pipeline news september 2014

PIPELINE NEWS��

September 2014 FREE Volume 7 Issue 4

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B1Ceres Northgate

Commodity Logistics

Hub nears completion

A8Gibson Energy

CEO talks crude-by-rail A3

Viking drilling outpaces Bakken

Photo by Brian Zinchuk

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INSIDESECTION A4 ATCO Lodge Estevan closes

6 Editorial

7 Opinion

8 Gibson CEO talks crude-by-rail

11 Edmonton crude-by-rail terminal to double

12 Technical talks

17 Bakken area sees big land sale

18 Bruderheim terminal might be sold

20 Kerrobert eyes camp

31 AER blames leak on CNRL steam strategy

36 OmniTRAX kyboshes Churchill crude shipments

SECTION B

3 Northgate Hub design explained

and outbound

unit trains

10 Crescent Point leads crude-by-rail charge

13 Tundra crude-by-rail up and running at Cromer

22 Ruins cause stop-work order

26 A heart-racing test

30 Long Creek Railroad

PIPELINE NEWS��

Oct. 2014 Focus��

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ESTEVAN OFFICE

LLOYDMINSTER HEAVY OIL SHOW/BOUNDARY DAM CARBON CAPTURE

SW SASK.

LLOYDMINSTER OFFICE

A2 PIPELINE NEWS September 2014

By Geoff LeePipeline News

Kindersley – The Viking is the hottest light oil play in Saskatchewan for drilling activity in 2014, but it’s still a cool second to its Bakken rival for production.

In 2013, there were approximately 1,045 wells drilled in the Viking focused in the Kindersley- Dodsland area compared to just 326 in the Bakken in the Estevan-Weyburn area.

A total of 435 wells have already been drilled in the Viking this year up to June 30 as the pace of drilling remains steady.

In April 2014, there were close to 2,800 hori-zontal wells producing in the Viking compared to 1,700 a year ago.

In the more developed Bakken play there were 2,389 producing horizontal oil wells at the end of 2013.

Bakken oil production exceeded 28. 9 million barrels in 2013, nearly double the 14.5 million bar-rels produced in Viking.

The Viking though is clearly the provincial hot-spot for light oil producers seeking low risk returns compared to the Bakken.

“In the Bakken you have a couple of major players, but the Viking there are a lot more players in the area,” said Melinda Yurkowski, assistant chief geologist for the Saskatchewan Geology Survey with the Ministry of Economy in Regina.

In 2013, there were 15 companies drilling the Viking and 16 so far in 2014 as the Viking contin-ues to win the popularity contest.

“I think it’s because it’s relatively inexpensive because it’s shallow and the fact that the technology works on this formation” said Yurkowski.

“The opportunity is there and the infrastructure is in place.”

Yurkowski said there is a combination of multi pad and horizontal well drilling going in the Viking with only one or two vertical wells drilled in the last couple of years.

The Viking formation in the area has produced more than 207 million barrels of oil since 1952.

Vertical well cores from the 1950s and on up indicate the Cretaceous formation is extremely vari-able in its geological makeup.

“The Viking can be best described as a biotur-bated siltstone-sandstone sandwiched between two marine shales; 700-800metres deep,” said Yurkows-ki.

Bioturbated means the disturbance of sediment by living organisms eons ago when the formation was part of a seabed floor.

“The reservoir itself is a combination of sand, silt and muds that can be mixed up into a heteroge-neous unit,” explained Yurkowski.

The Viking is an extensive formation that cov-ers the entire southern half of the province.

“It’s producing only in the Kindersley area at this point,” said Yurkowski.

“It’s a matter of having the right combination of structural and stratigraphic conditions and being in an oil bearing area.

“There are a lot of Viking oil pools in the area and in the Viking it’s all light oil.”

Despite the sandstone aspect of the formation, light oil from the Viking is not produced with sand as heavy oil is from the Mannville formation in the Lloydminster region.

The rock is more consolidated than the Man-nville so there is no sand produced with Viking oil.

The API of Viking oil ranges from 35 to 39, al-most the same as the Bakken where the API ranges from 36 to 40.

“It’s about the same oil density. It’s a lot lighter than the Mannville – the heavy oil fields,” said Yurkowski.

Interestingly there is some Bakken production as well as Mannville in the Kindersley and Dod-sland areas, but Yurkowski said those are heavy oil plays.

“That’s a separate system all together. The Bak-ken play in the southeast corner of the province is

very different than the Bakken play in the Kinders-ley area. That’s a different story.

“The Viking play is the Viking formation.”More than 8,000 vertical wells have been

drilled in the upper zone of the formation.Yurkowski said production from the Viking was

steady from the 1950s up to 1984 when there was a bit of an increase then production dropped back to pre-1984 levels.

“It’s just been since 2011 and 2012 that we started to see an increase. That was when they brought in the horizontals and the fracking,” she said.

The average length of a horizontal well in the Viking is 700 metres.

Horizontal drilling and multi-stage frac completions targeting the lower zone is driving the resurgence of the Viking today.

Viking production for April 2014 was 52,000 barrels. That’s an increase of about 73 per cent from 30,000 barrels produced during the same month in 2013.

“It’s pretty awesome. I was surprised to see it going up as high as that. That’s fantastic,” said Yurkowski.

The recent production boom coincided with strong lands sales in 2011 and 2012 that generated a lot of revenue for the province.

“On average right now the area is bringing in about a $1 million a land sale,” said Yurkowski.

Lands sales are still strongest month to month in the Estevan and Weyburn areas.

Yurkowski said overall oilfield activity in the Bakken seems to be in a temporary holding pattern compared to rising activity levels in the Viking.

“I think what’s happened is that the Viewfield pool that is the major pool is fairly well delineated,” said Yurkowski.

“A lot of the drilling has been already done in the Viewfield Bakken, but there are now other areas that are being actively worked and are starting to produce.

“I am just thinking it may be a lull at this time.”Despite active drilling and production in the

Viking, companies there can’t just drill anywhere into the formation and expect to find oil.

“No there’s definitely a geological component to it. You have to understand your reservoir,” said Yurkowski.

The first stop for many companies planning to drill into the Viking is the geology survey office in Regina.

The petroleum geology unit works out of the subsurface geological lab where the cores are.

“Our staff uses the core to help in their inter-pretations and we do get a lot of geologists coming here to look at the cores,” said Yurkowski.

“What we do is help oil companies understand some of the regional geology and try to put it in context for the local geology so industry can get a better understanding of the geological conditions that control their pools.”

In fact a geologist has just been assigned to research the Viking in greater detail.

“He’s going to take a look at it in a lot more detail and try to understand the reservoirs and try to understand the regional geology of the Viking,” said Yurkowski.

“That will help industry understand their reser-voirs a little bit more and put it into context. So he’s going to be doing the regional work on it.”

“It’s a matter of our geologist taking a look at all the cores and sort of putting a story together.”

While it’s not Yurkowski’s job to forecast the life expectancy of the Viking play she said, “I just know there’s still a lot of infill drilling that can be done.

“They are also drilling sort of the edge of the pools as well. I notice there’s sort of a halo effect.

“So some wells have been drilled sort of on the edges of some of the pools.”

The initial oil in place in the Viking is estimat-ed at just under 2.8 billion barrels.

The total reserves that could be recovered using conventional technology total 294 million barrels.

“To date we have recovered over 208 million barrels of oil and that leaves 85.6 million barrels to be recovered,” said Yurkowski.

TOP NEWSA3PIPELINE NEWS September 2014

Viking out-drills Bakken play

Tempco Drilling Company, a private oil and gas drilling contractor based in Nisku Alberta has had several of its rigs drilling for oil in the Viking play over the past few

is seen standing in front of Rig 2 that was undergoing a

3 top drive rigs.

BRIEFS

Briefs courtesy Nickle’s Daily Oil Bulletin

A4 PIPELINE NEWS SEPTEMBER 2014

By Brian ZinchukPipeline News

Estevan – Back in late 2009, when ATCO Structures and Logistics announced they were setting up a 202-bed camp at Estevan, they said they were going to be around for about fi ve years. It’s now 2014, and it appears that fi ve years is nearly up.

Back then, George Lidgett, then-executive vice president operations and fi eld services, ATCO Structures and Logistics, told Pipeline News, “We’re excited about getting our facility up and being part of the community.

“We do not come in a fl y-by-night style.”Asked how long the company planned on having the camp

at Estevan, he responded, “We’re there for the long haul - fi ve years plus, or whatever the market needs.”

A drive past the lodge in early August revealed barricades at each of its entrances. A neighbour said they had been closed for about fi ve weeks. Th e Estevan location is no longer listed on the ATCO Structures and Logistics open camps web page.

Th e closure coincides with the wrapping up of the Sask-Power Boundary Dam Carbon Capture Project. While the camp opened well before work on that project got going, it was during the construction of the $1.3 billion project that Estevan saw its most acute housing shortages.

Civeo, formerly known as PTI Group, opened its Bound-ary Lodge during the summer of 2013. Th e 346-bed camp is located northeast of Estevan. It remains open. Additionally, one hotel in Estevan is expanding, another is under construction, and more are planned.

Civeo is also in the process of opening a 258-bed facility at Melita, Man., known as the Antler River Lodge. It’s the estab-lishment of a new facility that will replace its Waskada, Man. camp.

Th e ATCO closure coincides with a profound shift in the Estevan housing market. Landlords who have had their phones ringing off the hook for years are now reporting vacancies.

“I know vacancies are up considerably,” said Lynn Chipley, broker with Estevan’s Century 21 Border Real Estate Service.

“I’m a landlord myself.”She noted in part that “Construction projects have a time-

line.”Chipley hopes that the clean coal project will be successful

and that the project will be repeated for Boundary Dam’s Units 4, 5 and 6.

For purchasing housing, she said, “Prices have relaxed 10 per cent to 2011 pricing.”

Developers have been cautious not to fl ood the market. Th e big diff erence now compared to recent years is, “We have prod-uct,” she said.

Now the purchase market is neither a buyers’ nor sellers’ market, according to the broker.

“We have rental property available,” she added.Th ere has been some relaxation in rents. A two-bedroom

apartment is going for $1,600 to $1,700 per month, as opposed to $2,000 per month. Th at’s still enough for a revenue property investor to make money, but they won’t see the higher returns they were getting before. Th ere’s still a good return on the in-vestment, according to Chipley.

“Th ere is no reason for our rental market to be higher than Vancouver or Toronto, and we were,” she said.

With a looser real estate market, she said people have more options now. Th e key is to get the word out that there are places to rent now in Estevan.

“Th ere’s defi nitely change in the air,” Chipley said.ATCO isn’t entirely out of the Saskatchewan workforce

accommodations market yet, however. In April 2014, ATCO announced it would be operating a 1,470 person accommoda-tions facility for the K+S Potash Canada GP camp near Moose Jaw. ATCO will provide catering, housekeeping, janitorial and maintenance services for the facility that houses workers constructing the K+S Potash Canada Legacy Project. Th e vol-ume-based, multi-million dollar contract began in April 2014. ATCO pursued this project with its local Aboriginal partner; the George Gordon First Nation (GGFN) as the K+S Potash Canada Legacy Project is located on the traditional lands of the GGFN.

ATCO Lodge Estevan closes around the time it expected toEstevan housing situation not as tight as before

Barricades are now at the entrance of the ATCO Lodge Estevan. Photo by Brian Zinchuk

T. Bird Oil sold

On July 18, Crescent Point Energy Corp. signed an agreement to acquire T. Bird Oil Ltd., a privately held Estevan-based oil and gas company with assets in southeast Saskatchewan and Manitoba.

Th e price is about $88 million, including 1.5 mil-lion Crescent Point shares and assumed net debt, based on a fi ve-day weighted aver-age share price of $45.36 per Crescent Point share. Clos-ing was expected in mid-August.

Th e assets produce 700 boepd and include more than 24 net sections of land. Cres-cent Point said the assets of-fer excellent rates of return and include 53 net low-risk drilling locations and signifi -cant exploration potential in multiple horizons.

On July 30, Crescent Point Energy Corp. closed an agreement to buy as-sets in the Viewfi eld Bak-ken and Flat Lake plays in southeast Saskatchewan from an unidentifi ed pro-ducer for $99.1 million in cash.

Th e Flat Lake assets are producing about 825 boe a day and include more than 54 net sections of land. Th ese assets are next to Crescent Point’s Viewfi eld and Flat Lake lands, and include 38 net low-risk drilling locations.

Crescent point locks up land

BRIEFS

Briefs courtesy Nickle’s Daily Oil Bulletin

A5PIPELINE NEWS September 2014

See us at the Lloydminster Oil Show Booths 2 & 3

Lac-Mégantic, Que. – Th e Transportation Safety Board is calling for new physical measures to prevent runaway trains and for more complete audits of railway safety management systems.

Th e TSB made the two recommendations with the release of its fi nal report on the Lac-Mégantic Quebec rail disaster on Aug. 13

Th e report cited multiple factors that led a runaway train carrying crude oil to derail and ignite into a large fi re more than a year ago, killing 47 people and burning dozens of buildings.

“Accidents never come down to a single individual, a single action or a single factor. You have to look at the whole context,” said Wendy Tadros, TSB chair.

“In our investigation, we found 18 factors played a role in this accident.”

Th e TSB investigation found not enough hand brakes were set when the Montreal, Maine and Atlantic train (MMA) was parked on a descending grade of tracks in Nantes Que. the eve-ning of July 5, 2013.

Th e engineer applied just seven of 17 to 26 brakes needed to secure the train and did not follow rules requiring him to test the eff ectiveness of the hand brakes.

“What we are saying is the rules aren’t enough. Th ey are not suffi cient; no matter what the rules are you can improve the rules. You can beef them up,” said Jean Laporte, TSB’s chief operations offi cer.

“Th ere will always be a chance for mistakes so what we need is additional physical defences.

“We need additional physical defences in addition to the

rules to make sure the risks are eliminated.”Th e report noted the rolling train reached a top speed of 65

mph and derailed in the centre of town. Almost every derailed car was breached spilling almost six

million litres of crude oil which ignited into a fi reball.TSB offi cials said new defences against runaway trains

could include introducing wheel chocks for parked trains or in-stalling new, more modern braking technology to prevent trains from moving.

“Th is accident has really brought about and will bring about a sea change I believe in terms of the thinking of the train in-dustry, the shippers and the regulators,” said Tadros.

Th e investigation found MMA was a company with a weak safety culture that did not have a functioning safety manage-ment system to manage risks.

Th e TSB also learned that Transport Canada did not audit MMA often and thoroughly enough to ensure it was eff ectively managing the risks in its operations.

Furthermore, the investigation found problems with train-ing, employee monitoring, and maintenance practices at MMA; with industry rules for the securement of unattended trains; and with the tank cars used to carry volatile petroleum crude oil.

“Th is investigation and its fi ndings are complex, but our goal is simple: we must improve rail safety in Canada,” added Tadros

“Th is is about governments, railways and shippers doing everything in their power to ensure there is never another Lac-Mégantic.”

Lac-Mégantic report cites 18 factors in disaster

Windsor, Ont. – Penn West Petroleum Ltd. is being investigated by Sutts, Strosberg LLP, a law fi rm that represents investors in securities class actions.

