection pad through the co-injection of water into several injection wells. The purpose of the water injection is to help redirect the air in the reservoir to optimize the combustion zone. Wright said that Petrobank continues to evaluate the implementation of several other strategies designed to increase production. “One of the technical solutions we’re looking at using [at Kerrobert] is actually using our patented multi-THAI process, which would see us using more than one injector well per producer well to allow us to affect more of the reservoir and also increase the amount of total combustion air that’s going into the reservoir at any given time,” he said. “What we’re focused on 110 per cent of the time is trying to get Kerrobert production up to what we consider to be break-even rates, or commercial rates, which are in the 1,000-barrel-per-day range,” he said. O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

Saskatchewan

Crescent Point upping spending and production plans for 2013 By Richard Macedo

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J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

Crescent Point Energy Corp. has boosted its outlook for both production and capital expenditures for 2013. The producer now expects to spend $1.5 billion this year, up from the previous guidance of $1.35 billion. Production for the year is now expected to average about 114,000 barrels equivalent per day, up from the previous 112,000 barrels per day. The company’s exit production is now estimated at 117,000 barrels per day, up 3,000 barrels per day from the old guidance. “So far, 2013 is shaping up to be another great year of organic growth for us. Although there are acquisition opportunities in the market right now, we haven’t seen anything material that fits within our short- and medium-term business plans,” said Scott Saxberg, president and chief executive officer. “Acquisitions are a key part of our strategy, and we continue to evaluate opportunities, but we will remain disciplined in our approach to spending and focus on the development of our high-quality asset base, including the application of new technologies and waterfloods.” Crescent Point plans to continue to increase crude oil shipments through its Stoughton, Dollard and Alberta rail facilities, which are providing access to new markets and providing a hedge against price-differential volatility. Current capacities at the facilities are approximately 45,000 barrels per day, 8,000 barrels per day and 3,000 barrels per day, respectively. In addition, Crescent Point has 18,000 barrels per day of its oil production contracted to rail markets on a firm basis for the balance of 2013, providing fixed price differentials from West Texas Intermediate (WTI). Combined with financial WTI derivatives, these selling prices are fixed at levels greater than C$90 per barrel. During the first quarter, the company spent $459.1 million on drilling and development activities, drilling 227 (164.3 net) oil wells with a 100 per cent success rate. Crescent Point also spent $73.6 million on land, seismic and facilities, for total capital expenditures of $532.7 million. In the first quarter of 2013, Crescent Point participated in the drilling of 106 (87 net) oil wells and one (one net) water source well in southeastern Saskatchewan and Manitoba, achieving a 100 per cent success rate. Of the oil wells drilled, 80 (72 net) were drilled in the Saskatchewan Bakken light oil resource play. In the first quarter, the company also participated in the drilling of 26 (15 net) horizontal wells in conventional zones, several of which significantly exceeded initial production rate expectations. The company plans to drill up to 169 net wells in the Saskatchewan Bakken play during 2013 and to spend approximately $490 million, including expenditures on land, seismic and facilities. Discussions with the Saskatchewan government to implement the first of four proposed units for waterflooding in the Viewfield Bakken resource play continue. The approvals of these units are key steps in the company’s development plans for the play and would allow Crescent Point to implement the Viewfield Bakken waterflood across a larger area, which would be expected to assist in reducing corporate declines and add incremental reserves over time.

Saskatchewan

During the quarter, the company continued to convert additional Viewfield Bakken producing wells to water injection wells. Water injection support is positively affecting more than 5,000 barrels per day of Bakken production, resulting in shallower production declines that contributed to strong firstquarter results. Overall production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed Crescent Point’s expectations and demonstrate the field-wide applicability of waterflood to the play. Crescent Point also plans to expand its Viewfield gas plant to 42 million cubic feet per day from 30 million cubic feet per day to accommodate continued increased production from the success of the drilling program and shallowing decline rates. The company drilled three two-mile horizontal wells in the first quarter of 2013 in the Flat Lake area. Based on the initial success of these wells, the company plans to drill a total of six two-mile horizontal wells in 2013. The company expects that these wells will be drilled at considerable savings to similar wells drilled across the border in North Dakota, where demand has driven well costs up. During the first quarter, the company participated in the drilling of 29 (29 net) oil wells in southwestern Saskatchewan, all of which were in the Shaunavon area, achieving a 100 per cent success rate. The company plans to drill up to 95 net wells in the Shaunavon area in 2013, including 19 Lower Shaunavon infill wells spaced at eight wells per section and two at 16 wells per section. Four Upper Shaunavon infill wells are also planned at eight wells per section. In 2013, Crescent Point expects to spend approximately $315 million in the area, including expenditures on land, seismic and facilities. Subsequent to the quarter, the Saskatchewan government issued a permit approving Crescent Point’s application for a waterf lood unit in the Lower Shaunavon resource play. The approval of the Leitchville North Shaunavon Voluntary Unit #1 is a major milestone for the company and will allow Crescent Point to implement the Lower Shaunavon waterflood across a larger area. Water is currently being injected into 31 converted wells in both the Lower and Upper Shaunavon unconventional zones and several of the offset producers have begun to show positive response through shallowing declines and increased production. Acid fracture stimulation techniques are planned for seven Shaunavon wells in higher water saturation areas in 2013. To date, five have been completed with encouraging initial results. In January 2013, Crescent Point also commissioned the third of three new batteries built in 2012. The company has begun planning for 120,000 barrels of oil storage adjacent to its railloading facility. In the first quarter of 2013, the company drilled 10 (10 net) wells with a 100 per cent success rate in the Viking area on lands acquired in the Cutpick Energy Inc. acquisition. Crescent Point plans to drill 30 net wells on these lands in 2013, primarily focused on 25-stage cemented liner completions with energized fracture stimulation systems to optimize capital efficiencies and maximize reserve recovery. The company also plans to convert an additional three producing Viking wells to water injection wells on these lands in 2013.

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Cover Feature

Wet

shale

A boom is underway, turning huge natural gas liquids resource from tight rock into reserves

58.6 billion barrels. That’s how much natural gas liquids (NGLs) the Alberta government believes is trapped in tight formations along the western edge of the province. Tapping those liquids is in its infancy, but analysts are already forecasting that new production from tight plays in the Montney, Duvernay, stacked zones in the Deep Basin and west-central Alberta will reverse the recent decline in liquids production and possibly even allow for expansion of Alberta’s petrochemical industry. Total Canadian NGLs production averaged 732,000 barrels per day between 2000 and 2010, averaging 681,000 barrels per day in 2010. A recent study by the Canadian Energy Research Institute estimated that total liquids production fell to 564,000 barrels per day in 2012. It expects supply to reach a low of 498,000 barrels per day in 2014 as gas production continues stagnating, and then steadily increase to 790,000 barrels per day by 2035 as natural gas production volumes recover in the long term.

