Oil & Gas Inquirer August 2014

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THIS ISSUE

Trans Mountain leads oil pipeline race to west coast, says Wood Mackenzie

Western Canada's Exploration & Production Authority

LIQUIDGOLD Deep-cut facilities turn central Alberta gas stream into a money-maker

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PLUS: Tracking developments in the Horn River and Liard Basin shale plays

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CONTENTS

AUGUST.

in the news

Gas exports to U.S. to fall by half, oil exports to rise

regional news

British Columbia

Northeastern Alberta

Southern Alberta

Trans Mountain first, then Northern Gateway, says Wood Mackenzie

Alberta fabricators have capacity to AOSTRA 2 being crafted, but will differ build all oilsands modules, says study from AOSTRA 1, says Hancock

Northwestern Alberta

Pinecrest solving chemistry problems in Slave Point wells

Central Alberta

RMP Energy considering Kaybob development

Saskatchewan

Petrobank’s Kerrobert output improves

features

COVER

FEATURE

32 Liquid gold Deep-cut facilities turn central Alberta gas stream into a money-maker

every issue

6 38

Stats at a Glance Political Cartoon

36 Signs of life Waiting game continues in northeastern B.C. shale plays, but in the background work continues to bring gas to market

Cover design: Peter Markiw Photo: Joey Podlubny

OIL & GAS INQUIRER • AUGUST 2014

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Editor’s Note Vol. 26 No. 8 EDITORIAL EDITOR

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

Joseph Caouette, Lynda Harrison, Carter Haydu, Richard Macedo, James Mahony, Pat Roche, Elsie Ross EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE

Laura Blackwood, Matthew Stepanic CREATIVE

Fading hopes of a natural gas rebound

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Last year’s harsh winter and big drawdowns on natural gas inventories in North America stirred some long-awaited optimism for western Canada’s beleaguered gas producers. Henry Hub prices south of the border averaged $4.81 per million British thermal units in the first half of 2014, the highest level since 2008 and almost a dollar higher than the average for the last five years. At the end of the winter heating season, gas storage in the United States was half of normal levels. But a lot has changed since April, according to BENTEK Energy LLC, an oil and gas forecasting and analytics enterprise. In early July, BENTEK reported June proved to be another record-breaking month for U.S. natural gas output in the Lower 48 states, with production totalling 68.1 billion cubic feet per day. This was up 0.3 per cent from May and the highest monthly production average on record. It exceeded the previous monthly high in May by nearly 200 million cubic feet per day. On June 27, production set a one-day record high of 68.7 billion cubic feet per day, a record that BENTEK expects will be broken in July. Average June 2014 natural gas production was 3.5 billion cubic feet per day or 5.4 per cent higher than levels seen in June 2013. BENTEK data analysis suggests 2014 production will average approximately 67.5 billion cubic feet per day due to a higher overall price environment for producers and continued growth in liquids-rich basins such as the Eagle Ford, Bakken, Permian and Greater

Anadarko, in addition to continued increases in dry production in the Marcellus. The U.S. Energy Information Administration says this increased gas production is fi lling up storage at a record pace. Injections of natural gas into storage reached 100 billion cubic feet or more for eight weeks in a row. More than one trillion cubic feet of natural gas has been added to storage since mid-April, marking the quickest one-trillioncubic-foot increase in inventories since 2003. In other words, the increase in gas prices is looking like a short-term weather-induced boost in pricing rather than a longer-term rebalancing of supply and demand. And it once again underscores the fact that without liquefied natural gas (LNG) exports, the western Canadian natural gas industry will remain stalled. All future growth in gas output is dependent on LNG exports, according to Simon Mauger, director of natural gas supply and economics at Ziff Energy, a division of HSB Solomon Associates LLC. “Growth in western Canada will depend on market growth, fi rst and foremost. So no LNG exports, no growth,” Mauger says. Mauger says demand could grow by five billion cubic feet per day with LNG exports, to 19 billion cubic feet per day by 2022. But until that happens, it’s going to be more of the same for gas producers. Darrell Stonehouse

Editor dstonehouse@junewarren-nickles.com

Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2014 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 2nd Flr-816 55 Avenue N.E., Calgary, Alberta T2E 6Y4. Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N EXT I S S U E September 2014

We explore how operators are fine-tuning thermal oilsands technologies to drive value from deep bitumen and potential new technologies for the future. Plus a look at activity in the Peace River Arch in northwestern Alberta.

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

OIL & GAS INQUIRER • AUGUST 2014

FAST NUMBERS

.

billion cubic feet per day

Average U.S. gas production in 2009, according to Platts McGraw Hill Financial.

.

billion cubic feet per day

Average U.S. gas production in 2014, according to Platts.

Alberta Completions

WCSB Oil & Gas Completions

Source: Daily Oil Bulletin

M O NTH

OIL

GAS

OTHER

T O TA L

MONTH

OIL

GAS

D RY

T O TA L

Jul 013

263

33

Jul 013

671

103

0

Aug 013

394



Aug 013

817



Sep 013

357



Sep 013

735

113



Oct 013

528

153

3

Oct 013

953

204

1,

Nov 013

463

164

1

Nov 013

852

218

1,11



Dec 013

675

180





Jan 01

488

156

1

Feb 01

879

163

1,130

Dec 013 Jan 01

298

137

280

105

Feb 01

427

119



Mar 01

521

165

126

1

Mar 01

924

218

118

1,3

Apr 01

418



Apr 01

504

142

3

May 01

188

30

May 01

259

0

Jun 01

240

3

Jun 01

411

154

1

Wells Drilled in British Columbia

Saskatchewan Completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

Jul 013

379

Jul 013

358

3

Aug 013

405

Aug 013

362

3

Sep 013

422

Sep 013

347

3

Oct 013

474

Nov 013

Oct 013

380

3

532

Dec 013

Nov 013

339

3

Jan 01

Dec 013

321

30

Feb 01

150

Jan 01

181

1

Mar 01

205

Feb 01

401

0

Apr 01

261

Mar 01

349

33

May 01

302

Apr 01

10

Jun 01

364

May 01

1

Jun 01

163

10

*From year-to-date

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STATS

AT A

GLANCE

Drilling Rig Count by Province/Territory

Drilling Activity: Oil & Gas

Western Canada, July 9, 2014 Source: Rig Locator

Alberta, June 2014 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

AC T I V E (Per cent of total)

Western Canada Alberta British Columbia Manitoba Saskatchewan WC TOTAL

OIL WELLS

Alberta

GAS WELLS

Jun 1

Jun 13

Jun 1

Jun 13

247

314

1

44%

Northwestern Alberta



64%

Northeastern Alberta

1

Central Alberta

1

50%

Southern Alberta

30

33

03

%

TOTAL

0

11



1

Top Active Drillers In Canada

Drilling Activity: CBM & Bitumen

Western Canada, July 9, 2014 Source: Rig Locator

Alberta, June 2014 Source: Daily Oil Bulletin

O P E R AT O R

ACTIVE RIGS

DEV

EXP

OTHER

Crescent Point Energy Corp.

Tourmaline Oil Corp.

Progress Energy Canada Ltd.

Encana Corporation

Husky Energy Inc.

Cenovus Energy Inc.

Bonavista Energy Corporation

Peyto Exploration & Development Corp.

Canadian Natural Resources Limited

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

Alberta

BITUMEN WELLS

Jun 1

Jun 13

Jun 1

Jun 13

Northwestern Alberta

Northeastern Alberta

Central Alberta

Southern Alberta

TOTAL

11

1

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IN THE

NEWS Issues affecting Canada’s E&P industry

Gas exports to U.S. to fall by half, oil exports to rise

Photo: Joey Podlubny

By Pat Roche

The United States will need 50 per cent less Canadian natural gas by 2018, leaving western Canadian gas prices depressed until LNG exports begin, a consultant said. Some of the gas that would have gone to the United States will fuel projected increases in oilsands production, which will boost Canadian oil exports to the United States by about a million barrels per day in the same period, said Rusty Braziel, whose Houston-based consultancy is called RBN Energy, LLC. Braziel’s presentation at the 2014 Global Petroleum Show was based on data from Genscape, Inc., which sponsored his talk. The forecast rise in Canadian oil exports to the United States is based on projected growth in oilsands output and the expectation that no new pipelines to Canada’s East Coast or West Coast will be in operation before 2019. “So that means, for the most part, any increased Canadian oil production still has to come to the U.S. Those barrels are going to get there primarily via rail because there’s no Keystone XL,” Braziel said. He said a 60 per cent increase in U.S. oil production in the past three years has mostly come from the Permian, the Bakken and the Eagle Ford plays. But that increase in domestic output from those three plays was offset by an almost barrelfor-barrel decrease in U.S. oil imports via Gulf of Mexico ports. In other words, for every barrel that production increased in those three U.S. plays, imports via the Gulf dropped by one barrel. Braziel said U.S. imports from OPEC will fall by about two million barrels per day as domestic U.S. production grows and imports from Canada rise. Imports from Mexico and

West Africa decline by about a million barrels per day in the forecast period. Braziel expects most of the gas supply grow th will continue to come from the Marcellus/Utica play areas of the U.S. Northeast. He said Marcellus/Utica output has quadrupled to about 16 billion cubic feet per day from about four billion cubic feet per day, and is expected to rise to about 27 billion cubic feet per day by the end of 2018. Between 2006 and 2013, U.S. gas production rose by about two billion cubic feet per day each year and that is now expected to grow by up to 2.6 billion cubic feet per day per year “over the next few years”— even with the Henry Hub price remaining below US$5 per million British thermal units, Braziel said. This has had a profound impact on where U.S. gas flows. Historically, gas has flowed up from the Gulf Coast into the eastern United States, across from the Rockies into the eastern United States and down from Canada into the eastern United States. Already, some of the flow from Canada into the United States has been reversed with gas from the U.S. Northeast flowing into eastern Canada. “More will happen in the future,” Braziel said. In another reversal of the traditional flow direction, Braziel said gas will be shipped to Louisiana from the U.S. Northeast during the summer months. Braziel said the increasing gas supply will be used in a number of different ways. “We’re going to shut down coal plants, we’re going to replace them with natural gas–fired generation, and that’s going to be responsible for five or six billion cubic feet a day of an increase,” he predicted.

The United States expects to be exporting around 11 billion cubic feet per day of natural gas by 2019.

Secondly, “we’re going to be building more industrial plants that use natural gas, some for feedstocks. That’s going to be responsible for 2.5 billion cubic feet per day.” Braziel expects exports going to Mexico and liquefied natural gas exports from Louisiana and Texas will total a staggering 11 billion cubic feet per day by 2019 and even more after that.

