Oil & Gas Inquirer April 2014

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CONTENTS

APRIL.

in the news

9

Forecasting unconventional reservoirs a challenge

regional news

15

British Columbia

23

Northeastern Alberta

31

Southern Alberta

Canadian LNG will not miss the boat, says Paul Ziff

Debate over sharing of oilsands benefits continues

Liquids output up on Encana’s Clearwater lands

19

27

35

Northwestern Alberta

Central Alberta

Saskatchewan

Birchcliff sets $347.1-million capital

Full Duvernay development will

Alexander, Renegade to form Spartan

budget, with Montney a major focus

require planning, collaboration

Energy Corp. in $495-million deal

features Cover Feature

39 Busy as bees Operators expanding Saskatchewan Bakken play, reworking wells, advancing new completion technologies and piloting enhanced recovery schemes

43

every issue

6 Stats at a Glance 46 Political Cartoon

Driven by big data Information technology is automating oil and gas processes and helping decision makers from prospecting through production

Cover design: Peter Markiw; Photos: © iStockphoto.com/alle

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OILweek 4/14

Editor’s Note Vol. 26 No. 4 EDITORIAL EDITOR

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

James Mahony, Pat Roche, Elsie Ross, Paul Wells

Smaller resource plays pack a big wallop

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Big resource plays measured in the billions of barrels of oil and tens of trillions of cubic feet of natural gas have generated all the buzz in the western Canadian oil and gas industry in the last decade.

But they aren’t the only game in town.

Explorers of all sizes are also finding strong reserve and production growth targeting smaller resource plays with horizontal drilling and multistage fracturing.

The technology is also being applied in more conventional reservoirs, turning them into cash-generating machines.

The Charlie Lake oil play straddling the Alberta-B.C. border in the north is one example, with both Tourmaline Oil Corp. and Birchcliff Energy Ltd. building strong operations in the play. Tourmaline drilled 35 Charlie Lake wells in 2013 and plans 45 wells this year. It has proved-plusprobable reserves of almost 50 million barrels equivalent in the play. Birchcliff has around 39 million barrels of proven and probable reserves at its Charlie Lake operations at Worsley.

DeeThree Exploration Ltd.’s Belly River play northwest of Calgary in the Brazeau area is another example of a smaller resource play. DeeThree has 60,000 gross acres targeting multiple zones in the Belly River with current production of over 2,500 barrels equivalent per day. It has identified over 330 horizontal well locations and expects to move into the development phase in the play this year.

Bonavista Energy Corporation has a number of plays in more conventional reservoirs underway in west-central Alberta.

The Glauconite Formation in west-central Alberta will be the major source of growth for Bonavista in the next couple of years, with the company spending $150 million to $200 million per year in 2014 and 2015, and an anticipated doubling of production by the second half of 2015 from the current 17,000 barrels equivalent per day. This year, plans call for the spending of $161 million to drill 58 Glauconite wells where Bonavista has 400 horizontal locations and has already drilled 186 horizontal wells.

Also in west-central Alberta, Bonavista has budgeted $44 million to drill 11 gross wells in the liquids-rich Ellerslie, which it describes as the “most undervalued, probably unappreciated play in the company.”

What these plays demonstrate is there are significant opportunities in western Canada outside of the giant tight plays like the Duvernay, Montney, Bakken and Cardium. And combined with the giants, they demonstrate the massive potential of the basin’s future development.

Despite the current lack of export capacity, explorers continue turning resources into reserves and fine-tuning technology to wring more dollars from those reserves.

When pipeline capacity comes, get ready for a boom.

Darrell Stonehouse Editor

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OIL & GAS INQUIRER • APRIL 2014

5

FAST NUMBERS

$

million

Amount spent on measurement and control devices in Alberta in 2012.



per cent

Increase in spending on measurement and control devices from 2011 to 2012.

Sources: Statistics Canada; Government of Alberta

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin

M O NTH

MONTH

OIL



Feb 

899

161

17

83

,



Mar 

949

198

21

127

,

129



Apr 

581

146

18

127



14

73



Jun 

273

56

1

75



59

51



Jul 

671

103

15

51





Aug 

817

72

1

39





Sep 

735

113

1

30



953

204

8

79

,

OIL

GAS

Feb 

449

124

67

Mar 

544

149

119

Apr 

481

91

Jun 

179

Jul 

263

Aug  Sep 

394

46

357

72

OTHER

T O TA L

34 29

GAS

D RY

SERVICE

T O TA L

Oct 

528

153

72



Oct 

Nov 

463

164

44



Nov 

852

218

9

62

,

Dec 

298

137

52



Dec 

675

180

20

72



Jan 

280

105

57



Jan 

488

156

18

55



Feb 

427

119

80



Feb 

879

163

15

73

,

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 *

OIL

GAS

Feb 

358

0

31



Mar 

323

0

19



208

Apr 

88

1

5



45

330

Jul 

Jun 

80

0

2



49

379

Aug 

26

405

Jul 

358

1

13



Sep 

43

422

Oct 

52

474

Nov 

58

532

Dec 

45

45

Jan 

49

94

Feb 

46

150

Feb 

42

73

Mar 

66

139

Apr 

69

Jun 

*From year-to-date

MONTH

OTHER

TOTAL

Aug 

362

1

6



Sep 

347

0

1



Oct 

380

0

15



Nov 

339

0

27



Dec 

321

0

39



Jan 

181

0

13



Feb 

401

0

7



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APRIL 2014 • OIL & GAS INQUIRER

STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, March 11, 2014 Source: Rig Locator

Alberta, February 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

Feb 

Feb 

Feb 

Feb 

381

193



66%

Northwestern Alberta

143

125

84

56

British Columbia

70

7



91%

Northeastern Alberta

62

80

0

2

Manitoba

10

6



63%

Central Alberta

177

196

5

8

Saskatchewan

89

54



62%

Southern Alberta

45

49

30

56







%

TOTAL









WC TOTALS

Service Rig Count by Province/Territory

Drilling Activity: CBM & Bitumen

Western Canada, March 11, 2014 Source: Rig Locator

Alberta, February 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

Feb 

Feb 

Feb 

Feb 

211

136



61%

Northwestern Alberta

0

0

8

9

British Columbia

3

1



75%

Northeastern Alberta

0

0

62

80

Manitoba

5

1



83%

Central Alberta

0

2

68

60

59

32



65%

Southern Alberta

0

17

0

0







%

TOTAL









Saskatchewan

WC TOTALS

OIL & GAS INQUIRER • APRIL 2014

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IN THE

NEWS Issues affecting Canada’s E&P industry

Forecasting unconventional reservoirs a challenge

By Paul Wells

challenge

While the advent of horizontal drilling and multistage fracturing has opened up a plethora of potential targets for exploration and production companies, the ability to accurately forecast future well results and reserve potential has not kept up with the new technologies employed by the industry.

“The shift towards unconventional resource plays in the oil and gas industry, particularly in North America, has created some evident challenges in attempting to forecast production and calculate reserves with traditional tools,” said Gary Leach, president of the Explorers and Producers Association of Canada.

“Better methodologies that can enable operators to make wiser and more efficient investment and planning decisions are an important contribution to the industry’s long-term success.”

Even analysts and investors, who often want the initial production results from a company as soon as possible, agree that the rush to hail the results of a well in an emerging or hot play may compromise getting an accurate assessment of future potential.

“We all bear some responsibility for this. I wouldn’t say that the issue necessarily needs to be shouldered by companies—we all need to recognize, as analysts and investors, that initial results are just that,” said Don Rawson, managing director of institutional research with AltaCorp Capital Inc. “They don’t necessarily tell you how a well is going to perform 12 months or five years out and the economics that fall out of that.”

Ray Kwan, an analyst with Macquarie Capital Markets Canada Ltd., agreed, adding that forecasting methodology needs

to try to keep up with the evolving nature of exploration and production activity.

“Naturally, with most people and analysts, I think it’s human nature to have an optimism bias to forecasts, whether it be type curves or earnings estimates or how a play is going to evolve. We have a bias either to the negative side or the upside,” he said.

“So, with a lot of the plays here in Canada, we initially come up with a typecurve forecast, and certainly some come in below expectations and some have come in even above expectations in terms of potential,” Kwan added. “I think what needs to be done is really just look back and understand where the forecasting was wrong and then just kind of fine-tune those numbers so you can be conservative and more accurate.”

Crystal ball gazing Kwan said that, in general, “most guys have it wrong” in terms of forecasting future results, but “you can have an educated guess” as to what the future may hold.

“That’s how I see things in terms of forecasting. You can never be 100 per cent confident—you have bands where there’s a 50 per cent confidence interval that you can actually understand, stuff like where type curves are going to lie or what production growth is likely going to be.

“I think you just have to have those sensitivities to really understand where potentially the ranges could be versus a pinpoint answer.”

In response to that point, Chris Theal, president and chief executive officer of Kootenay Capital Management Corp., added: “If you’re looking at initial results from the Duvernay from a year ago, throw them out. Much has changed as companies continue to try to prove up their asset base.”

While Rawson also believes forecasting methods need to change, he noted that the continual evolution of drilling and completion techniques will make it hard for forecasters to stay ahead of, or even simply keep pace with, the curve as it relates to the new era of resource play–based exploration and production.

“We all have to recognize that the companies are constantly testing out new ways to complete wells and are trying to weigh the cost benefit of different completion techniques,” he said.

“I think that one of the changes that’s happened, or maybe why people may be more focused on it, is that when you have resource plays, people are looking to extrapolate certain results for a large resource base, where in the past when a company was drilling up a small pool, you wouldn’t extrapolate that much because results were expected to be more variable,” Rawson added.

“But when there’s now an expectation of repeatability, investors want as much information as they can get even though things are often in the early stages and evolving.

So there is some danger in extrapolating too far for the good or the bad.”

Brad Hayes, president of Petrel Robertson Consulting Ltd., said that in the past, forecasting conventional wells was a relatively simple exercise, and “you could make a pretty good prediction for the long term on how much oil and gas a well would produce.”

But, he added, that’s not the case anymore.

“What’s changed with the unconventional reservoirs is that you’re putting this big fracture network out into the reservoir, and you’re not quite sure how far it’s going, and you’re not quite sure how much reservoir volume or rock that’s been stimulated,” Hayes said.

OIL & GAS INQUIRER • APRIL 2014

9

In The News

“So just flowing it for a little while doesn’t tell you very much about the reservoir volume as a conventional well would.”

Hayes noted that when larger companies begin a program in a play like the Duvernay, they will typically drill “say a dozen wells” at different horizontal lengths and experiment with different numbers of fractures and then produce them for a period of time to get a production history.