The Montney Much of the early growth in liquids supply is coming from the Montney Formation, stretching from the Deep Basin in west-central Alberta north into the Peace River Arch. The Alberta Geological Survey estimates there are around 29 billion barrels of liquids trapped in the tight siltstone/shale formation. The advent of extended-reach horizontal drilling and multistage fracturing has opened up this bounty to production. Paramount Resources Ltd. was an early entrant into the Montney sweepstakes, and the company is now betting its future on the play. By 2014, it expects production to reach 50,000 barrels equivalent per day. 48

j u ly/a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

Paramount has more than 200 sections in the Kaybob area of the Montney and another 100 sections to the north. The company built its land position after drilling a vertical well with a propane frac that resulted in initial production as high as two million cubic feet per day. In the last two years, it has drilled a series of horizontal wells that have come in at rates ranging from seven to 12 million cubic feet per day. Liquids have come in between 50 and 150 barrels per million cubic feet, with some wells having initial condensate production as high as 1,300 barrels per day. Currently producing around 14,000 barrels per day at Kaybob and 5,000 barrels per day at its Grande Prairie, Alta., core area, Paramount is building processing infrastructure ahead of a major rush in production. “We’re going to see our production double or triple over the next few years,” Jim Riddell, Paramount’s president and chief operating officer, told the company’s annual meeting. Driving this growth is an increase in fracturing density per well. In 2008, when Paramount first targeted the Montney, it began with one well per section and one frac per section. Then it went to three wells per section and seven frac stages per well, for a total of 21 fracs per section. That increased to five wells per section and roughly 20 fracs per wellbore—or about 100 fracs per section—resulting in much better recoveries and economics. Delphi Energy Corp. is also progressing in turning the Montney liquids play into a cash-generating machine. After testing a series of technologies on its 108 gross sections of Montney lands at Bigstone, it now believes it has the know-how to develop the play efficiently, David Reid, company president and chief executive officer, told shareholders in May. Delphi began testing the Montney at Bigstone using conventional completion technologies and small, 20-to-30-tonne frac stages using oil-based gel. These initial wells

Image: Jeremy Seeman

By Darrell Stonehouse

Cover Feature

had high early production, but high decline rates meant three-tofour-year payouts. The company knew what the rocks were like and what the fluids were like, and that it needed a different fluid completion technique to open up and stimulate the rocks properly, said Reid. For its next two wells, Delphi switched to large slickwater fracs. The new fracture treatment opened up more of the reservoir, resulting in shallower decline rates and increased condensate production. “The whole objective here was not necessarily to increase initial production rates; it was all about initial decline profiles,” he said. The first three wells hit their peak rate within the first week and then dropped off quickly. The first slickwater frac had a singlesection horizontal leg and 20 fracs to test the liner. The second 1.5-section slickwater well with 30 fracs came on at seven million cubic feet per day and has had a very shallow decline. After 50 days, it’s more than two times better than those first three wells, said Reid. The Delphi chief executive officer said what surprised the company when it introduced slickwater fracs were the high volumes of condensate it was achieving. The first three wells were running between 20–30 barrels of condensate per million cubic feet at the wellhead with another 30–40 barrels per million cubic feet of NGLs at the plant, based on gas composition. In contrast, after 70 days its first slickwater hybrid well was still producing 40–45 barrels of condensate per million cubic feet at the wellhead. The second slickwater well was doing between 70 and 80 barrels of condensate per million cubic feet at the wellhead after 50 days. “But what’s truly impressive is the revenue that is generated compared to the first three wells because of the liquids yield,” said Reid. As a result, the well is expected to pay out in just seven or eight months. Delphi has also optimized its drilling at East Bigstone where it has perfected the well design to drill across two sections (two miles) rather than one. “Essentially we are saving the entire vertical section of one well by drilling across the second section,” said Reid. The company has drilled as far out as almost 3,000 metres horizontally, for a total measured depth of about 6,000 metres. “The cost of that last 1,300–1,500 metres has been as low as $500,000 and as much as $1 million, so the cost of drilling a little further is really minimal compared to what we can save,” he said. Another benefit is that in drilling deeper on the measured depth, the drilling credits earned against future royalties increases on a per-metre basis. “For less than $1 million in drilling costs, we are actually earning over $4 million in drilling credits by drilling that second section, so it all pays for itself over time,” he said. “It’s a huge boost to the economics.” While Delphi is not yet doing pad drilling, the next step will be drilling four of the two-section wells off one pad.

Delphi uses what it calls a hybrid slickwater completion. After pumping at high rates, it switches to a conventional frac but at a lower rate with higher-viscosity fluid (carrying more sand). On a perfrac basis, the cost of completions has been cut nearly in half. “You prop it very aggressively so that you have this super highway near the wellbore [very permeable and very well propped] and then way out in the reservoir you have all these little fractures with the odd sand grain in them,” Reid said.

Stacked Deep Basin and west-central Alberta major NGL targets Aside from the Montney, explorers are also targeting a number of other liquids-rich formations stacked in the Cretaceous zone of the Deep Basin. Encana Corporation is targeting liquids in the Cardium, Dunvegan, Cadotte, Fahler and Wilrich on its 400,000 acres in the Deep Basin that it calls its Big Horn play. In the company’s first-quarter report, Clayton Woitas, director, reported that Encana now has the technology to optimize liquids production at Big Horn. In 2008, when it began developing the play, it was drilling 800-metre laterals with eight to 10 frac stages. Today, it is drilling 1,800-metre laterals with as many as 20 frac stages per lateral. Two wells drilled and completed this winter delivered initial production of 960 and 1,036 barrels per day of NGLs. Encana expects to drill 25 wells into the stacked Cretaceous play in 2013, with each well costing $5 million to $10 million. It expects liquids production from the play to climb to 7,400 barrels per day from 5,500 barrels per day. Apache Corporation is behind Encana in developing its liquidsrich acreage in western Alberta. But after spending 2012 appraising its land base, in 2013 it will move into development mode, Rodney Eichler, president and chief operating officer, said during the company’s year-end conference call. Apache is in the process of completing its resource assessment in Canada for liquids-rich gas and oil opportunities and expects to identify several thousand economic wells in its various plays. This year’s program features more than 150 wells with a focus on oil- and liquids-rich gas opportunities and horizontal exploitation of the Sparky, Bluesky, Beaverhill Lake, Dunvegan and Viking oil plays. The company also intends to test the Montney and the Duvernay within its substantial acreage positions in these plays, said Eichler. The company’s intial focus has been horizontal drilling in the Kaybob and W5 development areas. This horizontal program has made a significant impact in the Kaybob area where Apache grew overall production by 50 per cent over the last two years to 21,000 barrels of oil equivalent per day from 14,000. Devon Energy Corporation is also advancing its NGLs program in west-central Alberta. The company has around 240,000 net acres in the Cardium oil- and liquids-rich Lower Cretaceous zones, including the Glauconite, chief operating officer David Hager told analysts O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

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early this summer. Based on the results of a multi-year oil- and liquids-rich resource exploration program, Devon is proceeding with a development project in the Ferrier area. The first phase of development is focused on about one-third of its acreage position and represents more than 100 million barrels of reserves potential. In conjunction with the development, Devon will construct a gas processing plant with an inlet capacity of 100 million cubic feet per day and liquids-processing capacity for approximately 13,000 barrels per day. Construction is scheduled to begin in the second quarter of this year, with completion slated for mid-2014. The company plans to ramp up drilling late this year with 13 wells in the fourth quarter. Devon also plans to test the potential beyond the currently sanctioned development and expects additional phases in the future, said Hager.

