Oil & Gas Inquirer March 2014

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INQUIRER Western Canada's Exploration & Production Authority

Lma Le e ea a n mac ach chi hin ne Manufacturers use automation, innovation to grow through labour shortages, economic doldrums

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PLUS:

The Montney tight resource play becomes world-class

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CONTENTS

MARCH.

in the news

Oil prices flat, gas prices to rise, says FirstEnergy forecast

regional news

British Columbia

Northeastern Alberta

Southern Alberta

Artek encouraged by liquids yield at Inga South Montney play

Increasing rail capacity could help narrow differentials, conference hears

DeeThree Exploration production continues climbing

Northwestern Alberta

Strategic focuses $80-million budget on Muskeg Stack light oil play

Central Alberta

Jury still out on Duvernay economics

Saskatchewan

Husky Energy approves two new heavy oil thermal projects

features

Cover Feature

42 Lean machine Oilfield manufacturers use innovation, automation to grow through economic doldrums, while oilsands manufacturers prepare for a possible boom

every issue

6 54

Stats at a Glance

Land of giants Montney tight resource matures into world-class play

Political Cartoon

Correction notice: Di-Corp COREMIX® was incorrectly advertised in the January 2014 edition as having a Microtox threshold of 35kg/m3. The correct Microtox threshold is 1.4kg/m3. We apologize for any confusion this may have caused.

Cover design: Peter Markiw

OIL & GAS INQUIRER • march 2014

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Editor’s Note Vol. 26 No. 3 EDITORIAL EDITOR

Big labour, big business, big government and the oilsands

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

carter haydu, richard macedo, James mahony, Pat roche, Elsie ross EDITORIAL ASSISTANCE MANAGER

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Peter markiw

CREATIVE SERVICES

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The development of the oilsands is an interesting study in how government ownership of resources challenges its ability to act in the interests of the people it supposedly represents. Ignoring environmentalists who are largely foreign voices in the debate, there are basically three domestic perspectives on oilsands development. The first perspective is that of oilsands developers, who consistently argue for the interests of their shareholders. Their goal is maximizing shareholder value while managing risk. If this means shipping raw bitumen to the Gulf Coast or China, so be it. And if it means buying equipment overseas or bringing in foreign workers to lower costs or speed development, they have a responsibility to their owners to do just that. The second perspective comes from big labour, in this instance Alberta Federation of Labour president Gil McGowan. McGowan has been a strong representative for the interests of the oilsands workers. He also increasingly finds himself the representative for all Albertans who want to see orderly development that captures as much wealth for Alberta as possible, a role that should be occupied by the Alberta government. McGowan makes two points about oilsands development. The first is that Alberta should capture as much value-added opportunity from the oilsands as possible through upgrading bitumen and supplying the petrochemical industry with feedstock. His second argument is that oilsands developments should be built and operated by Alberta workers. And if this means slowing down development, so be it.

Finally, we have the Alberta government, which is both a developer through its ownership of the resource and a representative for the people when it comes to how the oilsands should be developed. It’s easy to see the conflict this situation presents. We have the government speaking as a developer and saying the free market should decide on issues such as the pace of oilsands development, where bitumen should be upgraded or refi ned and where components of the projects should be built. Yet, at the same time, we have the government trying to represent the public by spending billions of taxpayer dollars on local facilities like the Redwater refi nery to spur domestic upgrading and hopefully encourage value-added petrochemical developments. And then we have the government put its developer hat back on and lobby for pipelines to ship raw bitumen overseas, thus putting any future local upgrading out of the picture. Here is one possible solution to this conflict of interest: The government could make its resource business into a separate entity like a Crown corporation that pays dividends back to the province—or better yet, directly to the people. From there, it can act as it is supposed to—as a regulator of industry in the best interests of the people of Alberta.

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

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April 2014

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.

We look at how drilling and completion

Bakken/Three Forks focus: The Bakken is now in the production-optimization phase. technologies are changing in the play and a review of secondary recovery eﬀorts. Plus our annual review of automation and

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.

instrumentation technology. MINI B&W FSC LOGO

OIL & GAS INQUIRER • march 2014

FAST NUMBERS

.

billion cubic feet per day

Expected Montney gas production by 2015, says the National Energy Board.

.

billion cubic feet per day

Expected Montney gas production by 2018, says Wood Mackenzie Limited.

alberta completions

WcSB Oil & Gas completions

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

SERVICE

T O TA L

Jan 2013

313

381

Jan 2013

542



Feb 2013

449

124

0

Feb 2013

899

161

1,11

mar 2013

544

149

119

812

mar 2013

949

198

127

1,29

apr 2013

481

129

01

apr 2013

581

146

127

88

Jun 2013

179

2

Jun 2013

273

0

Jul 2013

263

33

Jul 2013

671

103

80



aug 2013

817

929

735

113

89

953

204

1,2

aug 2013

394

Sep 2013

357

8

Sep 2013

Oct 2013

528

153

3

Oct 2013

Nov 2013

463

164

1

Nov 2013

852

218

1,11

Dec 2013

298

137

8

Dec 2013

675

180

9

Jan 201

280

105

2

Jan 201

488

156

1

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

Jan 2013

174

19

Feb 2013

358

389

mar 2013

139

mar 2013

323

32

apr 2013

208

Jun 2013

apr 2013

9

330

Jul 2013

379

Jun 2013

aug 2013

405

Jul 2013

358

32

Sep 2013

422

Oct 2013

474

Nov 2013

532

Dec 2013

Jan 201

*From year-to-date

aug 2013

362

39

Sep 2013

347

38

Oct 2013

380

39

Nov 2013

339

3

Dec 2013

321

30

Jan 201

181

19

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STATS

AT A

GLANCE

Drilling rig count by Province/Territory

Drilling activity: Oil & Gas

Western Canada, February 6, 2014 Source: Rig Locator

Alberta, January 2014 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

Jan 1

Jan 13

Jan 1

Jan 13

432

137

9

76%

Northwestern alberta

British columbia



90%

Northeastern alberta

manitoba

71%

central alberta

139

125

Saskatchewan

107

13

79%

Southern alberta

Wc TOTaLS

23

180

803

8%

TOTaL

280

31

10

8

Service rig count by Province/Territory

Drilling activity: cBm & Bitumen

Western Canada, February 6, 2014 Source: Rig Locator

Alberta, January 2014 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

Jan 1

Jan 13

Jan 1

Jan 13

295

215

10

58%

Northwestern alberta

2

48%

Northeastern alberta

1

53%

central alberta

Saskatchewan

101

1

70%

Southern alberta

Wc TOTaLS

1

29

9

0%

TOTaL

12

121

British columbia

manitoba

OIL & GAS INQUIRER • march 2014

A big STEP for the Coiled Tubing Industry STEP Energy Services’ new ultra-capacity spread unit is changing the way coiled tubing services are offered. By Graham Chandler

breakthrough in coiled tubing technology by STEP Energy Services will soon be saving operators time and money. No longer will they need to rig out and rig in again to service a well just three metres away on the same pad. The new STEPdesigned ultra-capacity spread enables the company to service six or more wells without moving a single piece of equipment. The heart of the three-part system is the new STEPARM (Articulating Rotational Mast)—a first in the industry. A COMMAND CENTER and ultra-capacity reel trailer capable of deploying up to 6,800 metres of 73.0 mm (2 7/8”) tubing rounds out the new revolutionary spread. Now that over 70% of WCSB wells are horizontal and increasing in length, depth and complexity, “STEP’s founders saw a gap in the marketplace of equipment capable of servicing these challenging wellbores both safely and efficiently; that is the definitive purpose of the ultracapacity spread,” says Marc Johnson, VP Sales & Marketing. “A typical pad includes many pieces of heavy equipment at any given time. It stands to reason that if you reduce the amount of time one service provider is required to spend on a lease, you increase the efficiencies of the entire operation. The STEP-ARM and ultra-capacity spread are designed so that the equipment can service multiple wells without having to re-spot.” Rigging-in can take up to eight hours, “so if you have a six-well pad you can potentially reduce the time required by our services on a job site by a day, if not more.” The ARM also eliminates one man from the lease, the need for crane anchors, and potentially dangerous crane side loading as well. “It is a unique solution that both addresses safety considerations and operational efficiencies of these types of deep, coiled tubing intervention programs,” says Johnson. Bailey Epp, VP Engineering & Technology at STEP, says the engineering for the STEP-ARM was demanding; the design had never been done before. “The most challenging obstacle

was working at greater heights; we had to consider things like wind load, the capacity of the system and the working radius of the unit. We took crane technology and integrated it into a dual-boom, masted system.” Epp worked closely with Serva Group Canada and Perazzi Engineering of Piacenza, Italy, on the design. “The design specifications were to lift 40,000 lbs on a radius of six wells spaced at five metres,” he explains. “The goal was to capture as many wells as we could without having to re-spot the equipment, while being cognizant of the engineering constraints in the design of the mast.” Another constraint was ensuring the whole assembly was road-legal in terms of weight and dimensions. “The United States is a potential market for STEP in the future, so we had to take into account various federal regulations.” The other two main components of the spread—the ultra-capacity reel trailer and the COMMAND CENTER—were “designed for increased capacity,” says Epp. Importantly, the design of the STEP-ARM allows the unit to access multiple wellheads while keeping the coil tubing pointed in the same direction as the spooling reel trailer. “That specific scope of the project—the ability to rotate the mast while the injector counter-rotates and points at the reel as you are slewing the mast—is

a technology that has never been done before,” says Epp. The ultra-capacity spread was designed with evolution in mind, too, allowing for new modifications in response to changing well and pad technology. “We are excited to prove the concept of this revolutionary innovation, and for our clients to experience the quantifiable efficiencies gained using this spread. We are focused on the future of coiled tubing technology and services, specifically how STEP can further increase our operational capabilities and enhance the technical services we deliver to our clients,” says Epp.

t: 403-457-1772 w: www.stepenergyservices.com e: info@stepenergyservices.com

IN THE

NEWS Issues affecting Canada’s E&P industry

rise

Oil prices flat, gas prices to rise, says FirstEnergy forecast By richard macedo

Oil price levels should be relatively steady in 2014, while the frigid winter t h at ’s g r ipp e d t he ea s te r n side of the continent has helped draw huge amounts of nat ural gas in bot h t he United States and Canada out of storage, which has boosted prices, a FirstEnergy Capital Corp. outlook session reported in late January. West Te x a s I nter med iate ( W T I ) and Brent prices are in a holding pattern, awaiting supply developments in Iran and Libya and more developments on the U.S. Gulf Coast. World demand has been holding up well as the global economic recover y gains stea m but remains uneven, noted Martin K ing, vice-president of institutional research with FirstEnerg y, who delivered the market outlook. Canadian oil pricing has recovered on improved U.S. intake of barrels and “better infrastructure performance.” Gas, meanwhile, has been supported by the cold winter in the east. Prices are forecast to rise in 2014 from last year.

Oil outlook Oil markets are facing three questions that will defi ne how global pricing (Brent) and North American pricing (WTI) will be driven this year, King noted. For Brent, how will global balances shake out in the event of a return of Libyan and/or Iranian supplies? For WTI, will there be a supply glut developing in the Gulf after just clearing out the previous glut at Cushing, Okla.? Will prices crash? And for Canadian prices, will the differential blow out once again or, as King asked, “Have we reached a better steady state for infrastructure movements of crude oil?” FirstEnergy believes that WTI and Brent prices will hold steady and Canadian heavy price differentials will hold at much improved levels versus 2013. “Things are probably looking more stable...for all of these cases, for both Brent and West Texas, and the differentials, we think, are kind of moving into more of a steady state,” King said. The next major milestones for Canada are additional infrastructure developments

FirstEnergy Capital 2014 price forecast WTI ($/bbl)

Brent ($/bbl)

WTI-Brent differential ($/bbl)

WTI-WCS differential ($/bbl)

Natural gas AECO ($C/MMBtu)

First quarter

94.00

104.00

10.00

22.33

3.73

Second quarter

92.00

100.00

8.00

17.00

3.72

Third quarter

93.69

99.67

5.98

18.00

4.01

Fourth quarter

94.67

99.67

5.00

19.00

4.23

2014 average

93.59

100.83

7.25

19.08

3.92

Time period

Sources: FirstEnergy Capital Corp.; Bloomberg

and how these will impact crude price spreads. Growing Canadian crude supply can fi nd its way into the Midwest and further down pipe to the Gulf Coast. Long term, though, more access to all coasts is needed. Natural gas outlook “In terms of natural gas...what an interesting development, needless to say,” King said. The current state of the market is “price bullish—I think it’s pretty obvious that’s been the case for the last five or six weeks.” U.S. heating degree days have been running 11 per cent greater than last winter and two per cent greater than average. It could end up being the coldest winter in the past 20–25 years in the United States. March-end storage in the United States is estimated at 1.34 trillion cubic feet. It’s shaping up to be the lowest storage exit for the United States since 2008— it could hit 10-year lows if February and March are colder than average. Western Canada March-end storage levels are estimated at 295 billion cubic feet and eastern Canada is estimated at 30 billion cubic feet. FirstEnergy’s previous assessment suggested a challenging gas market for 2014 in terms of supply meeting structurally growing demand; it’s now been made even more challenging by a huge winter withdrawal season. Demand is still growing in the industrial and power generation sectors, while “U.S. export commitments are rising.” The NYMEX price is expected to average US$4.35 per million British thermal units in 2014, compared to the previous outlook of $4.50, and the 2013 average of $3.69. AECO prices are expected to average C$3.92 for the year, compared to the previous estimate of $3.79 and the average of $3.16 in 2013. OIL & GAS INQUIRER • march 2014

Trican

In The News

Pressure pumping outlook mixed, says Trican By James Mahony

Frac companies are looking to the Duvernay for growth in 2014.