Th e Ontario based law fi rm with offi ces in Windsor and Toronto re-ported on July 30 that is investigating the accuracy and adequacy of some of the Penn West’s historical fi nancial statements.

Th e investigation comes as a result of Penn West’s announcement on July 29 that it is conduct-ing a review of certain of its accounting practices and it has concluded that certain of the company’s historical fi nancial state-ments must be restated.

Sutts, Strosberg LLP is a leading class action law fi rm that has recov-ered over $1.5 billion for its clients.

Penn West under

scrutiny

EDITORIAL

Publisher: Brant Kersey - EstevanPh: 1.306.634.2654

Editorial Contributions: SOUTHEASTBrian Zinchuk - Estevan 1.306.461.5599

SOUTHWESTSwift Current 1.306.461.5599

NORTHWESTGeoff Lee - Lloydminster 1.780.875.5865

Associate Advertising Consultants:SOUTHEAST SASK. & MANITOBA

Cindy Beaulieu Candace Wheeler Kristen O’Handley Deanna Tarnes Teresa Hrywkiw

NORTHWEST SASK. & ALBERTA

Krista Thiessen

CENTRAL Al Guthro 1.306.715.5078

SOUTHWEST

Stacey Powell

To submit a stories or ideas:Pipelines News is always looking for stories or ideas from our readers. To contribute please contact your local con-tributing reporter.

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Published monthly by the Prairie Newspaper Group, a divi-sion of Glacier Ventures International Corporation, Central Office, Estevan, Saskatchewan. Advertising rates are available upon request and are subject to change without notice. Conditions of editorial and advertising content: Pipeline News attempts to be accurate, however, no guarantee is given or implied. Pipeline News reserves the right to revise or reject any or all editorial and advertising content as the newspapers’ principles see fit. Pipeline News will not be responsible for more than one incorrect insertion of an advertisement, and is not responsible for errors in advertisements except for the space occupied by such errors. Pipeline News will not be responsible for manuscripts, photographs, negatives and other material that may be sub-mitted for possible publication. All of Pipeline News content is protected by Canadian Copyright laws. Reviews and similar mention of material in this newspaper is granted on the provision that Pipeline News receives credit. Otherwise, any reproduction without permis-sion of the publisher is prohibited. Advertisers purchase space and circulation only. Rights to the advertisement produced by Pipeline News, including artwork, typography, and photos, etc., remain property of this newspaper. Advertisements or parts thereof may be not reproduced or assigned without the consent of the publisher. The Glacier group of companies collects personal infor-mation from our customers in the normal course of business transactions. We use that information to provide you with our products and services you request. On occasion we may contact you for purposes of research, surveys and other such matters. To provide you with better service we may share your information with our sister companies and also outside, selected third parties who perform work for us as suppliers, agents, service providers and information gatherers.

NEWSPIPELINE

Mission Statement:Pipeline News’ mission is to illuminate importance of Saskatchewan oil as an integral part of the province’s sense of community and to show the general public the strength and character of the industry’s people.


Putting crude-by-rail numbers in context

There are lot of numbers thrown around in the oilpatch each day, and when it comes to crude-by-rail, it helps to have some context. So here’s a little bit of a primer, mostly based on stories in this edition:

Zero: The amount of crude-by-rail oil that has been shipped on the Long Creek Railroad since Au-gust, 2013.

All: Crescent Point Energy Corp.’s core areas are all serviced by crude-by-rail capacity in one way or another.

83 active rigs: The current level of drilling activ-ity in Saskatchewan as of Aug. 18. This is roughly on par with drilling activity in 2012 and 2013, but down from a record peak of 122 active rigs on Aug. 22, 2011.

600 barrels: This is the capacity of a typical rail tanker car, although it can sometimes be as much as 650. It depends on the weight of the oil, and what the track can bear, as some branch lines may be restricted in their load capacity.

30,000 barrels per day: The total daily produc-tion for Saskatchewan’s Viking play in April 2013. This is also currently the loading capacity of Tundra Energy Marketing Limited’s crude-by-rail terminal at Cromer, Man.

45,000 barrels per day: The loading capacity of Crescent Point’s Stoughton crude-by-rail loading facility. It’s not far off from their production numbers in the region.

52,000 barrels per day: The total daily production for Saskatchewan’s Viking play in April 2014. It’s also very close to the entire daily production of Manitoba for 2013.

60,000 barrels per day: this will also be the expanded capacity of Tundra’s Cromer crude-by-rail terminal by the end of 2014.

60,000 barrels to 70,000 barrels: These are the numbers that are usually referred to when a unit train is discussed. The actual number depends on the size of

the facility, how much is loaded into each car, and how many cars are in a unit train. That last number varies per railroad. The BNSF, which will services the Ceres Northgate Commodity Logistics Hub, prefers 120 cars per unit train. At 600 barrels per car, that would give you 72,000 barrels.

This range of numbers has other contexts, too. That is roughly the amount of Bakken oil production in Sas-katchewan each day.

120,000 barrels per day: This is the current capacity of the Gibson Hardisty Rail Terminal.

145,000 barrels per day: This is the “nameplate” capacity of the Consumers’ Co-operative Refineries Ltd Regina refinery, after its multi-year expansion was completed in the fall of 2013. The refinery receives its oil by the Enbridge mainline, which runs right past the complex. If it was set up to receive crude-by-rail, it would require two unit trains per day.

168,000 barrels per day: This is the planned initial capacity of the Torq Kerrobert crude-by-rail terminal, which has not yet seen construction.

205,000 barrels: This size of each of the new stor-age tanks at Tundra Energy Marketing Limited’s new storage tanks at their Cromer, Man., terminal, just across the border from Saskatchewan. Two are complete and a third is on the way.

240,000 barrels per day: This could be the future capacity of the Gibson Hardisty Rail Terminal if expan-sion plans are carried out, doubling the capacity of the facility.

500,000 barrels per day: A rough approximation of Saskatchewan’s crude oil production

It is clear that crude-by-rail capacity is growing at a tremendous rate, not just inside our borders, but just across them, at Hardisty and Cromer, with the capability of servicing Saskatchewan production. In a very short order, unit trains will become a standard unit of measure in our industry, so get used to it.

PIPELINE NEWS INVITES OPPOSING VIEW POINTS. EDITORIALS AND LETTERS TO THE EDITOR ARE WELCOME.Email to: [email protected]

� ��

OPINION��

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Organizers of the Lloydminster Heavy Oil Show to be held Sept. 10-11 are making a point to urge oil and gas companies to send their employees to the show.

The committee behind the next Bonnyville & District Oil and Gas to be held June 17-18 in 2015 also wants more regional employees to turn out for that event.

High attendance by oil and gas workers would seem obvious given these shows are held for the benefit of industry, but not as many employees have attended past shows that could have.

The 2013 Bonnyville oil show attracted a total of 2,559 registered visitors while approximately 5,000 people took in the last Lloydminster oil and gas show in 2012.

Given there are thousands more heavy oil workers in both regions driving the economy, the numbers seem low.

Industry interest as exhibitors at both shows is exceptionally strong given booths usually sell out quickly with a waiting list.

These shows however, are not just for exhibi-tors, but for the entire industry from management to field hands.

There are more good reasons for sending oil and gas employees to these shows than the list of lame excuses such as claiming to be too busy or not

having enough time.The best reason is to learn about the latest

technology that is driving growth of their compa-nies and industry and where the new technology is being used.

There is no better place to network and estab-lish key business and professional contacts with buyers and sellers of oil and gas products and ser-vices that can help your company grow.

For sales and management employees, these shows are the best way to establish face to face con-tact with new and existing customers and prepare the ground work for new sales or business.

These shows are also great way for all employ-ees to bone up on the state of the industry by talk-ing with employees from other companies, listening to the banquet speakers, and taking in a few of the presentations going on.

Having as many employees attend as possible is also a good way for everyone to get a handle on recent changes in the local market through mergers and acquisitions, expansions, reorganizations and new businesses.

Any company that says everyone knows who they are or what they do is kidding themselves un-less they are from Tim Hortons or have telepathic powers.

You don’t have to be an exhibitor to explain what you do. Your employees can speak with ex-hibitors and other employees attending the show

to deliver your message and generate new business opportunities.

At the oil show, your visiting employees are the face of your business if you don’t have a booth. That’s why it’s just good business to send your employees.

As for the being too busy excuse for not send-ing employees to these oil shows, the shows are scheduled to welcome visitors during the morning, afternoon and evening over two days.

Organizers of the Lloydminster show have even posted the names and phone number of bus compa-nies so regional oil and gas workers can attend as a group to save money and time.

Having lots of employees at these shows is im-portant to help educate the general public about the industry and engage the media to report exhibitors’ products and services.

Some of the general public may also be look-ing for employment and talking to someone in your company about what they do could help them decide to apply.

Companies might also want to think of these shows as professional development days.

Sending employees to the heavy oil technical symposium held during the Lloydminster show fits the bill perfectly.

These are industry shows s put on for the ben-efit of industry. Employee attendance should be a no brainer.

The protesters who have chained themselves to the Whitehouse fence protesting the Keystone XL pipeline, and all the others who have fought tooth and nail to fight pipeline development have failed.

Incrementally, a small facility here, a unit train terminal there, and Western Canada will have over-come that pipeline setback in the very near future through the tremendous growth of crude-by-rail capacity.

I don’t know if anyone is keeping track, but when you add up the current facilities in and near Saskatchewan, the planned expansions of those ex-isting facilities (Hardisty, Cromer), and those in the works (Kerrobert, Northgate), then throw in all the little sites here and there (Maidstone, Dollard, Wil-mar, Unity, Lloydminster), you soon get a number pretty close to the proposed Keystone XL pipeline. Obviously the biggest portion of that – Hardisty’s planned expansion to 240,000 bpd from 120,000 is largely, if not entirely, Alberta oil, but it’s a number you can’t ignore. When you add in other facilities in Alberta (Edmonton, Bruderheim), you’re pretty much there.

The environmental consternation stopping pipe-line development in its tracks has been sidestepped by rail.

The days of limited shipping options for Sas-

katchewan crude oil, particularly oil in the southeast, are coming to an end.

First we have Crescent Point Energy Corp.’s Stoughton facility capable of loading 45,000 bpd (They actually ship larger unit trains, just not every day). Tundra Energy Marketing Limited’s crude-by-rail facility at Cromer, Man. (just across the border) came online in September 2013. It is currently rated at 30,000 bpd but will be up to 60,000 bpd unit trains by the end of the year.

Also by the end of the year we will see the completion of the Ceres Northgate Commodity Hub. Initially it was expected to ship unit trains of oil at 70,000 barrels each. However, a change in management and the board of directors within Ceres means the company is re-evaluating its plans. What will come of this, we’re not sure, but since the track is already being laid, expect something to come of it shortly.

And if you want to stick with pipelines, to top it all off, TransCanada’s proposed Energy East pipeline is supposed to have a lateral going from Cromer to Moosomin. They wouldn’t tell us who they were planning to connect to at Cromer, but it turns out they have had discussions with Tundra. There’s no agreement yet, and it could be a long ways off, but it’s possible. If that should occur, that lateral is

expected to have a capacity of 200,000 to 300,000 bpd, which corresponds with roughly the total current production capacity of southeast Saskatchewan and southwest Manitoba.

Whether Energy East gets built is anyone’s guess, given how much trouble other pipelines have getting built these days. But if it should come to pass, when you factor in Enbridge’s existing capac-ity, the recently added crude-by-rail capacity, and Energy East, it will be theoretically possible to ship every drop of oil produced in southeast Saskatch-ewan and southwest Manitoba three times over.

If anyone thinks stopping Northern Gateway, in the same manner Keystone XL has been stalled, is going to stop the movement of oil, they are fooling themselves. Indeed, one could now wonder why that pipeline would be built at all, given there’s already a rail line to Prince Rupert and Kitimat. Just build the storage tanks and docks, and call in the supertank-ers. Is that a better solution? A safer solution? Prob-ably not. But it could very well be much cheaper, quicker, and easier.

The rail is already there.Brian Zinchuk is editor of Pipeline News. He can

be reached at [email protected].

Lots of shipping options

Send employees to heavy oil shows


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By Geoff LeeGibson Energy Inc., a Calgary-

based independent integrated service provider, is undertaking a multi-year build out of its new unit train facili-ties at its Hardisty Rail Terminal and its Edmonton Terminal. Th e unit train facility at Hardisty is a development project between Gibson and U.S. Devel-opment Group. Th e rail facility was com-missioned on June 30, and can load up to two 120-railcar unit trains per day or 120,000 barrels of oil day with plans to double the capacity to 240,000 bpd when new shipper commitments are in place.

Gibson president Stewart Hanlon spoke with Pipeline News on everything from the growth of crude by rail by Gibson to his industry outlook for crude by rail in Western Canada.

Pipeline News: What kind of oil product is being shipped by rail from the Hardisty Rail Terminal?

Stewart Hanlon: It’s whatever the shipper wants to ship on the railcar. One of the advantages that we have at Hardisty, of course, is that virtually ev-ery quality of crude oil that produced in Western Canada shows up there almost every day, kind of thing.

Some days it may make sense for the shippers to take light sour barrels to the east coast to take advantage of a Brent to WTI arbitrage.

Some days it may make sense for them to take heavier barrels down to the U.S. Gulf Coast. It really depends on what market is open on what day. We think that’s one of the key aspects of that terminal which will make it viable well into the future.

P.N.: Do you anticipate handling other types of products at the unit train facility in the future?

S.H.: At the terminal we do have a fractionator. We’re building an environmental services recycling and reprocessing plant and we do handle a multitude of other products, but the unit train facility is intended to handle crude oil products and potentially condensate, but nothing beyond that.

P.N.: When will you make a decision on doubling the capacity to 240,000 barrels per day?

S.H.: We are in the process of so-liciting customer support to backstop the expansion from 120,000 barrels a day to 240,000 barrels a day. Depend-ing on how quickly we can solidify that support and enter into a binding contract with our committed custom-ers – that will sort of determine when we are able to tell the market that we are in fact going to double the capac-ity.

I said in our investor call earlier last week (Aug. 6) that we would cer-tainly anticipate that prior to the end of the year we would be in a position to make an announcement.

P.N.: What other facilities are you considering to build at the

crude-by-rail facility?S.H.: Th e facility is expandable

from 120,000 barrels a day to 240,000 barrels a day. We are in the process of investigating whether a diluent recovery unit (DRU) adjacent to that facility would make some economic sense.

A DRU of course would be a facility we could use to remove the di-luent which is required to get a heavy barrel of crude oil transported on a pipeline – take that out before you put the actual bitumen or heavy oil mate-rial on a railcar. Th at’s the valuable material that a U.S. Gulf Coast refi ner would want to see. Th ey don’t see a lot of value in the actual diluent.

P.N.: What is the estimated total cost of the Hardisty unit train facility to a build out to 240,000 barrels per day?

S.H.: We haven’t been public with the actual cost to build the fi rst part of the facility. Th e facility is a joint development between ourselves and a company called U.S. Development Group (USDG), a private U.S-based unit train facility developer.

Th ey were responsible for the costs on the rail side itself and our cost is related infrastructure and a 24-inch pipeline between our main terminal and the unit train facility to connect the two and to make sure that oil can fl ow onto the railcars.