Juniors and intermediates nudge in While international producers are increasingly playing a role in the liquids rush in the Deep Basin, Canadian junior and intermediate

Bonavista Energy Corporation often flies under the radar, but it has a growing presence in liquids plays in both the Deep Basin and west-central Alberta. In the Deep Basin, the company is targeting the Bluesky, Rock Creek and Wilrich formations, with plans to drill 15–20 wells total in 2013. The company has drilled 14 horizontal wells with multistage fracs into the Bluesky Formation, reporting initial production of 40 barrels of liquids per million cubic feet of gas. Thirteen wells have been drilled into the Rock Creek Formation, with average liquids production of 50 barrels per million cubic feet. With 300 sections prospective for liquids-rich gas in the Glauconite in west-central Alberta, Bonavista has drilled 156 wells targeting the formation, reporting average liquids yields of 70 barrels per million cubic feet. The company has identified more than 400 horizontal targets on its land base, and plans to drill 40–45 wells this year. The company also has 90 sections of land in west-central Alberta covering the Ellerslie Formation and reports average liquids yields of 100 barrels per million cubic feet. It has identified 80 horizontal locations, and plans six to eight wells this year.

“ You’re starting to see an evolution in the completion of the wells and the technology people are using to try and maximize the return from the wells.”

producers continue expanding as well. One example is Cequence Energy Ltd., which has 170,000 net acres in the area. Its current focus is the Simonette area. “We’ve chosen this area because it’s got multi-zone potential, all liquids-rich,” Paul Wanklyn, president and chief executive officer, told the company’s annual meeting in May. “The Montney has become our primary zone of interest, but we certainly have a big stack of zones that we’re excited by.” The Simonette Montney is a large-scale resource play, with recent wells continuing to exceed model well rates, said Wanklyn. There are up to 150 metres of a siltstone to very fine sandstone reservoir and 74 million barrels of oil equivalent of proved-plus-probable reserves booked, with 81 undeveloped locations in the Upper Montney alone. The liquids yield averages 30 barrels per million cubic feet, with 70 per cent condensate. In the Wilrich play at Simonette, the company holds 20 net sections currently mapped with 40 potential locations. Deeper Montney drilling has confirmed an extension of the exiting trend to the south. Cequence is planning one well for the winter of 2014. The company also has an emerging Ansell/Edson Wilrich play, 140 kilometres south of the Simonette area, where the company has been buying land for a couple of years and now has more than 31 sections. “We have ended up right in the middle of what’s emerging to be one of the hottest new Wilrich resource plays in the basin,” said Wanklyn. “Competitor wells around us are testing at rates of well in excess of 20 [million cubic feet] per day.” Cequence controls 31 sections of 100 per cent land and retains a 49 per cent working interest in the Ansell project after a recent farmout to a joint-venture partner. The company has drilled its first well, which is now on production, but Wanklyn couldn’t say at what rate. The company hopes to drill two more wells before the end of the year. 50

j u ly/a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

— Jim Riddell, chief executive officer, Trilogy Energy Corp.

Further ahead, Bonavista plans to test the Notikewin in the Deep Basin and the Second White Specks in west-central Alberta for liquids-rich gas.

The Duvernay In the very early stages of development is the Duvernay play, stretching from west-central Alberta north toward Grande Prairie. So far, the industry has drilled about 120 Duvernay wells (more than 62 horizontal and 33 vertical), with at least 40 wells (35 horizontal and five vertical) on production. The Alberta Geological Survey estimates there are around 11.3 billion barrels of NGLs trapped in the play. Initial drilling results indicate it has economic potential. Drilling in the Duvernay began in 2010 when Celtic Exploration Ltd., along with partners Trilogy Energy Corp. and Yoho Resources Inc., spudded the first horizontal well into the play at Kaybob. Initial production came in at two million cubic feet of gas and 104 barrels per day of condensate. Since then, more than 100 wells have targeted the Duvernay with the majority in the northern region surrounding Kaybob. Talisman Energy Inc. has 350,000 net acres in the Duvernay and has drilled test wells in both its southern and northern reaches. Late this spring, the company reported that its first well in the southern Duvernay near Willesden Green produced nearly 1,000 barrels of liquids per million cubic feet of gas. “We hold the largest single position in this part of the play with 189,000 net acres of land, positioned in what we now believe to be the richest portion of the condensate and volatile oil windows,” said Paul Smith, executive vice-president, finance and chief financial officer. Talisman estimates it has a prospective resource of 600 million barrels equivalent on its southern Duvernay land, where it has now drilled three wells and completed two wells.

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Its first well, the 11-03 well in the southern Duvernay, was completed with a relatively short lateral of only 3,500 feet, with only five effective frac stages, he said. However, the 11-03-041-05W5 well had a 30-day initial production rate of about 300 barrels per day of condensate (50 degrees API oil) and a total liquids yield that topped 1,000 barrels per million cubic feet of gas, Smith announced. Its second southern Duvernay well, the 02-06 well, which is slightly to the northwest of the first well, was tested recently—again with a relatively short lateral of 3,500 feet and only seven stages completed. Smith said that during its first seven days of production testing, Talisman’s second well (02-06-042-05W5) in the southern Duvernay flowed 1.1 million cubic feet per day of gas, with a condensate yield of 110 barrels per million cubic feet. Talisman is now drilling its fourth well into the southern Duvernay and expects to bring another two or three wells on stream. He said the company is developing plans for a phased development scheme for the southern Duvernay that will start next year. In the northern Duvernay, meanwhile, Talisman has about 159,000 acres in the Kaybob area with a prospective resource of 800 million barrels equivalent, he said. So far, the company has drilled three pilot wells on these lands. Each well was completed with an average of only six stages per well—relatively short because they’re in pilot phase. Smith said the three pilot wells resulted in an average 30-day initial production rate of 3.2 million cubic feet per day and 60 barrels per day of field condensate. Talisman expects to see, on average, an additional 290 barrels per day of NGLs from each of its three pilot wells processed through a deep-cut facility. “Put another way, we estimate that an optimized

development well in our pilot area, drilled with a 5,000-foot lateral and completed with 12 stages, would result in a well of approximately 6.5 million cubic feet a day of gas and 700 barrels a day of condensate and NGLs.” Despite the stellar results, Hal Kvisle, president and chief executive officer, has said Talisman plans to divest all or a portion of its stake in the North Duvernay. With a focus on three areas of the Duvernay—Kaybob, Edson and Willesden Green—Encana has 460,000 gross acres in the play. “By all accounts, we have control over half of the high-grade fairway in the liquids-rich window; it’s a great place to be,” Brendan McCracken, Duvernay team lead for Encana Corporation, said at a recent conference in Calgary. The company has seen yields of anywhere from single-digit barrels per million cubic feet all the way up to 400 barrels per million cubic feet. In most of the Duvernay wells Encana has observed, a little more than 80 per cent of the C3+ mixture is condensate, with 75 per cent of that field condensate and another five per cent C5+ processed at the gas plant, said McCracken. “Contrast that to other liquids-rich plays where you are lucky if you get half of your C3+ mixture as condensate,” he said. “When you consider that condensate is trading at about a $14-per-barrel premium to WTI [West Texas Intermediate], that’s a pretty good news story from a commercial standpoint.” Encana has two rigs actively drilling in the play, and so far has drilled 10 gross wells (eight horizontal and two vertical). Four horizontal wells are producing and one is waiting for tie-in, while another awaits completion and two are shut in for active