“If you look at a West Coast LNG facility being completed in the 2018-20 time frame, the first leg of a meaningful activity increase is probably 2015-16. So, it’s not a big play in 2014, but medium to long term, it has a lot of potential.” South of the border, where Trican is active in several plays—including the Marcellus, Bakken, Permian, Eagle Ford, Barnett shale and Haynesville—things are less clear. “Activity in last year’s fourth quarter dropped from Q3,” Baldwin said. “A lot of

Canadian fracturing requirements by play

Play

Fracture stages/well

Fracturing hydraulic horsepower required

Frac size (tonnes/stage)

Oil plays Cardium

15–25

8,000–25,000

20–40

Slave Point

10–20

7,500–12,500

20–40

Beaverhill Lake

10–20

20,000–30,000

75–150 cubic metres

Viking

10–15

4,000–15,000

20–40

Bakken

10–25

2,000–4,000

6–12

Lower Shaunavon

10–15

6,000–10,000

20–40

Alberta Bakken

12–20

4,000–15,000

20–30

10–20

18,000–40,000

50–250

8–12

10,000–30,000

50–250

3–5

10,000–30,000

40–120

Horn River

15–30

30,000–50,000

200–300

Duvernay

10–20

35,000–50,000

80–150

Gas/NGL plays

Montney Deep Basin horizontal Deep Basin vertical

Sources: Canyon Technical Services Ltd.; Calfrac Well Services Ltd.

march 2014 • OIL & GAS INQUIRER

that was weather-related, typical with the Thanksgiving and Christmas slowdowns. It was not really unexpected, but it was a little bit slower. Activity for Trican is expected to rebound in the first quarter. “We’ve been underperforming for a period of time in the U.S. relative to some of our peers, and, as a result, we’re focusing on cost control and improving equipment utilization.... That said, the U.S. markets are a little bit more challenged than the Canadian [markets], with more of an oversupply of equipment.” Recalling last year’s second half, Baldwin said Trican saw a “really good” third quarter. “Horn River really helped our numbers. We pushed on pricing and continue to push that end of it. We generally saw ourselves, Calfrac Well Services Ltd. and Canyon Services Group Inc. pretty close to full utilization in the fourth quarter, but some of the other players were maybe not quite as fully utilized.” As for pricing, “Our view is that you need at least two solid quarters of increased activity for the whole industry to get pricing up significantly,” he said. “Q1 looks like it will be the first quarter for that to happen. Then you’ll have breakup in Q2, so the big question on pricing is how quickly things will bounce back in the third quarter.” As for the dynamics of the current pressure pumping market, it comes down to supply and demand, he said. “It’s positive. All the pressure pumpers are getting to the stage where they’re fairly busy. If you’re flat out and you’ve got a competitor that’s only running at 50 per cent utilization, it’s only smart for the customer to use them as pricing leverage. It’s just the nature of the beast.”

Photo: Joey Podlubny

One of Canada’s largest pressure pumping companies is looking for a roughly five per cent rise in demand from producers in western Canada this year, although market conditions in the United States are less clear. “A lot of the growth in Canada is expected to come from the Duvernay,” Michael Baldwin, senior vice-president, finance, and chief financial officer of Trican Well Service Ltd., told the CIBC World Markets institutional investor conference in Whistler, B.C. During the first quarter, he described interest and activity in the Montney and Deep Basin as “good.” At the same time, he said what will happen after spring breakup remains an open question, as it does almost every year in western Canada. “You have to monitor your customers’ capital budgets and adjust your operations as budgets go through. In the long term, LNG [liquefied natural gas] is obviously a big story. Our feeling is that we’ll start to see activity ramp up three years prior to a facility being completed.”

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BrITISh cOLUmBIa WELL acTIVITY JAN/13

JAN/14

Wells licensed

106

11

JAN/13

JAN/14

Wells spudded

Rigs released

JAN/13

JAN/14

▲

British Columbia

▲

Source: Daily Oil Bulletin

artek encouraged by liquids yield at Inga South montney play artek Exploration Ltd. says recent results from its Montney play at the Inga South area are showing substantial liquids content. Late in the fourth quarter of 2013, Artek drilled a successful Montney horizontal well from the 10-17-087-23W6 pad in the Inga South area. The well was completed with a total of 31 fracture intervals using a slickwater hybrid frac treatment. After a 140-hour clean-up and production test period, the well was flowing at a stabilized average rate of 1.7 million cubic feet per day and 503 barrels per day of free condensate, or 794 barrels of oil equivalent per day (63 per cent pentanes plus), over the 102-hour period, subsequent to drilling out the packers at a flowing pressure of 389 pounds per square inch with approximately 80 per cent, or 8,800 cubic metres, of load water left to recover.

Artek said it is very pleased with the high liquids rate from the well with yields of free liquids ranging from 214 to 289 barrels per million cubic feet throughout the test period, representing some of the highest in the Montney development fairway. In addition, another 45 barrels per million cubic feet of liquids is anticipated at third-party natural gas processing facilities from the Montney natural gas stream, which is some of the richest, or highest-heat content, natural gas in the basin. Although these are early stages in Artek’s Montney exploration plan, management believes parallels can be drawn to the high liquids recoveries being realized from Montney wells in the Tower and Blueberry areas in British Columbia.

The company and its partner continue to increase their landholdings in the Inga/ Fireweed area, bringing total Montney mineral rights to over 88,750 acres (52,400 net to Artek), or approximately 133 (79 net to Artek) sections. Artek operates the lands with approximately a 58 per cent average working interest. In other operations, the company’s first Inga South liquids-rich Doig well of 2014 reached total depth in mid-January and will be completed using a 30-interval slickwater frac completion. In addition, Artek has reached total depth on its first 2014 horizontal well in the Mulligan area targeting upper Charlie Lake oil. Completion was scheduled for the fi rst two weeks of February. — DAILY OIL BULLETIN

artek Exploration drilling inventory Prospect area

Zone/play

Inga/Fireweed

Doig liquids

Inga Montney

Montney liquids

Peace River Arch oil

Land (sections)

Locations (net)

Targeted reserves (bcf/mboe)

Targeted rate (mmcf/d/boe/d)

53.0

35.0

500.0–600.0

900.0–1,300.0

120.0

n/a

600.0–800.0

Triassic oil

60.0

n/a

350.0–400.0

400.0

Deep Basin

Cretaceous gas/NGLs

38.0

20.0

2.0–3.0

2.5–3.5

Peace River Arch/B.C. conventional

Multizone gas/NGLs

n/a

20.0

1.0–1.5

1.0–2.0

Pouce horizontal

Montney gas/NGLs

13.0

21.0

2.5

2.7

Sinclair

Montney gas

11.5

>30.0

3.5–4.2

3.5–5.5

Noel/Elmworth

Nikanassin gas/NGLs

>60.0

25.0

2.8

2.5–3.5

Noel

Cadomin gas

33.0

35.0

4.0

6.0

Total

>220.0

>80.0–100.0 mmboe

>0,000.0 boe/d

Source: Artek Exploration Ltd.

OIL & GAS INQUIRER • march 2014

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march 2014 • OIL & GAS INQUIRER

British columbians divided over Trans mountain expansion While B.c. residents who are aware of Kinder Morgan Canada Inc.’s proposal to expand its Trans Mountain Pipeline are divided on the issue, a new poll also shows a striking increase in the number of those who are undecided. In the Insights West online survey of a representative provincial sample, four in five residents (81 per cent) are aware of the proposed expansion—a 21-point increase since last year—and three in five (76 per cent) say they are familiar with it. When British Columbians who are aware of the proposed expansion were asked directly about it, 48 per cent—up 10 per cent since January 2013—said they support it, while a slightly smaller proportion (43 per cent)—down 14 per cent since a year ago—are opposed. However, the number of residents who are undecided had risen to 11 per cent in January 2014 from four per cent a year ago, the Vancouver-based pollster found. “As was the case last year, the Trans Mountain expansion remains a contentious issue across British Columbia,” Mario Canseco, vice-president of public aff airs at Insights West, said in a news release. “The pro-expansion side is now ahead of the anti-expansion side by five points at the provincial level, but the proportion of residents who have not made up their minds has almost quadrupled.” Across the Lower Mainland and Fraser Valley, 49 per cent of residents support the Trans Mountain expansion (11 per cent strongly and 38 per cent moderately), while 39 per cent are opposed (16 per cent strongly and 23 per cent moderately). However, just over one-third of those on Vancouver Island (36 per cent) are in favour of the project. Insight West also found the views on the proposed expansion vary significantly by specific demographics. For example, while 58 per cent of male residents favour the Trans Mountain expansion, that number drops to 37 per cent among women. In addition, younger British Columbians aged 18–34 are less likely to support the expansion, with 39 per cent of those aged 18–34 in favour compared with 43 per cent support for those aged 35–54 and 55 per cent support for those aged 55 and over, according to the poll. “The fi ndings of this survey on the Trans Mountain Pipeline confi rm what we learned on our recent research projects related to [fracturing] and the Northern Gateway Pipeline,” said Canseco. “Residents of Vancouver Island, women and the youngest residents of the province are more likely to look at energy projects with skepticism.” The results are based on an online study conducted from Jan. 7 to 9, 2014, among 728 B.C. social media users aged 18 and over who are also members of the Your Insights Panel. The data has been statistically weighed for age and gender. While statistical margins of error are not applicable to online panels/studies of this nature, the company has assumed that the same margins of error apply as if the study were a true unweighted random probability sample with a margin of error of plus or minus 3.6 percentage points, 19 times out of 20. — DAILY OIL BULLETIN

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NOrThWESTErN aLBErTa WELL acTIVITY JAN/13

JAN/14

Wells licensed

330

23

JAN/13

JAN/14

Wells spudded

274

307

JAN/13

JAN/14

245

234

Rigs released

▼

▲

Northwestern Alberta

▼

Source: Daily Oil Bulletin

Strategic focuses $80-million budget on muskeg Stack light oil play Strategic Oil & Gas Ltd. has set its 2014 capital budget at $80 million, focusing on horizontal wells and infrastructure exploiting the Marlowe light oil play in the Muskeg Formation of northwestern Alberta. That spending target would match last year’s budget of $80 million. Strategic has completed the 05-33 Muskeg horizontal well drilled in 2013 and plans to drill another 13 wells in 2014. Capital spending will be allocated as follows: $54 million for drilling, completions, equipment and tie-ins; $4 million for workovers/recompletions; $8 million for land, seismic, facility expenditures and plant turnarounds; and $14 million for the Bistcho oil pipeline. The drilling budget will focus primarily on the Marlowe Muskeg Stack resource play as well as new seismic-defined Keg River targets to capture additional upside. Construction of the Bistcho Pipeline is the focus of Strategic’s non-drilling capital spending. Strategic believes completion

of this pipeline to the Rainbow system is pivotal to its growth and profitability and will save between $3 and $4 per barrel on transportation-related expenses. The scope of the Bistcho pipeline project has been slightly expanded to include two more sales oil pumps to provide redundancy, as well as three more miles of six-inch emulsion line required to al leviate production constraints in the West Marlowe field, as additional Muskeg wells will be drilled during 2014. This year’s production is expected to average 4,400–4600 barrels of oil equivalent per day (70 per cent oil), which would be a 40 per cent increase from 2013. Using realized prices of C$81 per barrel of oil, including hedging, and C$3.70 per thousand cubic feet of natural gas, Strategic expects cash flow of $35 million to $40 million for 2014, which would be 100 per cent more than projected 2013 cash flow. The 2014 capital budget will be funded by a combination of cash flow, debt and

Strategic Muskeg drilling results Well

Horizontal length (metres)

Cumulative production (boe)

05-33 (Q4/2013)

1,506

1,200

400 (95% oil)

15-24 (Q4/2013)

1,204

5,885

220

240 (92% oil)

16-2 (Q3/2013)

1,461

5,400

175

130 (90% oil)

04-33 (Q3/2013)

1,538

17,800

400

190 (90% oil)

14-13 (Q2/2013)

875

35,750

136

340

240 (50% oil)