Our early day’s estimate of the cost to go from 120,000 barrels a day to 240,000 barrels a day won’t be as expensive as building the fi rst facility, but it’s certainly going to be a signifi -cant capital expenditure.

Page A9

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Page A8P.N.: What is the capacity of the Edmonton

Terminal and what is the expansion capacity?S.H.: The Edmonton facility is different from

the Hardisty facility in that it’s a manifest facility (mixed products) so it’s going to be less than unit train size.

The capacity today – it’s a multi-product facil-ity. We handle NGL (natural gas liquids) and LPG (liquid propane gas); we handle refined products, and we handle crude oil at our Edmonton facility. We are in the process of developing a 22 spot load rack for our customer Statoil and room for adjacent sort of ladder tracks as we call them as we move forward. So the ultimate capacity of the Edmonton facility could be quite substantial.

Today, we handle about 35,000 to 40,000 barrels a day of refined product and about another 20,000 barrels of day of other products including NGL, LPG and crude oil.

P.N.: Is there just one new storage tank as-sociated with the Edmonton Terminal?

S.H.: The initial announced plan was to build a 300,000 barrel tank for Statoil, but our plans call for an eventual build-out of that facility including many more tanks in both diluted bitumen service and condensate service.

The condensate service would be to feed the southern end of the Polaris pipeline system which is Inter Pipeline’s condensate pipeline that takes condensate from the Edmonton area into northern Alberta. We foresee building additional facilities for that as well.

P.N.: What are the advantages of shipping crude-by-rail to markets in Canada and the U.S for Gibson and its customers versus pipelines?

S.H.: Pipelines are always going to be the cheaper alternative to a railcar, but crude-by-rail – you get your barrels to market significantly faster. To put a barrel into a pipeline in Hardisty and then have it arrive at the U.S. Gulf Coast you are looking

45 days or about six weeks. You can make that same journey with a barrel in a railcar in about two weeks so it’s a significant time saving.

The next advantage is the railcar. It goes im-mediately to its final destination. You put a barrel on a pipeline and it goes across breakout tankage and then it goes into several different tanks. It will eventually end up at the refinery that you’re trying to sell your barrel to.

There may or may not be quality degradation as you go along, the route via pipeline interface or via going across tank bottoms. So a railcar can be loaded with a specific quality of crude and then arrive at the specific destination faster and in better form.

The other advantage of course, is you build a pipeline – it goes in one direction forever whereas a railcar gives you the option to go to a different market depending on the value of the barrel that you have at that specific market on the day.

P.N.: Is growing oil production in Alberta and the U.S. the main growth driver for the develop-ment of the Hardisty Terminal?

S.H.: In terms of growing volumes yes. Cer-tainly the difficulty that we as an industry have had in terms of getting new export pipelines sanctioned and then built has solidified in the minds of our customers the value of having multiple means to get barrels to market.

That has been a key aspect in terms of getting people comfortable with signing the levels of com-mitment they have to backstop the facility.

Having said that I think once you have made that determination, very quickly you recognize that having the ability to ship your barrels by rail is a nice option to have. It should be an element in your portfolio, if you will, going forward.

So I think as crude volumes grow irrespective of whether or not there are additional pipelines built in the future, the value of crude-by-rail is go-ing to remain. We think it’s going to be viable for a

very long time.P.N.: If new pipelines like Keystone XL, and

Energy East come into play in the next couple of years, will that make crude-by-rail less economic?

S.H.: I think the relative economics between crude by rail and pipelines would remain. I think if we are in a position then to get additional pipe-lines either to the west coast or to east coast or to the U.S. Gulf Coast sanctioned and built, that’s just generally good for the industry within western Canada.

It will allow us to invest and growing in vol-umes in both conventional and non-conventional volumes within the WCSB so that’s going to be good for the economy as a whole.

P.N.: What is the future of crude by rail and what are some of the challenges for sustaining its growth?

S.H.: I think the future for crude-by-rail is re-ally dependent on a case by case analysis. We think Hardisty is particularly advantaged because you’ve got ultimate optionality in terms of the volumes and the types of volumes you can ship. You can literally get any quality of crude oil to any market within North America within a couple of weeks. I think that’s going to make our facility particularly advantaged over the long term.

If you’re looking at a basin, and let’s take the Bakken as an example, where crude-by-rail has sprung up to alleviate a temporary lack of pipeline capacity, then I think eventually as that pipeline capacity shows up, the relative cost advantage of pipelines will start to erode the ultimate value of crude-by-rail.

It’s really something you have to be careful about making sure your investments are in the right area to give you a sustainable long-term advantage.

P.N.: What impact will the new tank car safety regulations in Canada and U.S. have on the growth of crude by rail from Hardisty or elsewhere? Page A10


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Calgary – Trans-Canada Corp. continues to work behind the scenes to develop crude-by-rail options as it prepares to fi le for fed-eral regulatory approval to build its $12 billion Energy East pipeline.

Shipping Alberta crude by rail to U.S. customers is also a possibility for Trans-Canada with continued regulatory delays in the approval of its proposed Keystone XL crude oil pipeline.

Th e $5.4 billion Keystone XL pipeline, has been awaiting U.S. government approvals for more than fi ve years amid strong opposition from environmental groups.

Th e Nebraska Su-preme Court will begin to address legal pipeline route issues in that state with a decision not expected until late 2015 or early 2015.

TransCanada has been looking at ship-

ping crude-by-rail in the past few months as a rail bridge to lagging pipeline developments on both sides of the Canada-U.S. border.

“We continue to explore the opportunity to create both receipt facilities in Alberta and delivering facilities in the marketplace,” said Paul Miller chief execu-tive of liquids pipelines during TransCanada’s second quarter confer-ence call on July 31.

Any investment in crude-by-rail by TransCanada would be limited to on-loading and off -loading facilities using existing rail infra-structure to transport oil to delivery points in North America.

“On the party development side on the engineering – the siting – we’re progress-ing well in that regard and then on the market development side we’re dealing with a num-ber of parties here to

anchor those facilities,” said Miller.

“And it just takes time to corral a num-ber of parties around a common project so we continue that eff ort but don’t have further updates at this point.”

Th e National Energy Board reports crude-by-rail shipments out of the country reached a new high of 160,000 barrels per day in the fi rst quarter of 2014.

Th at’s an increase of more than 50 per cent over the same period a year ago.

Th e Canadian As-sociation of Petroleum Producers estimates that about 700,000 bpd could potentially be shipped by rail in 2016 according to its June 2014 forecast.

CAPP’s estimate is based on publicly reported supply con-tracts with uploading terminals in Western Canada.

TransCanada is ex-ploring shipping crude by rail from its pipeline and oil storage facili-ties at Hardisty, Alberta the starting point for the Keystone XL and Energy East pipelines.

Meanwhile, the company is expected to fi le its application to build the Energy East project with the National Energy Board any day now.

“We’ve announced that we’re going to fi le that in the third quar-ter so you can expect to see that fi ling come in really in just a few weeks from us likely,” said Alex Pourbaix chief executive of develop-ments at the conference call from Calgary.

Energy East pipe-line will transport 1.1 million barrels a day of oil from Alberta and Saskatchewan to east-ern Canadian refi neries and export terminals.

Th e Energy East Pipeline project in-

volves repurposing 3,000 kilometres of existing natural gas pipe between the Alberta/Saskatchewan border to Cornwall, Ont., and constructing 1,600 km of new pipeline mainly in Québec and New Brunswick.

In Saskatchewan, Energy East will in-volve the construction of a tank farm at the Moosomin compres-sor station that would

create an estimated 150 construction workers at peak construction.

Construction of the 1.05 million barrel tank farm is expected to take two years starting in early 2016.

TransCanada also plans to build a lat-eral pipeline between the Moosomin and Cromer, Manitoba to feed Manitoba light oil into the Energy East pipeline system.

TransCanada on track for crude-by-rail

Page A9

S.H.: I think it’s going to be largely a non-event. Th e way our facilities work is that the shippers, the people who have contracted for capacity, have the obli-gation and the responsi-bility to bring their own railcars to take the crude away.

If you talk to the shippers that we have under contract, they are already well ahead of the regulations. We would have very few old style tank cars remaining in crude-by-rail in the fl eet. So I don’t think in the long term it’s going to be a detriment.

I think the industry got out ahead of the regulations because they recognize that safety is paramount.

Nobody wants to do any harm, so it’s just go-ing to make the industry safer as we go forward and that’s a good thing.

P.N.: Do these safety regulations make it more attractive from a public relations view-point to operate crude by rail facilities?

S.H.: I think from the PR perspective ab-solutely. Transportation of dangerous goods by rail is an economic real-ity and has been as long as railways have existed.

You just have to continually work at making sure that your protocols and practices around health, safety, security and environ-mental stewardship etc continue to improve, and on any day you do the best to ensure you do no harm.

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Edmonton – Th e Edmonton Rail Terminal will more than double its capacity to handle over 210,000 barrels of crude of a day by rail in the fi rst quarter of 2015 and potentially up to 250,000 bpd.

Kinder Morgan Energy Partners L.P. an-nounced on Aug. 7 that its 50-50 joint venture with Imperial Oil Ltd. will add 110,000 bpd capacity to the facility.

Construction has been under way since the project was announced last December.

Th e fi rst phase was originally designed to be capable of loading one to three unit trains per day totaling 100,000 bpd.

Th e impetus for the Phase 2 expansion came from additional take or pay (a penalty) agreements the project secured with several unnamed major oil producers.

“Th e continued interest in this facility, and additional volume being contracted for with this announcement, further demonstrates how impor-tant it is for our customers to secure crude oil take away capacity using a variety of transportation op-tions, including both pipeline and railway capacity to ensure crude oil reaches market,” said Kinder Morgan Terminals president John Schlosser in a news release.

Th e terminal will be connected via pipeline to Kinder Morgan’s adjacent Edmonton storage terminal and will be capable of sourcing all types of crude handled by Kinder Morgan for delivery by rail to North American markets and refi neries.

Th e rail terminal is being constructed and will be operated by Kinder Morgan, and will connect to both Canadian National and Canadian Pacifi c mainlines.

Including the addition of the expanded capac-ity, Kinder Morgan’s investment in the project now totals approximately $232 million.

Kinder Morgan Energy Partners L.P. and 50-50 joint venture partner Im-perial Oil Ltd. plan to add 110,000 barrels per day capacity to the Edmonton Rail Terminal. First phase

in this aerial photo. The terminal could eventu-ally expand to a capacity of 250,000 bpd. Photo courtesy Kinder Morgan

Edmonton crude-by-rail terminal to double


D&D OILFIELD RENTALS

By Geoff Lee

Lloydminster – Th ere will be four heavy oil technical presentations during the 2014 Lloy-dminster Heavy Oil Show to be held Sept. 10-11, but there could have been many more given the volume of submissions.

“We had quite a bit of interest this year. We always have quite

a bit of interest,” said Lloydminster SPE chair Mark Bacon.

“We are glad we are able to partner with the Lloydminster Heavy Oil Show again and there should be some very entertaining top-ics.”

By the time the deadline for submitting paper came and went weeks ago, the selection committee was tasked

with choosing topics based on the expected audience.

“Presentations were coming from every-where. We had people from as far as away as California who wanted to speak,” said Bacon.

“We are looking for things that would ap-ply a little more to the Lloydminster area.

“Some of the ideas out there were really in-

teresting. Some of them we saw a lot of potential in them and knew they would be good for the audience to see them.”

All of the presen-tations will be held in Prairie Room at the Lloydminster Exhibi-tion Grounds, the site of the oil show.

Th e sessions will begin 11 a.m. on Sept. 10 with a topic by Noralta Technologies Inc. titled, Increasing Netbacks by Applying Digital Oilfi eld Technolo-gies to Heavy Oil Opera-tions.

Tartan Canada will deliver the next presen-tation at 2 p.m. called Developing a Win-Win Maintenance Strategy.

Blue Spark Energy will wrap up the fi rst day of technical sessions with a talk titled Shake ‘n’ Rake Your CHOPS Reservoir at 3 p.m.

Th e event will con-clude on Sept. 11 with just one presentation by NOV Mono Artifi cial Lift Systems at 11 a.m.

Th at one’s titled,

Extending Production Life of Heavy Oil Wells Using Hydraulic Pump-ing Units.

Bacon said the plan to hold three sessions on the opening day and just one on the fi nal day of the oil show is in response to audience feedback from the 2012 oil show.

“One of the lessons we learned from the last heavy oil show was that some people would go to the exhibits or some people were leaving early because of fl ights and hotels, so when we ran our exhibitors later in the second day, the interest went down,” said Bacon. Page A13

Lloyd oil show books technical talks

Mark Bacon, chair of the Lloydminster chapter of the So-

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Mike McIntosh will chair the heavy oil technical sessions to be held during the Lloydminster Heavy Oil Show Sept. 10-11. McIntosh is the program chair of the Lloydminster Society of Petroleum Engineers. He is pictured address-ing the banquet during 2012 oil show at the Lloydminster

File photo

Page A12

“We found the best time for speakers was on the fi rst day when everybody was really primed and they’re out to learn something.”

Th e 2012 heavy oil show was the fi rst time the technical presen-tations were held in conjunction with the oil show.

On alternative years, the Lloydminster SPE

normally holds its own heavy oil technical sym-posium depending on interest from speakers and audience participa-tion.

More than 300 people attended the technical sessions dur-ing the 2012 heavy oil show, but Bacon expects to surpass that number given the presentations will be a part of the show exhibits for the second time.

“We are doing more advertising at the oil show. We are partnered very closely with the oil show itself. Th at’s defi nitely going to be strength,” said Bacon.

“Th e last time was the fi rst time we’ve done it. It will be a little easier to follow up on it this go around. We all understand the value in the speakers.”

Bacon may not be able to attend the show himself given his busy schedule as an opera-tions project manager for Nalco Champion, an Ecolab company in Calgary.

“I have to check my schedule to see if I will able to make it. My job has shifted a little bit. I’ve been spending a lot of time in Houston lately,” he said.

As for fl ying in at the last minute Ba-con said, “Last time I checked, fl ights into Lloydminster and hotel rooms are pretty hard to come by that week.”

Bacon will be introduced in person or in his absence by SPE executive member Mike McIntosh who

will serve as the techni-cal session chair for the second time since 2012.

McIntosh is also the chair of a major SPE Global workshop on the future of heavy oil to be held at the Lloydmin-ster Exhibition Grounds from Jan. 27 to 28, 2015.

Th e workshop with focus on determining what proactive discus-sions should be started now looking towards the challenges the industry will face by the year 2020.

Check the work-shop links on the SPE Lloydminster website for a detailed look at the workshop schedule.

Th e Lloydminster SPE will also resume its monthly technical luncheons in October at the Prairie Room.

Bacon noted this could be his last year as SPE chapter chair, a role he’s held for over two years. He said dis-cussions have been held already on who might carry the torch next.

“We are kind of building a transition plan right now. I’ve been chair for two years now. We normally try to ro-tate them out every once in awhile,” he said about executive positions.

“Th ere are a few other board members who are potentially stepping up. Lucky for us, our board members stay fairly consistent and keep that knowledge. We’ve been very good with communications.”