OIL & GAS INQUIRER • AUGUST 2014

In The News

Cost concerns slow pace of in situ oilsands development, says CAPP By Elsie Ross

Producer concern about cost competitiveness prompted the Canadian Association of Petroleum Producers (CAPP) to reduce its previous forecast for oilsands output in 2030 by nearly eight per cent, an association official said in June. “ T hey are ver y concer ned about the potential for rising costs,” Greg Stringham, vice-president of oilsands and markets, said following the release of CAPP’s 2014 Crude Oil Forecast, Markets and Transportation study. Oilsands production is expected to grow about 2.5 times to 4.8 million barrels per day (1.6 million barrels per day from mining and 3.2 million barrels per day from in situ projects), according to the report. However, that figure is 400,000 barrels per day lower than the 2013 forecast of 5.2 million barrels per day for 2030, reflecting a slower pace of development in response to greater uncertainty about project timing. For in situ producers in particular, there’s uncertainty around future prices for natural gas, which have climbed to $4.74

per thousand cubic feet per day from $3.16 a year ago, said Stringham. For some oilsands producers, there’s also the issue of capital availability, he said. “They have their projects out on the market now, but it is a longer process than they anticipated.” While total Canadian crude oil production will nearly double to 6.4 million barrels per day by 2030 from 3.5 million barrels per day in 2013, “there are some constraints that are causing people to take on a slower pace,” said Stringham. The CAPP report also forecasts that crude moving by rail will more than triple to about 700,000 barrels per day in 2016 from 200,000 barrels per day in 2013 as tight pipeline capacity and wide light-heavy differentials spur oilsands producers to look at new ways of getting their product to market. Although pipelines are the most efficient means of connecting large supply basins to large markets areas, “in the absence of adequate capacity in western Canada, rail transport is expected to continue to rise due to the protracted

regulatory processes for new pipelines and other uncertainties,” says the report. Current rail-loading capacity originating in western Canada has increased to 300,000 barrels per day from about 180,000 barrels per day at the beginning of 2013, as a result of a number of new facilities and minor expansions that came into service last year, says CAPP. In January 2014, there were more than 17,000 Canadian rail tank car loadings of crude oil and petroleum products, says the report. Due to economic challenges, upgrading is not expected to keep pace with the growth in bitumen production, says the CAPP report. Challenges include the high capital costs incurred in building an upgrader and the need for a sustained differential between light and heavy crudes of at least $25 per barrel, it says. In 2030, upgraded bitumen production of 1.5 million barrels per day is forecast to account for about one-third of total bitumen output compared to 1.1 million barrels per day last year, which amounted to about 55 per cent of total bitumen production.

International procurement of oilsands equipment not for everyone By Lynda Harrison

It wasn’t the Kearl fiasco and its own battle with getting oilsands modules through American court injunctions that prompted Athabasca Oil Corporation to shy away from international procurement. Ultimately it was cost that convinced the company to “go local” after investigating national and international sources, Rick Koshman, vice-president of operations, said at the recent Oilsands Review Speaker Series event on the risks and rewards of international module procurement. Despite Imperial Oil Limited’s best practices—conducting logistics research and using a test module—the company still “got stung” when procuring modules for its Kearl oilsands project three years ago in an exercise in which costs ballooned, the audience heard. 10

AUGUST 2014 • OIL & GAS INQUIRER

The project’s initial 200 loads from Korea turned into about 500 modules as the oversized loads had to be taken apart and reassembled, resulting in extra costs of around $70 million. “It ended up being a political agenda and not all local,” said Koshman. “Interested parties came in to try to halt production in ‘the dirty oilsands’ in Alberta.” Athabasca Oil, whose Hangingstone thermal oilsands project is now 83 per cent complete, faced a similar situation when it moved two vessels through that same area of Idaho and Montana, he noted. The first vessel went through amid much controversy and the second was halted by a court injunction, requiring the company to chop it into smaller sizes, but eventually they reached their destination.

“I know the argument could be that they’re oversize modules and that’s why they got held up in both cases, but I don’t hear about oversize wind turbine blades and farm equipment getting halted in the same way. So I do think if we were just sending through high volumes of modules in these areas, individuals and groups of people that want to stop it because of where it’s going will just find another way to frustrate the process,” said Koshman. Initially daunted by the prospect of competing with major oilsands developers for local fabrication shops, Athabasca Oil investigated international procurement for the 12,000-barrel-per-day Hangingstone project. The company was attracted by lower labour costs in Asia, and with a Chinese jointventure partner (PetroChina International

In The News

Investment Company Limited), Athabasca Oil’s eyes were opened to a global mindset, said Koshman. It decided to build relatively small modules—12 metres by 12 metres by 80 metres—and toured top-tier fabrication shops in eastern Canada, the United States and China. There are more than 2,500 of them in Shanghai alone, he said. “They were great shops,” said Koshman. “I would not be concerned about productivity out of those shops in general. If there were concerns, you could put your own people in the shop. That’s not really the concern we had in going in that direction; it’s more in the logistical end.” But as Athabasca Oil delved further into international module procurement, cost became the top consideration. In some cases the cost of structural steel would increase by 75 per cent to $9 million, he said. It also became evident that the maximum length for international modules was 80 feet so they can’t truly be consolidated off site in Alberta because the maximum length for transport is 120 feet, Koshman added. “So if you get a situation where you’re actually driving more hours to the field, this is little bit against what we’ve been doing as an industry for some time, so we wanted to keep away from that.” Transportation gets more expensive and logistically difficult the further afield one searches for modules, he said. Also through its research, Athabasca Oil determined the cost differential on the hourly rate in some areas was high but the productivity rates were not as high as in Alberta. Koshman said the biggest impact on productivity is labour, whether in the field or in module fabrication shops, and that is the project owners’ responsibility. “We have to make sure that we do not push the work to the field or the work to the fab shop until it’s ready,” he said. “It needs the engineering to be complete and accurate, it needs the tag materials to be in place and you have to be set up to go. That’s where a lot of the hits take place. Labour does a good job when they have work fronts to go to and materials to handle and the engineering instructions to do it.” R isk was anot her considerat ion. Alberta’s permitting process has clarity and transparency and takes seven days, he said. As it turned out, building the modules in Alberta was not without issues, but it worked out well overall, he said. “It was very well executed, quality was excellent, no issues on transport to site and it was

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In The News

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AUGUST 2014 • OIL & GAS INQUIRER

essentially on time. And it did what it was supposed to do: reduce the hours on site.” Operators must collaborate w it h module fabricators and fi nd every opportunity to save costs by procuring oilsands project equipment internationally, but also consider each situation individually, a supply chain manager told the meeting. “You have to look at everything on a continuum and you can’t say what you found out yesterday is applicable to today. It’s all situational,” said Ronald Levesque, manager of supply chain, Canadian capital projects, at ConocoPhillips Canada. Some companies are considering buying smaller modules from outside Canada and consolidating them into larger modules in Alberta module yards. While some people may be skeptical of this plan’s success because of its high cost, it depends on the situation and the design, he said. “Can the design accommodate the change? What about the process equipment? What about the placement of process equipment? If I’m shipping smaller modules, is there an opportunity to put the process equipment on the module and ship it all together? All these questions come into play. It’s all situational,” he said. There are risks in dealing with offshore, said John Leder, president and chief executive officer of Edmonton-based Supreme Group LP, as he showed a slide of shipping containers toppling off a barge. Even without schedule and other risk factors, there are no savings on total installed costs for structural steel, said Leder, whose company is the largest privately owned steel fabricator in Canada. But he believes there are savings on total installed cost of pipe. “A client could save on piping about $25 million on a $100-million pipe order. It’s that significant. You need to pay attention to that. But the cost of moving the schedule three to five months would normally be far in excess of any savings if schedule is a factor,” Leder said, adding that some clients say they want to save on costs and the schedule is not important. Simon Nottingham, general manager at Fluor Canada Ltd., said the risks from accessing lower-cost modules overseas can be mitigated with a full understanding of the source of materials, ensuring engineering is complete and having a truly rigorous logistics plan to get the modules to the job site in one piece. Companies should make sure the modules are the right size and that there is the right amount of labour for them, he advised.

B.C.

BRITISH COLUMBIA WELL ACTIVITY JUN/13

JUN/14

Wells licensed

JUN/13

JUN/14

Wells spudded

JUN/13

JUN/14

Rigs released

▼

▲

British Columbia

▲

Source: Daily Oil Bulletin

Trans Mountain first, then Northern Gateway, says Wood Mackenzie By Pat Roche

In Canada’s four-way bitumen pipeline race, Trans Mountain will fi nish fi rst, Northern Gateway will finish last and either Keystone XL or Energy East won’t get built. After prefacing his remarks with the caveat that no one knows what will happen, this was how Wood Mackenzie Limited analyst Michael Wojciechowski predicted the race would finish. “Everybody needs to have a base case and this is our base case. Certainly open to debate and discussion,” the Houstonbased energy analyst told a press briefi ng in Calgary. “But there are other scenarios that may be equally as plausible.” The Britain-based global consultancy expects Kinder Morgan’s expansion of the existing Trans Mountain Pipeline across the Rockies to be in service fi rst because the route follows an existing right-of-way.

If the Trans Mountain and Keystone XL lines are built, Northern Gateway will be pushed back a decade.

However, Wojciechowski cautioned this doesn’t guarantee successful negotiations with First Nations or clear the way for construction of an export terminal on the West Coast. “Those are still challenges to be overcome. But in our view, we see that that could come to market in late 2017,” he said. After about seven years of waiting, TransCanada Corporation’s proposed Keystone XL Pipeline connecting Alberta bitumen with the U.S. Gulf Coast will get U.S. presidential approval in 2015, Wood Mackenzie believes. “In our base case, we see Keystone XL being passed in the new year, past the midterm elections,” Wojciechowski said. “And from that approval, about a two-and-a-half to three-year process to build that pipeline and get that up and operational.” If Trans Mountain and Keystone XL proceed first, that will delay Enbridge Inc.’s proposed Northern Gateway Pipeline to the West Coast until the middle of the next decade, Wojciechowski said. Northern Gateway received federal cabinet approval on June 17 with 209 conditions. Immediately after the announcement,

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2017

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2017

Enbridge Inc.

Edmonton, AB

Kitimat, BC

,000

n/a

Keystone XL

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OWNER

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Source: Peters & Co.