13-2 (Q2/2013)

905

34,600

190

335

120 (65% oil)

Producing days

IP30 (boe/d)

Current rate (boe/d)

Source: Strategic Oil & Gas Ltd.

other sources. Strategic said it is evaluating several financing alternatives. Strategic said that despite numerous hurdles, the past year proved up the immense size of the Muskeg Stack resource. The company said it is now beginning to see reduced drill-to–rig release times, more effective wellbore placement, improved production per stage and faster on-stream cycle times. The company said its biggest challenge is downtime due to various plant, transportation and weather issues. With the Bistcho Pipeline project ongoing throughout the

Number of Muskeg Stack wells planned for 2014

first quarter of 2014, Strategic is setting conservative 2014 guidance and has modelled 25 per cent downtime for the first quarter and 10 per cent downtime for subsequent quarters. Once the new facility is operational, downtime is expected to be minimal, but the company said it is cautiously approaching the next phase of development until the major pipeline connection project into the Rainbow system is completed. Strategic said it has “climbed a steep learning curve” while discovering a new play and that its confidence in the immense resource is illustrated by its investment in the expansion and upgrading of the 09-17 oil facility at Marlowe. Future focus remains on capital efficiencies and reducing downtime to ensure stable production and cash flow. — DAILY OIL BULLETIN OIL & GAS INQUIRER • march 2014

Northwestern Alberta

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march 2014 • OIL & GAS INQUIRER

The emerging Duvernay shale play will create opportunities for a wide range of new infrastructure, including condensate stabilization, once producers figure out what is needed, an institutional investors conference heard in late January. “You need facilities to take the gas out of the condensate and stabilize that condensate,” Mick Dilger, president and chief executive officer of Pembina Pipeline Corporation, told the CIBC World Markets conference in Whistler, B.C. In addition to a condensate stabilization unit, whose cost would depend upon the type of commodity mix in the gas stream, a gas plant would be required to handle the liquids-rich natural gas coming off the condensate, he said. However, many of the existing gas plants are not suitable for the type of liquids-rich product that is being produced, said Dilger. David Smith, president and chief operating officer of Keyera Corp., suggested there is a “little bit of a question” about the composition and volumes of condensate, as well as the condensate handling and stabilization requirements. “Producers still need more time to evaluate the productivity and sustainability of those wells and to figure out what they really need from an infrastructure point of view.” According to Smith, the infrastructure required in the Duvernay also depends on the geographic area. “In the Simonette area, there’s no question there is a need for more infrastructure, and we think we are part of that solution with our Simonette infrastructure,” he said. The company is in the process of building more condensate-handling capacity, as well as more raw gas–gathering and –processing capacity, the conference heard. In the southern part of the Duvernay in the Rimbey and Willesden Green area, there is lots of existing gas-processing capacity, but a fair bit of debottlenecking is required in order to accommodate some of the growing condensate production from the area, said Smith. The nine or 10 Keyera plants in the area have an estimated 100 million to 200 million cubic feet per day of available capacity, subject to some debottlenecking work on the gathering systems, he said. For its part, Pembina has been busy planning new pipelines in the Duvernay. “The Duvernay is new enough that a producer doesn’t know whether they are going to get liquids-rich gas, crude or condensate,” said Dilger. However, that won’t be an issue for shippers on Pembina’s proposed Phase 3 expansion because there will be three distinct pipelines in the core Fox Creek, Alta., to Edmonton corridor, he said. “They can decide later, and we will be able to accommodate them no matter what product type it is.” The $2-billion expansion project is expected to be in service between late 2016 and mid-2017, subject to environmental and regulatory approvals. According to Dilger, although a new 20-inch pipeline would have accommodated the initial demand, Pembina opted for a 24-inch pipeline for the project because its producer customers were saying, “That’s the start.” The expected initial capacity in the core area is 320,000 barrels per day, with an ultimate capacity of 500,000 barrels per day.

Northwestern Alberta

“It’s a vast resource, possibly, and as much as we have overbuilt our project, if it does turn out to be a million-barrels-per-day play... then I think there is going to be a lot more infrastructure required.” The Duvernay will also need fractionation capacity, he said. “We were surprised when we did RFS II [73,000 barrels per day] that it was filled by three customers, and there were other customers we couldn’t provide service for,” he said. “We build a certain kind of fractionator and we want to do that over and over—we didn’t want to redesign our whole process.” In addition to Pembina’s Redwater project, new fractionation capacity includes Keyera’s 30,000-barrel-per-day de-ethanizer and its 35,000-barrel-per-day fractionator, both at Fort Saskatchewan, Alta. If the Duvernay and Montney continue to develop, Dilger said he has no doubt that a third Pembina fractionator will be needed. The only question is the timing. “If our Phase 3 starts up in the 2017-18 time frame, I think there is a reasonable chance that a fractionator will be signed up before that time frame.” John Williams, president and chief operating officer of Trilogy Energy Corp., said that infrastructure restraints at Kaybob is one

“The Duvernay is new enough that a producer doesn’t know whether they are going to get liquids-rich gas, crude or condensate.” — mick Dilger, president and chief executive officer, Pembina Pipeline corporation

of the biggest issues currently plaguing his company, as none of the local plants were intended to handle the high-liquids-content gas now being experienced in that area with the Duvernay. “Those liquids in a Gething, Viking or Notikewin well would be five to 10 barrels per million, and in these Duvernay wells it’s 50–100 barrels. So the separation isn’t big enough, the condenser towers aren’t big enough, and we’re having problems bringing on more Duvernay gas and actually getting the recovery that we need so we meet the dew point to put it in the various pipelines.” According to Williams, the issue with high-liquids-content gas is felt by other producers in the area as well, and the solution will come with “purpose-built refridge plants,” which can chill down to minus 35 degrees Celsius and recover most of the propane and all the pentanes and butanes. “That is what is going to happen in the next couple of years,” he said, adding that all the added liquids will “roll into” the planned Phase 3 expansion of Pembina’s $2-billion natural gas liquids pipeline to run parallel to its existing Peace Pipeline. Aside from its long-established Montney and bourgeoning Duvernay interests in the region Trilogy is also pursuing Nikanassin oil near Grande Prairie, Alta., at 10–12 locations at two million to three million barrels of recoverable oil, as well as a prospect inventory of 30–40 Dunvegan wells, Williams said. “We’re going to continue to put capital into these smaller projects based on a rate of return, capitalize them, and then in the next few years we have a lot of things that will fall in behind it. We have some Gething oil we can pursue, and obviously there are a lot of gas projects in expanding our Montney gas pool outside of its existing boundary.”

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N.E.

NOrThEaSTErN aLBErTa WELL acTIVITY JAN/13

JAN/14

Wells licensed

218

225

JAN/13

JAN/14

Wells spudded

219

14

JAN/13

JAN/14

218

16

Rigs released

▲

▼

Northeastern Alberta

▼

Source: Daily Oil Bulletin

Increasing rail capacity could help narrow differentials, conference hears By carter haydu

Even if all planned projects are completed to boost crude-by-rail capacity out of western Canada by 700,000 barrels per day between 2013 and 2015, there would still be other factors in the market that could impact the price Canadian producers receive for their products. “Differentials and volatility of differentials is really a symptom of chaos in the underlying marketplace, and that chaos is going to exist regardless of the takeaway capacity,” Stewart Hanlon, president and chief executive officer of Gibson Energy Inc., told the CIBC World Markets Whistler, B.C., institutional investor conference. “The chaos could be a refi nery fi re in the U.S., it could be flash production or lack of production in the oilsands region, it could be weather, it could be pipelines, etc., etc.” While he expects there will continue to be periods of wide and tight differentials, as well as volatility, Hanlon said increased takeaway capacity via additional rail capacity should nonetheless help narrow the differentials for Canadian producers. company

For its part, last year Gibson and U.S. Development Group LLC announced plans to develop a crude-by-rail terminal near Hardisty, Alta., which will handle multiple grades of crude oil with an initial capacity of 140,000 barrels per day and is expected to begin operations in early 2014. “It’s sold out, and we are basically starting discussions around expansion because we can go from two trains a day to four trains a day,” he said, adding that in the absence of knowing what the North A merican transportation f ramework will look like in a few years, rail capacity provides a long-haul option for a variety of potential crude types that might be required throughout the continent. “We’re certainly not smart enough to know what the market is going to be, but history would say that there is going to be a market if you have maximum optionality, and we will be in a position to exploit that.” According to Hanlon, the Hardisty unit train facility is exactly the right asset in Type

Location

exactly the right place, and his company’s view on rail is the same as its view on trucking—it is a vehicle that can get the right molecule to the right market at the right time. “To the extent you put those facilities into service where you have maximum optionality—and certainly Hardisty is that as virtually every grade of crude oil produced in western Canada is up at Hardisty every day—I think that capacity is going to be there for a long, long time.” Whether one or more of the current proposed pipelines such as Keystone XL or Northern Gateway gets built, Hanlon said it would in fact be a boost to Gibson because it would increase market confidence and investment into the Western Canadian Sedimentary Basin. In December, the company approved a 2014 capita l spendi ng budget of $410 million, which is 30 per cent higher than its 2013 capital guidance and represents the largest planned spend in the company’s history. capacity (bbls/d)

Start-up

Canadian terminal projects Canexus Corporation

Terminal expansion

Bruderheim, Alta.

Gibson Energy Inc. and U.S. Development Group LLC

70,000

Q3/2013

New terminal

Hardisty, Alta.

140,000

Q1/2014

Ceres Global Ag Corp.

New terminal

Northgate, Sask.

Tundra Energy Marketing Limited

Terminal for Manitoba and North Dakota crude

Cromer, Man.

Keyera Corp. and Kinder Morgan Energy Partners, L.P.

New terminal

Edmonton, Alta.

40,000

Q2/2014

TORQ Transloading Inc.

New terminal

Kerrobert, Sask.

168,000

Q3/2014

TORQ Transloading Inc.

Terminal expansion

Unity, Sask.

70,000 30,000 x 2

n/a

Q4/2013 August 2013/ Q1/2014

n/a Source: Daily Oil Bulletin

OIL & GAS INQUIRER • march 2014

Northeastern Alberta

canadian heavy oil diﬀerential Year

WTI (US$/bbl)

WcS (US$/bbl)

WcS diﬀerential (US$/bbl)

% of WTI

2005

56.56

36.24

-20.32

36.30

2006

66.22

45.04

-21.18

32.50

2007

72.31

49.62

-22.69

30.80

2008

99.65

79.59

-20.05

22.40

2009

61.80

52.14

-9.66

16.10

2010

79.53

65.30

-14.23

17.90

2011

95.12

77.97

-17.15

18.10

2012

94.20

73.17

-21.03

22.20

2013

97.97

72.77

-25.20

26.00 Source: Baytex Energy Corp.

Of the company ’s 2014 spending, 83 per cent will be directed toward growth investments, of which $230 million is earmarked for terminals and pipelines, while the company also plans to invest $70 million toward growing its environmental services segment. Assuming added pipeline capacity to the West Coast does not happen in a timely

fashion, Hanlon said virtually all expected added production in the Western Canadian Sedimentary Basin over the next few years is heading to its only customer—the United States. In light of that, he said Canadian crude will be moving through Edmonton to Hardisty or to Hardisty directly, and this is why his company continues to focus on its terminal business.

Pengrowth looking beyond Lindbergh for future growth By carter haydu

Pengrowth Energy corporation says it is on the lookout for more high-potential oilsands investments that could provide continued growth for the company as it transitions to sustainable, low-decline production with its Lindbergh thermal oil project. “We do think there are more opportunities in Lindbergh-type reservoirs,” said Derek Evans, president and chief executive officer. “I think that as you go north to Fort McMurray, there is now enough data up there to point to what we call the ‘Holy Trinity’ of low declines, low steam to oil ratios, the high rates of return,” he said. “You can start mapping and seeing where

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march 2014 • OIL & GAS INQUIRER

Northeastern Alberta

these high-rate, quality reservoirs are, and those would be projects that we would consider moving into as additional elements.” Evans said his company has been “incredibly well served” by not jumping into multiple steam assisted gravity drainage projects before its current pilot project was up and running, and he believes the lessons learned from Lindbergh will be critical as the company considers other opportunities in the oilsands. “We’re just taking it slowly, and we think there are lots of opportunities out there,” he said. “We haven’t seen a lot of transactions take place in this space, and so we haven’t felt pressured to do anything, but we feel there are some real jewels out there and that we will be able to put our modular, cost-effective, on-time and onbudget facility-building strategy to work.” According to Evans, Pengrowth is also interested in pursuing potential future projects with a partner, and it continues to “build credibility in the eye of any potential partner” through Lindbergh for future relationships.