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By Geoff LeeCalgary – Gibson Energy Inc. will have a lot to

celebrate when it offi cially opens its Hardisty Rail Terminal in a ceremony expected to take place in September.

Plans are already in the works to double the ca-pacity of the unit train facility to 240,000 barrels of crude oil per day in 2015 – just weeks after the fi rst 120,000 bpd phase began operating on June 30.

Th e facility, located fi ve kilometers east of the main Hardisty Terminal has a current capacity to load up to two unit trains per day on the Canadian Pacifi c mainline.

“We’re hoping to have a grand opening and a little bit of a celebration to thank all the people that worked really hard to get this facility up and running on time and on budget which I am happy to say,” said Gibson president and CEO Stewart Hanlon in a phone interview on Aug. 11.

“We’d love to have as much of the media both from local and the larger Alberta area as possible. It will be some time in September.”

Th e grand opening will also celebrate Gibson’s ongoing multi-year expansion of its crude-by-rail

loading facilities at the Edmonton Terminal that utilize both CP and Canadian National Railway systems.

Gibson owns and operates key terminal, blend-ing, and injection assets in both locations.

Th e Hardisty crude-by-rail facility is a develop-ment partnership between Gibson and U.S. Devel-opment Group (USDG), a Houston based devel-oper of rail logistics and terminal facilities.

Th e rail Phase 1 rail terminal specs called for a fi xed loading rack with 30 railcar loading posi-tions plus a unit train staging area and loop tracks capable of holding up to fi ve unit trains.

Th e project complements the construction of an additional 2.3 million barrels of storage capacity at Gibson’s main terminal in Hardisty to go with 4.3 million barrels of existing site storage.

Th e fi rst two 400,000 barrel tanks out of six tanks of various sizes currently under construction are expected to be commissioned near the end of 2014 or in the fi rst quarter of 2015.

“So we are expanding our facility by 53 per cent, and it will come on between now and mid 2016,” said Hanlon.

A 24-inch pipeline transfers stored crude at Gibson’s main terminal in Hardisty to the unit train facility.

“Construction has progressed a little more quickly than anticipated on the Hardisty east ex-pansion,” Hanlon told a second quarter conference call on Aug. 6.

Hanlon said unit train volumes will continue to ramp up “in accordance with customer agreements over the course of the next months” with a decision to double the initial capacity likely to be made this year based on fi rm shipper agreements.

“Eff orts to market the Phase 2 of the unit train will commence now that the fi rst phase is operat-ing,” Hanlon told the conference.

Th e Hardisty rail site includes 143 acres of undeveloped land for expansion with 32 acres of undeveloped land for expansion at the Edmonton Terminal.

Th e Hardisty unit train facility is set up to handle all qualities or crude oil while the Edmon-ton Terminal is a manifest facility for handling multiple products.

Page A15

Gibson aims to double Hardisty rail volumes


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Page A14

“We handle NGL (natural gas liquids) and LPG (liquid propane gas); we handle refi ned products, and we handle crude oil at our Edmonton facility,” Hanlon told Pipeline News.

“We are in the process of developing a 22 spot load rack for our customer Statoil and room for adjacent ‘sort of ladder tracks as we call them’ as we move forward so the ultimate capacity of the Edmonton facility could be quite substantial.”

Th e Edmonton Terminal currently handles about 35,000 to 40,000 barrels a day of refi ned product and about another 20,000 barrels of day of other products including NGL, LPG and crude oil.

Th e initial plan called for the construction of one 300,000 barrel tank for Statoil, but more tanks are planned for Gibson’s diluted bitumen and con-densate services.

“Th e condensate service would be to feed the southern end of the Polaris pipeline system which is Inter Pipeline’s condensate return line that takes condensate from the Edmonton area into northern Alberta,” explained Hanlon.

“We foresee building additional facilities for that as well.”

Gibson signed a long term contract with Statoil to build infrastructure at the Edmonton Terminal with construction announced in July 2013.

Th e new facilities will provide Statoil with multiple delivery options for its crude production to points across North America.

Th e new infrastructure at Edmonton emulates the business model of Gibson’s Hardisty Terminal and rail facility that provide storage, fl exible deliv-ery options and pipeline connectivity to customers.

In the second quarter presentation, Gibson noted one of the growth drivers for crude-by-rail transport is forecasted growth of Canadian oil pro-duction to 5.3 million barrels of oil per day by 2020 led by oilsands development.

U.S. production is also expected to grow to 9.5 million bpd by 2010 driven by lighter tight oil development with limited pipeline capacity moving shippers to try rail.

Gibson is also increasing its capital growth spending in 2014 to $375 million and $375 million in 2015 for project expansions.

CFO Don Fawlis told the second quarter conference call that Gibson intended to spend $340 million growth capital and $70 million of upgrad-ing and replacement capital in 2014.

“In the fi rst half we invested $161 million on growth capital and $23 million on upgrade and replacement projects,” said Fawlis.

“We have reviewed our capital spending plans and have increased our estimate for 2014 to $375 million for growth capital with no change to up-grade and replacement spending.”

Fawlis explained that is primarily due to certain projects accelerating their timelines thereby moving

capital that was expected to be spent in 2015 into 2014.

“Due to the likelihood long term build up of

our Edmonton and Hardisty terminals we are in-creasing our preliminary estimate for growth capital spending in 2015 to $375 million,” he said.

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Regina – Could it be that another land rush is happening in the Estevan-Weyburn area of Saskatchewan?

That area of the Bakken play generated $43 million of the $48 million total earned by the province in the August sale of petroleum and natural gas rights.

The Lloydminster area was a distant second at $2.1 million, followed by the Swift Current area at $1.8 million and the Kindersley-Kerrobert area at $1.5 million.

The August sale pushed the 2014 total up to $158 million, surpassing an-nual totals for 2012 and 2013.

The average price per hectare received for the latest sale was $1,916 per hectare, the third highest on record.

The April 2008 sale holds the title for highest average price per hectare for a single sale at $2,725 per hectare, followed closely by the February 2008 sale at $2,495 per hectare.

The leases acquired in the billion dollars worth of land sales in 2008 that were not developed expired on March 31 this year. The August sale is the first land sale where lands returned to the Crown from 2008 were available.

“The Bakken and Shauanvon light-oil plays in southern Saskatchewan are both prone to spectacular single-parcel results that we experienced once again in this sale,” Economy Minister Bill Boyd said in an Aug. 15 new release.

“However, we’re equally pleased about land acquisitions in the heavy oil-prone areas of the province that are consistent in sale-after-sale, year-after-year.

“By any measure, the volume of heavy oil in the province, estimated at 20 billion barrels of heavy oil in place, is impressive, but recovering this oil is a complex and capital-intensive process.

“The province applauds both the oil and gas industry and the research institutions providing innovation and investment in the continuing effort to maximize production from this resource.”

The next sale of petroleum and natural gas rights will be Oct. 6Weyburn-Estevan area (numbers rounded up)

The top purchaser of acreage in this area was Standard Land Company Inc. that spent $17.1 million to acquire one exploration licence.

The top price paid for a single lease was $5.1 million by Stomp Energy Ltd. for a 777 hectare parcel situated partially within the Roche Percee Bak-ken Oil Pool, 15 kilometres south of Estevan.

The top price paid for a single licence was the $17.1 million purchase by Standard Land for a 2,202 hectare block located partially within the Steelman Frobisher Beds Oil Pool, 25 kilometres east of Estevan.

The highest dollar per hectare in the sale was received from Plunkett Resources Ltd. that paid $10,136 per hectare for a 62.6 hectare parcel located adjacent to the Roche Percee Bakken Oil Pool, 15 kilometres southeast of Estevan.

Lloydminster areaThe top purchaser of acreage in this area was Rockwell Resources Inc. that

spent $552,742 to acquire two lease parcels.The top price paid for a single lease in this area was $316,317 by Rock-

well Resources for a 259 hectare parcel situated three kilometres north of the Celtic McLaren Sand Oil Pool, 10 kilometres south of St. Walburg.

This is the highest dollar per hectare in this area at $1,221 per /hectare.Swift Current area

The top purchaser of acreage in this area was Scott Land & Lease Ltd. that spent $671,095 to acquire three lease parcels.

The top price paid for a single lease in this area was $367,482 by Feder-ated Co-operatives Limited for a 259 hectare parcel situated adjacent to the Illerbrun Upper Shaunavon Oil Pool, 20 kilometres south of Gull Lake.

The highest dollar per hectare in this area was received from Scott Land & Lease that paid $5,254 per hectare for two 32.37 hectare parcels located within the Eastbrook Upper Shaunavon Oil Pool, 20 kilometres south of Eastend.

Kindersley-Kerrobert areaThe top purchaser of acreage in this area was Plunkett Resources that

spent $879,665 to acquire 11 lease parcels.The top price paid for a single lease in this area was $125,936 by Plunkett

Resources for each of five 259hectare parcels situated adjacent to the White-side Viking Sand Oil Pool, 35 kilometres west of Kindersley.

The top price paid for a single licence in this area was $49,740 by Ca-nadian Natural Resources Limited for a 1,295 hectare block situated eight kilometres west of the Laporte Basal Mannville Sand Oil Pool, 25 kilometres west of Eatonia.

The highest dollar per hectare in this area was received from Rock Energy Inc. that paid $1,051 per hectare for a 16.19 hectare parcel located within the Laporte Basal Mannville Sand Oil Pool, 15 kilometres west of Eatonia.

Bakken play sees August land grab

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Calgary – Canexus Corp. may have to sell its troubled dedicated crude by rail facility near Bruderheim Alberta or some of its chemical assets to balance its books.

The 480-acre transloading facility located 55 kilometres northeast of Edmonton has been shut down since June 17 to expand capacity to six to seven unit trains per week.

The expansion is expected to be complete by the end of August when the company will recommence load-ing unit trains on CN and CP tracks.

Canexus’s new president Doug

Wonnacott appointed on July 2 an-nounced the company is exploring its options to maximize the value of its assets along with second quarter results on Aug. 6.

Wonnacott said that his first objective is to stabilize the company which involves getting the crude-by-rail facility up and running and look at opportunities to strengthen the balance sheet.

“As we look at opportunities to strengthen the balance sheet we are looking at potential divestments,” he said.

The Calgary-based chemicals and handling company also owns sodium chlorate and chlor-alkali assets in Canada and Brazil that could be sold.

“At this point we are not provid-ing any specifics but we are certainly moving down the path to shore up the balance sheet,” said Wonnacott.

“We will continue to advance discussion with those parties that have expressed a potential interest in certain assets.”

The company may be looking for a partnership, capital investment or an outright sale of its crude-by-rail facil-ity to right its financial ship.

During the question period Won-nacott wouldn’t say if they are looking to “entertain a majority position or a 100 per cent sell off ” of the Bruder-heim facility

“So we are continuing to explore and have conversations with inter-ested parties but at this point in time there is not a clear path,” Wonnacott told a conference call.

The transloading site has poten-tial to use existing salt caverns for storage, or to back-hauling conden-sate among many possibilities Won-nacott listed to increase value of the transloading business.

Wonnacott went on to tell a caller that if they were to seek an invest-ment partner for the rail facility they would look for the interested party to certainly bring value.

“Capital is one of those value

buckets. Operating expertise is the other bucket that we would consider,” said Wonnacott.

About 60 to 70 per cent of cur-rent capacity is currently contracted out to shippers with no new contracts on the horizon.

Canexus is looking at further debottlenecking projects to increase crude handling capacity to 10 and a half unit trains per week or 100,000 barrels a day capacity sometime in 2015.

The company is currently adding a fourth loop track for $2 million as part of its summer expansion work. The loop will be completed after the shutdown is over.

Canexus said the loop will reduce the risk of rail service disruptions that impact capacity.

The company is also in the final stages of negotiating the purchase of a second incinerator to flare vapors discharged from crude being loaded into rail cars.

“The last area that may require some debottlenecking is in the area of adding capacity by adding pumping facilities,” said Wonnacott.

That decision will wait until op-erations resume when the shutdown is over.

The ongoing expansion involves the installation of another 12 loading arms on the loading rack and the tie in of the facility into the Cold Lake pipeline system. Page A19

Bruderheim crude-by-rail terminal might be sold


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This is an aerial shot of the 480 acre crude oil transload-ing facility owned by Canexus and serviced by CN and CP rail taken in November 2013. The Calgary-based chemi-cals and handling company shut the facility down on June 17 to begin an expansion to handle six to seven unit trains a week or 70,000 barrels per day with the work ex-pected to wrap up by the end of August. The company is considering selling the facility and/or some of its chemi-cal assets to improve its balance sheet.

Page A18“Th e shutdown is progressing well and we

expect to be back up and operating by late August,” said Wonnacott.

He went on to state, “2014 is the year that will position Canexus for the future.”

Canexus will focus on ramping up crude-by-rail operations this fall to six to seven unit trains per week following the commissioning of the expan-sion.

Th e cost of ramping up to the full planned 100,000 barrels per day by 2015 has risen by 60 per cent to $355 million.

Construction was slowed in the fi rst and second quarter by a cold winter and a shortage of labour in Alberta.

Th e company reported an operating profi t of $29.2 million in the second quarter.

Wonnacott warned the third quarter will be will be impacted by summer shutdown of the facil-ity and chemical facilities for planned maintenance.

As the latest expansion at Bruderheim winds down, Canexus is monitoring proposed tank car safety regulations in Canada and the U.S. for trans-porting crude oil and ethanol.

“We will remain engaged to understand the potential impact on its operations and their rail cus-tomers,” said Wonnacott.

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By Geoff LeeKerrobert – According to Kerrobert Mayor Erhard

Poggemiller, Torq Transloading Inc. may finally start to move earth in late September to construct its $100 million Kerrobert Rail Terminal.

Officials from Torq were unavailable by our press time to confirm start up plans after announcing the project last August. The project is engineered to handle two, 120 car unit trains per day or up to 168,000 bar-rels per day.

The Kerrobert area will also be the focal point of Inter Pipeline Ltd’s upcoming $100 million expansion of its Mid-Saskatchewan Pipeline System to handle increased volumes of light oil produced in the area.

Enbridge Inc .may also have crews in the area in by 2015 when it rebuilds its Line 3 pipeline from Hardisty to Wisconsin.

In a brief interview with Pipeline News, Erhard also talked about work camp applications and housing plans.

P.N.: How would you describe the level of oilfield activity this spring and summer?

Erhard Poggemiller: It’s been huge. There’s been a huge amount of activity going on east of town as well as west of town between Luseland and Kerrobert.

P.N.: What are you hearing about the startup of the Kerrobert Rail Terminal project by Torq Transloading Inc.?

E.P.: The last word I got is that all the tenders have gone out from Torq and that they’re hoping to have dirt moving going on this fall starting the end of September and early October.

P.N.: Do you think a labour shortage delayed the construction start of the terminal?

E.P.: They had a lot of hurdles to go through as far as environment goes and as far as the province goes and the municipality goes. There’s a huge bit of paper work that had to be done there.

P.N.: Have you heard anything about accom-modations for their site workers?

E.P.: There’s been numerous applications hit the town office for setting up a work camp and that kind of stuff on an interim basis.

There’s just no way that we’re going to be able to get housing in place for that kind of numbers of men in time for their construction.