“What they’re trying to do is figure out what the typical well in their development program would be like. They’re generating type curves for each area—a plot of production rates over time that you can use to sort of see how the production flow will vary from day to day or month to month. Then you can also extrapolate it out if you’ve got a long enough history to understand what the total reserves might be,” he said.

“But it’s highly variable according to the characteristics of these unconventional reservoirs, and it varies from place to place.”

But because there is not a lot of historic data from many of the expansive resource plays in western Canada, Hayes contended that getting an accurate read on future performance remains difficult.

10

APRIL 2014 • OIL & GAS INQUIRER

optimism

Improved pipeline access drives producer optimism There are signs that western Canada’s oil production will have improved access to markets, an oilsands forum heard recently.

It’s been a rough past three years or so for oil producers, but possible events on the horizon in 2014—such as the expected significant increase in pipeline access of western Canadian crude to tidewater and the emergence of transportation by rail—might start making a difference, said Robert Mason, an investment banking executive with TD Securities.

He stressed the word “might.”

Theoretically, by the end of 2013, only 600,000 barrels of oil per day could get to the West Coast and U.S. Gulf Coast from western Canada, Mason told Insight Information’s Canadian Oil Sands Summit in Calgary.

But with the start-up of a number of new major pipelines this year, including TransCanada Cor poration’s Gulf Coast line, expansions at Enbridge Inc.’s

Seaway and Flanagan South, the number of barrels of western Canadian crude that theoretically can access the United States by mid-year is expected to grow to more than 1.5 million barrels per day, he said.

“That’s a theoretical capacity because, clearly, in places like Cushing, [Okla.], and the mid-U.S., there are U.S. volumes that are also trying to get onto those pipelines,” he added.

Another significant change has been the emergence of rail, the conference heard.

Current rail loading capacity in western Canada is estimated at between 300,000 and 400,000 barrels per day, up from about 150,000 barrels per day a year ago.

That’s expected to grow to well over one million barrels per day, possibly 1.2 million barrel per day, by the end of this year, said Mason. “With that, very significant increases in rail volumes will be leaving the country,” he said.

In The News New pipelines improving the ability to move Canadian crudes Project

Owner

From

To

Throughput capacity (bbls/d)

Completion date*

Completed projects Steele City, Neb., and

Keystone Phase 1

TransCanada Corporation

Hardisty, Alta.

435,000

June 2010

Keystone Phase 2 (Cushing extension)

TransCanada Corporation

Steele City, Neb.

Cushing, Okla.

156,000

February 2011

Cushing, Okla.

Freeport, Texas

150,000

June 2012

Cushing, Okla.

Freeport, Texas

250,000

January 2013

Seaway Reversal Phase 1 Seaway Reversal Phase 2

Enterprise Products Partners L.P./Enbridge Inc. Enterprise Products Partners L.P./Enbridge Inc.

Wood River and Patoka, Ill.

Spearhead North Expansion (Line 62)

Enbridge Inc.

Flanagan, Ill.

Griffith, Ind.

105,000

Late 2013

Line 9A Reversal

Enbridge Inc.

Sarnia, Ont.

Westover, Ont.

240,000

Late 2013

Gulf Coast (Keystone XL southern leg)

TransCanada Corporation

Cushing, Okla.

Nederland, Texas

700,000

January 2014

Cushing, Okla.

Freeport, Texas

450,000

H1/2014

Approved/under construction Seaway twinning/looping

Enterprise Products Partners L.P./Enbridge Inc.

Flanagan South

Enbridge Inc.

Flanagan, Ill.

Cushing, Okla.

600,000

Mid-2014

Clipper (Line 67) Phase I

Enbridge Inc.

Hardisty, Alta.

Superior, Wis.

120,000

Mid-2014

Batching improvements

Enbridge Inc.

--

--

?

--

Proposed Line 61 (southern access) Expansion Phase 1

Enbridge Inc.

Superior, Wis.

Flanagan, Ill.

160,000

Mid-2014

Line 9B Reversal and Expansion

Enbridge Inc.

Westover, Ont.

Montreal, Que.

300,000

Q4/2014

Eastern Gulf Crude Access

Energy Transfer Partners L.P.

Johnsonville, Ill.

St. James, La.

420,000

Mid-2015

Line 61 (southern access) Expansion Phase 2

Enbridge Inc.

Superior, Wis.

Flanagan, Ill.

640,000

H2/2015

Keystone XL

TransCanada Corporation

Hardisty, Alta.

Steele City, Neb.

830,000

2015

Clipper (Line 67) Phase II

Enbridge Inc.

Hardisty, Alta.

Superior, Wis.

230,000

2015

Sandpiper (N.D.–Minn.)

Enbridge Inc.

Beaverlodge, N.D.

Clearbrook, Minn.

225,000

2016

Sandpiper (Minn.–Wis.)

Enbridge Inc.

Clearbrook, Minn.

Superior, Wis.

375,000

2016

Energy East

TransCanada Corporation

Hardisty, Alta.

1,100,000

2017

Montreal and Quebec City, Que., and Saint John, N.B.

Trans Mountain twinning

Kinder Morgan Canada

Edmonton, Alta.

Burnaby, B.C.

590,000

2017

Northern Gateway

Enbridge Inc.

Edmonton, Alta.

Kitimat, B.C.

525,000

--

* Completion dates shown are as currently targeted.

Sources: Peters & Co. Limited estimates; company reports

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855.REDGUARD OIL & GAS INQUIRER • APRIL 2014

11

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There have been recent expansions in off-loading capacity and refineries in eastern Canada, and there are plans to significantly increase off-loading capacity throughout the United States, he added.

Limited market access to export western Canadian crude —both light and heavy—is the most important issue facing the industry and possibly the country, said Mason.

It has resulted in extremely large price discounts for Canadian crudes in the past three years and had a very significant impact on the overall Canadian economy of between $20 billion and $30 billion in lost revenues in 2012 and 2013, he said.

“That’s not just revenues to companies, but revenues to tax dollars and royalties to various levels of government. When you add that up, that equals roughly 1.2–1.8 per cent of Canada’s gross domestic product, to put it in context.”

According to Mason, other key issues facing the industry include opposition to development from environmental and certain First Nations groups and regulatory approvals that have taken longer than usual for some Alberta projects.

The availability of skilled labour is a continuing concern with costs for some projects escalating, while financing for junior companies and merger and acquisition activity have largely dried up in the past 12 months, he added.

With the combination of surging oil production from a number of plays south of the border—the Bakken, Eagle Ford and Permian Basin among them—and the fact that the United States has a partial export ban on crude oil, U.S. light oil is already facing price discounts, especially on the Gulf Coast, said Mason.

In contrast, crude that’s being produced on Canada’s East Coast is actually getting international pricing, he said.

In the past six months, some of the eastern refiners, such as Suncor Energy Inc., Valero Energy Corp. and Irving Oil Limited, have started bringing cheap light oil from the Gulf Coast up by ship.

“As it turns out, it is actually cheaper to ship light oil to Canada...than it is to ports in the U.S. because of an interesting law called the Jones Act, which requires any shipments bet ween U.S. ports to run on U.S. ships by U.S. crews, which is more expensive than international ones,” said Mason.

— DAILY OIL BULLETIN

12

APRIL 2014 • OIL & GAS INQUIRER

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BRITISH COLUMBIA WELL ACTIVITY FEB/13

FEB/14

Wells licensed

89

9

FEB/13

FEB/14

Wells spudded

61

7

FEB/13

FEB/14

61

7

Rigs released

▲

B.C. British Columbia

▲

Source: Daily Oil Bulletin

Canadian LNG will not miss the boat, says Paul Ziff

By James Mahony

With a number of Canadian liquefied natural gas (LNG) export facilities set to come on stream about 2020, some experts are wondering if the current gap between low North American and higher Asian natural gas prices will last long enough for Canadian LNG exporters to benefit from it.

“There’s certainly a scenario where U.S. Henry Hub gas prices look attractive now, but they may not be 10 years from now,” said natural gas expert Paul Ziff. “[That gap] is what’s driving North American LNG projects.”

Still, he argued there’s no cause for worry, at least for now. “There’s very strong demand for LNG, particularly for gas-fi red power plants,” he told a Calgary audience in a presentation to the Petroleum Acquisition and Divestment Association.

“The demand will be there.”

In addition to Asian demand, European demand for LNG is on the rise, said Ziff, executive vice-president for Ziff Energy Group, a div ision of HSB Solomon Associates LLC. On the supply side, some traditional Asian suppliers of LNG have been slipping,

which means that the supply Asia previously relied on may not arrive in the same volumes, a factor that bodes well for Canada’s group of aspiring LNG exporters.

At the same time, Ziff acknowledged the situation is more complex, since the current gap between North American and Asian gas prices is also affected by global crude oil prices. Anyone trying to get a bead on future LNG prices—in Asia or elsewhere—has to fi rst factor in the oil price they’re forecasting for the same period.

Ziff showed his audience a chart illustrating a range of proposed Canadian LNG projects, including some that have been approved by the National Energy Board.

Added up, the approved group would together yield roughly 34 billion cubic feet per day of gas production, were all of them to be built. “That’s a pretty staggering amount, about double current production,” he said.

As for defi ning ingredients for success in the LNG business, Ziff identified a few key factors.

“The first is the gas resource, and most of the Canadian projects have this potential,”

British Columbia LNG plant proposals Facility Aurora LNG

Proponents Nexen Energy ULC, INPEX Corporation, JGC Corporation Canada

Capacity (bcf/d) 3.12

BC LNG Export Co-op

LNG Partners of Houston, Haisla Nation

0.24

Kitimat LNG

Chevron Canada Limited, Apache Canada Ltd.

1.28

Kitsault Energy

Kitsault Energy

2.64

LNG Canada

Shell Canada Limited, KOGAS Canada Ltd., Mitsubishi Corporation, PetroChina Company Limited

3.23

Pacific NorthWest LNG

PETRONAS, Japan Petroleum Exploration Co., Ltd.

2.74

Prince Rupert LNG

British Gas Group

2.91

Triton LNG

AltaGas Ltd., Idemitsu Kosan Co., Ltd.

0.31

WCC LNG Ltd.

ExxonMobil Canada, Imperial Oil Limited

4.00

Woodfibre LNG Project

Woodfibre Natural Gas Limited

0.29 Source: Company websites

he said. The second is LNG industry experience, something that has been harder to come by, especially for North American companies, Ziff said. A third factor is the longterm supply contracts that would be needed to justify the huge, upfront capital costs of LNG projects.