“We have had lots of discussions with potential people. It’s sort of like dating. We’re not engaged to anyone yet, but we understand the significance of these sorts of decisions, and as we build our track record, as we build those relationships, and as we continue to look around for the right type of asset to put in that type of partnership—be it a joint venture or

Pengrowth Lindbergh SaGD production ramp-up plan Year

capital expenditure ($ mm)

Production (bbls/d)

2013

300

2,000

2014

365

1,700

2015

350

12,500

2016

490

16,000

2017

450

25,000

2018

360

38,000

2019

100

50,000

Source: Pengrowth Energy Corporation

working interest–type partner—those are all key considerations.” L i ndbergh, however, w i l l rema i n 100 per cent Pengrowth-owned and operated, emphasized Marlon McDougall, chief operating officer. “We have taken our model of risk at Lindbergh, we’ve proven it out, we’ve spent the money, and we are going to enjoy the production and cash flow growth.” In January, Pengrowth announced a 2014 capital program of $715 million, which provides $365 million for Lindbergh to complete construction at the central processing facility, drill 23 well pairs for the fi rst phase and facilitate incremental production growth over the next two to three years. Pengrowth considers the Lindbergh project critical to the company’s strategy of developing sustainable energy production, analysts heard. Located in eastcentral Alberta near Lloydminster, the pilot project began with steam injection in February 2012, and between June 2012 and September 2013 it produced in excess of 840,000 barrels of bitumen.

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OIL & GAS INQUIRER • march 2014

Northeastern Alberta

First steam for the 12,500-barrel-per-day first phase of Lindbergh’s commercial development is planned for the fourth quarter of 2014. The project, which the company believes will be on time and on budget, is expected to produce upwards of 50,000 barrels of bitumen per day from a resource potential of 769 million barrels of exploitable bitumen initially in place. “From a reservoir performance perspective, the pilot continues to give us confidence in what we are doing, and we continue to drill wellbore holes and shoot 3-D seismic, and we continue to see reservoir homogeneity and consistency that gives us the confidence that the rest of Lindbergh is going to perform similar to the pilot,” said McDougall. One advantage Lindbergh offers is the location in east-central Alberta, just off a paved highway, said McDougall. The area also has construction advantages as there is no muskeg, unlike the Fort McMurray area, and it is not in the same labour market. “We have the modular construction opportunity here, where things are just trucked in and we bolt them together as opposed to being stick built, which is the way it is on some of the much larger operations,” he said. Lindbergh also has access to both railway and pipeline transportation options, analysts heard. “We believe that flexibility is critical from a transportation perspective. It’s not really ‘if’ pipelines are going to be built—it is ‘when’—and so we need to be ready to be able to react, and we have that flexibility with Lindbergh,” said McDougall. Because the blending ratios at Lindbergh are very low, Pengrowth can choose rail or pipe without having to spend more money on diluent recovery, he said.

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march 2014 • OIL & GAS INQUIRER

canadian Natural to use low-pressure steam at Primrose By Pat roche

canadian Natural resources Limited will apply for a low-pressure steam flood as one way of reducing the chances of reservoir fluids seeping to surface, the company reported in late January. “What we are doing as we go forward, particularly in Primrose East, we’re applying for more of a low-pressure steam flood. That will mitigate a lot of the challenges we’ve had with high-pressure steam and seepage to surface while still allowing basically the same ultimate resource recovery,” said Corey Bieber, Canadian Natural’s chief financial officer. “The timing of that is affected somewhat, but not materially,” Bieber told a CIBC World Markets conference in Whistler, B.C. While low-pressure steam may take a bit longer to recover the same amount of oil, Bieber said the capital efficiencies would be “very similar to what we would have had under high-pressure steam.” For years, Canadian Natural has injected steam to mobilize bitumen at its Primrose/Wolf Lake operation about 55 kilometres north of Bonnyville in northeastern Alberta. Mostly the project uses

Northeastern Alberta

cyclic steam stimulation, which alternates between high-pressure steam injection and oil production through the same wellbores. However, it also uses some steam assisted gravity drainage, which continuously injects lower-pressure steam through a horizontal wellbore while continuously producing oil through a parallel well. Though the output in any given period varies with the timing of steaming and production cycles, Primrose/Wolf Lake produces roughly 80,000 barrels of bitumen per day. I n t he fou r t h qua r te r of 20 0 8, Canadian Natural began production from its 40,000-barrel-per-day Primrose East cyclic steam stiumulation expansion. Primrose East achieved fi rst oil on a positive note after construction was completed on budget and ahead of schedule. However, as production was ramping up, the initial success of Primrose East was marred by reservoir fluids seeping up to surface. The most serious release occurred last year when about 6,000 barrels of reservoir fluids seeped to surface. Bieber said remediation of the site is “effectively complete.” “There will be continual ongoing monitoring of those sites where the flow to surface occurred. And that could continue for months,” he said. “But the vast majority of the cleanup, and certainly all the ancillary cleanup around those sites in particular, has been completed.” However, the investigation into the cause of the release of fluids continues. “Certainly, we did have to wait for some freeze-up to get on location to actually drill observation wells and follow up a lot of those activities. Certainly with freezeup, we’re in the midst of completing that today,” Bieber said. Ever since the surface seepage was discovered, Canadian Natural has been convinced the cause was wellbore failures, not a reservoir defect. “We continue to believe that,” Bieber told investors. “We are seeing some indications that tell us that could be correct, but the investigation has yet to be finalized.” He noted the original Primrose pool has been producing for about 30 years and “even today its operating costs are amongst the lowest in industry. So it’s a very, very good reservoir.” Development has since expanded out to Primrose East and Primrose North.

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UFA.com OIL & GAS INQUIRER • march 2014

cENTraL aLBErTa WELL acTIVITY JAN/13

JAN/14

Wells licensed

320

224

JAN/13

JAN/14

Wells spudded

244

213

JAN/13

JAN/14

232

11

Rigs released

▼

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Jury still out on Duvernay economics By Elsie ross

While the Duvernay Formation in Alberta has been generating considerable excitement, one of the early players in the Kaybob area cautions that it’s still too early to be able to determine the true economics of the shale gas play. “We know they are good, we just don’t know how good,” John Willliams, president and chief operating officer of Trilogy Energy Corp., told the BMO Capital Markets unconventional resources conference in New York City. “Before you start allocating all your money into the Duvernay, you have to reduce that risk.” “Today, the longest-producing wells— the 03-13 [060-20W5] wells—have produced just over one billion cubic feet of gas in about 2.5 years,” he said. “So, I think it is premature to actually be able to say this well is going to be a 250 per cent rate-ofreturn project.” In order to calculate the long-term economics, an operator really needs to know what production in the second and third years looks like and what will happen to the liquids yield in that period of time, said Williams. For example, Trilogy’s longest-producing well in its Montney oil play has been on production for 34 months, he said. “It has taken us two or three years to figure it out to know what those true economics are worth.” Williams said the industry has made a lot of progress in learning about the Duvernay resource play in the last 2.5 years. Well costs that were initially $15 million to $20 million have come down to $12 million as part of a multi-well pad. About 100 wells have been drilled and about 50 are producing, and “the results to date have been very, very positive,” he said. “We didn’t know what to expect, but it has

exceeded our expectations in well economics, the rate of return.” In the second half of this year, Trilogy plans to spend about $100 million on its Duvernay program as part of its focus on land retention over the next two years. It has roughly 200 sections of Duvernay land with 75 in the condensate window and 125 in the volatile oil window. The company is currently working on what a template type curve would look like in the various liquids fields of the play, said Williams. A number of wells in the 50–100-barrel-permillion-cubic-feet-per-day window have been on stream for one to 1.5 years, and that will enable it to start generating that information. However, further north where liquids yields are in the 200–400-barrel-per-millioncubic-feet range, the industry doesn’t yet have the production history. “As an industry, we are all waiting for the same thing.” About 12–15 months ago, there was a step-change in completion techniques with the arrival of the majors such as Encana Corporation, Chevron Corporation and Royal Dutch Shell plc in the Duvernay, said Williams. The number of hydraulic fractures increased to 60–100 per well from 25–30. The completion technology is the game changer, he suggested. “We have gone from the Packers Plus [Energy Services Inc.] balldrop system doing fracs every 75 metres down to roughly every 20–25 metres,” said Williams. “Ultimately, it is about stimulating the rock and increasing your ultimate recoverable reserves. However, “we probably need another year of production history on all of these wells to see what they look like and to identify what the NPV [net present value] of each type curve would look like,” he said.

active Duvernay landholders Acreage (sections)

Wells drilled

578*

Shell

n/a

Talisman

303

Sinopec Daylight

203

ConocoPhillips

n/a

Vermilion

321

Enerplus

133

Bonavista

400

Canadian Natural Resources

623

Exxon Mobil

169

Athabasca Oil

550

Encana/ PetroChina

578*

Trilogy

207

Chevron

508

Shell

n/a

Yoho

Husky

EOG

155

Apache

n/a

Talisman

243

Bounty Developments

200

South Duvernay Encana/ PetroChina

North Duvernay

*Total acreage in both North and South Duvernay. Sources: BMO Capital Markets; Keyera Corp.; JuneWarren-Nickle’s Energy Group

OIL & GAS INQUIRER • march 2014

Central Alberta

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march 2014 • OIL & GAS INQUIRER

Operators in the Duvernay are sharing information on day-to-day operations to improve the drilling, completion and production of their wells, the conference heard. “Everyone will benefit from making sure we understand the best drilling, completion and production practices for the Duvernay,” said Williams. Shared information could potentially include longer lateral lengths, the amount of sand or water pumped and even the length of time wells are allowed to soak before they are put on production. Once wells are on production, there’s the question of whether to draw them down or to choke them back to a restricted rate. To date, Trilogy has participated in 27 wells and has access to information on another 25–30 wells through confidential data exchange agreements, exchanging like data for like data. However, in some cases the company will also be studying public data as a number of Duvernay wells—the earliest in the next generation of completion technology—are coming off confidential status this year, he said. “For us, expanding outside that core area and looking at some of the fringe wells and seeing how economic the Duvernay looks when it is down to 20 metres thick or 30 metres thick will be important.” Over the past 18 months, operators have spent an estimated $2 billion on Duvernay drilling opportunities, and Trilogy expects a similar level of capital spending in 2014. About 95 per cent of Duvernay prospective land has already been taken up, and it is quite tightly held by eight to 10 companies, according to Williams, who said perhaps six of them hold 80 per cent of what he said he considers the “sweet spot” of the play. As industry ramps up activity in the play, there’s the potential for increased competition for drilling rigs and pumping equipment, he said. “Drilling 100 wells a year shouldn’t be a problem, but when we start drilling 500 wells a year, I think that’s when we are looking at the competition for services, making sure we have the right rigs and the right number of rigs to do the job.” However, if the service companies know that Duvernay players will be stepping up activity in 2015 or 2016, it gives them a chance to move equipment into the area or to build pumping equipment, said Williams.

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cequence Energy Ltd. has reported initial success in its Wilrich Formation drilling program at Ansell, and the addition of key lands has increased its total landholdings to 46.5 gross sections. The most recent Wilrich well (49 per cent working interest) was drilled at 14-19 and tested at 2,500 barrels of oil equivalent per day, producing for 60 days at an average restricted rate of 960 barrels per day, said the company. Two Ansell wells have been completed to date and are ahead of the company’s model expectation. Current net production in the Ansell area is approximately 650 barrels per day and is restricted by production facilities. One additional Wilrich well was drilled in the first quarter and is awaiting completion, and two additional horizontal wells are currently drilling. The first-quarter capital program at Ansell is expected to include six (three net) wells, and the construction of gathering and compression facilities to increase production capacity to approximately 40 million cubic feet per day. Five of the six wells are scheduled to be “earning wells,” where Cequence pays 15 per cent of the capital cost to retain a 49 per cent working interest, with the sixth well scheduled to be drilled at the company’s 49 per cent working interest. Drilling to date at Ansell has identified the Notikewin and Falher formations as prospective secondary targets on Cequence acreage, said the company. Its partner is shooting a 135-squarekilometre 3-D seismic program to both focus the Wilrich drilling program and image these additional potential targets. Cequence said it considers Ansell a new core area with the recent addition of contiguous and highly prospective lands, continued drilling success by it and other operators in the area, the acquisition of 3-D data and construction of the gathering system. Pending results from the initial wells and the ongoing plans of its partner in the area, Cequence may direct further capital to this area in 2014 to drill additional Wilrich wells and add production facilities. cequence Energy ﬁve-year outlook average production (boe/d)

Wells drilled

capex ($ mm)

2014

14,000

120

2015

16,000

170

2016

21,500

200

2017

26,000

270

TOP FILL Retro-ﬁts

2018

36,000

430

Tank Installations & Changeouts

Year

Source: Cequence Energy Ltd.