O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

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pad completion. According to McCracken, Encana has drilled the three longest horizontal wells in the play. Trilogy, one of the Duvernay pioneers, has spent three years exploring the play, where it has participated in 11 horizontal wells to date. The company holds roughly 100 sections in the gas/condensate reservoir area and roughly 100 sections in its potentially oilier part. The company spent $55 million in the Duvernay in 2012 and plans to spend another $75 million in 2013. “Spending this year is mostly to make sure that we don’t lose any of the land and try to maximize our understanding in the play,” Jim Riddell, chief executive officer, told the company’s annual meeting. “We also have access through data-sharing agreements to a significant additional database of offset wells. Between our own information, the offset information and industry information around us, we have been able to put together a bit of an idea of where we sit in the play.” During the first quarter of 2013, the company spudded, completed and tied in two horizontal wells close to one it drilled in 2012. Improved completion techniques have enabled Trilogy to increase the number of fracture intervals to more than 60 in the new wells, from 30 in the previously completed ones. “We think the place that you want to be in this play is where you’re obviously in the thicker shale; you’re in the liquids-rich-most part, or the oil part, where it’s still over-pressured,” said Riddell. An early well Trilogy brought on stream in April 2011 at 03-13-060-20W5 has produced 870 million cubic feet per day and 70,000 barrels of condensate, cumulative to Mar. 30, 2013. It included a 1,391-metre lateral length, 100 tonnes of sand and roughly 900 cubic metres of slickwater per frac interval, as well as a plug-and-perf completion technique. It has four billion cubic feet of recoverable reserves. “We learned a lot with that well, but to understand what the true potential of the play is, you have to focus your evaluation on the most recent results,” he said. “You’re starting to see an evolution in the completion of the wells and the technology people are using to try and maximize the return from the wells. “We’re starting to see some much better wells, particularly as the play has migrated into the oil window,” he added.

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Rush of natural gas liquids drilling driving billions in infrastructure spending By Darrell Stonehouse

Photo: Joey Podlubny

all it the quiet boom. While all eyes are focused on the tens of billions of dollars of planned investment in the oilsands region of northeastern Alberta, along the western edge of the province and into the petrochemical clusters of central Alberta, billions of dollars are also being spent as a rush of natural gas liquids (NGLs) drilling drives new infrastructure development. And with extended-reach horizontal drilling and multistage fracturing technologies opening up access to almost 60 billion barrels of NGLs resources, the boom in processing-facility construction will likely last well into the next decade. Andrew Botterill, senior manager of Deloitteâ&#x20AC;&#x2122;s resource evaluation and advisory practice, says with dry gas prices O I L & G A S I N Q U I R E R â&#x20AC;˘ j u ly/a u g u s t 2 0 1 3

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still below economic recovery levels in all but the most prolific wells, right now NGLs are the only show in town when it comes to gas drilling across North America. In Deloitte’s recent quarterly price forecast, Botterill says it is condensate prices that are driving gas drilling in Alberta, with prices for propane and ethane flat or declining because of oversupply. In the near future, however, he expects their demand to pick up as petrochemical facilities expand and enhanced recovery projects soak up excess production. Deloitte has decreased its propane price forecast for 2013 and 2014 to 40 per cent of Edmonton Par oil from 55 per cent, while forecasting a pentanes plus (condensate) price 115 per cent that of Edmonton Par oil to reflect the increasing oilsands demand for pentanes plus used as a diluent. The butane forecast is unchanged at 85 per cent of Edmonton Par oil. With the continued growth in propane production, companies are beginning to look at ways to increase the market for propane with more export terminals, and moving propane in different directions within North America and potentially offshore. Propane is also being studied for use in the oilsands, as a solvent in miscible floods and in other enhanced recovery methods, Botterill says. “Some of those projects are a year out, others are two or three years out, so we have our forecast lower in the short term, then dropping back to more of a five-year average of 55 per cent beyond that.” According to Botterill, the erosion in propane prices is not due to the fact that there is more propane in the growing liquids volumes from North American shale gas, but is due to a lack of demand for the product. “Propane production remains relatively unchanged at 28 per cent of total liquids in the market. It’s just that pentanes and butanes have found a demand that has grown,” he says. “In contrast, propane hasn’t been able to find a way to increase demand at the same rate as those increased volumes are coming on.” Last winter, there was low demand, which meant a lot of it went into storage. The price differential for butane, though, has been consistent over the past five years, which suggests that growth in both supply and demand has been balanced, he says. Butane is typically used for gasoline blending and can be used in the creation of petrochemicals and solvents. Horizontal drilling and multistage fracturing technology are beginning to turn the almost 60 billion barrels of NGLs in Alberta’s tight formations into reserves. As those reserves are turned into production, a major infrastructure build-out to process and add value to that production is underway.

Keyera prepares for increasing demand Keyera Corp. expects to spend as much as $450 million this year to add to its NGLs processing and handling capacity where throughput was 1.24 billion cubic feet per day during the first quarter. Jim Bertram, chief executive officer, told analysts at Keyera’s first-quarter conference call that increasing liquids-rich gas production is resulting in new business opportunities at the company’s gas-processing facilities, as well as generating increasing demand for fractionation, storage and marketing services for the liquids removed from the raw gas stream. Bertram pointed to increased demand at Keyera’s Rimbey, Minnehik Buck Lake, Strachan, Brazeau River and Nordegg River facilities in west-central Alberta as an indication of an expanding liquids midstream. He 54

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says customers across west-central Alberta are targeting the Glauconite, Cardium, Montney and Duvernay formations, which are all liquids-rich plays. The company has a number of expansion plans in the works as this production picks up. Keyera is looking at expanding fractionation capacity at its gas plants at Nevis, Alta., and at Fort Saskatchewan, Alta. Other proposed projects include a 90-kilometre pipeline at Wapiti, and expansion at the Simonette plant. The company plans to add 100 million cubic feet per day of capacity at Simonette, along with condensate stabilization facilities. Together, the projects are estimated to cost $210 million. Keyera is also doing detailed engineering work on a 30,000-barrel-per-day de-ethanizer at its NGL fractionation and storage facility in Fort Saskatchewan. “Some of the new liquids that are being brought on stream from the Deep Basin, from a variety of facilities, are C2+, so we wanted to be in a position to have the flexibility to accommodate both C2+ as well as C3 streams,” said Bertram. “We’re still working with producers to determine what the appropriate timing and volume commitments are to make that a commercial project.” Keyera continued to advance the 400-million-cubic-feetper-day turbo expander project at the Rimbey gas plant during the first quarter. The turbo expander will extract up to 20,000 barrels per day of ethane, which will be sold to a large consumer in Alberta under a long-term sales agreement. Based on current plans and subject to regulatory approvals, construction is scheduled to be complete in late 2014. Keyera is also working with producers to determine interest in the construction of a gathering pipeline to deliver liquids-rich gas to the Rimbey gas plant. In April, Keyera announced it was partnering with Plains Midstream Canada to test the waters on building a new liquids pipeline system in northwestern Alberta. Called the Western Reach Pipeline System, the project is expected to be 570 kilometres long and consist of two pipelines for mixed liquids and condensate transport. The pipeline route travels through both the Montney and Duvernay zones.