Among successful international LNG players, a few have distinguished themselves, he said. As for the factors drawing these players to Canada, Ziff cited this country’s proximity to Asian markets, followed by Canada’s reputation for political stability. Another factor making this country attractive is the wish of many LNG players to diversify their global supply.

Internationally, Japan still dominates LNG markets. Since that country’s Fukushima nuclear disaster in 2011, there has been even more pressure to boost imports of foreign LNG, he said. Korea ranks second after Japan, ahead of both China and India, although Ziff said the latter two are among the fastest-growing LNG-consuming countries.

Meanwhile, growth in demand for LNG in Europe is being led by countries seeking to balance their gas imports from Russia, a country viewed by some Europeans as a less-than-secure source of imports, he said.

Also affecting global demand is a drop in LNG exports from such countries as Indonesia and Malaysia, traditionally viewed as generous LNG exporters.

“They’ve reached the point that either their gas reserves are depleting or there’s increased demand for gas-fired power generation in their own country,” said Ziff.

“The amount of gas available for export has actually declined for some LNG exporters.”

For North American LNG exporters, he acknowledged that most of these factors represent good news. At the same time, Ziff cited LNG projects in Qatar and Australia, either completed or in the works, as further evidence that it’s not an open market.

OIL & GAS INQUIRER • APRIL 2014

15

British Columbia

One wrinkle that makes it difficult for Canadian LNG projects is the fact that their counterparts in the United States tend to be brownfield projects.

“In the U.S., they’re basically reversing some of the large plants built 10 or 15 years ago, which affords some economy,” Ziff said.

“But the big difference between Canadian and U.S. LNG is that U.S. projects generally do not have the dedicated physical gas reserves, whereas in most cases, in Canada, they do.”

Also in Canada, some major LNG developers have gradually grown upstream,

effectively creating a totally integrated project, as opposed to one company doing the producing, another handling the shipping and another buying LNG the way a U.S. project might unfold, he told the audience of Calgary acquisition and development practitioners.

Artek sets $66-million capital budget Artek Exploration Ltd. said it plans to drill approximately 14–15 gross (nine to 10 net) wells in 2014 with a capital expenditures budget of $61 million to $66 million.

The currently planned capital program will be weighted 100 per cent to projects targeting oil and condensate with associated natural gas that deliver the best returns and most upside potential for the company, said Artek.

The 2014 program aims to strike a balance between production growth and pool extension investment in the condensaterich Doig play at Inga, the significant upside potential in its exploratory Montney play at

Inga and the emerging exploration Charlie Lake oil play in the Mulligan area of Alberta.

The program includes nine to 10 (5.3– 5.9 net) horizontal wells in the condensaterich Inga/Fireweed area, including seven at Doig and up to three at Montney. The program represents 70 per cent of planned investment and targets a balance of development, pool extension, and exploration drilling and production operations investment.

Artek also plans three horizontal wells targeting Charlie Lake oil in the Mulligan area of Alberta and two (0.8 net) vertical wells in the Leduc-Woodbend area.

Approximately 20 per cent will be directed toward drilling and production operations in Alberta. The remaining 10 per cent will be allocated toward land, seismic and facility optimization investment.

Artek said it entered 2014 at a record production level of approximately 4,800 barrels equivalent per day (approximately 38 per cent oil and natural gas liquids) based on field estimates.

The company will monitor commodity prices closely, but assuming the capital program is carried out in its entirety, 2014 average production is forecast to

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APRIL 2014 • OIL & GAS INQUIRER

British Columbia

be approximately 4,700–4,900 barrels per day (38–39 per cent liquids), representing approximately 30 per cent growth over 2013 average production of approximately 3,700 barrels per day.

Forecast 2014 exit production is approximately 5,200–5,300 barrels per day (40 per cent oil and natural gas liquids).

The company is currently drilling its second Inga Doig horizontal of the year in the Inga South area at 05-11-088-23W6.

Artek is also currently testing its fi rst Doig horizontal of the year in the Inga South area where, in its previous two Inga South Doig wells, the company encountered exceptionally high initial liquids rates. As a result, it has doubled the number of fractures typically used by employing a 28-stage slickwater frac for this operation, its first on the Doig play.

The company has also begun a 20-stage frac on its first Charlie Lake horizontal well of the year.

— DAILY OIL BULLETIN

Septimus Montney play boosts Crew Energy reserves Crew Energy Inc. increased its proved reserves by 35 per cent and its proved-plus-probable reserves by 29 per cent for the year ended Dec. 31, 2013, as determined by an independent reserve evaluation.

Proved reserves grew to 115.22 million barrels of oil equivalent after production of 10.01 million barrels and net acquisitions of 2.41 million barrels, from 85.09 million barrels equivalent as of Dec. 31, 2012, according to a Sproule Associates Limited report.

Proved-plus-probable reserves increased to 197.3 million barrels equivalent from 152.98 million barrels as of Dec. 31, 2012. Of the 44.32-million-barrel increase, pool extensions and improved recoveries accounted for 25.64 million barrels, which was concentrated at Crew’s Septimus Montney property in northeastern British Columbia.

In the Sproule report, approximately 298 undeveloped locations are booked in Crew’s four core areas out of an inventory of over 2,500 potential drilling locations.

Proved-plus-probable gross reserves include 34.42 million barrels of oil (19.99 million barrels proved), 31.35 million barrels of natural gas liquids (18.16 million barrels proved) and 789.2 billion cubic feet of of natural gas (462.47 billion cubic feet proved).

Crew achieved its targeted exit production range with December 2013 production averaging 29,300 barrels equivalent per day while fourth-quarter production averaged 28,682 barrels per day.

At Crew’s Septimus Montney property, proved-plus-probable reserves increased 82 per cent to 84.7 million barrels equivalent.

The majority of this increase occurred in the proved producing category, recognizing better type well performance as a result of improved completion techniques and infrastructure enhancements.

Average proved-plus-probable undeveloped Montney reserves increased to 4.3 billion cubic feet per well from 3.2 billion cubic feet per well in 2012. Crew currently has 69 undeveloped locations booked at Septimus at an average proved-plus-probable reserve booking of 772,000 barrels per location (15 per cent natural gas liquids) with 52 of those locations booked in the proved undeveloped category.

— DAILY OIL BULLETIN

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17

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NORTHWESTERN ALBERTA WELL ACTIVITY FEB/13

FEB/14

Wells licensed

219

296

FEB/13

FEB/14

Wells spudded

251

22

FEB/13

FEB/14

274

21

Rigs released

▲

▲

Northwestern Alberta

▼

Source: Daily Oil Bulletin

Birchcliff sets $347.1-million capital budget, with Montney a major focus Birchcliff Energy Ltd. has set a 2014 capital budget of $347.1 million (including $56.1 million for acquisitions), up from a preliminary budget of $275 million.

The largest share of the budget ($219.9 million) has been allocated for drilling and development (drill, case, complete, equip and tie in). Plans call for 40 (39.5 net) wells and expected exit production of between 37,500 and 39,500 barrels equivalent per day.

Of the total drilling budget, $155.8 million will be spent to drill 25 (25 net) Middle/ Lower Montney horizontal oil and gas wells. Another $29.2 million will target eight Worsley Charlie Lake horizontal oil wells and $25.8 million for four Basal Doig/Upper Montney horizontal gas wells.

In addition, Birchcliff has budgeted $5.6 million to drill one other oil well and $3.5 million (net) for two (1.5 net) Halfway oil wells.

The budget also includes $30.2 million for facilities, $13.1 million for production optimization and $12.9 million for land and seismic.

Production averaged 28,391 barrels equivalent per day in the fi nal quarter of 2013, an increase of 6.5 per cent from the fourth quarter of 2012.

Fourth-quarter operating costs of $5.44 per barrel equivalent were down 7.5 per cent from $5.88 per barrel the previous year. This reduction in operating costs was largely due to the benefits achieved from processing increased volumes of natural gas through the Pouce Coupe South (PCS) gas plant and implementation of various optimization initiatives, said Birchcliff.

Birchcliff drilled 12 (11.5 net) wells in the fourth quarter of 2013, comprised of seven

Birchcliff Energy resource play land holdings (as of Dec. , ) Working interest

Gross (acres)

Net (acres)

Middle/Lower Montney play

93.3%

209,920

195,821

Basal Doig/Upper Montney play

92.4%

196,640

181,715

Worsley Charlie Lake light oil play

98.7%

125,280

123,610

Duvernay play

99.8%

168,320

167,936

Nordegg play

85.8%

432,960

371,571

Banff/Exshaw play

99.3%

447,360

443,669 Source: Birchcliff Energy Ltd.

(seven net) Montney/Doig horizontal natural gas wells, four (four net) Charlie Lake horizontal oil wells and one (0.5 net) Halfway horizontal oil well, all of which were successful.

Capital expenditures were $73 million in the quarter, which also included a $54.7-million strategic disposition (net of adjustments), of predominantly non-operated, low–working interest, non-core assets in the Progress area

28,391 barrels of oil equivalent per day Birchcliff Energy’s fourth-quarter average production

of Alberta. The transaction included approximately 520 barrels per day of Doe Creek light oil production, 2.7 million barrels of proved reserves and 4.5 million barrels of provedplus-probable reserves. This transaction resulted in a financial gain of $33.8 million ($25.3 million net of tax).

Production averaged 25,829 barrels equivalent per day in all of 2013, a 13.3 per cent increase over 2012 average production of 22,802 barrels per day. The increase was due to the success of its capital drilling program and increased incremental production from new horizontal gas wells on the Montney/Doig gas resource play processed through the PCS gas plant, said Birchcliff.

Output consisted of approximately 81 per cent natural gas and 19 per cent crude oil and natural gas liquids. Roughly 73 per cent of Birchcliff ’s natural gas production and 61 per cent of corporate production was processed at the PCS gas plant during 2013.

Capital expenditures in 2013 were $270.1 million ($215.8 million net of dispositions).

Birchcliff drilled a total of 43 (41.67 net) wells in 2013, consisting of 26 wells on its Montney/Doig natural gas resource play, including 25 horizontal natural gas wells and one vertical exploration well.

The drilling program also included 13 (13 net) horizontal wells on its Worsley Charlie Lake light oil resource play and four (2.67 net) horizontal wells on its Halfway light oil play.

The company had an undeveloped land base of 544,917 net acres at Dec. 31, 2013, OIL & GAS INQUIRER • APRIL 2014

19

Northwestern Alberta

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up from 506,024 net acres at Dec. 31, 2012, with a 94 per cent average working interest. Birchcliff added 90,325.3 net acres (141.1 net sections) of undeveloped land in 2013, substantially all at 100 per cent working interest and all within its core area of the Peace River Arch of Alberta.