Simonette project In the fourth quarter of 2013, Cequence completed a 65 per cent working interest Dunvegan well at 05-02. The well was recently put on production at restricted gross production rates of 10 million cubic feet per day of natural gas and 300 barrels per day of free condensate. The 05-02 well is a follow-up to the company’s

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OIL & GAS INQUIRER • march 2014

Central Alberta

10-02 well that has produced 2.5 billion cubic feet since coming on production in February 2013. Montney development at Simonette is ongoing with three wells drilled in the fourth quarter of 2013. The 10-24 well was recently brought on production at restricted rates of five million cubic feet per day and 75 barrels per day of free condensate at flowing casing pressure of 1,715 pounds per square inch. The 10-24 well is on a new pad site 1.5 miles from existing offset Montney development. The remaining two Montney wells were drilled off the 07-29 pad site and experienced mechanical difficulties on completion. Diagnostic tools were run

on both wells, and Cequence is currently evaluating remediation plans. It is anticipated that completions will be able to be performed on these wells. These two wells offset Cequence’s best liquids producers at 09-21 and 03-21. A Montney exploration well at 16-10061-01W6 is currently drilling and will be the first test on the southwestern Montney acreage at Simonette in which Cequence has a 100 per cent working interest. Management said it believes the geologic data observed from the open-hole logs of the full Montney section is encouraging. The well is expected to be completed in the first quarter of 2014. If successful,

Lightstream now focused on Swan hills By Pat roche

Lightstream resources Ltd. will take the same approach in developing its emerging Swan Hills play as it did with the Cardium, the company said in late January. Lightstream is currently producing more than 20,000 barrels of oil equivalent per day (70–75 per cent light oil and natural gas liquids) from the Cardium play, said chief financial officer Peter Scott. The Cardium stretches across western and central Alberta. In early 2010, Lightstream entered the light oil play, which is currently its largest business unit by pro-duction, Scott told a CIBC World Markets investor conference in Whistler, B.C. With about 580 drilling locations, Lightstream believes it has “a few years

of growth still left in the Cardium play,” he said. Based on four wells per section, Lightstream can probably build its Cardium production to 25,000–30,000 barrels per day, Scott said. “And what’s significant for us in the Cardium play is [that] we turned it into a net cash generator for us,” he said. “What I mean by that is revenue less royalties, less all op costs, less capital. The play in 2013 actually generated some surplus cash on an operating basis.” North of Lightstream’s Cardium business unit is its emerging play area where the company plans to spend roughly $90 million this year.

Lightstream resources play summary Play type

Saskatchewan conventional

Bakken

cardium

Swan hills

Total well costs ($ MM)

1.6

2.9

4.1

5.3

50.40

63.81

55.16

50.14

114

254

218

23.97

25.44

16.52

24.26

1.5

2.1

1.6

1.1

>300

>900

>580

>220

Netback ($/boe) Estimated ultimate recovery (Mboe) Finding and development ($/boe) Payout (years) Inventory

Total well costs include drilling, completions, equipment and tie-in. Bakken wells are bilateral Crown wells. Swan Hills numbers are company estimates.

march 2014 • OIL & GAS INQUIRER

Source: Lightstream Resources Ltd.

Cequence management believes 16-10 would de-risk Montney acreage on the western portion of Simonette where the company’s reserves evaluators have not previously assigned any Montney reserves or resources. In addition, Cequence has drilled a Wilrich well at 13-30-061-26W5. The well is a significant step out from the producing Wilrich wells at Simonette and in an area where the company’s reserves evaluators have not previously assigned any Wilirch reserves. The 13-30 well was expected to be completed in February. The company currently has two operated rigs drilling at Simonette. — DAILY OIL BULLETIN

The majority of that $90 million will be spent on drilling, completions and tie-ins in the Swan Hills play, though it also includes roughly $30 million for a battery being installed in the area during the first quarter, he said. “I think through the next several years you’ll see us spend more money in the Swan Hills area.” Asked about Lightstream’s Swan Hills results and approach, Scott said, “We’re liking the results that we’re getting from the Swan Hills. Results have been at or above our type curve for the play.” He added, “A good analogy is the Cardium. When we first entered the Cardium back in 2010, operators at that time weren’t having great success with the play. What we were focusing on in the Cardium at that time [were] areas that hadn’t been developed. We see the same thing in the Swan Hills as well—making sure you’re getting those areas that haven’t seen some depletion.” Referring to the Cardium, Scott said, “We were the company to bring slickwater fracs to that play, which reduced costs and improved results.” In the Swan Hills play, Lightstream is “using the latest drilling techniques to bring down costs.... And then on the completions side, we are using acid and proppant in the same completion, and we think we’ve been able to make that work and get better results,” he said. “So in terms of making that play work, I think you need to pay attention to where you’re drilling. You need to be, like any play, controlling those costs. We’re looking to be in the $5-million range. And the type curve that we have, we see getting our money back in two years or less.”

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SOUThErN aLBErTa WELL acTIVITY JAN/13

JAN/14

Wells licensed

JAN/13

JAN/14

Wells spudded

118

102 ▼

JAN/13

JAN/14

109

7

Rigs released

S.A.B.

▼

Southern Alberta

▼

Source: Daily Oil Bulletin

DeeThree Exploration production continues climbing DeeThree Exploration Ltd. reported in midJanuary that, based on field estimates, it met its targeted 2013 exit production rate of 10,000 barrels of oil equivalent per day. DeeThree’s current production rate is approximately 9,500 barrels per day (76 per cent oil and natural gas liquids and 24 per cent natural gas) from its two core properties at Brazeau and Lethbridge. The company currently has two core properties active in the Brazeau area, with a fourth rig drilling in the Alberta Bak ken at Lethbridge. Current additional operations include the expansion of the enhanced recovery re-injection scheme in the Alberta Bakken, including the addition of a second re-injection well soon to be operational, as well as the continuation of the multilateral horizontal drilling initiative in Brazeau, which is improving cost efficiencies in the area. DeeThree is presently in the later stages of drilling three horizontal wells on its Brazeau Belly River property and expects to continue to operate three drilling rigs on this property for the balance of the winter drilling season.

DeeThree recently successfully drilled and completed its first multi-leg horizontal well. This 100 per cent working interest well was drilled on the Brazeau Belly River property and has two legs each with a horizontal length of 1,500 metres. The combined production from the horizontal legs is currently about 350 barrels per day of 44-degree API reservoir oil and 950 thousand cubic feet per day of gas. As a result of the significantly increased capital efficiency realized through the drilling of multiple horizontal legs from a single well pad, DeeThree’s 2014 Brazeau Belly River drilling program will focus on well locations that provide for multiple horizontal legs. Future bilateral wells will be drilled with the use of extended-reach horizontal well drilling technology with a view to realizing the capital efficiencies of wells with horizontal lengths in excess of 1.3 miles. Based on the positive results of the pilot gas re-injection enhanced recovery scheme implemented by DeeThree on its Alberta Bakken property, the company will expand the size of the area under the program with

the addition of a second gas re-injection well, which was anticipated to be operating by the end of January. This well was producing approximately 200 barrels per day prior to being converted into a re-injection well in December 2013. A third gas re-injection well is planned in the coming months following which substantially all gas produced by DeeThree from its Alberta

9,500

barrels equivalent per day DeeThree’s current production

Bakken property will be re-injected to enhance oil recoveries. DeeThree will operate one rig on its Alberta Bakken property for the balance of the winter drilling season. — DAILY OIL BULLETIN

DeeThree exploration Brazeau Belly river resource evaluation Producing zone

Discovered oil in place (mmbbls)

Undiscoverd oil in place (mmbbls)

horizontal wells drilled

295

130

140

Basal

168

Total

733

220

20 Source: DeeThree Exploration Ltd.

OIL & GAS INQUIRER • march 2014

Southern Alberta

Goldenkey facing opposition to Lethbridge well By carter haydu

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a bid by Goldenkey Oil Inc. to drill an oil well within the City of Lethbridge has put the spotlight on the inability of municipalities to regulate oil and gas projects within their borders, said the city’s mayor, Chris Spearman. “We’re the people on the ground, but what I think happens is in Edmonton they grant licences without a whole lot of knowledge about where the drilling is going to go,” said Spearman, whose council has voted unanimously to oppose the Goldenkey project to drill three exploration wells on the city’s west side. Spearman said that municipal governments have limited powers to approve or reject such projects, which is why he wants the province to speed up a review of the current rules and update policy to provide greater local jurisdiction. “We see the complications here,” he said. “We see the way our roads are designed, the way our residential subdivisions are designed, and we see the complications that aren’t seen when the licences are currently granted. We see a contrast between the interests of the municipality, along with its residents, and the interests of the energy industry.” David Hill, an independent consultant working with privately held Goldenkey, said the small start-up company obtained some seismic data of the Lethbridge site about three years ago. It showed potential for oil in the Big Valley Formation, which led the company to lease Crown land and forge a plan for development. “We have gone through the process of doing the optimization of the site selection and looking at the geology. We have selected three wells—two are directional and one is essentially vertical, but none are horizontal,” he said. A typical onestage hydraulic fracture would complete the wells. The Penny Project went through the normal bidding process before Goldenkey was leased the mineral rights that are subject to typical time restraints, Hill said.

Southern Alberta

“What we have here is a very typical 1,700-metre well that’s going to have a pumpjack on it. We have tens of thousands of these wells in the province. Technically, there is nothing unique. They are very typical, conventional wells.” H o w e v e r, i n N o v e m b e r 2 01 2 , Lethbridge city council adopted a resolution stating its opposition to oil and gas drilling and production within urban boundaries. The opposition stems from concern about the implications for future development of urban land, including the additional costs associated with continuing to build safe communities. Council reaffirmed its position in a 2013 official statement, which also recognized that it cannot legally prevent any operator from drilling a well within city limits if the project has Alberta Energy Regulator approval. This is not the first time urban well projects have faced local opposition. In 2012, then–Alberta Energy minister Ken Hughes instructed his staff to review polic y options related to urban-area energy developments after residents in the northwestern Calgary neighbourhood of Royal Oak raised concerns about a proposed Kaiser Exploration Ltd. project. Helen Rice, president of the Alberta Urban Municipalities Association, told the Daily Oil Bulletin that the association strongly favours responsible oil and gas development throughout the province, but members also believe that municipalities must have early and meaningful input into the site of wells to ensure they align with land-use planning. While giving more power to municipalities to regulate urban drilling would in part resolve the matter, Rice said the concerns of municipalities also go beyond their current borders to include portions of the abutting rural municipalities that may one day be incorporated. “Even if proposed wells are in the counties, the municipalities still need to be factored into approval decisions. That is very important.” Rice said the issue of unwanted urban wells within municipal limits is not an ever yday occurrence, but is common enough in A lberta that the prov ince should address it in updated legislation. In response to Lethbridge’s concerns about its ability to use the Goldenkey lands for future development, Hill said

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Southern Alberta

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Goldenkey has taken the unprecedented step of agreeing to make the lands containing the wells available if development reaches that area. This includes ensuring proper abandonment and reclamation. “Currently, these sites in the area are scheduled for 2050 urban development, and we feel we can be drilled, completed and out by the time the city needs this land. But should we still be there when they need the land, at that time frame we are prepared to prematurely abandon ahead of the economic limit of the wells.”

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march 2014 • OIL & GAS INQUIRER

“The unique thing about this is there are already wells existing in the area that are closer to urbanization than what we are proposing.” — David hill, an independent consultant working with privately held Goldenkey Oil Inc.

Hill said Goldenkey plans to submit its application to the regulator in the first quarter of 2014 and would continue to hold discussions with the city and concerned residents while the regulator considers the file. However, Spearman said there is nothing Goldenkey could do to alleviate the concerns of city council about the project because he believes the vast majority of residents strongly oppose well construction anywhere near their homes and schools. “That is a fairly unanimous position in this city, so, as the city council representing our citizens, we really have no choice but to voice their concerns. The citizens are saying that it is just not a suitable use of land.” While Hill appreciates the “not-in-my backyard” attitude of many Lethbridge residents, he said Goldenkey has gone “above and beyond the normal requirements in terms of the drilling and production features” for the Penny Project.