OIL & GAS INQUIRER • AUGUST 2014

British Columbia

Enbridge president and chief executive officer Al Monaco said that while Northern Gateway could possibly be in service by late 2018, it could be later than that, depending on a number of things that could happen over the next 12–15 months. Wood Mackenzie’s prediction that Northern Gateway will be built last is based on its assumption that Trans Mountain and Keystone XL will be built first, and that the combined capacity of those two pipelines will meet Alberta’s bitumen export needs until about 2025. “The market doesn’t need it until the middle of the next decade,” Wojciechowski said of the outlook for Northern Gateway if Trans Mountain and Keystone XL are built. Securing shipper commitments is one of the 209 conditions for Northern Gateway, he said, adding that if Trans Mountain and Keystone proceed, Enbridge will be hardpressed to find the extra barrels needed for Northern Gateway to go ahead before about 2025. Such a scenario—pipeline capacity temporarily exceeding shipper needs—

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would be a welcome reversal of fortune for Alberta’s bitumen producers after several years of inadequate capacity. “If you get two bitumen export pipelines built before the end of the decade, you’re going to outstrip supply and have more take-away capacity than there is barrels to fill that capacity. That’s when things become a little bit more interesting,” Wojciechowski said. “That’s when differentials should really recover. That’s when competition will re-enter the market.” Where does this leave TransCanada’s proposed Energy East Pipeline to central Canada and New Brunswick? Here’s how Wojciechowski believes TransCanada is thinking as it awaits a U.S. decision on Keystone XL: “If they’re not getting a yes, then they’re going to assume a no and continue to progress another alternative, in this case, Energy East. If they get a decision on Keystone XL, then they’ll know very clearly what they’re going to do here. But if they don’t get Keystone XL, they’ll put all of their resources into an Energy East option.”

High LNG prices could crimp demand By Richard Macedo

Driven by booming demand, the “golden age” of natural gas that is now firmly established in North America will expand to China over the next five years, the International Energy Agency (IEA) says in its 2014 Medium-Term Gas Market Report released in June. The projected near-doubling of Chinese gas demand through 2019 compensates for a slight slowdown in growth in many other areas of the world, the report says. The annual report, which provides detailed analysis and five-year projections of natural gas demand, supply and trade developments, sees global demand rising by 2.2 per cent per year by the end of the forecast period, compared with the 2.4 per cent rate projected in last year’s outlook. Liquefied natural gas (LNG) will meet much of this demand, with new pipelines

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AUGUST 2014 • OIL & GAS INQUIRER

British Columbia

also playing a role. In a shift away from the traditional dominance of state-owned suppliers, private-sector operators in Australia, Canada and the United States are taking the lead in the expansion of the LNG trade, which is expected to grow by 40 per cent to reach 450 billion cubic metres by 2019. Half of all new LNG exports will originate from Australia, while North America will account for around eight per cent of the global LNG trade by 2019. “We are entering the age of much more efficient natural gas markets, with additional benefits for energy security,”

“High LNG prices are threatening to crimp demand as many countries are increasingly unwilling, or unable, to afford these supplies—and that could open the door to coal.” — Maria van der Hoeven, executive director, International Energy Agency

said Maria van der Hoeven, IEA executive director, as she presented the report at the Conference of Montreal. “While demand growth is driven by the Asia Pacific region—and especially China—supply growth for the international gas trade is dominated by private investments in LNG in Australia and North America.” Despite the projected growth in gas demand and production, van der Hoeven offered a warning. “High LNG prices are threatening to crimp demand as many countries are increasingly unwilling, or unable, to afford these supplies—and that could open the door to coal,” she said. “Looking ahead, unless we see timely investment in new production and LNG facilities and the reversal of the recent cost inflation of LNG, only a very strong climate policy commitment could redirect Asia’s coal investment wave to gas.” In China, where air-quality concerns are prompting the government to adopt tough plans to reduce pollution, gas is emerging as a major part of the solution. The power, industrial and transport

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British Columbia

sectors will drive overall Chinese gas demand to 315 billion cubic metres in 2019, an increase of 90 per cent over the forecast period, the report said. While China will remain a significant importer, half of its new gas demand will be met by domestic resources, most of them unconventional. In contrast to the dynamic growth projected in Asia, the report paints a starkly different picture in Europe. Due to low power-demand growth and robust policy support for renewable energy, European gas consumption will not recover to its 2010 peak over the next five years. There will be no meaningful diversification of European gas supplies through the end of the decade, according to the report. The report said that despite abundant geological resources, the Middle East will struggle to achieve its full production potential—with some countries even experiencing gas shortages. The main reason for this is unrealistically low regulated gas prices that hinder upstream investment and encourage wasteful consumption.

AUGUST 2014 • OIL & GAS INQUIRER

Artek provides operations update Artek Exploration Ltd. experienced some mechanical issues at Inga during the fi rst quarter during the water-based multistage fracture stimulation program performed on its second horizontal Doig well of the year at A5-11-088-23W6, as previously disclosed. Following breakup, Artek was able to complete its remedial work on the operation and reports that over a 64-hour production test period the well averaged 2.7 million cubic feet per day of natural gas and 944 barrels per day of free condensate or approximately 1,400 barrels equivalent per day (67 per cent condensate) at an average flowing pressure of 446 pounds per square inch. In addition, the company drilled its first horizontal Doig well early in the second quarter of 2014 at B-93-I on the Fireweed property that Artek acquired

in 2013 as an extension to its Inga area Doig trend. Subsequent to breakup, Artek successfully executed a 22-stage energized water fracture stimulation program on the well, which after a 60-hour production test period averaged 3.4 million cubic feet per day of natural gas and 1,224 barrels per day of free condensate, or approximately 1,771 barrels equivalent per day (69 per cent condensate) at a flowing pressure of 857 pounds per square inch over the last 24 hours of the test period. The company said it is very encouraged by the results of these last two operations, in particular the high free-liquids rates from the Fireweed area well that has historically produced lower liquids yields using older technology. The company continues to optimize its completion methodology used in the area. Artek currently has one drilling rig active and a second rig was ready to begin operations in late June, all in the Inga area of British Columbia. — DAILY OIL BULLETIN

NORTHWESTERN ALBERTA WELL ACTIVITY JUN/13

JUN/14

Wells licensed

187

257

JUN/13

JUN/14

Wells spudded

153

JUN/13

JUN/14

Rigs released

▲

Source: Daily Oil Bulletin

N.W. Northwestern Alberta

Pinecrest solving chemistry problems in Slave Point wells By Carter Haydu

Photo: Joey Podlubny

Pinecrest Energy Inc. is seeing improvements on some of its Slave Point wells, after its technical team recently investigated the cause of and potential solutions for production impediments. “We had a really challenging year with a couple of curve balls thrown at us from a play standpoint,” Wade Becker, president and chief executive officer, told the company’s annual general meeting. “I think, though, that for the most part we have identified some key issues. We spent a lot of time technically working on the asset, and we are seeing some of the benefits of that as we move forward.” In the first quarter, Pinecrest’s technical team, with the help of a third-party technical expert, identified causes for reduced output from the horizontal wells, leading management to employ several different treatments with various costs and benefits, at an average treatment cost of $115,000 per well. Paraffin and asphaltene in the oil is one of the culprits, as is iron in the water,

Becker said, adding that paraffins, for example, can block the reservoir. “Part of the challenge we have with this play is…precipitates that we get out of the oil chemistry. They can be a problem and that is what we have addressed with our remediation plans at the start.” Chemistry is not the only issue, Becker said, as there is also low pressure with which the company must contend. “We are working on some new technologies that should alleviate that problem, although they are still in the experimental stage. However, we are pretty excited about what opportunities they afford. “We are talking about sometime in the next six months for when we can get a real good handle on the pump configuration and technologies changing the outlook on this play quite a bit.” Becker said the success of the technical team’s efforts is demonstrated in the slowing decline rate of the wells in question. While Pinecrest is monitoring these wells, management is also planning further work

Pinecrest has reduced drilling costs from $5 million to $3.5 million in the Slave Point play.

for the balance of the company’s vertical and horizontal wells. “We’re pretty confident we have identified what the issues are, and we have come up with a remediation plan we think will reply. When we put that in with some of the new pumping technology, I think that is going to bode well for the production performance on some of the existing wells going forward. “What we are hoping to get to is that once the waterfloods kick in based on a different fluid handling for completions, then we can get back to a point where we can pick up the drilling and get back to those 400 drilling locations on that 500-million-barrel pool.” According to Becker, Pinecrest has been on the “bleeding edge” of Slave Point technology for the last four years, working in a large play comprised of certain difficulties and requiring lots of capital, manpower and resources. “We have been pushing the boundaries to try and learn. Not all of it has been easy or a bowl of cherries, but I think we have made tremendous strides in the past six to eight months trying to identify some of the challenges outside of regular drilling completions that may be facing us, and which may have caused some of our poorer performances in some of the wells.” The key driver in the Slave Point is cost reductions, Becker said, which is why Pinecrest has undertaken significant changes over the past 18 months to reduce drilling costs. “When we first started the play, the drilling costs were north of $5 million, and our last round of drilling came in at about $3.5 million, and so it has changed dramatically as we’ve focused on the cost reduction,” he said, adding the company is currently in a mode of waterflood monitoring and adjusting. “Now, we have to focus on the production optimization that goes along with that program, and a real key driver, we think, is the secondary recovery we can generate with waterflooding.” OIL & GAS INQUIRER • AUGUST 2014

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Strategic Oil & Gas encouraged by latest Muskeg Stack wells results Strategic Oil & Gas Ltd. said its latest Muskeg Stack well has exceeded internal expectations. The well (10-24) was drilled in March with 1,438 metres of horizontal section and a 15-stage completion program. It had been tied in and producing for 52 days with initial rates well over the company’s Muskeg type curve. Initial rates for the Muskeg Stack well 10-24 are a 30-day initial production rate of 560 barrels equivalent per day, and a 52-day initial production rate of 509 barrels per day. The well produced approximately 26,500 barrels (60 per cent oil) in less than two months. Strategic has initiated its summer drilling program in the Marlowe core area, spudding the fi rst well 11-24 in June and intends to drill a total of five or six Muskeg Stack horizontal wells prior to the end of the year as part of its 2014 capital program. The Steen River plant and the sales oil pipeline are up and running. The field estimated average for April production is 3,800 barrels equivalent per day. As a result of a noncore asset disposition of 90 barrels per day as well as the 9,000 barrels of oil production at Marlowe used to fill the Bistcho sales oil pipeline, sales volumes are estimated to be 3,600 barrels per day for the second quarter of 2014. The company is seeing a significant reduction in both operating and transportation costs in its core asset at Marlowe during the second quarter of 2014. As a result, Strategic anticipates a decrease of $10–$12 per barrel equivalent in corporate transportation and operating costs compared to the first quarter of 2014. Current production, subsequent to the asset disposition, is estimated at 3,800 barrels per day. Strategic said it is encouraged by the latest Muskeg well results at Marlowe and believes the summer drilling program will further increase production volumes in the second half of the year. The company anticipates exiting 2014 with production of 4,000 barrels per day. — DAILY OIL BULLETIN