Current production is approximately 33,000 barrels equivalent per day. The PCS gas plant is currently processing approximately 136 million cubic feet per day. The estimated $11.6-million Phase IV expansion of the plant, which will expand processing capacity to 180 million cubic feet per day with additional compression and sales pipeline capacity, will start up in the fall of 2014.

Birchcliff currently has four drilling rigs at work: three are active in the Pouce Coupe area, drilling Montney/Doig horizontal natural gas wells, and one rig is active in the Worsley area, drilling Charlie Lake horizontal oil wells.

Year-to-date drilling results include the drilling of six (six net) wells, consisting of four (four net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and two (two net) Charlie Lake horizontal light oil wells in the Worsley area.

— DAILY OIL BULLETIN

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20

APRIL 2014 • OIL & GAS INQUIRER

Seal CSS pilot well “shows promise,” says Murphy Oil

By Elsie Ross

At Seal in the Peace River oilsands, Murphy Oil Corporation is continuing to focus on its enhanced oil recovery (EOR) projects with recent work centred on steam, said the company’s chief executive officer.

T he company ’s f irst c yclic steam stimulation (CSS) pilot project continues to show promise with two initial wells, Roger Jenkins, president and chief executive officer, said in a conference call to discuss 2013 fourth-quarter and year-end results. He said he’s more excited about the second well as the fi rst well had some mechanical issues in the completion. The second well is currently producing in its third cycle and showing the best response

Northwestern Alberta

to date with production rates as high as 670 barrels of oil per day, analysts heard.

“The steam-oil ratio continued to improve in the previous cycle in this well, reporting an impressive steam-oil ratio of 1.8,” said Jenkins.

Murphy expects to receive regulatory approval for a third well in the second quarter and would be ready to inject steam in the third quarter. The company plans to run one rig all year in the area and has increased activity with drilling strat wells this winter, he said.

Murphy also has taken strategic hedges and has sold approximately 3,000 barrels per day of Seal heavy crude at an average netback price near US$49 per barrel in February and March 2014.

In the Montney Formation at Tupper and Tupper East in northeastern British Columbia, Murphy is focused on managing netbacks and has signed third-party processing agreements totalling 60 million cubic feet per day through its two facilities, said Jenkins. It plans to run two rigs through the year, focusing on liquids-rich gas and well completion optimization to maintain gas plant rates.

The company is using a new completion technique based on an Eagle Ford technique, said Barry Jeffery, vice-president of investor relations. Capital expenditures of US$180 million should be close to matching cash flow as Murphy has 110 million cubic feet per day of gas forward-sold at roughly C$4 per thousand cubic feet at AECO, he said.

“The steam-oil ratio continued to improve in the previous cycle in this [Seal CSS pilot] well,

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reporting an impressive steam-oil ratio of 1.8.”

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In 2014, Montney gas production is expected to decline to 145 million cubic feet per day from about 170 million cubic feet per day in 2013, said Jeffery. “In our business it is oil-weighted, so we are declining in the Montney,” he said.

Total Canadian gas production decreased to 162.45 million cubic feet per day in the fourth quarter from 186.97 million cubic feet per day in the 2012 period.

In Canada, net heavy oil production increased in the quarter to an average of 9,018 barrels of oil per day from 7,518 in the 2012 period due to volumes attributable to properties acquired in late 2012. For the year, production rose to 9,128 barrels per day from 7,241 barrels per day.

Murphy also has Canadian synthetic production from its interests in Syncrude Canada Ltd., which averaged $86.15 per barrel in the fourth quarter, and conventional production from eastern Canada offshore Newfoundland and Labrador that attracts North Sea Brent prices, which averaged $109.51 per barrel in the fourth quarter.

In 2013, Canadian operations produced total revenue of US$1.14 billion compared to $1.08 billion in 2012. Total revenue for Murphy rose to $5.31 billion for the year from $4.61 billion the previous year.

Canadian exploration and production capital expenditures from continuing operations in the fourth quarter were off sharply to $51.7 million from $417.8 million in 2012. Exploration and production capital expenditures for the year in Canada were $367.3 million, down from $897.7 million the previous year.

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NORTHEASTERN ALBERTA WELL ACTIVITY FEB/13

FEB/14

Wells licensed

163

12

FEB/13

FEB/14

Wells spudded

207

17

FEB/13

FEB/14

204

17

Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Debate over sharing of oilsands benefits continues

By James Mahony

Photo: Joey Podlubny

A speaker addressing a Calgary oil and gas audience countered what he saw as the myths about the oilsands, especially the idea that Alberta is the only region benefiting from oilsands development.

When it comes to jobs, while creating thousands in Alberta, the industry also creates many in other provinces, Kevin Birn, an executive with IHS CERA told Insight Information Inc.’s Canadian Oil Sands Summit in Calgary.

Quoting a recent IHS CERA study on the economic benefits created by the oilsands, Birn differentiated between jobs created directly by the industry, typically in Alberta, and those created indirectly, often in other parts of the country. According to Statistics Canada, the industry directly employed some 18,000 people in 2012.

Yet Birn quoted a far larger number, 478,000, as the total jobs the industry has contributed to, covering all sectors of the economy and all regions nationwide.

That figure includes spinoff s the industry

Canadians own around 30 per cent of oilsands equity.

generates up and down the supply chain, he said.

As for other benefits arising from the industry, the study cited Alberta government coffers that have swelled in recent years, thanks largely to some $7.7 billion in tax revenue and $4 billion in royalties from the oilsands sector in 2012. Still, those figures pale beside the roughly $15 billion in tax revenue the study said the federal government took in as a result of the “total effect” of oilsands development in 2012.

All told, the IHS study estimated the economic benefits generated by the industry are greater than the economy of a province like Saskatchewan, and Birn predicted that by 2025 the oilsands sector’s contribution to Canada’s economy could double.

As for industry ownership, the same IHS CERA study revealed that only about 30 per cent of oilsands equity is owned by Canadian interests. Of the remainder, a hefty 54 per cent is owned by Americans,

the single largest group of foreign investors in the industry.

Others addressing the conference session also took a broad view of the oilsands sector. Robert Mason, an investment banking executive with TD Securities, said a weaker medium-term outlook for light oil prices is mitigating interest in the sector and affecting activity levels.

While attributing recent discounts in North American oil prices to a limited export capacity due to a lack of access to tidewater, he said recent weakness is also a function of the weaker outlook for Canada’s economy.

54

per cent

of the equity in the oilsands is owned by Americans

In terms of the outlook for light versus heavy oil, heavy oil carries a more positive outlook than light, especially on the U.S. Gulf Coast. On the other hand, condensate prices on the U.S. Gulf Coast are likely to remain weak because the area is “awash in the stuff,” he said.

Mason also mentioned mergers and acquisitions (M&A) activity, which while brisk in the 2009-11 period, had essentially dried up in 2013. “Last year was one of the slowest years on record, despite the fact that there were companies willing to sell projects during the period.”

A s for foreign investors, he said, Ot tawa’s new r ules for state- ow ned enterprises (SOE) mean foreign players are still interested, but they’re mainly interested in acquiring interests of less than 50 per cent, meaning the new rules would be of limited effect for many SOEs considering the oilsands. Among SOEs, OIL & GAS INQUIRER • APRIL 2014

23

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there continues to be interest in joint ventures with Canadian companies.

While applying different metrics, TD Securities’ research was similar to IHS’s, in showing that foreign ownership has changed since 2001. “You can see that the amount of Canada’s oilsands that are now controlled by foreign companies is much higher than it used to be,” Mason said. In particular, U.S. ownership of the sector has risen to 19 per cent from roughly 10 per cent some years earlier, according to TD Securities’ research.

The outlook for new money coming into the industry was mixed. “Until we start seeing some positive impact on market access and Canadian crude oil discounts, we think financing for new companies and M&A activity will continue to be challenged,” he said.

“We haven’t seen new equity come back in yet because people are uncertain whether the turnaround is six months or four years away,” he said, adding that one factor that would set the stage for a revival would be if oilsands producers started reporting better netbacks.

A positive decision by the U.S. government on Keystone XL would also help, but in the meantime, the market would take a wait-and-see attitude, he said.

Shell halts proposed Pierre River mine Shell Canada Limited has suspended its proposed Pierre River oilsands mine while it reschedules several of its projects.

The company has changed the development timeline on the project, said Stephen Doolan, Shell spokesman.

“Pierre River mine has always been kind of a long-term growth project for Shell, and right now our near-term focus is on growth projects and other projects like Quest and Carmon Creek,” said Doolan.

No construction had been started on the project, he said.

On February 11, the company issued a letter to the chair of the joint-review panel (JRP) for the project and various stakeholders, stating it is “re-evaluating the timing of various asset developments with a focus on

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The letter, by Andrew Rosser, vicepresident of heavy oil sustainable development and regulatory, said Shell needs to adjust the development timing for the 200,000-barrel-per-day mine and that it is not prepared to proceed to a hearing on the project, so it asked that the review process be suspended.

The mine, about 90 kilometres north of Fort McMurray, was scheduled to start operating in 2018, pending approvals.

The JRP requested that the company update its project application and environmental assessment accordingly and that it provide quarterly updates as to the status of its evaluation of the timing of the mine project.

The JRP launched a comment period on additional information provided by Shell, and that period was to have ended January 17.

Shell is to provide an update on its internal evaluations by Feb. 11, 2015.

The Pierre River mine project entered the regulatory system in 2007, along with Shell’s Jackpine Mine Expansion, which received regulatory approval in late 2013.

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25

CENTRAL ALBERTA WELL ACTIVITY FEB/13

FEB/14

Wells licensed

210

27

FEB/13

FEB/14

Wells spudded

256

221

FEB/13

FEB/14

261

2

Rigs released

▲

▼

▼

Source: Daily Oil Bulletin

C.A.B. Central Alberta

Full Duvernay development will require planning, collaboration

By Pat Roche

Canadian oilfield service firms could easily support the drilling of 200 wells per year in the Duvernay, but full development will require a significant expansion of the existing equipment fleet, a service sector engineer said in late February.

According to the most recent estimates, roughly 125–200 horizontal wells are expected to be drilled into the emerging Alberta shale play this year, up from about 105 last year and 51 in 2012, said Tyler Elgar, engineering manager for the Canadian division of Calfrac Well Services Ltd. He said the 2014 projection is now lower than initial forecasts for the year, due mainly to inadequate take-away capacity in the greater Kaybob region and insufficient facilities to maximize the high yields of natural gas liquids.