Southern Alberta

There also are plenty of examples of such urban wells throughout Alberta, including Lethbridge, he said. “The unique thing about this is there are already wells existing in the area that are closer to urbanization than what we are proposing. Where were all of the concerns at that time? Why now, all of the sudden, are there the concerns?” Spearman said that while there have been wells within city limits in the past, those wells are no longer active and they were drilled on the outskirts of Lethbridge many years ago when there was little expectation of people moving into those areas. “Twenty years ago, those wells would have been five kilometres or more away from the residential area, but right now the proposed sites are virtually right over the back fence within a kilometre, with continued growth planned.” While there is vocal opposition to the Penny Project, Hill said there are also Lethbridge residents who support the company and recognize the value of its efforts. “We definitely have had some voices of support, absolutely, as I think many recognize that they enjoy the benefits of oil and gas.”

manitok outlines spending plans The Stolberg area will get the biggest allocation under Manitok Energy Inc.’s 2014 capital budget, with $46.9 million to be spent and 13 (7.8 net) wells planned for that Cardium light oil area. Under a 2014 capital budget of about $104.5 million, the company plans to drill 34 (28.2 net) wells targeting light oil in its Stolberg, Entice and other southern Alberta Foothills areas. The $104.5-million budget compares with estimated 2013 spending of about $82 million. Manitok allocated $14.7 million for other Foothills areas where it will drill three (2.4 net) wells. That estimate, which includes the southern Alberta Foothills area—primarily Quirk Creek—depends on a successful production testing period for the two recently drilled wells. The company has budgeted $30.3 million for the Entice area of southeastern Alberta where it leased 38,757 hectares (96,893 acres) of freehold land from Encana Corporation. Manitok plans to drill 18 (18 net) wells on those lands. The 2014 budget includes $3.2 million for land and seismic and $9.4 million for other activities, including a pilot waterflood project in Cordel, fourth-quarter 2013 projects that carried into 2014, maintenance capital, corporate costs and capitalized overhead. Manitok is forecasting average 2014 production of 6,000– 6,200 barrels of oil equivalent per day (62–65 per cent oil and liquids), about 50 per cent more than its estimated 2013 average of 4,000 – 4,100 barrels per day. The company forecasts 2014 exit output of 7,100–7,500 barrels of oil equivalent per day (67–70 per cent oil and liquids), up from the 2013 exit rate of 5,550 barrels per day.

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— DAILY OIL BULLETIN OIL & GAS INQUIRER • march 2014

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SaSKaTchEWaN WELL acTIVITY JAN/13

JAN/14

Wells licensed

368

433

JAN/13

JAN/14

Wells spudded

383

426

JAN/13

JAN/14

324

37

Rigs released

▲

Saskatchewan

▲

Source: Daily Oil Bulletin

husky Energy approves two new heavy oil thermal projects husky Energy Inc. has sanctioned two new heav y oi l t her ma l projec t s i n Saskatchewan, which will deliver a total of 20,000 barrels per day of production. Engineering is underway with construction of the 10,000-barrel-per-day Edam East project and the 10,000-barrelper-day Vawn project scheduled to begin this year, with fi rst oil expected in 2016. The projects build on the success the company has had in the Lloydminster region in using thermal technology to access longerlife heavy oil deposits. “Three years ago, with heav y oil production fighting to remain flat, we implemented a strategy to transform and rejuvenate the business. We are seeing the results of that today,” chief executive officer Asim Ghosh said. “Steady performance from our existing thermal facilities and these two new plants, along with projects currently under construction at Sandall and Rush Lake, will add another 33,500 barrels per day of new production over

the next three years, more than offsetting declines in non-thermal production.” Husky’s growing focus on thermal projects is guided by a rich portfolio of opportunities and a proven template of smaller steam assisted gravity drainage plants providing better access to heavy oil reservoirs, says the company. The two new plants will be nearly identical to the Pikes Peak South and Rush Lake projects. A solid return on investment is being generated for the company from low operating costs—which were under $10 per barrel at existing plants in 2013—efficient project execution, time to first oil and the long-life nature of the projects. In December 2012, Husky set a target of achieving 55,000 barrels per day of production from thermal projects by 2017. With the continued success of its thermal projects, that timeline is being accelerated to 2016. Steaming is currently underway at the 3,500-barrel-per-day Sandall thermal project, with first production expected this

quarter, and construction is advancing at the 10,000-barrel-per-day Rush Lake project, with fi rst oil expected in the second half of 2015. Husky has a pipeline of additional thermal projects under evaluation for development.

55,000 barrels per day

Husky’s thermal production target by 2016

The company is further integrating its heavy oil business by taking advantage of its Lloydminster Upgrader, existing pipeline systems and the proposed crude oil flexibility project at the Lima Refi nery in Ohio. Through this focused integration, Husky is able to maximize the value realized for its heavy oil production. — DAILY OIL BULLETIN

husky thermal portfolio Project

Production date

current production (bbls/d)

Design rate (bbls/d)

Pikes Peak

1981

4,200

Bolney/Celtic

1996

16,000

Rush Lake Pilot

2011

1,500

Paradise Hill

2012

5,000

Pikes Peak South

2012

10,000

Sandall

2014

3,500

Rush Lake

2015

10,000

Edam East

2016

10,000

Vawn

2016

10,000 Source: Husky Energy Inc.

OIL & GAS INQUIRER • march 2014

Saskatchewan

raging river reports record output

JUNE 10 - 12, 2014 Stampede Park

Calgary, Alberta, Canada

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MUST-ATTEND INTERNATIONAL EVENT

raging river Exploration Inc. reported that estimated daily production reached a record of 9,000 barrels of oil equivalent per day (96 per cent oil) during the second half of December 2013. Based on field estimates, the company’s 2013 fourth-quarter average production increased 37 per cent from the third-quarter average to 7,700 barrels per day (96 per cent oil), which is five per cent ahead of the company’s previous fourth-quarter guidance of 7,300–7,400 barrels per day. Raging River exited 2013 with 16 net wells awaiting completion and is off to a solid start in the fi rst quarter with 17 (15.5 net) wells drilled since Jan. 1, 2014. With production averaging above 9,000 barrels per day in the first two weeks of January, the company anticipates achieving its 2014 average production level of 9,500 barrels per day in early February. Production is expected to be strong through the first quarter, followed by a modest reduction in the second quarter due to spring breakup. Raging River reaffirmed its average 2014 production guidance of 9,500 barrels per day. Finding, development and acquisition costs, including the change in future development capital of $298 million, are $26.29 per barrel on a total proven basis. Its reserve life index increased to 13 years based on current production of 9,000 barrels per day. Reserve additions replaced 2013 production by greater than nine times on a proved basis and 12 times on a proved-plus-probable basis.

raging river Exploration 201 drilling plans area

8.0

0.0

33.0

8.0

Lucky Hills

5.4

2.0

Kerrobert

7.7

0.0

Plato & Forgan

7.0

8.0

61.1

1.0

Dodsland

Enter reference code: OGINQ

globalpetroleumshow.com @petroleumshow #GPS14

Beadle

Total

march 2014 • OIL & GAS INQUIRER

Saskatchewan

Raging River’s development drilling inventory has increased to 2,000plus risked locations as at Jan. 1, 2014, of which approximately 75 per cent are currently unbooked. Average estimated ultimate recovery per horizontal well drilled in 2013 increased by 27 per cent to 475,000 barrels per well from an average of 375,000 barrels per well for those drilled to the end of 2012. Raging River is in the midst of an active quarter in which the company anticipates drilling 60 net horizontal wells. The company currently has two operational drilling rigs and has drilled 17 (15.5 net) wells this quarter at a 100 per cent success rate. According to the company, with completion operations well underway, a new well is being placed on production every day, and it is expected that trend will continue throughout the quarter. To date this quarter, Raging River said it has successfully tested four previously undrilled sections at Beadle, with expectations that an additional 12–15 previously undrilled sections will be tested this quarter. In the recently acquired Forgan area, Raging River’s operations team has been actively working toward obtaining the first drilling licences in the area, and it is now expected that the company will be able to drill up to four wells, testing previously undrilled sections in this area during the first quarter. Raging River also continues to be active on adding additional lands in the Viking light oil fairway. Since early December 2013, 15 additional sections of land have been added in the greater Beadle area. The company’s total prospective Viking light oil land holdings are now in excess of 215 net sections. — DAILY OIL BULLETIN

Q

Net wells drilled 201

31.0

6.0

45.0

1.0

24.5

66.5

19.0

15.3

41.7

8.7

5.5

21.9

14.5

4.0

33.5

74.2

55.3

20.6

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Source: Raging River Exploration Inc.

OIL & GAS INQUIRER • march 2014

L an Le a ma mac ach chi hin ne Oilfield manufacturers use innovation, automation to grow through economic doldrums, while oilsands manufacturers prepare for a possible boom By Darrell Stonehouse

LMa Le e ea a an n Mac ach chi hin ne ne How big is Canada’s oil and gas manufacturing supply chain? The oil and gas industry spent around $12 billion in 2012 on machinery and equipment, according to Statistics Canada. In 2013, it expects that number to come in at around $10.3 billion. Going forward, however, expenditures are expected to begin climbing significantly as oilsands development accelerates. Domestic manufacturers compete against each other and against global competitors for a piece of this pie—and that competition is fierce. According to U.S. government statistics, more than half of Canadian oil and gas machinery and equipment comes from south of the border. Despite the strong presence of global manufacturers in the Canadian marketplace, domestic manufacturers continue to expand their market share at home and are grabbing their own piece of the international oil and gas machinery and equipment marketplace, led largely by Alberta manufacturers. Alberta’s oil and gas field machinery output reached $5.1 billion in 2012, more than quadrupling in size between 2002 and 2012. Pumps and compressor sales reached $1.2 billion in 2012, nearly doubling between 2002 and 2012. Boiler and tank output reached $1.1 billion in 2012, again nearly doubling revenues over the previous 10 years. Around one-quarter of this output is exported, according to the province.

Driving this expansion has been a mix of factors, including technical innovation and increasing reliance on automation to make up for worker shortages—and, of course, growth in the oilsands. Packers Plus Energy Services Inc.’s new MX Manufacturing Centre in Edmonton is one example of the state-of-the-art manufacturing facilities allowing Canadians to compete in the global oil and gas equipment market. Packers Plus describes the plant, which opened in 2013, as the first of its kind in the world and its largest manufacturing centre worldwide. The plant includes the world’s first robotic assembly of its type and a testing and torquing system that includes a proprietary traceability method developed by Packers Plus in conjunction with one of its key suppliers. “Some companies manufacture in China and ship to Canada,” says company president Dan Themig. “We manufacture in Canada and ship to China.” Packers Plus invested over 10,000 hours of engineering into crafting the automated set-up and producing its openhole multistage frac stimulation tools. While humans are still an important part of the operation—between offices and the factory floor, the 20,000-square-metre building houses 200 workers—the robotic arms on the shop floor do much of the manual labour.

2009 Alberta

2011

2012

2013*

7,030.00

6,975.80

7,532.80

5,979.10

6,624.30

Saskatchewan

563.50

847.90

1,466.90

1,961.00

1,308.70

British Columbia

455.00

756.80

1,097.50

1,347.20

821.60

37.40

58.20

101.20

95.60

96.10

9,115.60

10,752.20

13,247.10

11,914.40

10,277.30

Manitoba Canada *Estimate based on intentions

2010

march 2014 • OIL & GAS INQUIRER

Source: Statistics Canada

Photo: Daniel Villeneuve/Photos.com

Capital expenditures for mining, oil and gas machinery and equipment ($ millions)

Cover Feature

The facility is capable of building 240 tools per day. The automated assembly robots form the core of the production process. They are fed by a computerized storage and retrieval system that tracks an inventory containing up to 6,000 crates. Constantly learning and adapting, the system is intelligent enough to change how it stores items based on demand. The final step in the process involves testing the tools at pressures of up to 10,000 pounds per square inch. Four or five staff members monitor the two torque-and-test robots, compared to 15 employees working in the manual testing area. The automated system can handle about 26,000 tools in a month, while the manual system might process 1,800 in the same time frame, according to Marlon Leggott, manufacturing director. The new facility was designed to address concerns about attracting and retaining a skilled workforce. As well, Packers Plus had the building constructed larger than its current needs to accommodate growth. Another Edmonton-based company, Bri-Chem Corporation, is also on the cutting edge of oilfield equipment manufacturing. In 2011, Bri-Chem announced it was partnering with Chinese steel company Wuxi Huayou Special Steel Co., Ltd. to establish a largediameter seamless steel pipe manufacturing facility in Edmonton. Bri-Steel Manufacturing Inc. opened in 2012 and has been setting records ever since. The plant uses a method called thermal pipe expansion (TPE) to produce pipe with an outside diameter from 14 to 36 inches. The TPE process heats carbon steel tubes while pushing the tubes with a hydraulic press over a mandrel, thereby expanding the pipe. The steel pipe is then finished by lacquering and stenciling and is put through a series of tests to ensure it meets industry specifications. The whole operation is run on an automated conveyer system that moves raw material into the facility for production and moves finished steel pipe out of the facility for shipping. The TPE process has been utilized for producing large-diameter steel pipe for several years in China, but Bri-Steel is the first to introduce TPE production and testing in North America. In June, Bri-Steel announced it had successfully produced 36-inch-diameter seamless carbon steel pipe, the largest seamless steel pipe manufactured to date in North America. In addition, the 36-inch pipe manufactured has a standard wall thickness, which is generally the most difficult to produce utilizing the TPE manufacturing process, and as a result it can now focus on producing heavier-wall-thickness 36-inch steel pipes and expand into 32and 34-inch pipe diameters as well. “The successful production of the 36-inch seamless pipe solidifies our position as the next generation of pioneers for large-diameter steel pipe manufacturing,” says Don Caron, chief executive officer of Bri-Chem. The growth in oilfield equipment and machinery manufacturing targeting the oilsands in recent years has made Edmonton into a global centre of advanced steel manufacturing technologies, with the area supporting the largest concentration of automated steel fabrication equipment in the world, according to Paul Collins, founder and chief executive officer of Collins Industries Ltd. and one of the driving forces behind the Alberta Steel Manufacturers (ASM). ASM is a partnership between the Alberta Pressure Vessel Manufacturers’ Association, the Canadian Institute of Steel Construction, the Alberta division of Canadian Manufacturers & Exporters (CME) and the economic competitiveness division at