Pembina expands processing to nearly one billion cubic feet Pembina Pipeline Corporation continues to see significant growth opportunities resulting from the trend toward liquids-rich natural gas drilling and the extraction of valuable NGLs from natural gas in the Western Canadian Sedimentary Basin. It expects recent and planned expansions to increase its gas-processing capacity to 903 million cubic feet per day. This includes enhanced NGLextraction capacity of approximately 535 million cubic feet per day (net). These volumes would be processed on a contracted, fee-for-service basis and are expected to result in approximately 45,000 barrels per day of incremental NGLs to be transported by early 2014. The company is proposing to expand its NGL infrastructure for a total cost of approximately $1 billion. Plans are to twin its 200-million-cubic-feet-per-day Saturn deep-cut facility to extract NGLs from raw gas streams in the Berland area of Alberta and to twin the 73,000-barrel-per-day ethane-plus fractionator at its Redwater site near Fort Saskatchewan. “These projects mark the next stage of our growth in the NGLs business,” said Bob Michaleski, Pembina’s chief executive officer. “The projects are all extremely complementary and position us well to offer

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integrated services across the NGL value chain. With our existing ethane-plus infrastructure and marketing capability, we can offer a competitive, cost-effective solution for incremental ethane-plus production from the Western Canadian Sedimentary Basin.” Also to support increasing liquids volumes, Pembina is proceeding with its proposed Phase II NGL pipeline capacity expansion on its Peace Pipeline and Northern NGL Systems. The company is currently completing the Phase I expansion, which will increase NGL capacity on the system by 45 per cent to 167,000 barrels per day by October 2013. Phase II will increase capacity to 220,000 barrels per day. Both expansions are expected to increase NGL transportation capacity by 90 per cent. Subject to obtaining regulatory and environmental approvals, Pembina expects costs of approximately $415 million and completion in early to mid-2015. Pembina is also considering expanding its Resthaven extraction plant. It recently announced potential scope changes to the $230-million, combined shallow- and deep-cut extraction facility that could push the in-service date to the third quarter of 2014 from the first quarter. Customers have requested some new liquids-handling capability and additional service, said Scott Burrows, vice-president of corporate development and investor relations, in a conference call. He said the company is looking at additional capital of up to $35 million for which it would be compensated through contracts. Pembina’s partners have not yet approved the expansion. Pembina is also expanding and modifying its existing gas plant at Resthaven, and is constructing a pipeline to transport the extracted NGLs to its Peace Pipeline System. Pembina will own approximately 65 per cent of the facility and 100 per cent of the NGLs pipeline. Once operational, the 200-million-cubic-feetper-day facility should have the capacity to extract up to 13,000 barrels per day of liquids.

Petrochemical industry needs to pay for more ethane extraction By Elsie Ross If Alberta petrochemical producers are looking for increased supplies of ethane, they should be prepared to pay for the higher costs associated with extracting it from natural gas, says Richard Dunn, vice-president of regulatory and government relations, Canadian division, for Encana Corporation. “What’s being offered these days is essentially heating value, so it’s just not working, hence industry is going back to focusing on the C3+ type [shallow-cut] facilities,” Dunn told the Canadian Energy Research Institute Petrochemical Conference. To make ethane recovery economic, producers need an additional $1.50– $2.50 or more per gigajoule for ethane at a greenfield deep-cut facility—which will be the case for many projects in the Montney or the Deep Basin, said Dunn. Liquids-rich natural gas producers increasingly are choosing to leave ethane in the gas stream rather than face the higher costs of a deep-cut processing facility to extract a product that is not recognized in the price they receive for natural gas, he said. The all-in cost of ethane recovery is up to 25 per cent higher than for a shallow-cut facility that removes only pro-

AltaGas could spend $5 billion to expand exports

pane because of the higher horsepower required along with

AltaGas Ltd. is not only expanding its liquids capacity, but also looking at developing export markets for excess propane supply. In total, David Cornhill, AltaGas chairman and chief executive officer, sees as much as $5 billion in potential capital expenditures as the market for natural gas expands. “Our strategy is to capitalize on opportunities that the renaissance of natural gas and clean energy are creating,” said Cornhill. In 2012, AltaGas expanded its Harmattan, Gordondale and Blair Creek liquids processing plants. Its Harmattan co-stream facility, with a 20-year, cost-of-service deal with NOVA Chemicals Corporation, is currently running at 65 per cent capacity, but volumes are expected to increase in the coming months. Gordondale is operating as planned with take-or-pay levels at about 42 per cent of capacity, but its volumes are also expected to increase as producer activity ramps up in the area with additional tie-ins. Blair Creek, meanwhile, is running at around 78 per cent utilization. In the first quarter of 2013, the company’s average ethane volumes increased to 31,335 barrels per day from 29,155 barrels per day the previous year, largely due to the addition of the co-stream facility. NGL volumes declined to 15,185 barrels per day from 16,031 barrels per day, compared to the same quarter in 2012 as a result of lower volumes at the Younger facility and the Joffre Ethane Extraction Plant. NGLs produced at the co-stream facility and

larger vessels and higher pressure, he said. Using a relatively new high-efficiency ethane rejection process, Encana can recover 90–95 per cent of the propane, the conference heard. But there is more than just price involved, he said. “In today’s environment where cash flow is extremely important to producers and there is a desire to maximize cash flow and to minimize capital outlay and also minimize the long-term commitment to further infrastructure, the focus of C3+ targets makes a lot more sense.” The province is also losing out because royalties rise with higher prices on a percentage basis, Dunn pointed out. “It’s really a double whammy.” If producers were to receive another $2.50 per gigajoule for their ethane, that would amount to an eight or nine per cent increase in royalties for an incremental $25 million on a 35,000-barrel-per-day ethane stream, he said. In the question period that followed, Dunn said the Alberta government has been working hard to facilitate discussions and there is a bit of a window of opportunity before producers build ethane rejection facilities, for example. The timing is good in that LNG appears to be coming along and the liquids-rich unconventional plays are in the early stages where people are looking at their facilities and how they start planning them, he said. O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

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delivered to NOVA Chemicals partially offset the declines. Field gathering and processing throughput in the first quarter of 2013 averaged 403 million cubic feet per day, compared to 400 million cubic feet per day in the same quarter of 2012. AltaGas and its Japanese partner, Idemitsu Kosan Co., Ltd., each own a 50 per cent interest in the AltaGas Idemitsu Joint Venture Limited Partnership that is pursuing opportunities to export liquefied natural gas and liquefied petroleum gas (LPG) to Asia. Idemitsu is targeting 25,000 barrels per day of LPG exports. The partnership has completed a pre-feasibility study which addressed pipeline capacity additions to the system. In the second quarter of 2013, it expects to proceed to the next stage of development: engagement with First Nations and undertaking an environmental review process.