P.N.: What will the impact be on services and facilities and housing when Torq gets to work on its crude by rail terminal?

E.P.: This is going to be huge impact. There’s going to be several hundred people floating around and probably families and so on too.

Page A21

Kerrobert eyes work camp for Torq crews

Kerrobert Mayor Erhard Poggemiller charges an AC unit on a semi at his Kep Industries repair shop. Poggemiller expects to see a lot of work camps in town in the next 12 months with several major oil and gas projects coming to the area.


Page A20We haven’t heard

any impact as far as schools go or any of that stuff yet. Exactly what’s going to happen there I don’t know.

There are people that are developing housing and apartments and so on for the long term, but for the short term, probably the best thing that’s going to be done is the work camps.

P.N.: Has the privately-owned Kelor-dan Open Camp for workers been busy all year?

E.P.: I think it has been full for the last while already, and I hear tell there may be some expansions in mind

there too.P.N.: What is the

status of housing plans and a hotel proposed by Al-Sask Ventures last fall?

E.P.: They’ve been negotiating with some of the contractors that are going to be coming in.

I think they are also going to be looking at some kind of camp situ-ation.

They are still on the program for the hotel, but I don’t know exactly when they are going to start.

We had a lot of work to do on getting our community plan done and our zoning bylaws done. We are

coming to an end with that now.

A lot of the approv-als have come back from the province on our stuff, so that’s going to help out tremendously with these developers.

P.N.: Where will the first subdivision be developed?

E.P.: Probably up behind Yukon Avenue in the southwest part of town. That’s a totally new development that needs servicing.

Who’s ever going to do that – and it’s a dif-ferent contractor – they

are going to be doing different segments and as they finish they will be doing other seg-

ments.We are hoping to

get some of it started this fall, but with the

labour shortage and the huge demand for contractors and ground work it’s tough.

Erhard Poggemiller writes out an invoice at his Kep In-dustries repair shop where business is brisk these days. As the mayor of Kerrobert, Poggemiller reports work is

new housing. The town is bracing for an expected rush -

this fall by Torq Transloading Inc.

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By Geoff LeeKindersley – Growth in oil and gas activity in the light oil Viking play con-

tinues to outpace available housing in Kindersley, but some relief is in sight.Easing the pressure on labour shortages and infrastructure needs to keep up

with growth from the strong oil and agriculture economy in the area will need long term solutions.

“We want responsible change and responsible growth and we are trying to find ‘yes’ with all of the different municipal partners that we work with,” said Mayor John Enns-Wind.

Kindersley is working with Marathon Properties Corp. to develop the first phase of the Brookhollow Estates subdivision on a 43-acre site at the southeast corner of town.

Crews and equipment from Gee Bee Construction are working hard to service the first lots for single detached house and a modular townhouse condo.

Mayor John Enns-Wind hosted a site tour for Pipeline News on Aug. 13 with site inspector Luke Bergstrom from Bullee Consulting Ltd. on hand to explain what’s going on.

“We’re basically just installing all of the lower depth sewer and water mains right now,” said Bergstrom.

“Once we have that in, then we pull in all the services to the lots that will service the houses that will exist there in the future.

“We will have eight lots serviced by the end of today, and hopefully another 24 condos by the end of the month,” he said.

The service work taking place is part of a mixed residential development at Brookhollow that will include housing for seniors.

The master plan could house up to 3,000 people over the next 10 years de-pending on the demand with the land purchased for phase expansion.

“I wish it was done yesterday, I really do. It can’t come soon enough,” said Enns-Wind.

“The 24 condos and eight lots are a welcome addition but we really need more than that.

“Those are considered affordable houses. We have a lot of temporary foreign workers who’ve come to the area to take some of the service jobs because some of the people have moved on to the oilpatch.

“We need homes that are in reach of them as well. We need housing for dif-ferent price points.”

By June 30 of this year, 435 horizontal wells had been drilled in Viking. A total of 1,045 wells were drilled in the play from April 2013 to April 2014

bringing more oilfield workers than ever to the area to find housing or trailer space.

“They are putting three to a lot now,” said Enns-Wind about the local campground. “There’s just barely enough room to get them in.

“Housing is a significant challenge. We didn’t have serviced lots, so Mara-thon Properties, Gee Bee and Bullee are working hard to put the necessary infrastructure in to get the housing in there.

“These things don’t happen overnight.”The Open Camp Lodge in town is busy and new temporary camps are pop-

ping up in places beyond the town limits.“Even in town, people are putting up their RV trailers. It’s just a tremendous

squeeze,” said Enns-Wind.“We have crowed housing – six people to a house or something like that.”Enbridge Inc, Inter Pipeline Ltd and Torq Transloading Inc. are expected to

launch major infrastructure projects in the Kindersley-Kerrobert area within the next 12 months and put a choke hold on the housing market.

Construction is underway on another three storey expansion at the Kinder-sley Inn that will add 76 single and double rooms to its footprint sometime in 2015.

A new 100-room hotel will also be build on land recently sold to West Fra-ser Developments on 12th Ave., one block north of busy Highway 7 east.

The hotel site is adjacent to the new Guppy’s Car and Truck Wash Spa.Meanwhile, construction is proceeding on the new Snow White Inn with

Highway 7 frontage.Canalta Hotels has just announced plans to build a new 84-room hotel

along with a truck stop in Holland Park fronting Highway 7 west of Highway 21.

The deal hinged on the developer and property owner making upgrades to the sewage lift system to handle the extra load from the new hotel development.

At least one more motel expansion is due to be announced soon at Holland Park as the demand for rental rooms continues to grow.

“They are important and they’re coming on,” said Enns-Wind on new ho-tels.

“Some of them probably won’t be ready for about a year, so we are still going to have a critical shortage next year.”

Growth according to Enns-Wind is a challenge for the municipality, but he said the town is up to it.

“We’re trying our best. We’ve completed a growth plan, so we know where our infrastructure is at – what we can yes to or what we can no to.

“Our philosophy is how do we get to yes?The inclusive Growth Plan covers all of the bases that will help temporary

residents become full time citizens and provide a range of services and facilities that will make it attractive for families to live in town permanently.

“Families are looking for different qualities in a community and we’re trying to address that in a number of different ways,” said Enns-Wind.

A committee is investigating potential fundraising for a portion of an in-door pool with a $27.7 million price tag.

The town would seek borrowing approval from the Saskatchewan Municipal Board to cover the balance.

Building a cheaper outdoor pool is also open for discussion as the town needs “significant money for a sewage lagoon, landfill, and fire hall” in the words of Enns-Wind among its many infrastructure needs.

Enns-Wind said new businesses in town also need new infrastructure which make prioritizing and budgeting a tough task.

“You can’t grow or sustain what the businesses are doing for growth, if we don’t have the appropriate infrastructure,” he pointed out.

“We’ve had to make some decisions beyond the budget to spend some major money to develop the infrastructure to ensure that the growth can go forward without too many problems.”

Asked if he wished he didn’t have to face daily growth issues from the oil and agriculture industries in the region, Enns-Wind said: “I would much rather be a mayor of a growing town than the mayor of a dying town.”

The value of building permits up to August 2014 was $6.8 million not in-cluding the newly announced hotel developments.

Work is proceeding on the new East Crossing retail development near the Walmart complex with local labour shortages an issue for many businesses in town.

Enns-Wind said Council sent a resolution earlier this year to local provin-cial and federal government officials to lobby for viable changes to the Tempo-rary Foreign Worker Program on behalf of local businesses.

“So they are concerned with a reduced level of service – how will that affect their ability to make payments for various expansions and things like that,” said Enns-Wind.

“So we have been advocating on behalf of our local businesses that we need some changes there to ensure the community can grow and continue to service one another.”

Kindersley stares growth in the face

Kindersley Mayor John

---


Proudly serving Lloydminster Area for over 20 Years

Calgary – Produc-tion gains from heavy oil thermal projects in the Lloydminster area helped Husky Energy to generate a second quarter profi t of $628 million, up from $605 million a year ago.

“We’ve had an-other quarter of steady consistent performance and we continue ac-cording to plan,” said CEO Asim Ghosh in a conference call from Calgary on July 24.

“Our continued investment in longer-wavelength projects such as heavy oil ther-mals, resource plays and oil sands provide steady production and more predictable cash fl ow to support our growth projects in the Asia Pacifi c and the Atlantic regions.”

Production in the quarter was boosted by new high-yield thermal projects in the Lloydminster region and strong results from resource plays in West-ern Canada and the startup of the Liwan Gas project.

Upstream produc-tion averaged 334,000 barrels of oil equivalent per day, up eight per cent from the same period a year ago.

Husky’s suite of thermal projects in the Lloydminster region continued to build mo-mentum over the second quarter with production reaching about 44,000 barrels of oil per day.

Th e company has a goal to produce 80,000 bpd from thermal by 2019 as new and exist-ing short term, mid-term and long term projects in the region come into play.

“We are seeing exceptionally strong performance from our latest thermal project at Sandall,” said Ghosh.

Sandall came online ahead of schedule in the fi rst quarter and is exceeding its design ca-pacity of 3,500 bpd that with an average produc-tion rate of 5,300 bpd.

“Sandall is part of a long line of thermal projects either in pro-duction or in planning with a lot of running room in terms of at-tractive metrics,” said Ghosh.

“Th ese are lon-ger wave projects that underpin the rest of our portfolio by providing a steady production base and more predictable cash fl ow.”

Meanwhile con-struction of the 10,000 bpd Rush Lake ther-mal project sanctioned in 2013 is 55 per cent complete.

“We’ve completed drilling the fi rst two pads and have con-fi rmed the excellent quality of this reservoir as we work towards fi rst oil in the second half of 2015,” said COO Rob Peabody.

Site clearing and module fabrication is currently underway at two 10,000 barrels per day projects at Edam East and Vawn.

“We are also ad-vancing Edam West, a 3,500 bpd project which is being built using the same modular template as Paradise Hill and Sandall,” Peabody told investors.

“All three of these projects are scheduled to start up in 2016 begin-ning with Edam East.”

Husky also drilled four horizontal heavy oil wells in the Lloydmin-ster area in the quarter bringing the total to 27 wells drilled to date in 2014.

Th e company’s Western Canadian op-erations encountered no production delays over spring breakup during the quarter.

Production from an extensive liquids-rich gas and oil resource portfolio averaged 32,500 boepd compared to 24,700 boepd in the second quarter of 2013.

Looking ahead, Husky expects third party turnarounds at its Ansell liquids rich play in Alberta to impact production in the third quarter for several weeks.

Planning is under-way for an additional four-well pad at Ansell later this year

Results from a four-well pad and a two-well pad at Kaybob in the Duvernay continued to be monitored in the quarter as the play is tweaked for greater pro-ductivity and effi ciency.

At the Wilrich

liquids-rich gas play at Kakwa, three horizontal gas wells were drilled and three wells were completed during the second quarter.

At the Strachan Cardium play, two hori-zontal gas wells were completed with further development drilling scheduled later in 2014.

Th ree horizontal oil wells were drilled and three completed in the second quarter, with ac-tivity primarily focused on the Viking and Car-dium oil resource plays.

A four-well pad at Wapiti Cardium is delivering good results, and the Husky has ex-panded its land position on the play to add more drilling locations.

Th e fi rst phase of the Sunrise oilsands project is progressing towards startup this year with all of the regula-tory approvals including the maximum operating pressure permit in place.

Everything from the well pads, diluent, diluted bitumen and gathering pipelines is proceeding through the commissioning stage.

In downstream op-erations Husky expects construction progress during the quarter on two 300,000-barrel stor-age tanks and new pipe interconnections will be

completed in 2015.Plans are underway

to extend Husky’s south Saskatchewan gathering system to accommodate increased heavy oil ther-mal production from Rush Lake, Edam West, Edam East and Vawn.

Th roughputs at the downstream refi neries and the Lloydminster upgrader were 304,000 barrels per day in the

quarter compared to 317,000 bpd in the sec-ond quarter of 2013.

Th e Lloydminster upgrader will undergo a partial 42-day outage scheduled this fall with operating capacity to be maintained at about 80 per cent.

Th e Lloydminster upgrader contrib-uted $49 million to net earnings in the second

quarter compared to $88 million a year ago.

“Th is takes into account a longer than anticipated ramp up in April as well as lower upgrading diff erentials driven by higher feed-stock costs,” said acting CFO Darren Andruko.

“Th e higher heavy oil price was in turn captured in the up-stream business.”


Summer Savings

By Geoff Lee

Vermilion – Th e Alberta Electric System Operator is recommending the construction of two high voltage transmission lines in the East Central Alberta region to meet the demand for power from pipelines and new power generation plants.

AESO fears customers in the region face an increased risk of power outages without the transmission upgrades.

“Th e system will allow power to fl ow to where it’s needed within the east central Alberta area and to other parts of the grid when it’s needed,” said AESO spokesperson Matt Gray at the fi rst of two open houses in Vermilion on Aug. 7

AESO held open houses in vari-ous regional communities from Aug. 5 to 27 to seek public support for the need to build two 240 kilovolt trans-mission lines.

Th e proposed lines will connect fi ve service points from east of Red Deer to Vermilion and from Edgerton to Provost.

“Mostly the demand we’re seeing in our forecasting, which is what we use to plan our system, is coming from pipeline growth – pump stations that move the product through the pipeline,” said Gray.

“Each of them uses about 25 megawatts which is about three times as much as the town of Vermilion would use.”

Maps show the location of planned high-load projects such as TransCanada Corp.’s Keystone XL pump station, Enbridge Inc.’s Heart-land pump station and upgrades to ATCO’s Irish Creek substation.

New planned power generation projects in the region led by wind power projects also support the need for improved transmission.

Th e needs assessment includes a proposed 120 megawatt Grizzly Bear wind farm by E.ON southwest of Vermilion and a 150 MW Main-stream Wainwright wind project.

Th ere are also plans from Rocky Mountain Power for the Alberta Sas-katchewan Intertie Storage (ASISt) project in Lloydminster.

Rocky Mountain plans to con-sume electricity when prices are low and use a salt cavern to store com-pressed air that would generate up to 160 MW of power from a turbine when prices are high.

Th e main regional coal-fi red pow-er plant near Battle River generates 700 MW, but Gray said the demand in the area peaks at 880 MW.

Th e existing system of 138 to 144 Kv transmission lines is too weak to support a forecasted regional power demand increase of two per cent a year for the next 20 years.

“When you look at not only what the demand for power is in the future, but also the interest in devel-oping power generation to satisfy the demand for power in the area, you see that also burdening the system,” said Gray

“It basically requires a stronger system than we have right now.

“We rely pretty heavily on our forecast so there are a number of diff erent things that we look at when we’re doing it.

“Th ese include economic indi-cators and population and industry growth. We also see demand increas-ing from regional centres – towns growing and that sort of thing along with some residential growth.”

Gray noted AESO is seeing growth and power demand along the Highway 41 oilfi eld corridor that runs from the Wainwright and Provost ar-eas north through Vermilion towards Bonnyville. Page A27

Pump stations drive power line needs


Ramaiah Divi, the lead planner with the Alberta Electric System Operator’s East Central Alberta Transmission De-velopment plan explains the need to construct two 240 Kv transmission lines to meet the growing demand for

Page A26

“Th ere is an oil transportation corridor there that is contrib-uting to the demand forecast,” he said.