AUGUST 2014 • OIL & GAS INQUIRER

NORTHEASTERN ALBERTA WELL ACTIVITY JUN/13

JUN/14

Wells licensed

JUN/13

JUN/14

Wells spudded

108

101 ▼

JUN/13

JUN/14

101

103 ▲

Rigs released

▼

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Alberta fabricators have capacity to build all oilsands modules, says study

Photo: Joey Podlubny

By Joseph Caouette

Demand for heavy industrial modules in Alberta could peak at over 1,000 between now and 2019. It’s a sizeable figure, but the province’s modular fabrication yards should have the capacity to handle the work, according to a new study that says fabricators have the capacity for over 1,400 modules in that time frame. A total of 17 of the 18 module manufacturers serving the Alberta market responded to a survey asking about production capacity, skilled labour requirements and yard sizes. The resulting study—prepared by Ronald Ekyalimpa, a PhD student at the University of Alberta’s Hole School of Construction Engineering—offers the most comprehensive picture of the province’s modular construction industry to date. The participating companies represent 28 module yards covering 947 acres in Alberta. Because of the province’s highload corridor, Alberta modules can weigh as much as 340,000 pounds and measure 24 feet high by 24 feet wide by 120 feet long. Using that size as a baseline, the yards have space for 1,418 modules at a time. On average, the yards are 32.66 acres in size and hold 50.64 modules. The average capacity of the industry works out to 1.64 modules per acre, while the average operating age of the yards is 9.97 years. Additionally, there is a 15-module yard in Saskatchewan, as well as two yards in northern Montana that have a combined capacity of 140 modules. All three would also serve the Alberta region. The study looked at six basic module types: stair, process/equipment, pipe rack,

Alberta fabricators have the capacity to build 1,400 modules in the next ﬁve years.

electrical, building and e-house. Pipe racks were the most common, representing 25.32 per cent of capacity. Process/equipment modules followed at 20.52 per cent and building modules at 15.23 per cent. When workloads were at regular levels, there are 234 craft workers and 24 supervisors per yard. At peak times, the number of craft workers spiked by 54.27 per cent, while supervisors increased by 66.67 per cent. Depending on work volumes, the number of craft workers in Alberta module yards ranged from 6,552 to 10,105. Supervisors varied from 602 to 1,033 between typical and peak seasons. Gary Trigg, vice-president of fabrication at PCL Constructors Inc., presented the study’s findings at the Innovation in Construction Forum 2014 in Edmonton in early June. Along with Fred Haney, executive director of design engineering at Fluor Corporation, he served as an industry representative on the project. Trigg said the study was spurred by increasing international competition and the rapid rise in the number of mod yards in Alberta.

“I think lots of EPC [engineering, procurement and construction] companies do this internally, but there’s never been a public study done like this before,” he said. “We wanted to establish capacity parameters that we could use when speaking with our clients, and use that to understand and improve our competitiveness.” An earlier session at the forum seemed to offer an example of the disconnect between owner companies and module manufacturers on matters of local capacity. Mark Becker, vice-president of the Fort Hills project for Suncor Energy Inc., said that his company was drawing upon both international suppliers and local companies to build the $15-billion oilsands mining megaproject. Sub-assemblies from South Korea will be shipped to Edmonton yards to be put together, but completed modules and other materials will also come from Asian suppliers. While acknowledging the higher shipping costs that come with global sourcing, Becker said that it was the only way to access the resources needed to ensure the project is completed on time. “The most cost-effective way to do modules and do projects in the oilsands is to actually build them right here in Edmonton and then bring them to site,” he said. “The fact of the matter is we don’t have enough qualified resources. We don’t have enough skilled trades even with temporary foreign workers.” Becker also believes there isn’t enough local shop space to support all the projects, although Trigg said that’s not the case. While the report does not address if the province has the skilled labour to handle the work, Trigg said the availability of shop space should not be in doubt. If anything, the industry has too much empty shop space at the moment, according to Trigg. “Right now, it’s not as busy as it has been,” he said. “We’re running through the Edmonton area modular yards at about 30 per cent.” OIL & GAS INQUIRER • AUGUST 2014

Northeastern Alberta

Accelerated capital cost allowance could spur more upgrading, says Hancock By Pat Roche

While the Alberta government says it wants two-thirds of the bitumen produced in Alberta to be upgraded in the province, the percentage is already well below that target and is forecast to shrink even further. Last year only 52 per cent of Alberta’s bitumen production was upgraded in the province and that share is expected to fall to 36 per cent by 2023, predicts the Alberta Energ y Regulator ’s (A ER’s) recently released 2013 reserves report, ST98-2014: Alberta’s Energy Reserves 2013 and Supply/ Demand Outlook 2014-2023. The Canadian Association of Petroleum Producers (CA PP) also expects a big decline in the proportion of Alberta bitumen production that will be upgraded in the province. In its 2014 Crude Oil Forecast, Markets and Transportation study, CAPP forecast that only one-third will be upgraded in Alberta in 2030, down from 52 per cent last year. Economic deter rents to building upgraders in Alberta include high capital costs and the need for a sustained differential of at least $25 per barrel between the price of heavy and light crudes, the CAPP report said. Speaking to reporters after his speech during the SPE Heavy Oil Conference— Canada at the 2014 Global Petroleum Show in Calgary, Premier Dave Hancock was asked whether the declining percentage of bitumen being upgraded in the province was still a concern to the government.

“That’s very much a concern,” he said. “That’s why we pushed forward with our Bitumen Royalty in-Kind project and that’s why we’ve dedicated a portion of that stream to the North West upgrader project.” He was referring to the North West Redwater Partnership Sturgeon upgrader/ refinery currently under construction near Edmonton. A 50/50 joint venture of North West Upgrading Inc. and Canadian Natural Resources Limited, Phase 1 will process 50,000 barrels of bitumen per day. To increase the amount of upgrading done in Alberta, the province provided an incentive to that project. A portion of the government’s royalty bitumen, collected from oilsands producers, will provide 75 per cent of the plant’s bitumen feedstock, which the upgrader/refinery will process for a fee. Canadian Natural will provide the remaining 25 per cent of the bitumen feedstock. The province previously said it wants to see how the North West project goes before deciding whether to do any other such deals. But while CAPP says upgrading in Alberta remains economically challenged, the government hasn’t changed its position on wanting more value-added processing done in Alberta. “We have a policy that 66 per cent of the bitumen will be upgraded here at home,” Hancock said, but acknowledged “it’s getting harder and harder to achieve that.” He said Alberta’s high capital and labour costs and harsh winters are a problem,

particularly when capital has already been invested in upgrading capacity on the U.S. Gulf Coast. The problem is that in situ bitumen output is outpacing production of mined bitumen. Mined bitumen has traditionally been upgraded in Alberta, but most in situ producers don’t have upgraders in the province. In its reserves report, the AER predicts only seven per cent of Alberta’s in situ bitumen production will be upgraded in the province in 2023. This makes it even more unlikely the government will realize its goal of having 66 per cent of the bitumen produced in the province upgraded here. “So if we want that to happen, we have to look at the marketplace and say, ‘Where is the appropriate way for governments to intervene in this—if it is appropriate to intervene?’ It won’t happen unless we do that in some way—as we did with the North West upgrader,” Hancock said. “We have to look at that. And we have to talk to the federal government,” he said, adding that “probably the most important tool for achieving that is accelerated capital cost allowances. Because if you’re talking about risk assessment on a volatile investment, early return of capital is probably one of the easier stabilizers of risk. “So we have accelerated capital cost for investment in manufacturing on a temporary basis. That’s okay for the car industry because you can get an early return of capital on smaller investments. We need it longer term and...we need it on upgrading so upgraders can happen here—and, quite frankly, so liquefied natural gas terminals can happen on the B.C. coast,” the Alberta premier said.

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AUGUST 2014 • OIL & GAS INQUIRER

Northeastern Alberta

Canadian Natural pilots polymer nanosphere test at Nipisi By Pat Roche

When it comes to polymer ﬂooding, Canadian Natural Resources Limited is best known for its large successful project at Pelican Lake in northeastern Alberta. In a typical polymer-based enhanced oil recovery (EOR) scheme, thickening agents are added to water injected into a heavy oil reservoir so that it more closely matches the viscosity of oil. But at Nipisi in northern Alberta, Canadian Natural is experimenting with a different kind of polymer process—injecting tiny particles called nanospheres to increase recovery from a mature waterflood in light oil. Nanospheres are meant to block the natural flow paths for the injected water so it can be diverted to unswept parts of the pool. The pilot started in the fourth quarter of last year and will inject a slug or slugs of nanospheres over the nine months following June, followed by straight water injection, said Lyle Stevens, Canadian Natural’s executive vice-president of Canadian conventional oil. “We’ve seen some positive initial response, but it will take us one to two years before we can fully assess this technology,” Stevens told the company’s annual investor conference.

“If the test proves successful,” he said, “it may be possible to transfer this technology into North Sea applications where the reservoirs have many similar traits.” Besides mature waterfloods, another potential application could be high-salinity reservoirs, Canadian Natural says. At Nipisi, the oil is about 41 degrees API with a viscosity of four centipoise. Canadian Natural is doing an inverted seven-spot pilot test. According to a slide in Stevens’ presentation, Canadian Natural estimates the cost— including pilot facilities and chemical purchases—at $19 per barrel of additional oil recovered. The current recovery is 39 per cent of the original oil in place. If the project is successful, Canadian Natural hopes it will increase recoveries by three per cent, or about 21 million barrels. Canadian Natural’s polymer nanosphere experiment is one of five EOR pilots the company is currently operating. At Lone Rock and Epping in western Saskatchewan near the Alberta border, the company is doing three separate tests in partially depleted heavy oil pools. These are typical heavy oil reservoirs—only 10–15 per cent of the oil is recovered on primary production. In 2011 and 2012 the company began two waterflood pilots in an unconventional heavy oil application at Lone Rock and South Epping. Successful heavy oil waterfloods are rare in viscosities greater than 1,000 centipoise. Oil viscosities in the Lone Rock and South Epping pools range between 700 and 2,300 centipoise and the gravity is 15–17 degrees API. Stevens said the production response from the two waterflood pilots has been “excellent.”

“The production has increased from essentially zero in these depleted pools to approximately 600 barrels per day,” he told analysts. The two Lone Rock and South Epping pilots have 28 producer wells producing from the Sparky Formation. Stevens said the value of the pressure support was shown recently when an injection well was temporarily shut in and oil production dropped steeply. “So far, the response has met our expectations and the results are pointing to the economic viability of the waterflood and its expansion to the rest of the pools,” he said. If the pilots are successful, commercial projects would be undertaken in the next two to three years, Stevens said. Canadian Natural hopes unconventional waterflooding at Lone Rock and Epping can recover an additional 20 million barrels of oil. POLYMER PILOTS

Also at Epping, the company is testing a polymer f lood pilot with vertical wells that will allow it to compare the economic viability of waterflooding versus polymer flooding. The Southwest Epping polymer pilot began in the fourth quarter of last year and is still in the fi ll-up period. About 12 per cent of the 64 million barrels of original oil in place at South Epping has been recovered. Canadian Natural hopes to increase recovery by about 13 per cent of the original oil in place. “Success here could result in doubling the recoverable oil,” Stevens said. At Grand Forks in southern Alberta, injection will start on an alkaline surfactant polymer (ASP) pilot early in the third quarter, Stevens said.