Williams also looks to capture value of propane Like AltaGas, Williams Energy (Canada) Ltd. is looking to capitalize on excess propane production in western Canada. It is building the country’s first and only propane dehydrogenation (PDH) facility near its existing fractionation plant at Redwater, northeast of Edmonton. The new facility, with its price tag of $900 million, will allow Williams to significantly increase output of polymergrade propylene from its Canadian operations. It will use propane feedstock primarily from its expanding oilsands upgrader operations, but also propane produced at gas plants. Williams is the only company in Canada currently producing polymer-grade propylene, a valuable petrochemical feedstock used in plastics manufacturing. “It’s really exciting because it’s a whole new value-add for the province,” David Chappell, president of Williams Energy Canada, said in an interview. “It’s also a whole new value chain—propane to propylene and then hopefully polypropylene.” Pending regulatory approvals, the PDH facility is scheduled to go into service in the second quarter of 2016. The company will be undertaking its consultation process shortly, and early this summer plans to begin ordering long lead time items, he said. It also plans to start some fabrication of modules in advance of regulatory approvals. “Obviously we are taking some risk, but if we do everything the right way—which we will be doing from an environmental perspective—we believe we will get approval for this,” said Chappell. “This is a huge value-add for our resources in Alberta.” The PDH facility also will produce by-products including a “fairly substantial” amount of hydrogen, butane/butylenes and a small amount of condensate. Plans are to sell the associated hydrogen by-product in the Alberta market. Williams is also in talks with global petrochemical companies about siting a propylene derivative plant in Alberta to produce polypropylene or propylene glycol, a more environmentally friendly type of antifreeze, he said. “The annual total production of 1.3 billion barrels would be more than enough for a world-scale polypropylene plant,” said Chappell.

Producers are getting in on the action While midstream giants expand liquids operations and move further downstream into the petrochemical complex, oil and

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gas producers are increasingly entering the liquids-processing market to control costs and add value to their production. For example, late in 2012, natural gas–weighted Peyto Exploration and Development Corp. completed an enhanced liquids recovery project at its Oldman gas plant. The company expects the liquids yield will increase to 40 barrels per million cubic feet from 25 barrels per million cubic feet, principally from improved propane and butane recoveries. Scott Robinson, its chief operating officer, says the Oldman plant and other associated infrastructure are key drivers of the company’s long-term business plan. “First and foremost, in a developing situation where we really focus in a core area and we concentrate on the things we can do well, having a facility there is really the foundation to allow us to grow in a cost-effective manner,” he says. “There are numerous advantages. The nature of the resource we’re tackling is a long-life resource asset to the various formations that we’re drilling, so it really behooves us to own our own facility rather than paying fees for 30 or 40 years into the future, which would pay for a facility multiple times.” Given the continued weakness in natural gas prices, Robinson says, the economics of owning infrastructure assets and the resulting low operating costs have proven valuable, particularly last year when commodity prices were so low. “People were not making any cash flow, and even at a $1.50-per-[thousand-cubicfoot] gas price, we were still generating operating income because of that low-cost aspect of owning our own facilities.” Furthermore, the facility’s on-stream times are some of the best around, if not the best, he says. Certainty of market access is another compelling benefit of facility and infrastructure ownership, Robinson notes. Paramount Resources Ltd. shares this perspective. In 2012, the company launched a massive build-out of its gas and liquids processing infrastructure in the Kakwa area of west-central Alberta in anticipation of a major bump in liquids production. It has also secured access to third-party processing facilities. Once projects underway at Musreau and Resthaven are completed, Paramount will have 73,000 barrels of oil equivalent per day of capacity in the region. Current production is just 23,600 barrels of oil equivalent. Driving the expected production growth is the Montney play, Jim Riddell, Paramount president and chief operating officer, told a recent breakfast meeting in Calgary. The company greatly expanded its presence in the play after doing a propane frac on a vertical well, which resulted in initial production rates of between one million cubic feet and two million cubic feet per day. The company has now acquired more than 200 sections of land in this area and has another 100 sections of land to the north, he said. Because it’s a new area, infrastructure has been a priority for Paramount. The company is participating in a major expansion of the Resthaven plant’s deep-cut capacity and building massive deep-cut capacity of its own at Musreau for additional capacity of 57,000 barrels of oil equivalent per day in 2014. “We’ll have a total of 73,000 barrels of oil equivalent a day. That’s a very big deal for Paramount—Paramount produces about 20,000–25,000 barrels a day today, and we’re going to see our production double or triple over the next few years,” he said.

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Ramping up in central Alberta Cardium pushes oil production in province, but natural gas about to make a comeback By Godfrey Budd

rilling and development activity in central Alberta is playing a big role in reversing the long-term decline and boosting the province’s conventional crude oil production. Beginning in 1973, conventional oil production has been in decline for almost 40 years. But in 2010, the application of multistage fracking in horizontally drilled wells started powering growth in the province’s conventional crude volumes. The Energy Resources Conservation Board (now the Alberta Energy Regulator) reported a 14 per cent increase in production in 2012 and a 9.5 per cent increase in reserves over 2011 levels. In 2012, Alberta’s crude oil production totalled 556,000 barrels of oil per day with a yearly total of 204 million barrels. “This is due to the higher production rates of horizontal wells,” stated the regulator. Natural gas production, at 9.4 billion cubic feet per day, was down 5.5 per cent from 2011, the release said. The drop was driven by low gas prices, which has producers scrambling to increase their oil weighting. The junior sector, especially, has been bailing on natural gas in recent years. The median natural gas weighting for juniors in the third quarter of 2012 was 44.1 per cent of overall production, compared to a natural gas weighting of 50.4 per cent in the previous quarter, and 75 per cent back in the third quarter of 2009, according to investor relations firm Bryan Mills Iradesso (bmir). The Cardium formation of central Alberta has been an especially attractive target for companies looking to increase oil production. Production from horizontal wells in the formation has skyrocketed to about 80,000 barrels per day in only four years, according to a recent report from Peters & Co. Limited. At the start of 2009, horizontal Cardium wells were producing less than 2,000 barrels of oil per day, with the lion’s share of total production, an estimated 40,000 barrels per day, from older, vertical wells. Citing figures from the Peters report, the Alberta 58

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government’s most recent update states total overall output from the Cardium is now about 115,000 barrels per day. Describing horizontal drilling in the Cardium as “one of the most targeted light oil plays” in the Western Canadian Sedimentary Basin (WCSB), the Peters report pegged the number of horizontals drilled in the formation in 2012 at about 580, and the number brought on stream at about 715. The current Cardium total of about 2,000 horizontal wells has leapt from fewer than 70 in early 2009. About 1,700 of the horizontals drilled in the last few years have been outside the main conventional conglomerate play in the Pembina field, Peters said. New areas where horizontal Cardium wells are being drilled include Wapiti, Kakwa and Kaybob in the northwest, with Stolberg, Willesden Green, Ferrier and Harmattan East on the southern portion of the core Pembina fairway. Noting that costs, production rates and other key metrics varied by area, the Peters report highlighted four emerging areas that saw increased horizontal drilling and good results in 2012: Kaybob, Willesden Green, Ferrier and Stolberg. It said Ferrier and Willesden Green were productive for Cardium oil in conventional conglomerate reservoirs while the new horizontal wells have targeted the undeveloped halo sandstone reservoirs. In its report released in early March, Peters said that over the past 12 months about 40 operators have drilled a combined total of about 450 horizontal Cardium wells. Peters said the top three horizontal drillers in that period were PetroBakken Energy Ltd., (now Lightstream Resources Ltd.) (60 wells), Bonterra Energy Corp. (53 wells) and Whitecap Resources Inc. (41 wells). It said the leading operators to license Cardium wells in the past year were PetroBakken (93), Bonterra (85) and Vermilion Energy Inc. (70). Penn West Petroleum Ltd., the largest landholder in the Cardium, is also on track to do a significant amount of drilling in central Alberta. With an approved capital budget of $900 million