“It’s our understanding that these are perceived to be short-term issues at this point,” Elgar told a Daily Oil Bulletin Speaker Series breakfast, sponsored by NCS Energy Services Inc. “But really, you must start thinking beyond the 200 wells a year. If we start talking 300, 400, 500, which many have pegged to be the number for full development of the Duvernay, we need to consider what challenges face us,” Elgar suggested.

“We’re going to be talking about large, multi-well pads—eight, 16, maybe 24-plus wells on a pad. It’s certainly going to be 24-hour operations,” he said. “The estimate we’ve seen on the hydraulic horsepower demand to facilitate this is 300,000-plus. We’ve seen some estimates encroaching on 400,000.”

To put this into perspective, Elgar said that’s roughly 20 per cent of the capacity that exists in Canada today.

“This will require significant collaboration and preplanning. I say that because, to the best of our knowledge, nobody has really committed the capital yet to build the crews to support this work,” he said. “I think we’re all in the background, trying to get an appreciation for where this play is going so we can be ready when the workload is there.

“And keep in mind, a crew of this size to do this style of work is roughly a 12- to 18-month build time.”

So what could hamper Duvernay development? The fi rst possible constraint Elgar lists is a potential shift of capital back into natural gas drilling from oildirected activity.

As the prospect of LNG looms closer, relatively dormant dry gas plays, such as the Liard and the Horn River, are likely to become busier, he said, adding that improved North American gas prices could also slow the pace of Duvernay development by competing for the same service sector resources.

While the number of horizontal and deviated wells drilled in western Canada was fairly flat in 2012 and 2013 at about 9,000 per year, “we see a sizable estimated uptick in 2014 to put us somewhere over 10,000,” he said, noting that the metres drilled has been increasing.

He added, “We’re going to be competing for resources against the Montney, the Cardium, the Deep Basin and other successful plays in this area.”

The drilling of wells with longer laterals and tighter spacing will also tie up more services that would otherwise be available for the Duvernay.

Elgar pointed out that success in the Duvernay could generate its own challenges. As drilling in the play ramps up,

demand for services in the Duvernay itself could hamper the pace of development.

Within the Duvernay, in the short term, there are infrastructure constraints such as limited take-away capacity and processing capability.

As well, the industry needs to better understand play economics. Capital costs have been declining and efficiency has been improving. “Once we better understand some of the long-term production, we will be well on our way to getting a better handle on the return on investment,” he said.

200 Potential number of wells that will be drilled in the Duvernay this year

While much of the initial Duvernay drilling was on single-well pads, full development mode would obv iously involve multi-well pads.

“On a per-pad basis, we’re talking perhaps eight wells” with 15 frac stages per well—each stage using 150 tonnes of proppant and 2,000 cubic metres of fluid, he said. That would work out to 120 fracs, 18,000 tonnes of proppant and 240,000 cubic metres of fluid for an eight-well pad.

With the ability to conduct roughly four fracs in a 24-hour period, it would take about 30 days to get through 120 fracs, pumping 600 tonnes of proppant and 8,000 cubic metres of fluid per day.

“The highlight here is, logistically, this poses a significant challenge, though one that we have the ability to overcome,” Elgar said, referring to the service sector in western Canada.

OIL & GAS INQUIRER • APRIL 2014

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Devon deal shows Canadian Natural’s improved outlook for gas prices

By Pat Roche

Signalling a change from its previously bearish outlook for natural gas prices, Canadian Natural Resources Limited has agreed to pay $3.13 billion for the bulk of Devon Energy Corporation’s western Canadian assets.

Devon said proved reserves associated with the divestiture totalled about 170 million barrels equivalent exiting 2013.

The blockbuster deal will give Canadian Natural assets producing 86,633 barrels equivalent per day in western Canada with six owned and operated gas plants and four oil batteries. Excluded from the deal were Devon’s thermal bitumen, conventional heavy oil and Horn River shale gas assets.

“This is a gas-weighted acquisition— about 70 per cent is gas,” Canadian Natural president Steve Laut acknowledged during an analyst conference call.

“And the metrics on the gas, we think, are very reasonable and fair,” he said, noting North American gas storage is down significantly this year and the forward strip pricing is positive.

“We think it’ll take quite a bit of time here to get the storage fi lled up. So 2014, and potentially into 2015, looks like pretty strong gas pricing, and that helps the metrics of this deal,” Laut acknowledged.

“But that’s not the driver of the deal,” he emphasized. “It’s the assets themselves, and our ability to integrate those assets, achieve operating costs and G&A [general and administrative] synergies, and just develop some of the light oil properties and liquids-rich natural gas that drive the acquisition.”

Canadian Natural said the 2013 estimated operating costs for the Devon assets averaged about $1.79 per thousand cubic feet equivalent.

At present, Canadian Natural expects to spend roughly $150 million on the Devon properties during the remainder of 2014.

Central Alberta

Exclusive Authorized Distributor Canadian Natural Resources Limited’s new assets production Location

Gas (mmcf/d)

Oil (bbls/d)

NGLs (bbls/d)

Wapiti

67

250

3,800

Elmworth

34

250

600

Pinto

46

500

500

Narraway

48

--

--

Ferrier

47

2,200

1,800

Northeastern British Columbia

50

1,400

1,500

Source: Canadian Natural Resources Limited

This is the second recent move by Canadian Natural that could signal increased confidence in gas.

In the first quarter of last year, Canadian Natural began looking for buyers or joint-venture partners for 380 net sections of its Graham Kobes –area Montney lands in the liquids-rich fairway of northeastern British Columbia. However, the company has since decided to hang onto that acreage.

Calfrac completes first high-rate slickwater annular coil frac operation in Cardium Calfrac Well Services Ltd. said it has successfully completed the first high-rate slickwater annular coil frac operation in the Cardium.

Using a sleeve-shift completion, 40 stages were successfully placed, with rates reaching 7.8 cubic metres per minute and sand concentrations upwards of 700 kilograms per cubic metre.

The unconventional fracturing technique was made possible by implementing new methods, unique to Calfrac, to allow for increased annular velocity rates, the company stated.

“Furthermore, this methodology serves to act as an alternative to typical ‘cluster’ fracs, as spacing between zones is readily reduced to allow for greater ability to enhance connectivity within the reservoir,” Calfrac stated.

Initial post-frac results have been extremely positive and plans are in place to complete the next wellbore with up to 65 stages.

Calfrac’s Canadian operating division president, Rob Montgomery, expressed optimism at the significant achievement late last week.

“It is always exciting to be part of a new technology that has the potential to shift the paradigm of how wells are to be completed in the future and further optimize well production,” he said. “The ability to design and implement new techniques utilizing advanced coil fracturing technologies strengthens Calfrac’s position in the industry and further showcases its technical and operational capabilities.”

Calfrac said it will explore opportunities to introduce this technology in other areas of the Cardium, in the Montney and in other deeper resource plays as an alternative to the completion techniques that are currently being used.

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— DAILY OIL BULLETIN OIL & GAS INQUIRER • APRIL 2014

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SOUTHERN ALBERTA WELL ACTIVITY FEB/13

FEB/14

Wells licensed

102

6

FEB/13

FEB/14

Wells spudded

108

6

FEB/13

FEB/14

109



Rigs released

S.A.B.

▼

▼

Southern Alberta

▼

Source: Daily Oil Bulletin

Liquids output up on Encana’s Clearwater lands

By Pat Roche

Encana is spinning off its Clearwater lands, which consist of 5.2 million net acres in southern Alberta.

Despite marginally lower spending, fourthquarter production of oil and natural gas liquids increased on the freehold lands Encana Corporation plans to transfer to a new public company. Last November, Encana announced it would create a new public company to own and operate its fee title and associated royalty interests in 5.2 million net acres with freehold oil and gas rights.

These lands—which Encana calls its Clearwater area—are scattered across a 360-by-260-mile block of southern Alberta.

The Clearwater area includes 96,893 net acres of freehold land—the bulk of the company’s freehold acreage. Encana will own a majority of the new company, but the exact percentage hasn’t been disclosed yet.

An initial public offering for the new entity is expected around mid-2014.

Photo: Joey Podlubny

Encana Corporation Canadian resource play results () Play

Natural gas (mmcf/d)

Oil and NGLs (1,000 barrels per day)

Capital ($ millions)

Cutbank Ridge

506

1.8

143

Bighorn

255

8.9

268

Peace River Arch

133

8.7

435

Clearwater

335

9.9

128

Greater Sierra

156

0.3

17

Other and emerging

47

0.8

374 Source: Encana Corporation

Oil and natural gas liquids (NGLs) output from Encana’s Clearwater acreage averaged 12,200 barrels per day in the final quarter of last year, up from 8,100 barrels per day in the fourth quarter of 2012, the company reported.

For the full year, oil and NGL output on those lands averaged 9,900 barrels per day, up from 8,600 barrels per day in 2012.

However, total spending on the whole area was off slightly at $128 million last year compared with $131 million in 2012.

That includes $23 million in the fourth quarter of last year versus $37 million in the fourth quarter of 2012.

Spending was more weighted to liquids as natural gas production from the same lands fell to 329 million cubic feet per day in the fourth quarter from 366 million cubic feet per day in the fourth quarter of 2012. Clearwater gas output for the full year 2013 averaged 335 million cubic feet per day, down from 374 million cubic feet per day in 2012.

“What happened in 2013 was we put new emphasis in the Clearwater area, particularly on the liquids potential, and the team did a nice job,” Encana president Doug Suttles said during the company’s fourth-quarter earnings conference call. “Also, we did see activity from people who were developing things on our acreage.”

Encana has been struggling for several years since it decided to become entirely gas-weighted just as the shale gas boom drove down the price of the clean-burning fuel. Spurred by relatively strong oil prices, the company has been trying to grow its liquids output. A restructuring announced last November, a few months after Suttles became chief executive officer, is intended to reverse the company’s fortunes.

A key element of Encana’s new strategy is to concentrate spending on five oil- and liquids-rich growth plays: the Montney, the Duvernay, the DJ Basin, the San Juan Basin and the Tuscaloosa Marine shale.

OIL & GAS INQUIRER • APRIL 2014

31

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DeeThree drills first multi-leg horizontal into Belly River play DeeThree Exploration Ltd. has successfully drilled and completed its fi rst multi-leg horizontal well, whose combined production is currently about 350 barrels per day of 44 degrees API reservoir oil and 950 thousand cubic feet per day of natural gas.

The 100 per cent working interest well on its Brazeau Belly River property has two legs, each with a horizontal length of 1.5 kilometres.