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CENTRAL ALBERTA WELL ACTIVITY JUN/13

JUN/14

Wells licensed

153

227

JUN/13

JUN/14

Wells spudded

121

124

JUN/13

JUN/14

101

102

Rigs released

C.A.B.

▲

Central Alberta

▲

Source: Daily Oil Bulletin

RMP Energy considering Kaybob development By Carter Haydu

RMP Energy Inc. has not drilled a Kaybob Montney natural gas well in over four years, but in light of changing technologies and increased commodity prices, the company could start capitalizing on its 25 identified development locations in the area before the end of 2014. “We’re looking at the new completion techniques and seeing if we can make this economic, as well, with higher gas prices, and we’re trying to figure out if we should be doing something here,” John Ferguson, president and chief executive officer, told the company’s annual general meeting. “I think we’re going to have to make a decision on this in the next couple to three months, and probably drill a well before the end of the year.” Ferguson said at Kaybob there is already established third-party infrastructure, and so there would be quick tie-in to bring production on stream. By contrast, he said, gas infrastructure at the company’s Ante Creek operations is currently full, and RMP is taking steps to increase its capacity at that location. “We can truck the oil, but we have to conserve the gas. Right now, we are working on what we can do to expand production through the facility at Ante Creek.” According to the company ’s firstquarter financial and operational results, RMP commissioned its expanded Ante Creek bat ter y and began delivering light oil and associated gas through its Ante Creek–to-Waskahigan pipelines, enabling record-level first-quarter production averaging 9,229 barrels equivalent per day. For the second half of 2014, RMP expects production to exceed 12,000 barrels equivalent per day. D u r i ng t he qua r ter, R M P spent also $19.3 million related to Ante Creek

pipeline interconnection and batter y expansion, including about $5.8 million for the installation of an oil trunk line loop downstream of its Waskahigan battery. The company also installed $2.4 million of gathering lines beneath West Waskahigan River to facilitate future drilling and well tie-in plans at Waskahigan to the south. However, capacity is still a concern for the company. “Our biggest issue is infrastructure right now,” Ferguson said. “A lot of our infrastructure is full, but we won’t be able to accelerate some of the drilling if we won’t be able to get it on stream.” It would cost between $20 million and $25 million to double capacity at the Ante Creek facility, and the company fortunately has “lots of room to do that,” especially considering RMP’s bank line of credit is currently approximately $175 million. Management is currently deciding whether to add capacity at Ante Creek with a very large project, or if more modular steps would be the better, practical approach. Ferguson said, “We’re trying to get more run time on these wells so that we can understand and make decisions on that, so that we don’t strand a bunch of capital.” The company’s capital expenditures in the first quarter totalled $56.26 million, which included a horizontal light oil drilling and completions program encompassing four Ante Creek wells, two Waskahigan wells, as well as the completion and tie-in of one-net exploration well at Grizzly drilled in December, and jointventure participation to shoot 3-D seismic at Waskahigan for $1.6 million. This year, RMP has a total capital budget of approximately $130 million,

targeting the Montney Formation at Ante Creek, Waskahigan and Grizzly. At Ante Creek, Ferguson said, well performance has been “truly exceptional,” and the company has seven wells planned in the area for the balance of 2014. “I saw t he nu mber s, a nd we’re approaching two million barrels of oil coming out of this pool in about a year,” he said, adding it costs about $3.6 million to drill wells at Ante Creek, and payout is in about six to eight weeks. The rate of return per well exceeds 200 per cent. “Our longest-producing well has produced almost 400,000 barrels of oil in just over a year...and that one well up to the end of May has done $35 million of revenue and $21 million of cash flow.”

Penn West Cardium plans become clearer By Pat Roche

Before David Roberts took over as president and chief executive officer of Penn West Petroleum Ltd., the company planned annual spending of $50 million on its Cardium play. Roberts, who took the helm over a year ago, doubled spending in the central Alberta light oil play to $100 million. This year he doubled the Cardium budget again to more than $200 million, and he plans to increase it to between $400 million and $500 million in 2015. With a typical Cardium well costing more than $3 million and with drilling to ramp up to 200 wells per year, Penn West will eventually spend more than $600 million per year in the Cardium. To put that into perspective, the company’s overall 2014 capital budget is $900 million, unchanged from last year. Pen n West pla ns to i nc rease it s Cardium production to 60,000 barrels OIL & GAS INQUIRER • AUGUST 2014

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equivalent per day by 2018, up from 25,000 barrels per day at present. Many tight oil players are stymied by sky-high production decline rates that force them to devote a large share of their capital budgets to offsetting the previous year’s declines, leaving little to spare for growth. But Roberts says Penn West’s legacy production gives it a huge advantage. (The company reported average first-quarter output of 110,795 barrels equivalent per day.) Penn West’s overall production decline rate, like the decline rate in its Cardium play, is only 20–22 per cent, Roberts said. That’s despite first-year declines of roughly 50–70 per cent on Penn West’s multi-frac horizontal Cardium wells. “I think one of the unique things about Penn West is we’re probably the only company that has running room enough to actually drill those wells on a continuous basis and offset that decline,” Roberts said in an interview following the company’s annual general meeting. He believes the company can lower its overall Cardium decline rate even further with increased waterflooding. “We are pursuing integrated development—that is, installing pressure maintenance sooner in our programs to preserve recoveries and, importantly, leading to lower declines on a regional, and eventually, corporate level,” he told shareholders. “But we also have the well stock...to be able to off set those declines on new wells, and hence my comments that we can grow production from 25,000–60,000 barrels per day over the next four years,” Roberts said. “We’re fortunate that the original operators in the Cardium put in waterfloods back in the 1960s to support the pressure in the field,” he said. Roberts said the Cardium play will be the main driver of light oil and cash flow growth for Penn West. “We are chasing a contingent resource target of over 600 million barrels of oil equivalent, of which 500 million barrels is light oil with a drilling inventory that may reach 2,500 locations,” he told shareholders. “But I think the one thing that gives us an advantage is you cannot recreate a 600,000-acre position in the Cardium today that we own and operate,” he told the Daily Oil Bulletin. If Penn West drills 200 wells per year on its core Cardium acreage, it will still have more than 10 years of drilling locations in the play, Roberts said. “We do not need to be out acquiring a new core asset for our portfolio—it’s already in house.” He said Penn West is improving efficiencies and costs in the Cardium, including a reduction in the average time it takes to drill a well to eight days from 20 days. “We’re drilling better wells with longer lateral sections, accessing more reservoir for the same cost,” he said. “For example, we started drilling 1,200-metre laterals and have now extended those to 1,600 metres with plans to go to even longer laterals in our secondhalf 2014 program.” Penn West is also increasing the intensity of its completion programs with as many as 25 frac stages—up from 15 in the recent past—increasing the productivity of each wellbore without a proportional cost increase. “What we’re working towards in this play is to develop the capability to execute a 200-well-per-year program for approximately 15–20 well-starts per month, excluding the second quarter, which is impacted by spring breakup,” Roberts said.

Central Alberta

Two are stronger than one.

Bonavista chases liquids By James Mahony

In the first quarter of 2014 , 95 per cent of Bonavista Energy Corporation’s capital spending went to the company’s Deep Basin and west-central Alberta core areas, with roughly 21 per cent of spending allocated to infrastructure and facilities designed to support future development, management said. As well, the company closed asset divestitures of about $101.2 million in the quarter. Bonavista invested $176.64 million in exploration and development during the quarter, drilling 37 (27.6 net) wells, with a success rate of 100 per cent. Included in spending was $35.7 million directed toward facility and infrastructure improvements, the company said. Thanks to lower operating costs in the quarter, Bonavista saw its operating netbacks rise to $27.01 per barrel equivalent, representing a 39 per cent increase from first-quarter 2013 levels. In March, Bonavista bumped this year’s capital budget up 25 per cent, to between $580 million and $600 million, from an earlier estimate of about $444 million. The bulk of this year’s budget—$370 million to $380 million— will go to Bonavista’s west-central Alberta core area, where drilling will target the Glauconite, Ellerslie and Cardium plays, company president and chief executive officer Jason Skehar said. Between 95 and 100 horizontal wells are budgeted for the area. In the first quarter, Bonavista spent $87 million in west-central Alberta, drilling 25 wells. A key focus was the Glauconite play in the Hoadley area. A total of 14 horizontal wells were drilled in the play in the fi rst quarter, out of a planned 64-horizontal-well program in 2014. Nine of the 14 were brought on stream, while five are being completed. Bonavista brought one horizontal Ellerslie well on stream in the first quarter, as part of a planned 2014 horizontal drilling program of 10 wells. This year, the company will focus on the Garrington and Westerose areas, where it holds about 135 sections. In the first quarter, Bonavista drilled eight horizontal Cardium wells, five of them in the Lochend area. For the full year, the company plans 12 Cardium wells in the same area. Based on the planned capital budget, Bonavista’s second most active area this year will be the Deep Basin, where $160 million to $170 million is allocated, mainly to drilling targets in the Bluesky and Wilrich formations. Up to 30 gross wells are planned for the Deep Basin this year. During the first quarter, the company spent about $81 million on exploration and development activities, using four rigs to drill 12 wells. Bonavista holds about 280,000 net acres in the Deep Basin. During the fi rst quarter, Bonavista drilled seven wells in the Wilrich Formation. Of these, five were drilled at Ansell and two at Marlboro. At Marlboro, two wells were drilled and have tested at the company’s type-curve expectations, currently producing at a combined rate of seven million cubic feet per day. In the fi rst quarter, Bonavista participated in five horizontal Bluesky wells (three operated and two non-operated). Three of these were drilled in the Pine Creek area. All exceeded type-curve expectations, with a fi rst month average production rate of 770 barrels equivalent per day per well, the company said.