Photo: Aaron Parker

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in 2013, and another $300 million potentially available in the second half of the year depending on commodity prices and other factors, the Cardium will take 13 per cent of this money. Cost reductions have continued with the company’s recent operations. Noting that Penn West’s activity in the Cardium was modest in the first quarter this year with only six wells drilled in the Alder Flats area, Rob Wollmann, senior vice-president of exploration, said during a May conference call that, “Drilling and completions costs dropped from $3.3 million per well last year to $2 million, a result of improved drilling times down to just over seven days, spud to rig release, and substantially lower completion costs due to the adoption of water-based fracs in an area which had been historically fracked with oil. “Development of the Cardium light oil resource is anticipated to accelerate in 2014 as large-scale integrated development plans are finalized,” Wollmann said. Continued strong oil prices of around $90 per barrel West Texas Intermediate combined with the twin technologies of horizontal drilling and multistage fracking have been giving the Cardium a new lease on life. As a Raymond James Financial, Inc. report noted, “Historically, the limits of conventional Cardium fields have been defined by reservoir quality cut-offs (porosity and permeability) as opposed to physical barriers (such as oil/water/gas contacts). Horizontal multistage fracs serve to significantly lower the permeability and porosity cut-offs, and in so doing significantly expand the boundaries of prospective Cardium fields well beyond where vertical development traditionally stopped. In addition to this ‘halo’ development, horizontal multistage fracs can be used within conventional field boundaries by accessing lower, tighter parts of the reservoir where the top high-permeability layer has been exploited vertically.” Located outside the traditional boundaries of a pool, in the past halo wells would have typically been dismissed as uneconomic. But the new technologies have yielded unexpectedly good results. For instance, much of the recent horizontal drilling in the Pembina West area of the Cardium has focused on the halo, or outer margin of the play, with lower and tighter portions of the Cardium “A” zone being the primary target. Some horizontal drilling, on the other hand, has sought to boost recovery factors within thicker pay zones inside the traditional boundaries. Surprisingly, wells inside the conventional pool have been producing at lower rates than the halo wells by as much as 60 barrels per day. “The reason for this is that the horizontal wells have been targeting lower Cardium ‘A’ tight sands where vertical wells have mainly targeted upper Cardium ‘A’ higher permeability sands and conglomerates. So in-pool wells generate lower initial production rates (offset by shallower declines), but not as much as we initially thought would be the case,” said the Raymond James report.

Smaller companies making the switch to oil Manitok Energy Inc., DeeThree Exploration Ltd., Tamarack Valley Energy Ltd. and Alexander Energy Ltd. are some of the smaller companies that have managed to significantly reduce their gas weighting from quarter to quarter through oil drilling, much of it in central Alberta. Manitok decreased its gas weighting to 51 per cent from 78 per cent in the second quarter of 2012 as the company found success on its Cardium light oil play, according to bmir. Tamarack Valley had Cardium oil drilling success in the Lochend and Garrington areas of Alberta and brought its gas weighting down to 51 per cent in the third quarter of 2012 from 58 per cent the previous quarter. DeeThree reduced its third-quarter gas weighting to 32 per cent from 38 per cent through success in the Alberta Bakken and Belly River light oil resource plays.

A rig drilling north of Edmonton.

Other plays are also developing in central Alberta, helping companies build their oil production. Three years ago, DeeThree, one of the juniors bmir identified as switching from gas- to oilfocused activity, was producing 400 barrels of oil equivalent per day of dry natural gas. Today, thanks to two light oil plays—the Exshaw Formation in southern Alberta and the Belly River in the Brazeau area of west-central Alberta—it is producing 7,000 barrels of oil equivalent per day, with a 75 per cent oil weighting. The company raised $125 million and bought its Belly River asset. O I L & G A S I N Q U I R E R • j u ly/a u g u s t 2 0 1 3

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We are not manufacturing yet, but we are pretty close to it. We know where we want to drill, what we want to drill and how we do it. — Jim Evaskevich, president and chief executive officer, Yangarra Resources Ltd.

“There hadn’t been a well drilled in here,” company president and chief executive officer Martin Cheyne said at DeeThree’s annual general meeting in May. The Brazeau Belly River pool could prove to be a blockbuster conventional light oil reservoir. DeeThree’s 2013 capital budget calls for $160 million to be spent drilling 11 wells in the Belly River and 20 in Exshaw. “But I think we’re probably going to switch that to go 50/50,” he said. Cheyne said he believes its lower-end wells will produce between 200 and 300 barrels per day and the average well pump between 400 and 500 barrels per day, while one out of four or five wells will produce more than 1,000 barrels per day. Yangarra Resources Ltd. is another junior building out a new play in central Alberta. Yangarra has been learning the tight oil business targeting the Cardium play, and is now using that knowledge to crack open the Second White Specks Formation. Yangarra has participated in 50 horizontal wells in the past three years and now understands horizontal drilling techniques applied to resource plays, company president and chief executive officer Jim Evaskevich reported to shareholders at the company’s annual meeting. “We are not manufacturing yet, but we are pretty close to it,” Evaskevich said. “We know where we want to drill, what we want to drill and how we do it.” The company has an interest in 140 sections of land at Willesden Green and Ferrier. Its $25-million capital budget for 2013 is focused on Cardium light oil and liquids-rich Glauconite wells split between the two oil- and liquids-rich areas. Yangarra has accumulated 45 (29 net) sections of land overlying the Second White Specks Formation, and is now working to make it pay. Evaskevich described the play as a thick shale lying between the Cardium and Viking formations. It has an estimated 10 million to 20 million barrels of original oil in place per section and considerable oil has been produced over the past 30 years, the meeting heard. With three horizontal wells and two vertical wells in the play, “we’ve drilled more of them than anybody else to our knowledge,” Evaskevich said. With the Second White Specks now generating $250,000– $300,000 per month in revenue, Yangarra is content to pay down the capital it has put into the play while seeing what other producers in the area are doing, he told the meeting. “Ultimately, this is going to be a big play; it’s going to take some time,” he said. 60