Comments received from the open house will pave the way for AESO to submit its needs application to the Alberta Utilities Com-mission by the end of 2014.

“We want to tell the public that there is a new project coming in this area so we are giving them a heads up,” said Ramaiah Divi, AESO’s

lead planner.“It is an extremely

exciting project because it helps the local area to move excess wind power from this area to the rest of Alberta.

“It will also serve the pipeline loads in this area. Th e oil and gas industry are the major drivers for load growth in this region.

“It provides the energy capacity not only for the current proj-ects, but we are looking beyond 2030 to 2050 periods.

“Th e two 240Kv will serve the area for a long

period of time.”While the AUC

is reviewing the needs assessment, transmission facility owners ATCO and AltaLink will determine the routes for two 240 Kv transmission lines and the locations of substations.

“Th ey will com-ing back and knocking on doors telling people where exactly the lines will be built,” said Divi.

Th e routing process is expected to begin in 2015 and take about a year to complete with more public consultation to follow.

Once AUC ap-proves the project they will issue a permit and a licence to ATCO and AltaLink to build the lines with an expected in-service date some-time in 2017 or 2018.

Th e AUC approved the fi rst East Central Alberta Transmission Development plan in 2011, but changes in the location, size and timing of power generation and power load projects brought AESO back to the drawing board.

AESO applied to the AUC earlier in the year to rescind parts of the plan that no longer meet the long-term transmission needs in the area.


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Calgary – TransCanada Corporation is helping to train welders, pipefi tters and apprentices across Canada in advance of constructing its proposed Energy East oil pipeline.

Th e company has linked forces with the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry of the USA and Canada to launch a new pipeline training pro-gram in Canada.

TransCanada is donating 24 sections of 42-inch diameter pipe to be used in building new sections of the Energy East pipeline to eight UA locations in Canada for pipe welding and cutting practice.

“TransCanada is committed to supporting the development of training programs that address the signifi cant workforce needs of the pipeline indus-try,” said Bob Eadie, Energy East project director in a July 29 announcement in Toronto.

“We are very excited to work with the UA on training programs, and look forward to developing further relationships that build up the number of welders whose skills and techniques go above and beyond industry standards.”

Sections of pipe line are being donated to UA locations in Edmonton, Winnipeg, Toronto, Th under Bay, Sarnia, Montreal, Miramichi and Dartmouth.

Highly-skilled welders will be a key part of important pipeline projects such as Energy East.

Th e UA has a signifi cant role in preparing fu-ture generations for important job opportunities as pipeline professionals with expertise in their fi eld.

Th is new national program will enable welders, pipefi tters and apprentices to continue to obtain the advanced training and upgrading in pipe welding and cutting they require to work in the pipeline construction industry.

“Th e considerable amount of pipe that Trans-Canada is off ering our training schools across the country will allow our journeymen and apprentices to cut and weld pipe as if they were working in the fi eld,” said John Telford, director of Canadian af-fairs for the UA.

“Th is donation also allows the UA to redirect a large portion of its training monies towards in-creasing the number of instructors to train a new generation of outstanding pipeline welders, jour-neymen and apprentices.”

TransCanada submitted an initial project description of Energy East to the National Energy Board in March 2014 and expects to submit an ap-plication to the board seeking regulatory approval this summer.

Th e Energy East pipeline will transport 1.1 million barrels of oil per day from Alberta and Saskatchewan to refi neries and port terminals in Quebec, Nova Scotia and New Brunswick.

Th e $12-billion project involves the conversion of a portion of 3,000 kilometres of the Canadian Mainline to oil transportation and the construction of 1,600 km of new pipeline.

TransCanada estimates the project will cre-ate more than 10,000 jobs during its development and construction, and generate billions of dollars in spin-off jobs and tax revenues for communities along the pipeline’s route.

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Calgary – Th e Alberta Energy Regulator blames Canadian Natural Resources’ steaming strategy and wellbore issues as the root causes of ongoing ground to surface bitumen emulsion leaks at the Primrose oilsands near Cold Lake.

AER restrictions on steaming activity at Primrose East and within one kilometre of Prim-rose South will remain in place pending action by CNRL to provent further seepages.

Th e AER on July 22 released the results of an independent technical report of CNRL’s own four cause report on the leaks submitted to the regula-tor on June 27.

Th e AER has determined the two main en-abling factors are CRNL’s steaming strategy and wellbore issues.

Th e independent technical review indicated that CNRL’s strategy to inject large volumes of steam at fracture pressure in closely spaced wells was a fundamental cause of the seepages.

“Our assessment of the reports leads us to

believe that these fl ow-to-surface events can be prevented if proper mitigation measures are put in place,” said AER president and CEO Jim Ellis.

“Th at said, the AER is not prepared to approve a return to full operations at these sites until all potential risks are addressed and proper require-ments are in place to avoid a similar incident.

“Th is will require a gradual, step-by-step ap-proach that allows us to manage those risks.”

Crews have recovered over 7,421 barrels of bitumen emulsion from four surface leaks at Prim-rose reported to AER since last spring.

Th e bitumen release aff ected 20.7 hectares at the east and south sections of CNRL’s Primrose project is contained but cleanup eff orts are ongo-ing.

Th e AER ordered CNRL to suspend and re-strict steaming operations at the four sites last July until the cause of the leaks could be determined.

At a site tour last August CNRL offi cials told the media and the regulator they believed the cause

of the seepage to be a mechanical failure of well-bores similar to a 2009 leak at Primrose.

CNRL produces bitumen at Primrose East and Primrose South using cyclic steam stimula-tion with just one horizontal wellbore required for steaming and production on alternating cycles.

Wells are steamed for several weeks to mobi-lize the heavy oil followed by a production phase of several months.

Erin Flanagan, an analyst at the environmen-tal Pembina Institute, said the AER fi ndings “call into question whether high-pressure cyclic steam stimulation activity should be permitted at the CNRL Primrose facility.

“Th is technical report confi rms that CNRL’s project design and operation are the root cause of bitumen emulsion coming to the surface,” he said in a news release.

“Th e fi rst such fl ow-to-surface event happened in 2009, and the leaks currently in question started in June 2013. Page A32

The Alberta Energy Regulator asserts the root cause of four seepage of bitumen to surface are CNRL’s steam strategy and wellbore issues following a review of an inde-pendent study of CNRL’s own four cause report to the AER. Crews were hard at work last August recovering between 1 and 2 cubic metres a day of bitumen emulsion from

File photo

AER blames leaks on CNRL steam strategy

The Alberta Energy Regular has released the results of an independent review of CNRL’s own report of the probable causes of ground to surface leaks at CNRL’s Primrose oil-

bitumen emulsion seeping to the surface. File photo

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Page A31

“The technical review has identified CNRL’s steam injection volumes and well spacing as key contributors to these leaks.

“Given these findings, we urge the AER to broaden the technical review to include the entire CNRL high-pressure cyclic steam stimula-tion project.

“This will help ensure that

the public and the environment is protected from the risk of similar accidents.”

The AER investigation is ongo-ing.

CNRL's and the panel and the panel that conducted the indepen-dent technical review continue to collect and analyze data.

They will submit final reports to the AER in September once all the data have been analyzed.

Volumes and spacingskey to leaks

This is a recent photo of well pad at Cenovus’s steam-assisted gravity drainage opera-

Calgary – Cenovus Energy Inc. is on track to ship 30,000 barrels per day of crude oil by rail by the end of 2014 as it focuses on improving market access.

The company announced it shipped eight unit trains of crude oil in the first half of the year during the release of its second quarter results on July 30.

They also loaded their first unit train at the new Hardisty Rail Terminal in the second quarter.

The Hardisty crude-by-rail terminal is a project between Gibson Energy Inc. and USD Group LLC that was commissioned on June 30.

Meanwhile, crude-by-rail shipments from the Canexus facility near Bruderheim to tie-in Cenovus’s Cold Lake pipeline volumes have been side-tracked pending completion of maintenance work at the site.

“We anticipate this work will be completed in the fourth quarter and we resume shipping from the Canexus facility at the end of that time,” said John Brannan executive vice president and CEO.

“Overall our quarter was sound and we continue to focus of delivering dependable performance.” Page A33

Cenovus grows crude- by-rail transportation

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Page A32

Cenovus more than tripled its profi ts to $615 million from $179 million a year ago.

Oilsands produc-tion driven by the Christina Lake project averaged 125,000 bpd net in the second quar-ter, up 33 per cent from the previous year.

Th e company is also hiring new transporta-tion expertise to its leadership team to help it move some its grow-ing thermal oil produc-tion in northern Alberta to market by rail.

“One of our prime areas of focus is im-proving marketing access. We have recently strengthened our lead-ership in this area,” said Brian Ferguson Ceno-vus’s chief executive.

Ferguson told the quarterly conference that Robert Pease had joined Cenovus in June as the executive vice-president, markets and transportation.

Pease brings to the job 34 years of experi-ence in refi ning, mar-keting and transporting oil.

He responsible for developing and execut-ing strategies that will help Cenovus maximize the return it receives for its products.

Kent Avery has also recently joined Ceno-vus’s management team as vice-president of rail.

Avery will support Cenovus’s growing ca-pacity to ship crude oil by rail to access higher value markets.

He has exten-sive experience in rail

operations and business development involving the transportation of oil and other petroleum products.

In pipeline trans-portation, Cenovus and ConnocoPhillipps have a transportation agree-ment in place with Inter Pipeline Ltd. (IPL) through their oilsands partnership to receive up to 350,000 barrels per day of diluent via the new Polaris East pipeline.

Deliveries on the Polaris line began at Foster Creek in July and are expected to begin at Christina Lake in September.

Th ese deliveries are expected to increase over the next few years as the company’s dilu-ent needs grow.

Th e agreement also includes future diluent deliveries to the Nar-rows Lake project.

Th e partnership also

has an agreement in place with IPL to ship up to 500,000 bpd of oil blend via the planned Cold Lake pipeline expansion.

Oil blend deliver-ies on the Cold Lake

expansion are expected to commence in early 2015.

Th e agreement also includes future oil blend shipping capacity from the partnership’s Nar-rows Lake project.

Cenovus has com-mitted to ship 75,000 bpd on Enbridge’s Flanagan South sys-tem and expects to start moving an initial 50,000 bpd in the sec-ond half of 2014.

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Th e wells are producing from the Bakken, Frobisher, Midale, and Ratcliff e Formations, and several of the lands off er additional Bakken hori-zontal potential. Th e properties are generating a combined cash fl ow of approximately $700,000 per year.


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Vancouver – Saturn Minerals Inc. hopes to raise $10 million through a sale of flow through units to fund further exploration of its Bannock Creek and Little Swan oil and gas properties in south eastern Saskatchewan.

The Vancouver-based coal and oil and gas company has entered into an agreement with EMD Financial for a brokered private placement of a combination of shares and non flow through share warrants.

In May, Saturn teamed up with Vector Ex-ploration Corp. in Calgary to form a joint venture agreement with a 50-50 working interest in the Bannock Creek and Little Swan properties.

The two properties are two of the largest oil and gas permits in the province covering 370,000 acres.

The joint venture holdings include 250,000 acres at Little Swan and 100,000 acres at Bannock Creek.

Reservoirs on permit lands include the entire geological section form Devonian to Cambrian which present “multi-stacked targets” or formations.

These include the Duperow, Souris River, Win-nipegosis, Interlake, Red River (Yeoman Forma-

tion), Winnipeg Group (Black Island Formation) and Deadwood formations.

Saturn and Vector will use the proceeds from the sale of flow through units to drill vertical explo-ration wells into the multi-stack targets.

Saturn has also made three shallow bituminous coal discoveries since 2009 with coal seams rang-ing in continuous vertical thickness from nine to 89 meters.

Saturn has a strategic ownership in Inowending Exploration & Development Corp., a First Na-tions owned exploration and development company based in Saskatoon.

Inowending Exploration is helping to develop the Armit coal project in eastern Saskatchewan.

The project is owned 87.5 per cent by Saturn and 12.5 per cent by Inowending Exploration The project is 13,000 acres in size and hosts the Leif coal seam which was discovered in 2010.

Inowending Exploration was co-founded by Saturn in October 2011 with Fishing Lake First Nation, Kinistin Saulteaux Nation, Key First Na-tion and Yellowquill First Nation.

Each founding partner including Saturn holds

a 20 per cent interest in Inowending touted as being first mineral exploration company to be co-owned by industry and First Nations.

Saturn also has a 100 working interest in the Overflowing and Rat Creek coal projects in western Manitoba and an 80 per cent working interest in the Red Earth coal project in eastern Saskatchewan.

Saturn orbits Saskatchewan oil pools

Calgary – Tuscany Energy is currently drilling a series of five new heavy oil wells in west-central Saskatchewan flush with cash from the recent clo-sure of $3 million in financing.

The new drilling program will build on Tus-cany’s average sales volumes of 750 barrels of oil equivalent per day during the second quarter of 2014.

The Calgary based company reported it began drilling the first new well in late July targeting a Dina formation prospect at Rutland, Sask.

Tuscany will pay 50 per cent of the drilling costs while retaining a 75 per cent working interest in the well and lands covering this new prospect.

The company will be the operator of all five wells to be drilled according to an operational up-date provided on July 29.

After the Rutland well Tuscany plans to drill two (1.2 net) horizontal development wells on its Evesham, Sask. oil property.

The wells will be drilled as 50 metre offsets from the most productive wells drilled on the prop-erty to date.

Each of these wells has produced over 30,000 barrels of oil since being placed on production in September 2013 and are currently producing at an average rate of approximately 100 barrels of oil per well.

The five well drill program will wrap up with the drilling of two net horizontal development wells on its oil property at Macklin.

The wells will offset another Macklin well which was placed on production in March 2014.

That earlier well has produced over 15,000 bbls of oil to date, and is producing at a rate of approxi-mately 95 bpd.

Tuscany plans to continue its development program in its core areas of Evesham and Macklin during the balance of the year and plans to com-mence drilling on its portfolio of new prospects before the end of the year.

Tuscany funds drilling near Macklin


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Lampman – Across the road from the scrapers and bulldoz-

ers doing grading work on the new Estevan Truck bypass, another

construction crew could be found. They were laying 14 inches of

gravel on two layer of geotextile. The sign on the site indicated this would be the new home of Campbell Oilfield Rentals.

Jason Frederick is the manager of Camp-bell’s Lampman loca-tion, the branch that will be relocating to Estevan.

Campbell carries drilling centrifuges and wellsite trailers. They also have 400 barrel rental tanks within the company, but not in Lampman.

The company has been operating in south-east Saskatchewan since 2009.

Frederick said the new location, is “more centralized, with sup-plies at our fingertips instead of driving to town.”

The new location will have a yard twice their current size. Along with a larger yard will be

a much larger shop, one that will be able to bring a wellsite trailer indoors for work. Initially it will have the office inside the four walls, but there are future expansion plans to build office space onto one corner.

The building will be a pre-fabricated steel building. Assembly started mid-August.

“We’ve got four guys plus myself,” Frederick said. The fleet includes 55 wellsite trailers, and 11 cen-trifuges mounted on hydraulic stands.