Tank repair company finds refuge from labour crunch in small town Country living carries with it many benefits, from less traffic to friendlier communities. For oilpatch service companies like Elite Integrity Services, it also offers an escape from the competitive labour market found in more crowded centres like Nisku, Alta. “You get guys leaving for 50 cents across the street, and as soon as you raise your rates, they’re back,” says Shawn Kirwan, president of Elite. “We don’t want to play that game. We like the smalltown feel.” Specializing in API tank repair and field construction, Elite is in the midst of expanding its operations in Ponoka, a central Alberta town of nearly 7,000. The company finds the town to be an ideal home base because of the local workers, which Kirwan describes as former farm kids that “were welding tractor pieces together at the age of 10.” Such mechanical skills will be invaluable as Elite grows to take on more front-end work, such as fabricating parts heading for the field. Kirwan says that the company is ordering its own downdraft burning table, allowing his shop to cut and prep its own plate steel, rather than relying on outside providers. “Taking on processes that we currently subcontract out will allow us to have more ownership and control of what we do,” he says. To date, much of the company’s growth can be attributed to oil and gas projects across western Canada, with a particular emphasis on steam assisted gravity drainage projects in the oilsands. Some jobs have already booked into 2015, Kirwan notes. Work began on the new facility—located just off Highway 2—in late November last year and will finish by May. The 14,500-square-foot building will include over 11,000 square feet of shop space and a two storey office building, as well as a crane rail standing 35 feet above the ground and capable of carrying 50 tonnes. With the facility being built on a 20-acre lot, the company has also left itself room to expand in the future. But the company has already grown a great deal from its humble origins, Kirwan says. “Four years ago, we were working out of one of the partner’s backyards, and we were running skid steers and building parts,” he says. “Companies like Cenovus [Energy Inc.] had to come out and do an audit on his backyard.”

OIL & GAS INQUIRER • march 2014

Cover Feature

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Alberta Enterprise and Advanced Education. The members first got together in late 2010 and concluded that fabricated steel was being sourced from offshore for oilsands developments for the wrong reasons, and that more collaboration among supply chain stakeholders within Canada would boost innovation and efficiency in the sector, resulting in more work for domestic producers. What’s at stake is huge, according to a new report from the CME, Canada’s largest trade and industry association. The study found Canadian manufacturers are currently capturing around 20 per cent of oilsands capital expenditures. Of that share, two-thirds stayed within Alberta, while 14 per cent went to Ontario-based companies, nine per cent to the other prairie provinces, six per cent to Quebec, four per cent to British Columbia and one per cent to Atlantic Canada. “Above all else, this data shows the close correlation between oilsands development and its positive impact on both Canadian manufacturing and the economy as a whole,” explains CME president and chief executive officer Jayson Myers. “But it also underscores the ongoing challenges and bottlenecks that threaten the ability of manufacturers outside Alberta to benefit from oilsands expansion. A big one is simply pipeline capacity. Companies won’t invest if they can’t reliably ship out product.” The CME estimates nominal capital investment in the oilsands could climb as high as $905 billion through the end of 2030. Maintenance, repair and operations expenditures, meanwhile, could total another $912 billion. Currently, there are 49 projects online and another 178 either under construction, approved through the application process or announced. “Based on what we know about the state of interprovincial supply chains, the types of manufacturing inputs required by oilsands producers and the rate of new projects coming online, there is a significant opportunity for Canadian manufacturers to capitalize on a rapidly growing market demand here at home,” says Myers. “They can’t, however, sit back and wait. Manufacturers need to plan, invest and retool—and governments at all levels must provide the policies and support needed to make that happen.” Provided interprovincial trade capacity increases at the correct rate, the projected range of opportunities for Canadian manufacturers supplying oilsands operations between 2012 and 2030 will be between $211 billion and $387 billion, says the CME. To put this growth into perspective, if the high end of the projection is accurate, this would result in oilsands-related manufacturing being equal to 75 per cent of current annual Canadian industrial production. The CME has a list of things that need to happen to make this a reality. They include: • Creating an oilsands supply chain working group to be established with senior leaders from project owners, EPCs and construction contractors and manufacturers that can focus on major bottlenecks in the supply chain, and identifying common threats to growth (such as labour shortages) and the role that each party can play in improving overall performance; • Creating detailed “how-to” guides for manufacturers from both project owners and EPCs on the expected actions to be undertaken to participate in oilsands supply chains;  • Establishing an oilsands supply chain resource office to help manufacturers learn about specific procurement opportunities and how to efficiently engage and navigate supply chains; and

Cover Feature

Alberta manufacturing

fast facts

In 2010, Alberta’s oil and gas sector purchased an estimated $4 billion in manufactured products from domestic and international companies in the oil and gas supply chain industry, including:

$1.8 billion

in industrial machinery (such as mining and oil and gas field machinery and equipment).

$1.5 billion

in steel products (mainly iron and steel pipes and tubes).

$438 million

in fabricated metals (such as forging, stamping, metal valves and pipe fittings).

$250 million

in electronic products (mainly measuring and controlling devices).

Alberta’s engineering construction sector purchased an additional $5.2 billion, including:

$2.2 billion

in fabricated metals (boilers, tanks, metal valves and pipe fittings).

$1.5 billion

in steel products (iron and steel pipes and tubes).

$900 million

in electronic products (measuring and controlling devices).

$576 million

in industrial machinery (mining and oil and gas field machinery, equipment and turbines). Source: Government of Alberta

• Developing common supply chain prequalification standards and centralizing a process for prequalifying manufacturers and their specific products and services. To strengthen the investment climate and make the supply chain more efficient, the business environment across Canada must be improved with a specific focus on manufacturing competitiveness and productivity, says the CME. With globally integrated supply chains and the ability to supply customers around the world, creating a competitive business climate is critical to attracting investment for value-added innovative goods and services. The CME recommends: • Improving the quantity and quality of the available labour pool;  • Supporting manufacturing investments in production, productivity, innovation and commercialization through globally competitive direct support mechanisms and through competitive tax regimes;   • Reforming and modernizing the regulatory system to lower operating costs and speed decision making; and • Strengthening supporting infrastructure that is essential to manufacturing competitiveness including the cost and reliability of energy and the connecting trade networks, especially east-west railway corridors. OIL & GAS INQUIRER • March 2014

Feature

Land of

giants Montney tight resource matures into world-class play By Darrell Stonehouse

march 2014 • OIL & GAS INQUIRER

Montney pioneers build on foundations Much of the credit for commercializing the Montney lies in early risk-takers like ARC Resources Ltd. ARC began drilling into the Montney in 2005 at Dawson, just north of Dawson Creek, B.C. The Dawson play models how development has taken shape in the Montney. “Dawson is a really nice case study because you can see the investment through to the cash flow,” ARC president Myron Stadnyk told a Peters & Co. Limited 2013 energy conference in Toronto. While ARC was building production at Dawson, it spent around $150 million per year, significantly exceeding the cash flow the play was generating. But as decline rates flattened and producing wells began accumulating, less new drilling was needed to keep production at ARC’s target of 165 million cubic feet per day. “In fact, we overdrilled a little bit there, so we hardly needed any reinvestment capital in 2012,” Stadnyk said. “But kind of the punch line is if you look at 2012...AECO was $2.27 for the year and we cash-flowed over $100 million at Dawson,” he said. Stadnyk said an increase of $1 per thousand cubic feet of gas would add $60 million to the company’s cash flow. “It’s a key play,” he said of the Dawson Montney. “The reinvestment, now that the field has stabilized, is very modest. A 25 per cent reinvestment will allow us now to produce this field for many, many years and have free cash flow.

Photo: cta88/Photos.com

ver 4,000 trillion cubic feet of natural gas, 126 billion barrels of natural gas liquids (NGLs) and 140 billion barrels of oil are trapped in the siltstone and shale layers in the Montney Formation straddling the border of Alberta and British Columbia, according to a recent estimate of petroleum in place released by the National Energy Board (NEB), in conjunction with the Alberta Energy Regulator and the B.C. Oil and Gas Commission. Of this huge resource, the NEB estimates 450 trillion cubic feet of marketable gas, 14.5 billion barrels of marketable NGLs and 1.1 billion barrels of marketable oil could be produced. That’s a world-class petroleum play by any measure. And Canadian producers are well on their way to monetizing this massive resource base. Starting in 2005, explorers began testing for Montney natural gas using a combination of horizontal drilling and multistage fracturing technologies. The industry has since branched out to target liquids and oil formations, refining its technology along the way. As of year-end 2012, the Montney was producing around 1.7 billion cubic feet of natural gas per day. The NEB expects gas production to rise to 2.1 billion cubic feet by the end of 2015 if prices come in at its mid-range estimate. Looking further out, global energy analysts at Wood Mackenzie Limited predict the Montney will be producing 5.1 billion cubic feet per day by 2018.

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“If you look at $3 AECO at Dawson, you’re at a 45 per cent rate of return,” Stadnyk said. With Dawson generating cash flow, ARC is now focusing on its other Montney assets. ARC has approved a 2014 capital budget of $915 million —the largest in its history—and a seven per cent increase from this year’s $860-million budget. ARC will spend $54 million on drilling and development activities in 2014 for nine gross operated horizontal natural gas wells at Dawson. The 2014 drilling program at Dawson will maintain production at current maximum facility capacity levels through 2014 and into 2015. ARC began commissioning a new gas-processing and liquidshandling facility at its Parkland/Tower Montney liquids play in the fourth quarter of 2013. The new facility is the fi rst phase of an approved 120-million-cubic-feet-per-day gas-processing and liquids-handling facility in the area. Total capacity from the fi rst phase is expected to be approximately 60 million cubic feet per day of natural gas, and 8,000 barrels per day of liquids (5,000 barrels per day of oil and 3,000 barrels per day of NGLs); however, actual liquids production will depend upon the ratio of Parkland and Tower wells feeding into the facilities. The Parkland/Tower region will see considerable activity and production growth in 2014 as the new gas-processing and liquidshandling facility is brought on stream. ARC invested significant capital in 2013 to pre-drill wells leading up to the start up of the

new facility. It expects to bring two eight-well pads on production at Tower, and 13 wells on four pads on production at Parkland when the new facility is brought on stream. In addition to the production increase resulting from the 2013 capital program, ARC will execute a $190-million capital program at Parkland/Tower in 2014 to drill 13 liquids-rich natural gas wells at Parkland and 17 oil wells at Tower to fill the newly constructed facility through 2014. ARC has been piloting production at Sunrise since the third quarter of 2011, with production coming from three layers in the Montney, and processing capacity through third-party facilities. With the continued strong performance of the wells and the current outlook for commodity prices, it has decided to pursue development plans starting in the fourth quarter of 2013. ARC has signed an agreement with a third party to increase natural gas processing commitments to 60 million cubic feet per day beginning in 2014. ARC’s 2014 capital program of $120 million includes the drilling of 14 gross operated natural gas wells and spending on associated infrastructure at Sunrise in 2014. Sunrise production is expected to grow to 60 million cubic feet per day from 20 million cubic per day throughout the course of 2014, averaging approximately 35 million cubic feet per day in 2014. At Ante Creek, ARC plans to spend $200 million to drill 40 gross operated horizontal Montney oil wells. ARC has grown its OIL & GAS INQUIRER • march 2014

Feature

Ultimate Potential For Montney Unconventional Petroleum In Alberta And British Columbia Hydrocarbon type

Resource in place Low

Expected

3,197

NGLs (million barrels) Oil (million barrels)

Natural gas (trillion cubic feet)