j u ly/a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

A recent study, however, said the pace of growth in oil drilling activity is going to slow down. The 51-page study from New York–based ITG Investment Research forecasted that non-mined oil production, which includes the Alberta Cardium, will slow to a compound annual growth rate of 3.3 per cent to 2020, down from 8.8 per cent in 2011-12. But the study expected renewed gas drilling to take its place. Based on the expectation that liquefied natural gas (LNG) exports will become a reality, ITG forecasted that the pace of gas development will quicken in the coming decade. The ITG study predicted a near doubling of total oil production from western Canada to 5.7 million barrels per day, and increased natural gas output to approximately 16 billion cubic feet per day by 2025. The projected growth does not rely solely on the Horn River Basin and the Montney. It also assumes success in the Duvernay, with 42 rigs running in the central Alberta play by 2016. ITG studied data from more than 300,000 wells in western Canada to develop its forecast of oil, gas and natural gas liquids production. Its analysis assumes an average annual total of 375 rigs, up from the 2012 average of 285, driven by increased drilling in those three plays. North America’s gas giant, Encana Corporation, is in the early stages of Duvernay development with its joint-venture partner, a subsidiary of PetroChina Company Limited. Initial test results have exceeded the company’s expectations, and a multi-year development plan has the potential to significantly lower drilling and completion costs. Encana has three drilling rigs working in the Duvernay right now, but has deep, very challenging wells to drill. Encana’s Duvernay wells entail drilling vertically for 4,000 metres, then horizontally for 2,200 metres. But the results justify the risks Encana’s Canadian president Mike McAllister said in its first-quarter report to shareholders. “Our most recent well came in well above expectations. After 30 days on production, it is producing roughly 1,400 barrels per day of field condensate and four million cubic feet per day of natural gas,” he reported. Field condensate yields from Encana’s wells across the play are top quartile, ranging from 45 barrels to 350 barrels per million cubic feet, McAllister said. “Our confidence in the play continues to increase, and we are successfully transferring knowledge and our technical expertise from our Horn River operations into the Duvernay as both plays share significant, or shall I say similar, rock characteristics,” he added.

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Business

Intelligence Tax credit can add up to big savings for R&D companies

Many businesses today rely on new technologies and advancements in scientific research to fuel progress, and the energy industry is no exception. It’s constantly on the lookout for innovative products, processes and materials to make the exploration, production and transportation of oil and gas safer, cleaner and more cost-effective.

By Michael Dennison at Grant Thornton LLP

Helping them accomplish this are a myriad of technology, research and manufacturing companies, from small, sole proprietorships to large corporations. All are involved in the exciting business of creating something new or discovering a way to make something better than it was in the past. For these companies, taking advantage of the potential benefits of a federal tax incentive program could add up to big savings in the form of a cash refund or tax credit. It’s called the Scientific Research and Experimental Development (SR&ED) Program, and it is a federal government initiative

Does your company qualify for the SR&ED Program? Check out

designed to support and encourage Canadian innovation.

the following questions to determine your potential eligibility.

Administered by the Canada Revenue Agency (CRA), the SR&ED Program encourages Canadian businesses of all sizes and in all sectors to conduct research and development (R&D) in Canada. It is the largest single source of

• Do you allocate some of your revenues/profits back to R&D investment?

federal government support for industrial R&D. The program gives claim-

• Do you have a test lab?

ants cash refunds and/or tax credits for their expenditures on eligible R&D

• Are you deploying new equipment or processes to improve some

work done in Canada. Most provinces also offer similar programs to augment the federal incentive.

aspect of your business? • Are you experiencing any serious operational problems or have

The SR&ED program contains significant income tax incentives such as

you had any serious development or implementation failures

full income deductions for eligible expenditures, a federal investment tax

that you are having trouble solving and that are costing you

credit (ITC) of 20 or 35 per cent of eligible expenditures that in some cases

resources that otherwise should go to commercial operations?

can be fully refundable, and in most cases a provincial ITC top-up of 10–15

• Have you heard of any nagging problems from your shop-floor work-

per cent. There are also tax planning opportunities as expenditures can be

ers that are hampering production or resulting in unexpected costs?

pooled and indefinitely carried forward. ITCs can also be pooled and carried

• Have you had to write off any materials or equipment due to

back (up to three years) or carried forward (up to 20 years).

failed changes or designs?

Every year, this innovative program helps tax-paying companies in

• Do you have contracts with other companies (foreign or domestic)

Canada. In fact, in 2011 the CRA processed 23,000 SR&ED claims. However,

to develop or design products, parts or other items due to your

determining if your business qualifies for a SR&ED credit, or ensuring that

expertise?

you have maximized the R&D funding entitlement, can be a complex and

• Do you have an R&D account in your G/L?

time-consuming process, particularly if you’re a smaller company that does

• Do you have large consulting fees paid to engineering firms or

not have access to in-house tax and accounting expertise. In 2012, significant changes were made to the SR&ED legislation in the federal budget. The CRA also introduced revised eligibility policies and administrative changes to the SR&ED claim review process that appear to be raising the bar for eligibility. As a result of these changes and the complexity inherent in making a SR&ED claim, selecting an experienced SR&ED practitioner is more important today than it’s ever been. For more information about the SR&ED Program, contact Michael Dennison at Grant Thornton LLP.

other technical organizations (e.g., for testing/design)? • Do you employ any research scientists or engineers (e.g., PhD/ M.Sc./P.Eng.)? • Does your company hold any patents, have any patent applications outstanding or have you thought about applying for a patent for any of the work you have done? • Have you made any payments to universities, technical associations or research institutes? • Do you have grant or loan funding from outside technical entities other than banks (WED, IRAP, AVAC, others)?

O I L & G A S I N Q U I R E R • J Ul y / a u g u s t 2 0 1 3

advertisers' index Abacus Datagraphics Ltd . . . . . . . . . . . . . . . . . . 30

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

MRC Global Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 39

Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 47

Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 28

Annugas Compression Consulting Ltd . . . . . . . . 34

Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . 22-23

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 47

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 39

DSI Thru-Tubing Inc . . . . . . . . . . . . . . . . . . . . . . . 32

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 56

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 52

Brews Supply . . . . . . . . . . . . . . . . . . . . . . 10, 15 & 29

Edey Consulting Services Ltd . . . . . . . . . . . . . . . 46

Brother’s Specialized Coating Systems Ltd . . . . 36

Expertec Van Systems Inc . . . . . . . . . . . . . . . . . . 33

Canadian Standards Association . . . . . . . . . . . . . 8

FlexSteel Pipeline Technologies Inc . . . . . . . . . . .16

City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . 40

Foremost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21

Clean Harbors . . . . . . . . . . . . . . . inside back cover

IDE Technologies Ltd . . . . . . . . . .inside front cover

ClearStream Energy Holdings . . . . . . . . . . . . . . . 24

Manulift EMI Ltee . . . . . . . . . . . . . . . . . . . . . . . . 44

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 57 Predator Drilling Inc . . . . . . . . . . . . . . . . . . . . . . . 13 Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . .19 Quinn Contracting Ltd . . . . . . . . . . . . . . . . . . . . . .14 Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . . 40 Shaw Cablesystems Ltd . . . . . . . . . . . . . . . . . . . . 4

Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 56

MaXfield Inc . . . . . . . . . . . . . . . outside back cover

STEP Energy Services . . . . . . . . . . . . . . . . . 27 & 37

CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 38

TCA Marketing Ltd . . . . . . . . . . . . . . . . . . . . . . . . . 5

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 57

V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 9

J Ul y / a u g u s t 2 0 1 3 • O I L & G A S I N Q U I R E R

TOG ETHE R WE CAN

For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment; MaXfield is now your one stop shop for industrial fabrication.

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