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SOUTHERN ALBERTA WELL ACTIVITY JUN/13

JUN/14

Wells licensed

JUN/13

JUN/14

Wells spudded

JUN/13

JUN/14

Rigs released

▲

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

AOSTRA 2 being crafted, but will differ from AOSTRA 1, says Hancock By Pat Roche

The Alberta government is working on an initiative to focus innovation that could see up to $250 million invested in oil and gas technology ventures, said Premier Dave Hancock. The premier made the comment in response to a question from the audience after his speech to the SPE Heavy Oil Conference—Canada, which was being held in Calgary in conjunction with the 2014 Global Petroleum Show. During the 2012 Alberta election campaign, former premier Alison Redford pledged that if her Conservative government was re-elected, it would invest in a new Alberta Oil Sands Technology and Research Authority (AOSTRA) initiative, which she dubbed AOSTRA 2. Formed about four decades ago, AOSTRA, which has since been replaced, supported pioneering research that advanced technologies such as steam assisted gravity drainage (SAGD). It was funded by the Alberta Heritage Savings Trust Fund. Today the Alberta government’s involvement with energy technology research is on a much smaller scale and is centred around a government entity called Alberta Innovates. “AOSTRA 2 was something [former] premier Redford sort of used as a name to say we need to move to the next generation of innovation and collaboration between industry and government,” Hancock elaborated later while speaking to reporters. He indicated the idea also flowed from a report prepared by the Premier’s Council for Economic Strategy, which was chaired by David Emerson, former chief executive officer of Canfor Corporation and former minister of foreign affairs. The province also appointed an expert panel, chaired by Massachusetts Institute of Technology

(MIT) engineering professor Daniel Roos, to study technology innovation in Alberta. “They made their recommendations, and we’re working very hard right now to bring that together into a coordinated ecosystem,” Hancock said. The government asked the Alberta Investment Management Corporation (AIMCo) to provide “patient capital” for technology-innovation ventures, Hancock said. AIMCo has agreed to make roughly $500 million available—about half of which, would be earmarked for oil and gas technology development, he added. “So there’s been significant progress on that side,” the premier said. AIMCo manages the investments totalling $75 billion for 27 Alberta pension, endowment and government funds. So AOSTRA 2 wouldn’t be like the original AOSTRA, which was a single dedicated organization for oilsands technology development. Hancock suggested the new effort would be more focused on coordinating a myriad of existing research efforts as well as new ones. “AOSTRA 2 essentially has morphed into...the whole renovation of our innovation ecosystem. We have done a lot of expert panel work and looking at what we need to do to go forward,” he said. “And we’re interested in innovation across the board. But it will have a huge impact on oilsands and oil and gas [in general] because that’s our major economic portfolio. So we are focusing in that area with both investment resources and in terms of bringing together the ecosystem to focus on, what are the questions we want to get solved?” Asked if the planned initiative to encourage innovation could change once the Conservative party chooses a new leader,

Hancock said, “Anything can change, of course, but I don’t anticipate it. We’re working very hard to get this embedded. We’ve been working on it for a couple of years now.” He noted the private sector is already collaborating to share information across companies through Canada’s Oil Sands Innovation Alliance. “So there’s some really good things, good direction and good impetus happening. I don’t anticipate that changing,” Hancock said.

Hemisphere Energy acquires additional land at Atlee Buffalo Hemisphere Energy Corporation has entered into an agreement to acquire certain petroleum and natural gas leases in the Atlee Buffalo area of southeastern Alberta. The property includes an 85 per cent working interest in 1.75 sections (1,120 acres) of land adjacent to Hemisphere’s existing land base. Total consideration for the acquisition is $510,000. The transaction is expected to close by mid-July and is subject to regulatory acceptance. In a separate release, First Mountain Exploration Ltd. announced it had entered into an arm’s-length transaction to sell certain petroleum and natural gas leases located in the Atlee Buffalo area of Alberta to an arm’s-length oil and gas producing company for an aggregate purchase price of $510,000. Net proceeds from the transaction will be added to the working capital of the company for business development. — DAILY OIL BULLETIN OIL & GAS INQUIRER • AUGUST 2014

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SASKATCHEWAN WELL ACTIVITY JUN/13

JUN/14

Wells licensed

313

366

JUN/13

JUN/14

Wells spudded

186

254

JUN/13

JUN/14

170

272

Rigs released

▲

Petrobank’s Kerrobert output improves

Photo: Joey Podlubny

Petrobank Energy and Resources Ltd.’s Kerrobert toe to heel air injection (THAI) production rose to 335 barrels of oil per day during the first quarter of 2014, increasing from 202 barrels of oil per day in the first quarter of 2013 and 222 barrels of oil per day in the fourth quarter of 2013. April 2014 production was 345 barrels of oil per day based on field estimates. Petrobank said it is committed to eliminating negative field-operating netbacks at the project by mid-2014, which may involve investing small amounts of capital to test new processes to increase production. It might also involve reducing costs by shutting in low-volume wells that require workovers, said the company. Petrobank is planning to test steam injection at one of its air injection wells. The company intended to suspend THAI operations if the negative netback cannot be eliminated by the end of the first half of 2014. Petrobank filed a regulatory approval application to test steam assisted gravity drainage (SAGD) operations at one of its THAI wells.

Cyclic steam operations at Cold Lake. Petrobank is using the technology at its Dawson operations.

S.K. Saskatchewan

▲

Source: Daily Oil Bulletin

Crescent Point acquires Polar Star assets

As of mid-May, the company had two conventional cold-production wells operating. The wells averaged about 50 barrels of oil per day combined in the first quarter of 2014 and were producing around 75 barrels of oil per day combined in June. At Dawson, the company began cyclic steam stimulation (CSS) operations at one of the two horizontal THAI production wells in late December 2013 and initiated steaming operations at the second well in mid-February 2014. Initial production was expected in the second quarter of 2014, with each well expected to produce for approximately nine months before starting a second steam and production cycle. If these two CSS wells are successful, Petrobank intends to prepare and submit an application for full-field CSS development at Dawson. Activity for the remainder of 2014 will focus on increasing heavy oil production on conventional wells at Luseland and increasing production at the Kerrobert THAI project, while minimizing costs. During the first quarter of 2014, the company recognized a non-cash accounting impairment of $900,000 related to its Kerrobert THAI project, reflecting assessed fair value less costs of disposal at March 31, 2014. Petrobank reported expenditures on exploration assets of $5.81 million in the first quarter of 2014 compared to $8.42 million in the first quarter of 2013. The decrease was primarily related to a decline in capitalized pre-commercial operating costs at its Kerrobert project and reduction in expenditures on land, seismic and exploration, partially offset by an increase in expenditures at its Dawson project for CSS operations. — DAILY OIL BULLETIN

Crescent Point Energy Corp. has completed an acquisition of Saskatchewan Viking oil assets from Polar Star Canadian Oil and Gas, Inc., a private western Canadian oil and gas producer. The Viking assets include all of Polar Star’s assets in the Viking play at Dodsland, Sask. The acquired assets consolidate Crescent Point’s existing Viking land position in the Dodsland area and include more than 2,800 barrels equivalent per day of high-quality, high-netback production. Total consideration for the Viking assets was comprised of approximately 7.6 million Crescent Point shares and $2 million in cash, or approximately $334 million, based on the five-day-weighted average price of Crescent Point shares prior to the execution of the Viking acquisition purchase and sale agreement in mid-May of $43.88 per Crescent Point share. Crescent Point is also boosting its 2014 guidance for production and funds flow from operations. The company’s average daily production in 2014 is expected to increase to 135,500 barrels equivalent per day from 134,000 barrels per day. And its 2014 exit production rate is expected to increase to 148,000 barrels per day from 145,000 barrels per day. The company’s capital expenditures budget for the year has also increased by $25 million to $1.8 billion. Of the increase, Crescent Point expects to spend $15 million on drilling and completions and $10 million on land and facilities across the company’s asset base. The Viking acquisition consolidates Crescent Point’s existing Viking land position at Dodsland and increases its land position by 38 per cent to approximately 145 net sections. The Viking assets include 258 net internally identified drilling OIL & GAS INQUIRER • AUGUST 2014

Saskatchewan

locations, which increase Crescent Point’s low-risk, high-rate-ofreturn drilling inventory in the Viking play at Dodsland by 70 per cent. “The Saskatchewan Viking play has very high netbacks of more than $85 per barrel,” said Scott Saxberg, president and chief executive officer of Crescent Point. “We expect these assets to provide free cash flow that will help us reduce our 2015 all-in payout ratio by another two per cent.” — DAILY OIL BULLETIN

Saskatchewan well authorizations up

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Operators licensed 1,116 new wells last month, with operators in Saskatchewan hitting a nine-year high for well authorizations during the month of May. The 1,116 permits represent an increase of 5.4 per cent from 1,059 wells granted authorization in May 2013. Saskatchewan licensed 456 wells during the month, up from 261 last year and the highest level for the month of May since 2005, when 544 wells were permitted. To the end of May, Saskatchewan’s licence count is up 29.6 per cent from a year ago to 1,986 from 1,532 in the comparable five-month period in 2013. This year’s five-month tally is the third highest on record (behind 2011 and 2012). British Columbia assigned 59 new licences during May, while 115 were approved (input) during the month. Over the first five months of 2014, British Columbia has assigned 446 new licences (an increase of 21.5 per cent from 367 in the January-to-May period of 2013). Manitoba granted 62 well authorizations in May, up from last year’s 18. The licence count is up 24.1 per cent in the January-toMay period of 2014 to 201 compared to 162 a year ago. In Alberta, 537 licences were issued last month compared to 695 in the year-prior period, while the province has granted 3,796 well permits in the fi rst five months of the year (off 10.3 per cent from 4,232 to the end of May 2013). A total of 6,434 permits have been issued to the end of May 2014 compared to 6,313 in the first five months of 2013. There were 242 gas wells authorized across western Canada last month, up from 173 a year ago. For the fi ve-month period, 1,169 gas wells have been permitted compared to 882 gas wells last year (up 32.5 per cent). Operators in the four western provinces licensed 804 oil and bitumen wells last month (795 in 2013), with the five-month tally at 4,036 permits compared to 3,978 in the January-to-May period of 2013. To the end of May this year, operators have licensed 4,193 horizontal wells versus 3,733 in the comparable period of 2013 (an increase of 12.3 per cent). In May, 73 oilsands evaluation permits were licensed, up from 37 a year ago. Over the fi rst fi ve months of 2014, 843 oilsands evaluation wells have been permitted, off 11.7 per cent from 955 licences to the end of May last year. The top five licensees of new wells in May, excluding experimental and oilsands evaluation holes, were Canadian Natural Resources Limited (88), Husky Energy Inc. (70), Teine Energy Ltd. (56), Raging River Exploration Inc. (51) and Crescent Point Energy Corp. (42). — DAILY OIL BULLETIN

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LIQUID GOLD Deep-cut facilities turn central Alberta gas stream into a money-maker By Darrell Stonehouse