Marketable High

Low

Expected

High

4,274

5,405

316

449

645

87,360

126,931

176,783

9,689

14,521

21,040

80,949

141,469

227,221

452

1,125

2,430

Source: National Energy Board

Ante Creek land holdings to 332 net Montney sections and will continue to delineate the large, prospective land base. The 2014 drilling program is expected to maintain production at the company’s Ante Creek facility at approximately 15,000 barrels of oil equivalent per day (50 per cent crude oil and liquids), representing an estimated 25 per cent increase relative to 2013 average production. Advantage Oil & Gas Ltd. is another Montney pioneer that continues expanding outwards from its original development at Glacier northwest of Grande Prairie, Alta. Advantage is currently on its sixth development phase at Glacier, with three rigs drilling in the play. The company expects production to reach 135 million cubic feet per day by the second quarter of this year. Like ARC, Advantage is now focused on increasing liquids production while fine-tuning its drilling and completions program to optimize resource recovery. In September, the company announced that two wells it had drilled in the eastern portion of its Glacier block targeting the Middle Montney had hit the liquids window. The 103/01-09-07612W6 well was production tested for 124 hours and flowed free condensate at 50 barrels per million cubic feet over the production test period. The final gas flow rate at the end of the production test period was 3.9 million cubic feet per day. The estimated C3+ yield based on a shallow cut liquids extraction process is 76 barrels per million cubic feet, utilizing data obtained from the production test. The 102/13-29-076-12W6 was production tested for 192 hours and flowed free condensate that averaged 24 barrels per million cubic feet over the production test period. The final gas flow rate at the end of the production test period was 5.3 million cubic feet at a flowing pressure of 3,358 kilopascals. The estimated C3+ yield based on a shallow cut liquids extraction process is 57 barrels per million cubic feet, utilizing data obtained from the test. Following the tests, Advantage acquired an additional 43 sections of land prospective for the Middle Montney, increasing its total Montney acreage to 125.65 gross (120.35 net) sections. Advantage has also tweaked its completion techniques in an effort to get more out of its Glacier resource. It used high-rate slickwater fracs with an open-hole packer system on 11 wells in the Montney in the first half of last year. “Production from these wells continues to demonstrate stronger production rates when compared to wells that were completed using our previous completion technique, after a similar production period,” the company reported in December. “Additionally, the new wells are significantly outperforming the older wells in terms of cumulative production. For example, the 100/07-07-07613W6 Lower Montney well, which was completed with a high-rate 48

march 2014 • OIL & GAS INQUIRER

slickwater frac utilizing an open-hole packer system, has produced 1.5 billion cubic feet compared to the older offset wells, which produced 0.5 billion cubic feet after six months of production.” Advantage expects to spend between $260 million and $270 million on its Glacier Phase 7 expansion by March 2015. The money will fund the drilling of 33 net wells—20 dry gas wells and 13 liquids-rich gas wells—and is expected to increase production to about 183 million cubic feet per day in the second quarter of 2015, including about 900 barrels per day of natural gas liquids from an initial 25-million-cubic-feet-per-day development in the Middle Montney. The wells in this program are designed to include an average of 17 hydraulic fractures per well at an estimated cost of $6.1 million per well. Some of the wells will be drilled on six-well pads to improve cost efficiency.

The next wave While the Montney pioneers build out from their core areas, a second wave of producers is growing production rapidly. Paramount Resources Ltd. is set to make a big splash in the Montney this winter as its new processing facilities come on stream. Paramount has had ownership of infrastructure that enabled it to produce up to about 15,000 barrels of oil equivalent per day, Jim Riddell, president and chief operating officer, told the recent CIBC World Markets institutional investors conference in Whistler, B.C. All that is about to change. At Musreau, Paramount has been developing a wholly owned 200-million-cubic-feet-per-day (raw gas) deep cut plant with a net sales gas capacity of 50,000 barrels of oil equivalent per day, and has expanded the condensate stabilizer by 15,000 barrels per day as it realized the high liquids content in the gas. The company is now commissioning the plant and expects to have first sales in March. It has about 300 million cubic feet per day of behind-pipe deliverability from 61 (47.9 net) wells drilled and completed over the last two or three years, said Riddell. Once in full operation, the 200 million cubic feet per day of raw gas to the plant will result in 154 million cubic feet per day of sales gas that will produce 30,280 barrels per day of NGLs, including 11,200 barrels per day of stabilized condensate, he said. Paramount plans build out to a total of more than 80,000 barrels of oil equivalent per day of sales capacity in the Kaybob operating unit by the beginning of 2015. The build out will be gradual as Paramount adds the expanded condensate stabilizer and amine unit at Musreau, the conference heard. The company also has a 20 per cent ownership in the Pembina Pipeline Corporation Resthaven/Smoky deep cut expansion to be in operation this year.

Feature

Top 20 Montney Acreage Holders Operator

Net acreage

Canadian Natural Resources Limited

1,043,800

“ I think it is pretty clear the data we have

PETRONAS (Progress Energy Canada Ltd.)

900,000

Encana Corporation

575,000

presented validates our theses of the

ExxonMobil Canada

545,000

ARC Resources Ltd.

493,000

benefits of the slickwater frac system,

Mitsubishi Corporation

410,000

for which we were really the first to try

Birchcliff Energy Ltd.

322,000

Crew Energy Inc.

239,000

this far east in a more normally

Talisman Energy Inc.

182,000

Murphy Oil Corporation

144,000

Tourmaline Oil Corp.

144,000

KOGAS Canada Ltd.

130,000

Paramount Resources Ltd.

128,000

ConocoPhillips Canada

124,000

Long Run Exploration

123,000

Painted Pony Petroluem Ltd.

122,400

NuVista Energy Ltd.

112,640

Chinook Energy Inc.

95,000

Sasol Limited

80,000

Advantage Oil & Gas Ltd.

77,000 Source: Company websites

Paramount has contracted for de-ethanization capacity at the Keyera Corp. plant at Fort Saskatchewan, Alta., that will be in operation later this year. The company believes it has de-risked all of its 335 sections of Montney land rights in the Kaybob area, which gives it an inventory of thousands of wells to drill, said Riddell. Estimated discovered gas initially in place is more than 70 billion cubic feet per section with a total of 23 trillion cubic feet of gas plus NGLs across the lands, he said. Typical wells are in the 10-million-cubic-feet-per-day range. But the real story is the liquids content. In the third quarter of 2013, a four-well pad in an area with a very high liquids ratio (up to 300 barrels per million cubic feet) tested a combined 34 million cubic feet per day plus NGLs. “That would be in the realm of a 10,000-barrels-per-day condensate deliverability initially out of that pad site,” said Riddell. Paramount has begun drilling two 10-well pads targeting the Montney that it expects to rig release in the first quarter of 2014. It is using its own drilling fleet (Fox Drilling) that has five triple AC top-drive fully automated walking rigs. The company is trying to drive down the cost with the drilling time reduced to 30 days from 70 days, and potentially seeing a further reduction of five or 10 days on its 10-well pad, he said. The cost of completions has also dropped. Delphi Energy Corp. is also unlocking the Montney on its 124 gross sections of land at Bigstone in northwestern Alberta. Delphi is in the midst of a five-year, 50-well development program targeting both gas and liquids. In 2013, the company re-jigged its drilling and completion program, resulting in major gains. Delphi was producing 700 barrels of oil equivalent per day from the Montney in March 2013. It exited the year at 5,000 barrels of oil equivalent

pressured Montney system.” — David Reid, president and chief executive officer, Delphi Energy Corp.

per day. It expects production to grow to over 20,000 barrels of oil equivalent per day by 2017. Delphi’s use of extended-reach horizontal wells and a slickwater fracturing system is producing some of the top liquids-rich wells drilled in the Montney. “The slickwater program obviously is working, and we will continue to optimize that,” David Reid, president and chief executive officer, said in the fall. He noted the company’s 10-27-060-23W5 well at East Bigstone was still producing over 1,150 barrels of oil equivalent per day after 120 days, which shows the potential of such a completion technique. The 15-10-060-23W5 well, also slickwater fractured, was producing 516 barrels per day after 120 days. “I think it is pretty clear the data we have presented validates our theses of the benefits of the slickwater frac system, for which we were really the first to try this far east in a more normally pressured Montney system,” said Reid. Three previously drilled wells at East Bigstone used conventional gelled oil frac designs. With the new completion techniques accomplishing the company’s goal of significantly reducing declines, the gap between the production rates of these two new wells compared to the first three continues to widen. Both wells (10-27 and 15-10) continue to exceed the current type curve. In addition, the new wells continue to produce at higher field-condensate-to-gas ratios compared to the first three wells. The application of extended-reach horizontal drilling across two sections and stimulating using a 30-stage frac design reduces overall capital requirements and generates significantly more royalty credits, the company said. The number of days to drill to a total depth of almost 6,000 metres across two sections has decreased to 33 days from 48 days. “That is a significant drop from the first well we drilled across two sections,” Reid said. On average, the cost to drill across the second section has decreased to approximately $750,000, compared to drilling a new well across the second section at an estimated cost of $4.5 million, Delphi said. In addition, incremental royalty credits of approximately $4.5 million are earned by drilling across the second section. Delphi continues expanding development from its initial East Bigstone play. OIL & GAS INQUIRER • march 2014

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Its initial exploration well at 11-17059-22W5 on its South Bigstone Montney farm-in lands averaged 4.4 million cubic feet per day of raw natural gas and 165 barrels per day of field condensate during the last 24 hours of clean-up flow, the company announced in December. Based on this test result, Delphi expects to begin development of the Montney play at South Bigstone in the latter part of 2014, using the same 2,500–3,000-metre horizontal well lengths and 30-stage fracs as employed in the ongoing Montney development program at East Bigstone. The 11-17 Montney horizontal well is about 13 kilometres south of the company’s ongoing drilling activity at East Bigstone. After successfully placing all 26 stages of the fracture stimulation, the well flowed on cleanup over eight days, recovering 34 per cent of the initial frac load water. The 11-17 well is expected to be pipelineconnected and on production in the third quarter of 2014, and will continue to recover load water over several months of production. Delphi said the test results at 11-17 validate that the reservoir rock quality and liquids-rich nature of the production mix is consistent with East Bigstone. At East Bigstone, Delphi has now drilled a total of 10 horizontal Montney wells, of which nine are extended-reach horizontal laterals with lengths up to 3,000 metres. Since Delphi changed its completion techniques from conventional oil fracs on the first three wells to a slickwater hybrid fracturing technique, the Montney wells at East Bigstone have exceeded the company’s expectations. The previously announced 15-30-06022W5 well, with a horizontal length of 3,014 metres and the most recent to be placed on production, has produced at a company recordhigh rate of 2,076 barrels of oil equivalent per day over the first 30 days of production. Comparing results of the slickwater hybrid fracturing technique to smaller conventional frac methods, Delphi said well performance at Bigstone during the initial 30 days of production has almost doubled. It said longer-term production performance has tripled when observing production rates after 180 days. Wellhead condensate production and yields have also improved by two to three times. Delphi said it continues optimizing capital efficiencies through its extended-reach drilling plan targeting horizontal lateral lengths between 2,500 and 3,000 metres. Drilling operations continue in East Bigstone with two additional wells now

drilled and one or two more wells to be drilled before breakup. To handle its rapidly growing Montney production volumes, the company is continuing with construction to expand its 07-11 facility to handle 45 million cubic feet per day of raw gas, as well as increased field condensate volumes with the installation of larger inlet separation and increased condensate storage tank capacity.

Montney oil moves to development phase While the Montney oil play is dwarfed by its natural gas and gas liquids plays, it is a cashgenerating machine. Peters & Co. ranked the Montney oil play at Kaybob as having the second highest rate of return of all resource plays in North America in September. Trilogy Energy Corp. is the dominant player in the play, with 50 net sections of land overlying around 500 million barrels of oil. So far, Trilogy has drilled around 75 wells targeting Montney oil, with current production of around 8,500 barrels per day plus around 21 million cubic feet per day of gas. Trilogy is developing the play using mile-long horizontal laterals, with 22 fracs per well. Costs to drill, complete and tie in each well come in at around $4 million. Trilog y expects to spend around $135 million in 2014 drilling 30 Montney oil wells and building out some infrastructure. Longer term, it expects production to climb to 12,000 barrels per day plus 30 million cubic feet per day of gas. It has 400 identified horizontal drilling targets in the play. Other companies are also focused on developing Montney oil, including energy giant Canadian Natural Resources Limited. Since acquiring a large gas-weighted asset in the Grande Prairie area in 2010, Canadian Natural has grown the property’s oil output by roughly 90 per cent and is expected to exit 2013 at 23,000 barrels per day, says Jeff Wilson, senior vice-president of exploration. During the past two years, Canadian Natural has been testing several tight oil plays in the area, which boasts 14 formations with horizontal initial production rates (IPs) 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 that range from 285 to 455 barrels per day and

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Feature

Delphi Montney Oil Fracs versus Slickwater Fracs Horizontal length (metres)

Number of fracs

IP30 sales (boe/d)

IP90 sales (boe/d)

IP120 sales (boe/d)

IP180 sales (boe/d)

Sales at day 180 (boe/d)

16-30 well

2,760

1,099

790

688

558

259

05-02 well

3,005

969

676

584

479

250

14-23 well

2,238

1,570

929

795

635

291

15-10 well

1,424

991

833

768

660

421

10-27 well

2,407

1,815

1,653

1,545

1,062

928

16-23 well

2,809

1,781

1,488

n/a

Well Oil fracs

Slickwater fracs

Calculated on operating days; excludes non-producing days

average EURs [estimated ultimate recovery rates] that range from 294,000 to 460,000 barrels equivalent per well,” said Wilson. Canadian Natural 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.”

march 2014 • OIL & GAS INQUIRER

Source: Delphi Energy Corp.

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. “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.

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