“Our newest piece

of equipment is a combo floc tank,” he said. That’s a four-sided, 60 cubic metre tank with an integrated hydraulic stand centrifuge and a polymer injection tank, all on one skid.”

The bypass location was inviting, accord-ing to Frederick, ideally located adjacent to the new truck route. It will have easy access for all heavy loads and not be affected by road bans.

The plan is to be in the new facility by Feb. 15, 2015. “Hopefully we’ll be there by break-up,” he said.


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EDMONTON

17327 106A Avenue

Edmonton, Alberta T5S 1M7

Phone: 780.481.3399

Fax: 780.481.3841

GRANDE PRAIRIE

11417 91st Avenue

Grande Prairie, Alberta T8V 5Z3

Phone: 780.532.6793

Fax: 780.532.7694

LLOYDMINSTER

1812 50th Avenue

Bay 10

Lloydminster, Alberta T9V 2W7

Phone: 780.875.6130

Fax: 780.875.1658

RED DEER

303A, 4406 50 Avenue

Red Deer, Alberta T4N 3Z6

Phone: 780.236.1603

MEDICINE HAT

1601 Dunmore Road S.E.

Suite 202

Medicine Hat, Alberta T1A 1Z8

Phone: 403.528.4215

Fax: 403.528.4287

HIGH LEVEL (FIELD OFFICE)

High Level, Alberta

Phone: 708.926.4123

Fax: 780.926.4550

REGINA

311 Albert Street

Regina, Saskatchewan S4R 2N6

Phone: 306.522.5628

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226 Cardinal Crescent

Saskatoon, Saskatchewan

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300 Begg Street West

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38 Smith Street

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100 - 158 11th Street

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By Carter Haydu(Daily Oil Bulletin) Churchill, Man. – Omni-

TRAX Canada is suspending plans to ship crude oil through to the Port of Churchill for the fore-seeable future, the company announced in mid-August.

“I don’t even want to hear about oil for the next two to five years,” Merv Tweed, president of Om-niTRAX Canada, told the Bulletin, a sister publica-tion of Pipeline News.

“We’re intent focusing on the grain industry and other markets, and oil is just not part of our plan at this point in time.”

The company was considering plans to make the Manitoba Hudson Bay seaport a northern ex-port link for crude oil, since the port could connect with many markets around the world as it has done for several years with Canadian wheat products.

On Aug. 15, though, Tweed announced the de-cision to suspend crude-by-rail initiatives, partially based on the fact grain shippers are willing to com-mit long-term orders in contracts of over 700,000 metric tonnes, which is a result of overall market growth. With last year’s record crop, the company is preparing for another strong shipping season.

The former Conservative MP noted that

consultations with First Nations, Métis and the Manitoba government were also important factors in the company’s decision to suspend its potential crude-by-rail business.

“I just think there are a lot of variables that need to be dealt with over time. As we continue to grow our business at the port, and then along the rail, it will give us the opportunity to review and look at any new opportunities as well,” said Tweed.

“But as of last week, we’ve made the decision that we are going to focus on what we have done best over the last several years.”

Page A37


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Eric Reder, Manitoba campaign director for the Wilderness Committee, said even though OmniTRAX is postponing plans to freight crude to the Manitoba coast, the environmental group would continue pursuing legislation to forever ban shipment of crude through the northern part of the province and onto Hudson Bay.

“Th ey could again change their mind next shipping season and start trying to put their plan into action,” he said, adding the bay region off the Churchill coast is too important for beluga whales and polar bears to allow crude shipments that could prove very diffi cult to clean up from ice-covered waters in the event of a spill.

“What we need to do is we need to ensure that we don’t ever ship crude oil through this area. We don’t have oil exploration through Hudson Bay and we don’t have anyone shipping crude oil through this region, and so we don’t need to put oil in this direction.”

According to Reder, there are multiple govern-ments that could enact legislation prohibiting any potential future movement of crude from Churchill and through Hudson Bay, including the Province of Manitoba, the feds, as well as Nunavut Territory.

He told the DOB that climate change is another reason Wilderness Committee wants to permanently prohibit crude shipments through Hudson Bay.

“Not shipping crude through this region means that we’re not making oil readily available for ev-eryone to say, ‘Oh, we have this cheap energy right here, right now.’ Th e climate-change reason for deciding to not ship oil through this region is a big deal, and the people in the North feel that climate-change impact.”

Moving oil on tracks atop the permafrost is also an issue, due to the shifting nature of the ground, posing a risk for trains, Reder said. He added that news of the crude-freight cancellation was “bitter-sweet” for environmentalists, as it came following the derailment of a grain-shipping train headed to the Port of Churchill the previous week, which he believes demonstrates the unsuitability of the train tracks for freighting oil.

However, Tweed said that derailment was not the reason for OmniTRAX postponing plans to pursue the shipment of crude to Churchill, as it is an issue his company has been debating for the past several months.

Tweed said, “I have been tasked by the compa-ny to fi nd new opportunities, and we were encour-aged by the federal and provincial governments to look at transporting oil. We did that.

“We did a lot of studies, and a lot of the studies we continue to do are for the improvement of the

line and the service we provide. We will continue with those studies, but it won’t be necessarily fo-cused on the oil side.”

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Arcola – Stopping at the Arcola Co-op to fuel up, and maybe pick up some chips and a pop, a quick glance past those chips shows something you’re not likely to find at a typical convenience store. There’s an aisle full of fire retardant coveralls, hard hats, safety boots and gloves.

Heather Penney, hardware manager trainee, is responsible for the inter-esting mix of wares. She used to work for another company that sold similar products. Having joined the Co-op in March 2013, Penney set about bringing in more selection.

In addition to the fire-retardant coveralls, there are also insulated fire-retardant bibs and parkas. Along the same lines one can find fire-retardant tear-away hoodies. Across the aisle are composite safety boots and conventional safety boots. “There’s even steel-toed cowboy-style boots,” Penney pointed out.

“When I came, they had a tiny section with coveralls, just a few that were FR,” she said. “There was no rain gear or anything.”

Now there’s an extensive glove section which includes the ubiquitous Red Barons that are standard winter wear.

“My biggest season is the end of August to March and April.” Winter gear coming in this fall includes balaclavas, hoods and hard hat lin-

ers. There’s already a selection of Bama socks, popular for keeping toes warm.The store benefits from being more than just as gas station and conve-

nience store. It’s also the local Co-op hardware store, with things like hammers, swather knives and other hardware.

“We’re in a prime spot, from Stoughton to beyond Carlyle,” Penney said. “We’re right on the highway.”

That means workers who stop for coffee or a quick snack will stop and see the work wear section.

“It’s convenient. Just grab your stuff and go,” she said.“Especially in the morning, it’s crazy. Sometimes lunch hour, too, and then

again at the end of the day. The busiest is in the morning. Penney noted her manager has been impressed with the results, and has

noted, “If you think it will sell, bring it in.”


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By Brian ZinchukEstevan – If you

want to lift bigger things, you’re going to need a bigger crane.

For Estevan-based Skylift Service Inc., that comes in the form

of a new 245-ton (220 metric tonne) crane, now the largest locally based crane in south-east Saskatchewan.

Th e model is a Terex Demag Explorer 5800.

“It comes out of the Demag factory in Germany. Every nut and bolt came from Germany,” said Dwight Packer, owner.

Th e new crane is an “all terrain crane.” It’s not as off -road as a “rough terrain crane,”

but it’s more mobile and more agile than a “mobile crane.”

Th e confi guration is a hydraulic crane on a wheeled carrier. It uses a “pinning boom.” Th e cylinder pushes out one section, which is then pinned into place.

It then pulls back and pushes out the next sec-tion. It’s a little slower than having all sections able to move at once, but there are advan-tages to the trade-off in speed.

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cylinder the boom to extend every section,” Packer explained. Th ere are six live sections.

“Th e advantage is you don’t have all that weight. You have a hollow boom and more capacity.”

Page A42


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Page A41The main boom is

230 feet long. A 108 foot jib can be added, for a total tip height of 350 feet.

“We can reach the top of the stacks at Boundary Dam Power station (with a

jib). That’s new for us,” Packer said.

The new Explorer has twice the lifting capacity of Skylift’s previous heavy lifter, a 120-ton unit.

“For many years, we contemplated buying a bigger machine,” said Packer. “We do have some projects coming up.”

He noted that Skylift has turned down some work for big-ger cranes in the past. “We’re finally ready to make the move,” he said.

“We don’t overlift. The machines need to be looked after. Either you can do it to the machine’s capability, or you can’t.

There are often a variety of ways to accomplish the same thing. As an example, moving a 50,000 pound building can be done with two cranes in a tandem lift. The larger unit allows one crane to do the lift instead.

“In some cases, we’ll get new work,” he said. “One project coming up requires this crane.”

That project in-volves lifting a new incinerator. Packer said, “The incinerator is a high lift. It’s not such

a heavy lift. You need a pretty big crane to do this.”

A major consider-ation for the new crane was its ability to work without a lot of support vehicles. It has suf-ficient counterweight built in that it doesn’t need to add additional counterweights every time. When they are needed, a big lift will require three loads of counterweight, totalling 155,000 pounds.

For small jobs, the crane will go out with an operator and swamper and at least a pickup truck. The most extreme heavy-lift scenario requires an additional semi with one trailer and a sec-ond pulling a B-train, carrying counterweight. As of mid-August, the dolly was still on its way.

“It can do a job without additional counterweight. IT has a good zero counter-weight (rating),” he said.

The new crane went into operation in early August.

Including cranes and boom trucks, Skylift has 16 units in opera-tion, from the tiny “spi-der” crane to the new 245-ton.


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NEWSPIPELINE SECTION B

September 2014

By Brian ZinchukNorthgate – Th is fall will see the Ceres North-

gate Commodity Logistics Hub go into operation after nearly a year-and-a-quarter of work on the site.

Th e location, physically touching the U.S. border, is unique in many ways. It links to the BNSF railway, the American juggernaut of crude-by-rail shipments out of the North Dakota Bakken. Th is provides shippers, both exporting and importing, a third option beyond the Canadian Pacifi c and CN railways, and a much broader access to American markets.

Th e demise of the Canadian Wheat Board as the sole marketing arm for Canadian wheat was one of the driving factors behind this new rail hub. It will start out with a temporary grain elevator and then see a much larger terminal built in the near future. Th ere are provisions for crude-by-rail loading, frac sand, and nu-merous other commodities, both inbound and outbound.

Ceres underwent a change in its management team and board just as Pipeline News began prepara-tion for this edition, which was timed for the opening of completion of the Northgate facility as well as several other crude-by-rail facilities that were announced in

2013. As a result, former CEO Michael Detlefsen is out and a new CEO will be in place soon. In the interim, Douglas Speers, chairman of Ceres Global Ag, spoke for Toronto-based Ceres in response to our emailed ques-tions.

Pipeline News: As the Northgate Commodity Hub nears completion, can you tell us what was the motivation behind this project? What do you plan to accomplish with it?

Douglas Speers: Th e Northgate Commodity Logistics Hub will ease the bottleneck of getting commodities, including grains and energy prod-ucts, out of Saskatchewan and into new markets. We believe it will be a new and welcome option for farmers. Additionally, Northgate will provide an origination source for grain for our company, Riverland Ag Corporation.

P.N.: How important is crude-by-rail to Northgate?

D.S.: We anticipate energy products will even-tually be an important component of Northgate. Our new board of directors and management team are developing the energy transport strategy for

Northgate, and building on the signifi cant experi-ence we gained from investing in Stewart Southern Railway and transporting energy by rail.

(Editor’s note: Stewart Southern Railway is the Filmore-based shortline railway that runs from Stoughton to near Regina. In recent years its lead-ing commodity has become unit trains of crude-by-rail for Crescent Point Energy Corp., which operates its own loading facility near the Stoughton terminus of the line. Ceres owns one-quarter of SSR.)

P.N.: What about other oilpatch related com-modities, i.e. frac sand, pipe, NGLs, etc.? Can you elaborate on these, and possibly other future commodities down the pipe?

D.S.: As part of developing our energy trans-portation strategy, we’re currently examining oppor-tunities to bring other products onto the Northgate site.

P.N.: Will this facility be used to ship out North Dakota oil? What about other American products?

Page B2

Ceres Northgate Commodity Logistics Hub nears completion

Photos by Brian Zinchuk

B2 PIPELINE NEWS September 2014

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Page B1D.S.: No. This facility will be used to ship Canadian products such as grain

and energy products to North American markets, and potentially could be used to ship American energy-producing supplies to Canada.

P.N.: What will the crude-by-rail capacity be at first, and will that increase in the future? If so, when?

D.S.: We’re focussed on the grain operation at the moment and final-izing plans for the energy side of Northgate.

P.N.: Will the focus be on unit trains? If so, why?

D.S.: The site has been designed to handle unit trains, but limited shipment volumes in the early stages may dictate using a smaller number of cars. Northgate has the flexibility to handle both.

P.N.: If you loaded a unit train of crude oil in Northgate, where is it likely to end up?

D.S.: Our connection to BNSF’s 32,000 mile railway network, will give shippers direct access to customers in 28 states, numerous Pacific and Gulf ports, and Mexico. Additionally, we will have access to strategic interior locations and Atlantic ports.

P.N.: Why Northgate? How does the choice of being on the BNSF fac-tor into the location?

D.S.: Northgate provides a lot of opportunities for Western Canadian farmers to market their grains. Connecting to BNSF’s extensive rail network will provide an additional strategic marketing outlet for Western Canadian farmers and energy producers – especially in light of recent grain and energy logistics bottlenecks in the region.

P.N.: How much investment has gone into this project so far, and how much more do you forecast in the future as later phases are developed?

D.S.: The total capital cost of this project is approximately $90 million, and we expect the facility will be built out over three years.

P.N.: Lac-Mégantic, and then Casselton put something of a chill on crude-by-rail, and has caused a great deal of concern in the pub-lic. Have these incidents had any impact on your project, either in the economics, interest of shippers, or design?

D.S.: Safety and environmental protection has been foremost in the design of the Northgate Commodity Logistics Hub. All of the facilities at Northgate will meet all provincial and federal standards. We place the high-est priority on employee and public safety, environmental protection and good stewardship of the facility.

P.N.: Ceres is part of a major thrust in the development of crude-by-rail facilities throughout Sas-katchewan, Manitoba and Alberta capable of handling unit trains. If everything that was announced in 2013 gets built to its full speci-fication, Saskatchewan will have

enough crude-by-rail capacity to theoretically ship every drop of oil it

produces, plus an additional “Bakken boom,” without ever seeing a pipeline. Is that much capacity needed and/or sustainable?

We believe Northgate’s location provides a competitive advantage and the hub will be very attractive to farmers and energy producers. Northgate will enable Saskatchewan energy producers to access a cost-competitive point-of-entry into the lucrative US market.

Connected to BNSF, a third option to CN and CP

A worker grinds the welds securing to lengths of rail together.

B3PIPELINE NEWS September 2014

By Brian Zinchuk

Northgate – Large scale rail facilities like the Ceres Northgate Com-modity Logistics Hub don’t get built every day on the wind-swept Ca-nadian prairie, especially ones that expect to see a broad array of commodi-ties beyond just grain.