AUGUST 2014 • OIL & GAS INQUIRER

Photo: Joey Podlubny

eyera Corp. has been waiting for a natural gas liquids (NGLs) rush in western Alberta for much of the last decade. The wait is now over, David Smith, Keyera’s president and chief operating officer, told analysts during the company’s fi rst-quarter conference call. “It’s happening. We’ve been talking about it for a long time, and it’s here,” he said. “I would say our business development people, our engineers, have half a dozen different planning sessions going on around particular plants trying to get more throughput so it seems like drilling for these types of resources is going to continue.” Smith said Keyera is now seeing a number of bottlenecks in its spiderweb of gathering and processing plants covering central Alberta starting to creep in. The current hot spot is the Simonette area of the Deep Basin. “We see a lot of demand coming at us from liquids-rich drilling from the Montney in the Wapiti area,” Smith said. “Our pipeline, effectively, contractually, is full before it’s in the ground. Clearly there are opportunities for other pipelines out into that same area if you follow drilling there. So the Montney, the Duvernay you see evolving, becoming commercialized east of the Simonette plant.” Capacity is expected to be tight at its Rimbey plant despite recent pipeline expansions and Keyera sees potential for expansion there, which will be relatively inexpensive compared to new builds, said Smith. He said the Strachan, Nordegg, Brazeau and West Pembina region is also experiencing more throughput and even smaller plants have Cardium drilling that is starting to create pressure. But the corridor between Edmonton and Fort Saskatchewan, Alta., is Keyera’s next bottleneck to address, now that the midstreamer has signed a long-term agreement to provide Cenovus Energy Inc. with diluent handling, so it is considering augmenting its pipeline there, potentially converting it to a different service. With over $1.5 billion of projects under development, Keyera continues to develop and expand its network of interconnected plants, pipelines, facilities and services that allow its customers to access the company’s entire value chain, he said. The company expects to spend between $600 million and $700 million this year—up from an earlier estimate of between $500 million

Cover Feature Alberta Ethane Supply/Demand Forecast Supply Supply from from Conventional Oilsands Gas Off-gas

Import from Vantage Pipeline

Alberta Pentanes-Plus Supply/Demand Forecast Supply Supply from Alberta from Conventional Demand Oilsands Gas Off-gas

(103 m3/d)

Year

Import from Vantage Pipeline

Alberta Demand

(103 bbls/d)

Supply

Year

Alberta Demand

(103 m3/d)

Supply

Alberta Demand

(103 bbls/d)

2012

34.0

0.1

0.0

215.5

0.4

0.0

2012

19.1

53.2

120.2

2013

35.9

0.8

0.0

36.7

227.3

5.1

0.0

232.3

2013

20.8

66.0

130.9

415.3

2014

35.5

1.2

1.4

38.1

224.8

7.7

8.9

241.4

2014

21.2

78.9

133.1

496.2

334.9

2015

34.9

1.7

2.8

39.3

220.7

10.6

17.4

248.6

2015

20.9

88.9

131.8

559.6

2016

34.0

2.0

3.7

39.7

215.5

12.5

23.2

251.1

2016

20.7

98.4

130.4

618.9

2017

33.3

2.1

4.7

40.1

210.7

13.2

29.7

253.6

2017

20.5

111.2

128.8

699.6

2018

32.7

2.2

5.7

40.5

206.7

13.7

35.8

256.2

2018

20.3

124.8

127.9

785.4

2019

32.1

2.2

6.6

40.9

203.1

13.9

41.6

258.7

2019

20.2

140.5

127.4

884.0

2020

31.8

2.5

7.1

41.3

201.0

15.6

44.8

261.3

2020

20.3

154.8

127.8

974.3

2021

31.8

2.6

7.5

41.8

201.1

16.3

47.2

264.7

2021

20.3

165.3

127.9

1,040.2

2022

31.8

2.7

7.7

42.2

201.6

17.2

48.7

267.4

2022

20.6

174.3

129.9

1,096.9

2023

32.1

2.7

7.9

42.7

203.3

17.2

50.2

270.5

2023

21.0

181.6

132.3

1,142.9

Sources: Alberta Energy Regulator

and $600 million—on projects already sanctioned and underway, he added. The company probably has more prospects ahead of itself than at any time in its 16-year history, Jim Bertram, chief executive officer, told the company’s annual general meeting. Drilling activity around many of its plants continues to be strong and the utilization of several of its gas plants continues to increase. Net throughput increased in the first quarter, averaging 1.1 billion cubic feet per day—14 per cent higher than the first quarter of last year, coming from geological horizons such as the Mannville, Cardium, Montney, Duvernay and Glauconite zones. In January, the company announced it will add 35,000 barrels per day of C3+ fractionation capacity at its facility in Fort Saskatchewan. This is in addition to the 30,000-barrel-per-day de-ethanizer currently under construction and the existing 30,000-barrel-per-day fractionator at that site. “The fractionator and de-ethanizer projects are in response to the growing demand for these types of services and support our customers’ liquids-rich drilling programs,” said Keyera. “Based on the current schedule, we estimate that the deethanizer facility will be operational later in 2014, while the fractionation expansion is expected to be on stream in the first quarter of 2016.” Producers, themselves, are also heavily investing in midstream assets. Tourmaline Oil Corp. has been building

facilities across the Deep Basin. With its six gas plants and 12-inch-plus lateral pipelines, Tourmaline has essentially built the infrastructure needed to serve its entire 1.2 million acres of land in the Deep Basin with the ability to expand facilities as required, company president and chief executive officer Michael Rose reported in his first-quarter address to analysts. Coming into 2014, Tourmaline had processing capacity of about 400 million cubic feet per day. It has a planned plant expansion of 55 million cubic feet per day at Musreau, Alta., and has already participated in a plant expansion at West Edson in addition to a planned Wild River expansion. Facility start-ups at Spirit River and Musreau and Doe, B.C., will yield approximately 25,000 barrels equivalent per day of new production in the fourth quarter of 2014. Paramount Resources Ltd. also announced in May commissioning of the company’s wholly owned 200-millioncubic-feet-per-day Musreau deep-cut facility is complete. The facility has been handed over to Paramount’s operations team and final start-up activities are underway to begin delivering sales volumes. This deep-cut processing plant allows Paramount to ramp up production from its behind-pipe wells in the Musreau area. The company expects to more than double its sales volumes to reach approximately 50,000 barrels equivalent per day later in 2014 and more than triple its sales volumes to approximately 70,000 barrels

equivalent per day in 2015 as third-party downstream NGL facilities expansions are completed and new wells are brought on stream. Over the same period, Paramount’s production mix is anticipated to increase from approximately 15 per cent liquids and 85 per cent natural gas to approximately 45 per cent liquids and 55 per cent natural gas. The company is expanding the development of its liquids-rich Montney lands in the Kaybob area. To provide incremental natural gas processing capacity, Paramount has sanctioned the construction of two new wholly owned 100-millioncubic-feet-per-day refrigeration plants. The first new plant is scheduled to be on stream in the second half of 2016 to align with the anticipated completion of expansions to third-party transportation and fractionation facilities in which Paramount has secured long-term firm capacity. The second new plant is scheduled to be on stream approximately six months later. Paramount’s total sales volumes are projected to surpass 100,000 barrels equivalent per day by the end of 2016 and 125,000 barrels per day in 2017 once the second new plant is on stream. The new facilities will use a refrigeration process to extract propane, butane and heavier hydrocarbons, with ethane remaining in the gas stream and being sold as higher-heat-content natural gas. The plants are expected to cost approximately $180 million each, and will include an oversized condensate OIL & GAS INQUIRER • AUGUST 2014

Cover Feature

Alberta Propane Supply/Demand Forecast Supply

Year

Alberta Demand

(103 m3/d)

Supply

Alberta Demand

(103 bbls/d)

2012

22.6

3.5

142.3

22.0

2013

23.4

4.2

147.4

26.5

2014

22.8

4.8

143.9

30.0

2015

22.4

5.0

141.3

31.3

2016

22.2

5.2

139.9

32.6

2017

21.9

5.4

138.2

33.8

2018

21.8

5.5

137.2

34.8

2019

21.8

5.7

137.2

35.7

2020

21.9

5.8

138.2

36.5

2021

22.2

5.9

139.7

37.4

2022

22.5

6.1

141.4

38.2

2023

22.8

6.2

143.6

39.0

Source: Alberta Energy Regulator

stabilization system, on-site natural gas power generation and an amine-processing train. Each of the new plants is being designed to allow for future expansions to double capacity to 200 million cubic feet per day. Demand driving expansion in LNG processing The bump in demand for NGLs is being driven by a lack of natural gas drilling in recent years due to low prices, increasing diluent needs in the oilsands, and a number of export projects now underway. Ethane production has taken the biggest hit due to the lack of gas drilling. In the second quarter of 2014, ethane imports from the Bakken play in North Dakota began moving northward to meet feedstock demands from Alberta ethylene producers, the Alberta Energy Regulator (AER) reports. The government expects this trend to continue until at least 2020, according to its ST98-2014: Alberta’s Energy Reserves 2013 and Supply/Demand Outlook 2014-2023 report. The regulator forecasts that ethane imports will rise to 7,900 cubic metres over the forecast period as the demand for ethane gradually increases to 42,700 cubic metres per day from 36,700 cubic metres per day in 2013. The Vantage Pipeline recently began to bring ethane from existing natural gas facilities in North Dakota to the Alberta Ethane Gathering System in Alberta. The pipeline has an initial rate of 40,000 barrels per day of ethane, expandable to 60,000 barrels per day. 34

AUGUST 2014 • OIL & GAS INQUIRER

The forecast assumes that the existing ethylene plants will increase their throughput capacity over the forecast period although no new ethylene plants have been announced. The AER says it expects Alberta ethane supply to stay relatively high over the next two years despite a reduction in total marketable gas production as producers are focusing on the wetter gas stream with higher ethane content and midstream companies have announced a number of projects to maximize liquids recovery. Ethane production from conventional gas is forecast to decline slightly to 35,000 cubic metres per day in 2014 and to continue to decline to 2020 before recovering slightly for the rest of the forecast period as liquids-rich gas production from the Foothills front and northwestern Alberta starts to increase. In terms of supply, the current plantprocessing capacity for ethane is about 70,000 cubic metres per day and is not a constraint to recovering the additional volumes forecast, says the AER. There are about 495 active gasprocessing plants that recover NGL mix or specification products, 10 fractionation plants that fractionate NGL mix streams into specification products and nine straddle plants. In 2013, ethane volumes extracted at Alberta processing facilities increased 5.5 per cent to 35,900 cubic metres from 34,000 cubic metres per day in 2012 due to volumes extracted by field plants and recovered at fractionation plants as a result of new deep-cut projects and increased ethane content in the gas stream. About 75 per cent of total ethane in the gas stream was extracted in 2013, while the remainder was left in the gas stream and sold for its heating value. As a result of wetter raw gas production and NGL infrastructure development in late 2012 and 2013, propane, butane and pentanes-plus production also increased over 2012 levels. Production of butanes and pentanes-plus extracted at field plants and fractionators increased in 2013 while volumes from straddle plants were down. Propane production increased by 3.6 per cent in 2013 to 23,400 cubic metres per day from 22,600 cubic metres per day in 2012. The AER attributed growth in propane production in 2012 and 2013 to increased extraction volumes from field plants and fractionation plants.