DeeThree said that, as a result of the significantly increased capital efficiency realized through drilling these multiple horizontal legs from a single well pad, its 2014 Brazeau Belly River drilling will focus on locations that provide for these legs.

Future bilateral wells will be drilled with the use of extendedreach, horizontal drilling technology to realize the capital efficiencies of wells with horizontal lengths in excess of 1.3 miles.

DeeThree said it will continue to operate three rigs on this property for the balance of the winter drilling season.

Based on field estimates, DeeThree met its targeted 2013 exit production rate of 10,000 barrels per day in December 2013, having reached its top rate of 10,200 barrels per day (81 per cent oil and NGLs and 19 per cent natural gas). Current output is around 9,500 barrels per day (76 per cent oil and NGLs and 24 per cent gas).

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Hemisphere Energy reports 80-barrel-per-day IP at first Atlee Buffalo well Hemisphere Energy Corporation’s first well in the Atlee Buffalo area of southeastern Alberta had an initial pumping (IP) rate over the last 10 days of roughly 80 barrels of oil per day with no associated water production.

This successful well confirms reservoir pressure, productivity and the effective use of horizontal well technology and supports additional drilling. Hemisphere’s first horizontal well in Atlee Buffalo targeted the oil-bearing sandstones of the Glauconitic Formation.

The company acquired the Atlee Buffalo property in November 2013, with a plan to increase oil recovery from existing pools with the use of horizontal wells and future pressure maintenance.

Hemisphere has 100 per cent working interest in nine contiguous sections covering two significant Glauconitic oil pools with current recovery factors of only four per cent.

A second horizontal well was anticipated to spud in March, and further drilling locations are being fi nalized for the remainder of the 2014 capital program.

— DAILY OIL BULLETIN

32

APRIL 2014 • OIL & GAS INQUIRER

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A Leader in the Business of Buzz S

oon after Brian Nelson launched Nexus Exhibits 35 years ago,

No problem for Nexus. From its original small office in Kensington,

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need for teamwork to achieve the best interests of our clients.”

The 1980s saw an explosion of innovation in trade shows and

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purchase an 8'x10' backwall that weighed just 25 pounds and could

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be transported in a single case. Set up time was reduced to a mere ten

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minutes. In no time, pop-ups were appearing as backwalls at trade

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showcase our entire offering from start to finish. We are proud of our

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space and can’t wait to share it with our visitors.”

With more than its fair share of “best in show” awards for both

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SASKATCHEWAN WELL ACTIVITY FEB/13

FEB/14

Wells licensed

338

1

FEB/13

FEB/14

Wells spudded

402

1

FEB/13

FEB/14

400



Rigs released

▲

▼

▲

Source: Daily Oil Bulletin

S.K. Saskatchewan

Alexander, Renegade to form Spartan Energy Corp. in $495-million deal Alexander Energy Ltd. and Renegade Petroleum Ltd. have agreed to combine to form a growth-oriented company they say will become one of the dominant light oil players in southeastern Saskatchewan.

The total transaction price of $495 million includes assumed net debt of $168 million and transaction costs of $13 million.

The price also assumes the completion of Renegade’s previously announced disposition of certain producing assets to an arm’s-length party for $109 million.

Spartan will be led by the existing Alexander management team and board of directors including Rick McHardy, president and chief executive officer; Michelle Wiggins, vice-president of finance and chief financial officer; Fotis Kalantzis, vicepresident of exploration; Eddie Wong, vicepresident of engineering; Albert Stark, vice-president of operations; and Tom Boreen, vice-president of geology.

The deal is anticipated to close on or around March 31, 2014. During the interim period, Alexander management will continue to conduct an intensive review of Renegade’s asset base, including planned capital expenditures, drilling inventory and targets, and operational optimization opportunities.

Underlying its commitment to build an aggressive, growth-oriented company, Alexander said that upon the closing of the arrangement, it intends to cancel the existing monthly dividend paid by Renegade.

The combined company, which will focus on southeastern and west-central Saskatchewan, will have a high-quality asset base characterized by large oil in place, low declines and a significant inventory of development drilling opportunities with attractive capital efficiencies, said Alexander.

“The transaction will establish a significant presence for Spartan in southeast Saskatchewan and will position the company for continued growth and success,” McHardy said. “This is the second highquality acquisition since the recapitalization of Alexander just two months ago, and a key strategic step in our growth towards becoming an oil-focused intermediate producer in the coming years.”

Spartan will have an inventory of 389 (316 net) horizontal drilling locations, including 228 (191 net) currently unbooked, across large oil in place assets that are typified by low risk, repeatable drilling, year-round access and extensive existing infrastructure.

Alexander brings a proven management team with a track record of value creation for shareholders, added Andrew Greenslade, interim chief executive officer of Renegade.

“We are proud of the high-quality assets that our team has put together and is contributing to the transaction,” he said. “The combined company represents an exciting opportunity for Renegade shareholders to retain their exposure to the upside inherent in these assets and participate in a larger, more liquid, light oil–focused entity with a substantial platform for growth.”

Renegade’s January 2014 average production, net of the assets to be disposed of, was 5,200 barrels per day (96.6 per cent oil and liquids).

Renegade gross proved-plus-probable reserves are 22.74 million barrels (92.2 per cent oil and liquids) of which 15.97 million barrels (91.8 per cent oil and liquids) are proved. Based on current production, the assets have a reserve life index of more than 8.4 years (proved) and 12 years (proved plus probable).

The acquired assets include a total of 145 (111 net) booked and 180 (155 net) unbooked development drilling locations in Saskatchewan. Included are all key producing infrastructure, including batteries, gas plants, pipelines and waterflood facilities.

The acquired assets have an average working interest of approximately 84 per cent, and the net production acquired is more than 96 per cent operated.

The acquisition also includes 150,571 net undeveloped acres of land (internally evaluated by a qualified professional within Alexander management at $22.6 million based on $150 per acre).

In addition, $540 million in tax pools is available.

The new Spartan Energy will have current production of 6,150 barrels per day (approximately 93 per cent liquids weighting), with a base decline rate of approximately 24 per cent.

Spartan will have an inventory of 389 (316 net) horizontal drilling locations, including 228 (191 net) currently unbooked, across large oil in place assets that are typified by low risk, repeatable drilling, year-round access and extensive existing infrastructure.

Spartan will have proved-plus-probable reserves of 27.24 million barrels equivalent, based on the independent reserve reports.

— DAILY OIL BULLETIN OIL & GAS INQUIRER • APRIL 2014

35

Saskatchewan

Tundra planning nitrogen/water EOR pilot in Bakken/Three Forks

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APRIL 2014 • OIL & GAS INQUIRER

Tundra Oil and Gas Partnership is seeking regulatory approval for an immiscible nitrogen flood in the Middle Bakken/Three Forks tight oil formations in the Daly Sinclair field of southwestern Manitoba.

Based in Winnipeg, Tundra is a privately held light oil producer that operated the drilling of 168 wells in Canada last year, with 163 in Manitoba and five in Saskatchewan.

This isn’t the company’s first foray into gasflooding in a tight oil formation. Since August 2008, Tundra has been operating a miscible gas pilot injecting CO2 in the southeastern quarter of section 04-008-28W1 within Sinclair Unit No. 1. Last August, this pilot was approved for conversion to a water-alternating-gas project.

Now the company is applying for an immiscible-gas-injection pilot using nitrogen. In miscible gasfloods, the injected gas forms a single homogeneous phase with the oil. The resulting fluid has lower viscosity, reduced interfacial tension and improved mobility.

While immiscible gas doesn’t form a single phase with the oil, it still has the benefit of improved pressure maintenance and sweep efficiency within the reservoir.

The pilot would use two horizontal injection wells. Based on expected reservoir permeability and pressure, Tundra is forecasting an average water-injection rate of 10–25 cubic metres per day. The nitrogen-injection rate is expected to be 2,000–5,000 cubic metres per day.

Tundra expects to alternate between nitrogen and water injection every three to six months to optimize the flood front and minimize gas channelling and breakthroughs.

In its application to the Manitoba government for the immisciblegas-injection pilot, Tundra is seeking approval to install nitrogeninjection equipment at two horizontal injectors in section 34-008-28W1.

“While the theoretical benefits of miscible EOR [enhanced oil recovery] are greater than for immiscible EOR, the operating costs are also greater,” Tundra says in its application, noting the current cost of CO2 renders commercial expansion uneconomic.

The company said it plans to use nitrogen because it is “readily available in the atmosphere.” Even with the initial set-up expense of the nitrogen generator, a nitrogen flood would cost less per barrel to operate than a CO2 project, the company said.

“N2 [nitrogen] has the additional benefit of not being a greenhouse gas and is environmentally safe and will not need additional facilities to recapture the produced gases,” Tundra said.

Due to the nature of its reservoir, the company believes gas can provide greater pressure support than water due to the gas’s favourable mobility ratio to oil.

Nitrogen would be generated on site because transporting liquid nitrogen is much more difficult than transporting CO2 due to nitrogen’s low boiling point, Tundra said. It would use a system that filters nitrogen from the atmosphere, then compresses and stores it.

“This is a significantly more cost-effective method of delivering gas injection [than] Tundra’s existing CO2 pilot,” the company said.

CO2 -based EOR pilots in western Canada typically use trucked CO2.

Injection water for the pilot would come from the Lodgepole Formation, which supplies the existing Sinclair units. Produced

Saskatchewan

water isn’t currently used for any water injection in the Tundraoperated Sinclair units, and the company said it has no plans to use produced water for the proposed pilot.

To do the EOR project, Tundra has applied to unitize 16 legal subdivisions in 34-008-28W1. The proposed unit—which would be called Ewart Unit No. 5—would consist of 16 tracts based on 40-acre legal subdivisions.

Tundra holds 100 per cent working interest ownership of the lands it is applying to unitize. The proposed unit would include four existing producing wells in the Middle Bakken/Three Forks reservoir.

Total net original oil in place in the proposed project area is estimated at 2.78 million barrels for an average of 174,000 barrels per 40-acre legal subdivision.

According to Tundra’s application, oil production per well in the proposed project area peaked in 2009 at 268 barrels per day.

As of last November, average oil production per well had fallen to 9.6 barrels per day. Production is forecast to continue declining at a rate of nearly 29 per cent per year.

By November 30 of last year, cumulative production from the four wells within the proposed Ewart Unit No. 5 project area was 206,500 barrels of oil and 292,800 barrels of water. The recovery factor was 7.4 per cent of the net original oil in place.

Estimated ultimate recovery of primary proved producing oil reserves in the proposed project area is estimated at 256,000 barrels with 49,500 barrels remaining as of Nov. 30, 2013.

Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place.

Based on a study by Coho Consulting Ltd., Tundra said the section was deemed to be suitable for a nitrogen flood.

Tundra estimates ultimate recovery of proved oil reserves in the project area, using a secondary water-alternating-gas EOR scheme, would be 379,000 barrels of oil with 176,000 barrels remaining.

The company estimates an additional 123,000 barrels of proved oil reserves could be recovered via its proposed unitization and secondary EOR scheme versus the existing primary production method.

Tundra estimates water-alternating-gas injection in the proposed Ewart Unit No. 5 would boost the total recovery factor to 13.5 per cent.

Under the planned EOR scheme, the existing horizontal 08-34008-28W1 producer well would be converted to an injector, and a new injection well would be drilled between existing horizontal producers.

Tundra’s water-alternating-gas-injection pilot would test two different production patterns within the same section. One pattern would test 40-acre spacing, the other 20-acre spacing.

The 40-acre spacing pattern would be achieved by converting the existing 08-34-008-28W1 producer into an injector. This injector would support the production from 00/01-34-008-28W1 and 00/09-34-008-28W1.

To create the 20-acre pattern, a new open-hole horizontal injector would be drilled between 09-34-008-28W1 and 16-34-008-34W1.

Pending regulatory approval, Tundra said the pilot could begin operating next summer.

The company plans to evaluate, over five years, whether wateralternating-gas injection will improve oil recovery where waterflooding and miscible gasflooding have been deemed uneconomic due to poor reservoir quality.

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Cover Feature

Busy as

Bees Operators expanding Saskatchewan Bakken play, reworking wells, advancing new completion technologies and piloting enhanced recovery schemes

By Darrell Stonehouse

Photos: ©iStockphoto.com/alle

A

Almost 10 years into development of the Bakken tight oil play in Saskatchewan, operators within the play continue expanding its boundaries while finetuning technologies to reduce decline rates and capture more of the light oil resource.

A large February land sale shows explorers still believe there is untapped potential in the Bakken. Over $47 million was spent in the Estevan-Weyburn area as explorers look to expand the play along the Saskatchewan-U.S. border.

“An arm of Bakken development in North Dakota has worked its way up against the international border and is mirrored on the Saskatchewan side with significant drilling activity that is making its way northward, while just 25 kilometres to the northeast of these exploration licences lies the southwest edge of the Viewfield Bakken play,” says Paul Mahnic, director of the Petroleum Tenure Branch in Saskatchewan.

“Combined with a smattering of Bakken wells in the gap between Viewfield and

North Dakota, it’s no wonder these lands attracted significant attention this sale.

“It is also encouraging that these lands were sold as exploration licences with a two-year term,” he adds. “These disposition-types are drill-to-earn, which forces accelerated development when compared to five-year leases.”

Crescent Point Energy Corp. is one of the key players in expanding the boundaries of the Bakken, as shown by its Flat Lake play straddling the Saskatchewan, North Dakota and Montana borders.

“We’re pretty excited about that play, and it will be a pretty significant production growth area for us,” Neil Smith, Crescent Point’s chief operating officer, told analysts in late 2013. “I think, putting it in context, we were zero production a couple of years ago, and we’re now at almost 5,000 barrels a day in that area. It is about a one-billon-barrel oil pool to us at this stage, multi-zone Bakken and Three Forks, so it’s very exciting for us.”

Smith said the Canadian side of the Flat Lake play is very economic to drill, making it an immediate target for development. Crescent Point had been drilling two-mile-long horizontals at Flat Lake with as many as 72 fracs per well, on both sides of the border.

All-in costs on the Canadian side have come in as low as $4.5 million per well “versus $9 [million] to $10 million in North Dakota, literally a mile away across the border,” said Smith.

But the economic story gets better.

“We’ve actually switched back to one-mile horizontals because of the royalty holiday and the depth related to that,” said Smith. “We get a bigger royalty holiday per well on the mile horizontals, and the economics are much better because of it. We have a huge advantage because of that in that area. We are very excited about that play and the development of that play and we’re building a gas plant, building our infrastructure there, and we’ll expand the capital program.”

OIL & GAS INQUIRER • APRIL 2014

39

Cover Feature

Improved completions drive productivity At its Viewfield Bakken play, Crescent Point remains focused on fine-tuning its completions technology. The company has been using cemented liners with 25 fracturing stages exclusively in the play for the last year with excellent results, said Smith.

“About three years ago, we moved from the packer system to cemented liners,” Smith explained. “Basically what it does is allow you more precision as to where you place the frac. And it allows you to go back into wells and do as many fracs as you want. So we started out with eight stages with a cemented liner, and then we went to 16-stage cemented liner, then to 20, then to 25. We adjusted the amount of sand, the amount of water used, and did the correlation between productivity and reserves and cost. And we’ve seen a tremendous uptick in that.

“Also what has occurred, which we didn’t actually really expect, was that we got higher IPs [initial production rates] and lower declines because we are opening up more rock,” he added. “And opening up more rock opens up more matrix porosity within the rock, which then allows more oil to flow and flow at lower pressure change, which then allows for the flattening of the production curves. We’ve seen that across all of the plays that we’ve implemented this in. And to give you an example, I think the math on the Bakken is something like after 12 months, instead of 50 barrels a day, it’s at 100 barrels a day.

It’s a pretty tremendous out-performance relative to the older 16-stage completion technique.”

40

APRIL 2014 • OIL & GAS INQUIRER

Smith said he believes the cemented liner system works better because it has fewer failed frac stages.

“A lot of it is simply that in the 16-stage packer system technique, you maybe got 10 –12 of the fracs that worked. So what we see is that there is a low percentage of fracs that work in that kind of methodology, and you wind up refracking the same frac in that case. And so, you don’t get the good productivity,” he explained.

The cemented liner completions technology has also cut costs, largely due to less water handling, says Crescent Point chief financial officer Greg Tisdale.

“When you complete a well, just to give you a simple example, instead of using 2,000 cubes [cubic metres] of water, we use 1,000 cubes. So there is less tank storage, less power to pump that fluid in. Then, when you flow it back, you’re disposing of less water.

All of that goes into your capital cost.”

Tisdale says the cemented liner completions save about $100,000 per well on water-handling costs.

“Our completion guides are really focused in on reducing the amount of fluid,” he adds, pointing out that often in the industry you hear about operators doubling their fluid, doubling their sand, doubling everything—and so their costs are going up. “We’re trying to look at it from the opposite direction and mitigate costs and reduce costs but get better performance.

That’s what we’ve seen. And so, we’re pretty excited about that side of it. There [are] further ways to reduce those costs. So that’s really over the last year to two years what’s happened is any of the inflationary

costs that you would have seen in capital programs, we’ve mitigated just by changing and optimizing our completion technique.”

Well optimization stems decline rates Lightstream Resources Ltd. is also focused on getting more for less out of its Bakken operations. In 2012, it launched a welloptimization program in an effort to stem decline rates on existing wells.

Lightstream has optimized more than 300 wells in the past 18 months, said Rene LaPrade, senior vice-president and chief operating officer, in late 2013. The program involves mill-outs and cleanouts of restrictions in the horizontal legs of Lightstream’s Bakken producers along with the optimization of downhole and surface equipment, including high-volume lift installations and casing gas compressor installations.

“This program was initiated in 2012 and resulted in over 2,800 barrels per day of incremental production at capital efficiencies of less than $10,000 per barrel,” LaPrade said. “Based on this success, we continued on this program in 2013 with over 2,500 barrels per day of incremental production to date. For a relatively small capital investment, we have managed to mitigate declines on over 300 of our existing wells. We plan to continue to build on this initiative in 2014.”

Lightstream expects to spend $30 million in 2014 on the optimization program in the Bakken.

EOR is the future of the Bakken The company is also advancing its natural gas–based enhanced oil recovery

Cover Feature

(EOR) project in the Bakken, which it began in 2011.

This has now progressed to project status from a pilot test with one injection well, LaPrade said.

“To date, we have been injecting dry gas into three wells in our Creelman project with a fourth injector presently being drilled and forecasted to be on injection in 2014,” he said.

The hydrocarbon-based EOR project is still at an early stage, but the company describes the results of its first injection pilot as encouraging. The second and third wells have been on injection for much shorter periods.

“We continue to refine our techniques, to improve well response and performance,” LaPrade said.

Asked whether hydrocarbon flooding could be done on a much larger scale next year, LaPrade said the company has to work through complications such as landtenure issues.

“As you know, you need continuous sections and acreage to implement those floods, or unitizations, which take even longer,” he explained.

If natural gas–based EOR is successful, it could be a low-cost way of adding reserves.

Lightstream is re-injecting its own natural gas separated from produced oil. The wells are already drilled, completed and on production, and infrastructure is in place.

In the Bakken, Lightstream hopes primary production will ultimately recover up to 15 per cent of the original oil in place.

While the proof will be in the production, the company believes recovery factors could top 25 per cent with EOR success.

Crescent Point is betting traditional waterfloods will enable increased recovery rates from the Bakken, while also slowing its decline rate. While it has technical support from the Saskatchewan government to unitize its Viewfield waterflood, it still needs to get landowner approval.

“What we have to do now that we’ve got the technical support in the Bakken pool is our people have to now start knocking on the doors of the different landowners and just soliciting their support,” said Smith.

If the waterflood is successful, the size of the prize is huge, said Smith.

“Everything that we’ve done during the last three, four years is showing that this is a pool that is going to be waterfloodable with strong economic returns,” he added. “And it’s really exciting. We haven’t seen this type of development probably as engineers in a generation.”

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big data

Feature

DRIVEN BY

Information technology is automating oil and gas processes and helping decision makers from prospecting through production

By Darrell Stonehouse

Photo: Sergey Nivens/Thinkstock

T

he information technology web continues penetrating deeper and deeper into the oil and gas industry, generating and then connecting vast stores of data together and allowing better decision making from prospecting for new opportunities through to production of resources.

Software developers are also filling niche markets in everything from safety to reserve evaluations, using data to generate expert systems that streamline work processes.

In recent years, sales of traditional field devices used to measure and control operations have skyrocketed. In Alberta alone, the measuring and controlling devices sub-sector reported revenues of $547 million in 2012, a 70 per cent increase from 2002, according to government statistics. However, all of this growth took place in 2012 as revenues surged 68 per cent between 2011 and 2012, and another year of solid growth is expected when the numbers are tallied for 2013.

That data generated by these devices, along with other data generated across the industry, is allowing the creation of numerous visualization tools enabling companies to better manage their operations. Large multinationals are now bringing all this information together, creating an integrated platform for managing field operations.