The AER expects propane production to decrease to 22,840 cubic metres per day this year and to continue to decline until 2020 due to lower gas production before beginning to recover over the rest of the forecast period. Moderate growth in domestic propane demand is forecast over the next decade as a feedstock for propylene and ethylene plants and from the construction of the Williams Companies, Inc. propane dehydrogenation facility at Redwater, Alta. In addition, Keyera recently announced plans to construct a rail terminal at Josephburg near Fort Saskatchewan, which will transport propane out of western Canada. Demand for NGL mix streams in the form of C2+ mix and C3+ mix exists in Alberta as solvent for injection into enhanced oil recovery (EOR) schemes for conventional oil fields. Most of the NGL mix solvent is extracted at deep-cut facilities adjacent to the injection facilities. Pentanes-plus production rose by nine per cent in 2013 to 20,800 cubic metres per day compared with 19,100 cubic metres per day in 2012. Production is expected to increase again this year to 21,200 cubic metres before declining in 2015. The AER is forecasting relatively flat production until 2020, increasing slightly to 21,000 cubic metres per day in 2023 with the growth in liquids-rich production. Demand for pentanes-plus is expected to remain strong due to continued high diluent requirements with increased bitumen production. As a result, pentanes-plus demand as a diluent is forecast to increase to 181,600 cubic metres in 2023 from 66,000 cubic metres in 2013, with much of the increased demand met by imported condensate. There has been a decrease in pentanesplus production since 2007, which has resulted in the assessment and use of alternative sources (imports) and types of diluent. Currently, Alberta imports pentanes-plus on trucks and railcars and in pipelines, including in Enbridge Inc.’s Southern Lights Pipeline, which transports diluent from Chicago to Edmonton and has a capacity to deliver 180,000 barrels per day. Production of butanes, which are used as refinery feedstock, in gasoline blends as an octane enhancer and as a diluent for bitumen, rose by 5.4 per cent to 12,600 cubic metres per day in 2013 from 12,000 cubic metres per day in 2012. Output

Cover Feature

though is expected to decline this year and to continue to decline through 2023. Alberta demand in the period is expected to increase to 7,900 cubic metres per day from 7,600 cubic metres per day in 2014. With supply outpacing demand, another potential source for growth is in the oilsands where butanes are injected as a solvent to enhance steam assisted gravity drainage (SAGD) bitumen recovery. With U.S. markets for gas shrinking and LNG exports in the distant future, gas producers can thank oilsands producers for providing a growing domestic market for natural gas production and for growing demand for condensate as pipeline diluent making wet gas production highly profitable. Oilsands natural gas demand has been climbing a steep cliff since the year 2000 when only 650 million cubic feet per day were used by the industry, according to AER figures. By 2013, the oilsands were burning 2.62 billion cubic feet per day, a fourfold increase. AER predicts by 2020 around 4.25 billion cubic feet per day will be needed. Demand for condensate by oilsands operators is growing at an even faster rate. Producers who don’t have upgraders use condensate to dilute their bitumen and heavy oil so it can move through pipelines. Transportation of non-upgraded bitumen from the oilsands continues to rise dramatically, driving up condensate consumption. In total, Peters & Co. estimates condensate demand from all oilsands producers and conventional heavy oil operators will exceed 350,000 barrels per day this year. The investment firm says the build-out of pipeline and other infrastructure in northern Alberta will accommodate consumption of more than a million barrels per day of condensate in the oilsands. While demand for condensate skyrockets, in recent years production in western Canada has been declining, but the trend has reversed as prices climbed with rising demand for bitumen transportation. Peters & Co. had previously predicted condensate production in western Canada, which has reached 150,000 barrels per day, would grow to 200,000 barrels per day by 2020. But given the stronger recent production results from several liquids-rich plays, Peters & Co. has now also included a more optimistic high-end production estimate of about 300,000 barrels per day by 2020. This high-end scenario assumes more production from the Montney and Duvernay formations.

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Signs of life Waiting game continues in northeastern B.C. shale plays, but in the background work continues to bring gas to market

rilling activity in the Horn River and Liard Basin shale plays in northeastern British Columbia is almost at a standstill, but that doesn’t mean that there isn’t work being done behind the scenes to prove up reserves and prepare for future liquefied natural gas (LNG) exports. And while LNG exports from the region may be at least five years away, the ramp-up once the facilities get off the ground should provide plenty of work for service companies operating in the region. Apache Canada Ltd. and Chevron Canada Ltd., 50/50 partners in the Kitimat LNG export facility and in the Kitimat Upstream partnership, continue working to move their project forward, Apache reported in May. During the first quarter of 2014, Kitimat Upstream production in the Horn River and Liard basins averaged 58 million cubic 36

AUGUST 2014 • OIL & GAS INQUIRER

feet per day net to Apache’s interest, down eight per cent from the fourth quarter of 2013 due mainly to a planned shut-in for pad drilling (D-28-B horizontal) and well testing in both basins, plus natural declines. Six rigs were drilling at the end of the first quarter, including three on vertical tenure wells; one on the 28-B horizontal tenure/production well, which is scheduled to be on production in the fourth quarter; one on the three-well horizontal 13-K south pad, expected to rig release in early 2015; and one on the seven-well horizontal 3-K north pad, which has an expected rig release date of fourth-quarter 2015. No wells were drilled for production during the quarter. Operations started on the 2013-14 winter 3-D seismic programs in the first quarter, with a 515-square-mile acquisition completed early in the second quarter of 2014. In 2012, Apache announced after a series of exploratory wells that it had 210

trillion cubic feet of resource on its Liard Basin lands, with expected recovery of 48 trillion cubic feet of dry sales gas. At the time, the company said it expects to drill 731 wells on 61 pads using two rigs per pad to develop the play. Apache said the D-34-K well, one of three wells it drilled in the play in 2012, could be the highest flowing shale gas well ever tested. The D-34-K well flowed 21.3 million cubic feet per day on a 30-day initial production test from a 2,900-foot lateral with six frac stages. It produced 3.1 billion cubic feet of gas in the first year, and Apache expects the well to ultimately produce almost 18 billion cubic feet of gas. Nexen Energy ULC also continues working to prove up its reserves in northeastern B.C. shale plays it plans to use to feed the proposed Aurora LNG facility. Nexen and partner INPEX Gas British Columbia Ltd. (IGBC) currently hold

Photo: Nexen Energy ULC

By Darrell Stonehouse

Feature

approximately 300,000 acres of shale gas resource in the Liard, Horn River and Cordova plays. In the latter part of 2013, the joint venture completed drilling the first of two high-pressure, high-temperature lease earning wells in Liard and spudded the second well that was expected to be completed in the first quarter of 2014. Further lease earning and appraisal work was planned for the Liard and Cordova basins in 2014. “Despite low gas prices, Nexen and IGBC are continuing to invest more capital than other asset holders in the region as they strive to optimize the design and development program to create long-term value and position themselves for future opportunities including the LNG market,” the companies stated in a filing for the Aurora facility to the National Energy Board late last year.

Service companies prepare for LNG development With a number of large operators sizing up their resource base for LNG exports, service companies are also beginning to gear up for development. Trinidad Drilling Ltd. announced last summer it had contracted to build one of Canada’s largest and most technically advanced land rigs. The rig is being constructed to drill natural gas in the Liard Basin, an area that is being developed to supply gas for the future LNG plants proposed for the West Coast of British Columbia, the company said. The rig is being constructed at Trinidad’s in-house manufacturing facility in Nisku, Alta., and will be equipped with the latest advancements in highperformance drilling technology, including an automated rig moving system. The rig will be a 1.25-million-pound hook load, 3,000-horsepower AC rig with a depth capacity of 8,000 metres (26,250 feet). The rig will be operating under a fiveyear, take-or-pay contract with a minimum of 350 days per year and is expected to be delivered in to operations in the second half of 2014. AKITA Drilling Ltd. also announced in 2013 that it had entered into a multiyear contract to construct and operate a new ultra-deep pad rig for use in the Liard Basin to help supply natural gas for anticipated upcoming LNG projects. This ultra-deep pad rig is on schedule and on budget, the company reported in March, and was anticipated to be completed by mid-2014. Work camp operator Black Diamond Group Limited is also gearing up for an upswing in drilling in the northeast. This spring, it announced the Black Diamond Dene Limited Partnership had acquired an operating camp lease and certain related infrastructure of a remote workforce housing lodge in the Horn River area of northeastern British Columbia. Located at kilometre 90 on Komie Road, three hours north of Fort Nelson, B.C., the facility has been operated by a leading North American energy producer and managed by Black Diamond since 2008. Black Diamond will operate the facility as an open camp. Three anchor tenants, which are active in exploration and production in the region, have been secured for the 425-room lodge with incremental contracted revenue expected to exceed $17 million through 2015.

“This is a unique opportunity for Black Diamond to service customers active in the Horn River Basin and satisfy the future housing demand we anticipate from increased B.C. natural gas exploration and production stemming from LNG export projects,” said Trevor Haynes, president and chief executive officer for Black Diamond. Trican Well Service Ltd. is also reporting an uptick in activity in northeastern shale plays. “Utilization of our Canadian equipment is expected to benefit from a Horn River project during the third quarter of 2014, which will be similar to the project completed during the third quarter of 2013,” the company reported this spring. “We also expect to complete a small project in the Liard Basin during the third quarter of 2014. This will be the first fracturing project completed by Trican in the Liard Basin and reflects potential customer interest in this region in light of Canadian LNG export opportunities.” When activity takes off in the northeastern shale plays, service companies can expect a major boost, according to a recent Petroleum Services Association of Canada study completed by David Yager, national leader of oilfield services at MNP LLP, an accounting and consulting firm. The study looked at the number of workers required to drill and complete wells in different types of unconventional resource plays. The first type of well used for the study was assumed to be in the Montney, Duvernay or Horn River play, and in northeastern British Columbia or northwestern Alberta. It was drilled to a measured depth of 6,000 metres, had an 18-stage frac, involved 46 suppliers and 302 workers, and required 2,871 worker days. Yager said the Horn River frac was assumed to consume 120,000 cubic metres of water (more than 750,000 barrels), hence employment related to water handling was significant. In the case of these shale-type wells, completion-related services generated the biggest share of the direct employment—38 per cent—because of the size of the frac. At 30 per cent, drilling-related services accounted for the second-biggest share of the work. Logistics accounted for 18 per cent and location or wellsite services created 14 per cent of the direct employment. OIL & GAS INQUIRER • AUGUST 2014

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