A report released in late February by IDC Energy Insights called Business Strategy: IDC Maturity Model Benchmark—Big Data and Analytics in Oil and Gas in North America finds the oil and gas industry is doing a good job in gathering and using data to better run their operations.

“The oil and gas industry is ahead of others in achieving benefits that met or exceeded their expectations from their initial forays into BDA [big data and analytics]. At the same time, many oil and gas companies do not yet have the big data and analytics maturity to address the entire range of technology, staffing, data, process

and strategic intent requirements needed to capitalize on their data assets,” says Jill Feblowitz, vice-president of IDC Energy Insights and lead analyst for the Worldwide Oil and Gas IT Strategies practice.

The study presents benchmark data on the maturity of big data and analytic capabilities of North American oil and gas companies, identifies the key capabilities that distinguish oil and gas companies whose efforts have met or exceeded their overall expectations from their competitors, whose efforts have fallen short, and offers guidance for achieving success.

The report finds two classes of oil and gas companies are emerging, “BDA haves” and “BDA have-nots,” each comprising about 16 per cent of the industry, immediately making big data and analytics a defining basis of oil and gas competitive advantage. With 68 per cent falling in the middle, the future of the oil and gas industry will swing on developing data acquisition and analytic capabilities, says the report.

An example of efforts to meet the demand for big data and analytics in the marketplace is the recently announced partnership between Accenture plc and SAP AG called Upstream Production Operations. Upstream Production Operations is designed to help oil and gas companies improve and standardize processes, replace legacy tools, provide a single view of production across the organization, minimize uncertainty and improve the management of production.

As part of the program, Accenture and SAP are providing an end-to-end solution from the wellhead to the invoice, which includes processes such as production forecasting, field data capture, production accounting and deferment management. Using SAP’s software platform as the backbone, Accenture will provide consulting, systems integration and outsourcing services.

“Our goal is to help our clients focus on improving their operations from the initial phase of production to the point of sales OIL & GAS INQUIRER • APRIL 2014

43

Feature

by optimizing energy companies’ investment in upstream assets,” says Jean-Marc Ollagnier, group chief executive of Accenture’s resources operating group.

Upstream Production Operations will run on the SAP HANA platform, providing oil and gas companies with integrated views of high volumes of complex data in real time. It is the next in a range of industry and functional solutions by Accenture and SAP running on the SAP HANA platform. Just recently, both companies have launched a marketing performance solution on SAP HANA for chief marketing officers.

While global giants are delivering enterprise solutions to manage production data, other companies are targeting niche markets. Calgary-based ACM Facility Safety, which targets plant safety, is one example.

In February, ACM released its SafeGuard Sentinel safety monitoring software to continuously measure, monitor and alert operations and management to process safety risks. The software also delivers contingency plans that can be executed immediately to address issues and reduce risk.

By presenting real-time risk information and expert knowledge to make effective operational decisions, the software helps prevent safety incidents, environmental infractions and downtime, says the company.

SafeGuard Sentinel enables plants to reduce risk and identify critical safeguards during operation, and it provides information to base strategic decisions on, including monitoring of safety performance indicators up to a board-of-directors level. It runs on a Windows-based server in a plant network and can be accessed by

44

APRIL 2014 • OIL & GAS INQUIRER

any device capable of running a browser, including DCS workstations, operator terminals, tablets and smartphones.

The SafeGuard Sentinel server connects through OPC and ODBC, allowing it to gather information from a variety of systems, including DCSes, PLCs and PACs from all major control system suppliers. Other sources of data typically include safety systems, historians, SCADA systems, maintenance systems, operator logbooks and workflow tracking systems.

Depending on the network set-up, it can be hosted in the plant DMZ, which allows access at a business level. And it only needs one-way communication from the various systems to gather data, thus preserving plant security.

SafeGuard Sentinel integrates data from these various systems to create an all-inclusive database of information including hazard and operability studies and layer of protection analysis. It uses this information to provide situational analysis and contingency plans for processing safety situations.

In real time, SafeGuard Sentinel monitors plant conditions, detects unsafe conditions and alerts operators. It also captures risk events and operator actions for immediate visualization and future analysis.

By comparing the real-time measured risk level with the designed level of risk, SafeGuard Sentinel provides quantitative, leading metrics showing changes in risk over time. Management can use it to see how process risk is changing and to benchmark safety performance across process units or entire plants. Drawing upon information from sources such as maintenance and training records, it reveals risks that would normally be undetected.

Feature

GuildOne Inc. is another example of a local company finding a niche in the marketplace, this time in creating plant schematics in response to government regulations. It recently announced the release of its FacilityStudio 2.1 data-driven measurement schematic software update.

Equipped with data integration capabilities, FacilityStudio establishes connections to both public and internal data source systems, including field, production and asset management systems, ensuring that business-specific data is captured for use in the generation of measurement schematics.

Automated workflow functionality—complete with versioning, defined user roles, automated change notifications and central storage to capture a complete audit trail—streamlines business processes, while comprehensive reports generated using measurement schematic data assist in compliance efforts and provide valuable insight into facilities.

FacilityStudio’s robust functionalities make it the ideal tool to elevate company-wide collaboration, improve operational efficiency and ensure regulatory compliance for measurement schematics, says the company.

Currently, 10 clients with more than 6,500 wells and facilities use FacilityStudio as a tool to generate, maintain, use and store measurement schematic data. The updated version of the software allows users to identify schematics containing a specific UWI, battery code or other device tag by searching for the tag in the project hierarchy using the new “Find Projects” function. Users are able to search by entering a full or partial tag, more commonly known as a “wildcard,” which pulls a

list of results containing the entered data. This facilitates greater access to information and efficiency in operations as it expedites the process of searching for schematics comprised of specific data.

To further streamline the process of generating schematics, a feature to copy and paste items from one project into another project has been added to FacilityStudio. This accelerates the schematic-generation process while maintaining the integrity of information included, making the procedure more efficient.

Commonly used device and attribute packages can be captured within FacilityStudio for personal use or use by others.

Once the package is saved to one project, another user can copy specific information and paste it into a different project. Users can store these common packages for future use, preventing them from having to duplicate efforts.

An asterisk is now added to mandatory attributes inside the Attributes panel, and if a mandatory attribute is left blank, it is coloured red until it is populated. This helps ensure regulatory compliance with the Alberta Energy Regulator’s Directive 017 and other province-specific measurement schematic regulations.

FacilityStudio 2.1 software also includes a suite of comprehensive services designed to ensure successful implementation and long-term company-wide value year after year. To optimize the schematic generation process for clients, GuildOne has measurement schematic experts available to provide services for accurate and efficient conversion of existing drawings into digital schematics.

OIL & GAS INQUIRER • APRIL 2014

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advertisers' index Risley Equipment Inc . . . . . . . . . . . . . . . . . . . . . .44

Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 25

Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 41

Annugas Compression Consulting Ltd . . . . . . . . 26

Gibson Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Bear Slashing Inc . . . . . . . . . . . . . . . . . . . . . . . . . 10

Hunting Energy Services (Canada) Ltd . . . . . . . . 34

Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 29

Maxxam Analytics . . . . . . . . . . . . . . . . . . . . . . . . 24

Brother’s Specialized Coating Systems Ltd . . . . . 6

MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 21

CENTA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

NAIT Corporate and International Training. . . . . 12

Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Netzsch Canada, Inc. . . . . . . . . . . . . . . . . . . . . . . 20

Southern Alberta Petroleum Show. . inside back cover

RIVEER. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 Rush-Overland Manufacturing . . . . . . . . . . . . . . 22 Shaw Communications . . . . . . . . inside front cover South East Electric Ltd . . . . . . . . . . . . . . . . . . . . 37

Compass Bending Ltd . . . . . . . . . . . . . . . . . . . . . 17

Nexus Exhibits Ltd. . . . . . . . . . . . . . . . . . . . . . . . 33

Tank Gauging Systems. . . . . . . . . . . . . . . . . . . . . 37

Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Northgate Industries Ltd. . . . . . . . . . . . . . . . . . . 25

Tervita . . . . . . . . . . . . . . . . . . . . outside back cover

Danatec Educational Services Ltd . . . . . . . . . . . 32

Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 17

TransGas Limited. . . . . . . . . . . . . . . . . . . . . . . . . 30

Dentec Safety Specialists Inc . . . . . . . . . . . . . . . 42

Pembina Controls Inc. . . . . . . . . . . . . . . . . . . . . . 38

Di-Corp Coremix . . . . . . . . . . . . . . . . . . . . . . . . . 42

Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Phoenix Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Dow AgroSciences Canada Inc . . . . . . . . . . . . . . 14

Pumps & Pressure Inc . . . . . . . . . . . . . . . . . . . . . 38

Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . . 4

PumpWell Solutions . . . . . . . . . . . . . . . . . . . . . .40

WashCars. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Eclipse Rentals Inc. . . . . . . . . . . . . . . . . . . . . . . . 36

RedGuard. . . . . . . . . . . . . . . . . . . . . . . . . . . .11 & 30

Zeeco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

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APRIL 2014 • OIL & GAS INQUIRER

TRTech . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 V J Pamensky Canada Inc. . . . . . . . . . . . . . . . . . . . 7 Vortex Drilling Ltd . . . . . . . . . . . . . . . . . . . . . . . . 22

OVER 200 EXHIBITORS - INDUSTRY NETWORKING - SWAG & PRIZES - FREE TO ATTEND* The Southern Alberta Energy Expo is the premier industry networking event for the petroleum and energy industries in Southern Alberta, Saskatchewan, & British Columbia. Produced by the Medicine Hat & District Chamber of Commerce, this event is designed to connect industry leaders and decision makers under one roof in an inviting networking atmosphere.

501310 Southern Alberta Petroleum Show full page · fp

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ASK US ABOUT ALSO BEING INCLUDED IN OUR GOLF TOURNAMENT & BANQUET PROGRAMS

decontamination and safe disposal of noRms allowing maximum metals recycling.

transport and decommission of six, 320,000 lb heat recovery steam generators.

Recycled over 854 metric tonnes of metal.

When it’s out With the old, in With the neW – yo u ’ l l Wa n t a s o l i d W i n g m a n .

Recovering value is what we do best. From servicing wells and recycling assets to recovering oil, we know how to make the most out of the work you do. We are Tervita, an environmental solutions company and your sustainability partner. We offer the most comprehensive range of integrated earth, water, waste and resource solutions – designed to help reduce your costs, manage your liability and protect your reputation. Minimizing impact, maximizing returns.TM It’s about helping to sustain your business. And everything around it. Visit tervita.com/resources to learn more.

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