Douglas Speers, chairman of Toronto-based Ceres Global Ag, in consultation with their McHenry, Ill.-based rail consultants, Engineered Rail Solutions, detailed some of the considerations and challenges that have gone into the project. He responded to our e-mailed questions on Aug. 16.

A recent change in management at Ceres appears to have affected their plans for crude-by-rail, as the responses on that front are much less detailed than in the past. The company noted Ceres has a new board and new management team coming in and they’re conduct-ing the normal review of strategy and operations

you’d expect in this kind of changeover.

Pipeline News: What goes into design-ing a crude-by-rail facility? What are the considerations?

Douglas Speers: Designing a crude-by-rail facility involves a strong focus on both site topography and transportation logistics. Access to a Class 1 rail mainline and service levels from the railroad, as well as proximity to a highway, enable easy access for shipping and loading oil by truck to rail.

Site topography must be carefully taken into account, as the topography of the site and soil composition impact both the founda-tional requirements of a crude-by-rail facility, as well as the infrastructure design for systems such as storm water drainage. Finally, loading limits have to be considered – the inbound volume of oil per day will deter-mine the size of tanks

and the loading rack configuration. If the site is on a branch line, load-ing limits for the line must also be taken into consideration, as these dictate the amount of oil which can be trans-ported by each car.

P.N.: What were the challenges in build-ing on this site?

D.S.: Given the cross-border nature of this site, we had to look at how customs processes would af-fect our transportation activities. The location of the site posed several challenges as well – not only did the remoteness of the site mean that we needed to deal with limited telecommunica-tions abilities, housing and support facilities, but also that we were at the tail end of the Sask-Power grid. As such, we required new services to be provided from 11 miles away.

Page B4

Ceres Northgate Commodity Logistics Hub design explained


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Grain shipments expected to begin this fall Page B3

Th e site’s physical attributes were a challenge: the soil conditions of the site were highly variable, requiring close monitoring of the stripping and replacement of good foundational quality soils, and perched ground water added moisture to areas we weren’t expecting.

P.N.: Can you describe the design?D.S.: Th e site is designed to accommodate

multiple commodities, including energy products, grain, frac sand, pipe and casing, and other prod-ucts. Th e inside “loop” of the site will be used to load unit grain from a grain elevator, and the outer “loop” can be used for unit oil loading. Th e yard tracks will accommodate inbound merchandise trains, while the transload area can accommodate frac sand and product unloading facilities. All of our rail operations are designed to avoid confl icts and to allow BNSF access to the rails at all times.

P.N.: How important is a loop track in a terminal like this? Wouldn’t a Wye (triangular junction) have been easier and cheaper?

D.S.: For all unit trains, a continuous move-ment of the rail cars is important. As per railroad requirements, unit trains may not be “broken” or uncoupled, so a loop is the most conservative design for accommodating this. Consider that each rail car must go over/under the loading/unloading rack. When a loop track is used, the track needed is only slightly longer than the train itself. If a wye or straight track is used, the track must accommodate an entire train on both sides of the loading/unload-ing location. Th is requires track to be twice the length of the longest possible train, which would double costs for the facility.

P.N.: What is the capacity of this facility? How many trains might we see a week in full operation? Can you have multiple trains in opera-tion at once, i.e. grain handling, frac sand and oil loading?

D.S.: Th e facility can handle more than one train per day. Th ere is room to grow the facility beyond this based on business volumes.

P.N.: Can you go into detail on the crude-by-rail handling? Will it be truck-to-rail transload-ing, or truck to tank, then to rail etc.?

D.S.: Th e fi nal design has not been determined at this time.

Page B5


Page B4P.N.: We understand this is a phased project,

with lots of potential for future expansion. When you open this fall, how far along will it be? Will there be continual construction of additional phases ongoing for the foreseeable future?

D.S.: We anticipate that the facility will be up and running with grain in the fall of 2014.

P.N.: Th is site is right on the U.S. border. How did that aff ect the design, i.e. customs, bor-der crossing, etc.?

D.S.: Given the cross-border nature of this site, we had to accommodate customs requirements for both countries. Clearance for the design of the site and border crossing had to be given by both countries’ state departments, and we ad-hered to the railroad regulations of both Canada and the United States.

P.N.: In the wake of Lac-Mégantic and Casselton, were there any additional design considerations

implemented in this facility?D.S.: Right from the beginning, safety and

environmental protection has been foremost in the design of the Northgate Commodity Logistics Hub. All of the facilities at Northgate will meet all provincial and federal standards. Should regula-tions change further, Northgate will comply with all these changes. We place the highest priority on employee and public safety, environmental protec-tion and good stewardship of the facility.

P.N.: How long did it take to build, and how many workers at peak?

D.S.: Planning for the site began in spring 2012, and design began in fall 2012. Mass grad-

ing at the site began in May 2013, although an extremely wet summer resulted in soil

conditions which delayed completion of the mass grading until 2014. By the

end of 2013, we had constructed one kilometre of railroad,

and connected across the Canada/U.S. border on

May 8, 2014. During mass grading, we employed upwards of 45 operators, and have a large team of engineering, legal and administrative personnel who have been with us throughout the project.

P.N.: What sort of work was this? Mostly dirt work? Or was there something else?

D.S.: Mass grading at the site began in May 2013, although an extremely wet summer resulted in soil conditions which delayed completion of the mass grading until 2014. By the end of 2013, we had constructed one kilometer of railroad, and connected across the Canada/U.S. border on May 8, 2014.

P.N.: Did the site have any special features or challenges?

D.S.: We believe that this site was at the very tail end of a glacier, and multiple advances and retreats of the glacier age created many deposits of sand, organics, clay and cobble. As a result, we were dealing with challenging soil conditions throughout the project.


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Numerous compa-nies have come together to assemble the Ceres Northgate Commodity Logistics Hub.

Toronto-based Ceres Global Ag is the client behind the project.

Riverland Ag., a subsidiary of Ceres, is currently building the temporary grain eleva-tor and will be operat-ing the final, much larger grain handling facility once it is con-structed. FWS, which built a large number of the concrete grain terminals throughout

Saskatchewan over the last two decades, is the contractor.

Chiacgo area-based Engineered Rail Solu-tions is the program-ming engineering firm for the project, and has worked closely with Ceres in developing the concept.

Clifton Associates of Regina provided the civil engineering, geo-technical work, survey-ing and environmental services.

Kelly Panteluk Construction. Ltd of Estevan did the grading work, having as many

as 40 pieces of iron on site at a time.

Swift, an Ontario-based rail contractor, and North Dakota based R&R worked as a joint venture on the construction of the actual railway, includ-ing welding the track together and building it.

Outside of the Northgate facility itself, BNSF, the railway which Ceres links to, has spent millions of dollars over the last year-and-a-half up-grading its track from Minot to Northgate.

Northgate commodities, both inbound and outboundNorthgate – The

Ceres Northgate Com-modity Logistics Hub will have the capabil-ity of exporting and importing numerous commodities, should the need warrant and the appropriate facilities are built.

The facility has a unique feature: High-way 9 southbound leading to the hub was built to a much-higher standard, such that the southbound lane is substantially thicker than the northbound lane. This was done to accommodate potash shipments from Es-terhazy to Northgate, North Dakota, just across the border. In the past, potash was trucked down to Northgate, N.D., where it was loaded onto trains and then shipped on the BNSF network.

Truck access will be from a main gate off Highway 9, several hundred metres north of the Canadian Border Services.

Customs facilities will be in place for both Canadian and American customs agencies where the train crosses the international boundary. A security plan will be incorporated through-out.

Outbound Outbound ship-

ments start with grain, which will begin shipments this fall. A temporary elevator will be in place on the north end of the loop track. It will eventually be re-placed by a much larger grain facility which is

still being worked out.Crude-by-rail fa-

cilities are in the works, but its implementation has been re-evaluated based on the produc-tion of the surrounding region as well as new requirements to the shipment of oil. The design includes tankage on the west side of the site as well as loading racks which will allow for unit train loading of crude oil on the outer

loop track. The facility is designed with the intent that pipelines could enter from the west side, and a truck unloading facility would also be there, near the main gate.

There is also the possibility of ship-ping natural gas liquids (NGLs) from North-gate by rail. About 16 kilometres to the west, the Steel Reef gas plant is under construction,

with piles in place and racks going up. Due north of hub are the nearby Nottingham and Steelman gas plants. To the northeast, the two Glen Ewan gas plants are a little further away. Finally, to the north-west, the Kisbey and Viewfield gas plants are also about an hour’s drive away.

Potash is a possible export in the future, as is hay.

InboundTrain tracks run

in two directions, and Northgate also has the option of importing numerous commodities into the facility.

On the northwest corner of the site is a space allocated for frac

sand imports.Steel products

like oil country tu-bular goods, casing and tubing, have been mentioned as possible imports.

Fertilizer is another potential import.

Further out, cement has also been mentioned as a possible import into Northgate.

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There’s unit trains, and then there are unit trains By Brian Zinchuk

Northgate – Th ere’s unit trains, and then there are unit trains. Canadian railroads break theirs apart, but American railroads keep them together, and that makes a world of diff erence in effi ciency according to an American rail consulting fi rm involved in the design of the Ceres Northgate Commodity Logistics Hub.

Over the past two decades there has been an increasing push by Class 1 railroads to unit trains – uniform trains all carrying one commodity from one singular pickup to one singular destination. Initially 26 then 56 cars, depending on the railroad, they are now typically in excess of 100 cars and

can be as much as 120.In the interests of effi ciency, railroads no longer wanted to drop off a few

cars at every siding on a train run. Similarly, manifest trains, those of varying commodities and destinations, were also seen as less effi cient.

Th e adoption of unit trains has literally changed the landscape of West-ern Canada. Th ey have driven the construction of massive concrete and steel inland terminals, and the corresponding demolition of small wooden grain elevators. Th at, has in turn, led railroads to abandon huge lengths of branch lines, and as well as the towns built along them.

Page B9


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Engineered Rail Solu-tions, LLC provided a background explana-tion to Pipeline News how the adoption of unit trains has varied between Canada and the United States, and how that has impacted the design of the Ceres Northgate Commodity Hub, of which they are the primary consulting fi rm for its construction.

When inland terminals were built in Canada, they were typically built with two to four tracks alongside the elevator in a sid-ing or forked spur. Th is meant that when a unit train was delivered, it would have to be split up into as many as four components for loading. It allowed for multiple loading operations at the same time, but also meant that trains had to be disassembled and reassembled every time. Additionally, the railroads would drop the cars off and take the engines elsewhere either for a rest for the crew or some other duties. Th ey would then have to bring engines back (when available) to pick up and reassemble the train before leaving for its destination.

American railroads, especially the BNSF, which will service the Northgate Hub, took a diff erent approach. Th ey broadly adopted loop tracks. A unit train stays as a unit the entire time and is never disas-sembled. Additionally, the engines stay with the cars instead of being dispatched elsewhere. BNSF has incentives for having loading com-pleted within specifi ed

times – not just a 24 hour turnaround like you might see at a Ca-nadian grain terminal, but eight or 10 hours. Th e shorter the time, the higher the incentive.

An eight-hour load-ing time, for instance, allows a crew to get their allotted rest time nearby and then return to the same train and take it on its way.

Th ere’s another compelling reason as well. BNSF collectively realized that disas-sembling trains in cold weather is problematic. Th at’s because the rub-ber seals on the airbrake gladhands become stiff in cold weather, making it diffi cult to “air up” the entire train after reas-sembling it. If you can’t air up a train, you can’t move it. By keeping the entire train intact and locomotives attached, this is no longer an is-sue.

Th e diff erences in methodology could per-haps account for the dif-fi culties Canadian Class 1 railroads reported last winter when confronted with the largest harvest in Saskatchewan history and long periods of cold weather.

Th ose diff er-ences also account for a

greater number of turns that a railcar can make between the origin elevator and the desti-nation. If you can turn a railcar every two weeks instead of every month, this is twice the effi cien-cy and half the railcars on the railroad, which in turns allows the entire rail network to speed up as less railcar congestion occurs.

It is with all of this in mind that the Ceres Northgate Commod-ity Hub has two loop tracks in its design, plus additional straight tracks. Th e inner loop is dedicated for grain loading, the outer one is meant for crude oil. Th ere is also room to add a third loop track on the outside if the need arises.


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By Brian Zinchuk

Calgary, Stough-ton – Crescent Point Energy Corp. has been leading the charge when it comes to crude-by-rail in Saskatchewan. Indeed, not only is it the fi rst company to develop its own capacity to ship unit trains out of south-east Saskatchewan, it has adopted the strategy well beyond that region to all of its major oper-ating areas.

Trent Stangl, vice-

president of marketing and investor relations, spoke to Pipeline News on Aug. 16 about the company’s crude by rail strategy.

Asked how they came to be the leader in crude-by-rail in Saskatchewan, Stangl replied, “When you go back to 2008, 2009, 2010, we were pretty focused corporately in southeast Saskatchewan. A large percentage of our production was in southeast Saskatchewan.

As you know, there’s really only one delivery system out of south-east Saskatchewan, the Enbridge Saskatchewan system leading into the Enbridge mainline system, leading into the PADD II market.

“Th at always caused us some concern in that if something happened to the Enbridge Sas-katchewan or Enbridge mainline system, we would be in a diffi cult position to move our crude. We wanted to put

some insurance in place to prevent that.

“It really came home in 2010, when Enbridge mainline had their spill in the Kalamazoo River. We realized just how dependent we are on that one pipeline system.

“For us, rail was about providing a relatively cost eff ective insurance policy to en-sure our crude will have a delivery option to get it to market.”

And thus, they turned to rail.

Stangl said, “Th at was when we started thinking about what

rail could look like in southeast Saskatchewan and started designing a rail loading terminal, how we would operate that and so on. It was early 2012 when we started shipping our fi rst rail cars out of southeast Saskatchewan.”

What started out as an insurance policy soon turned into a market-ing opportunity, as the PADD II market in the U.S. Midwest had become saturated.

“What we real-ized with the rail is once you’re on the rail, you can go anywhere.

Where a pipeline starts in one place and ends in one place, rail can go anywhere in North America,” he said. “Th at opened us up to a number of diff erent markets, be it the East Coast, Gulf Coast or West Coast, or even the mid-continent as well. You can move to diff er-ent markets in diff erent months. If the pricing is really strong in the Gulf Coast one month, you can go there. If the next month it’s the West Coast or PADD II, you can go there.”

Crescent Point now sells oil all over the continent.

“We do have some main markets that we go to that are competitive,” he said, but noted they don’t talk about where that is.

“Number two, it gives us fl exibility. It gives us the ability to get to diff erent markets in diff erent time periods to get better pricing.”

Page B11

Crescent Point leads crude-by-rail charge in Saskatchewan

This is the view from the east, looking west, of Crescent Point’s Stoughton crude-by-rail facility. In the centre you can see trucks loading onto rail cars. To their right, the long yel-low pipe is the above-ground header for loading rail cars directly from the pipeline. Photo by Brian Zinchuk


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Page B10Stangl said they

weren’t making a negative comment on Enbridge Saskatchewan or Enbridge mainline. Eff ectively they didn’t want all their eggs in one basket.

“We have facili-ties in all of our main operating areas now – southeast Saskatchewan, southwest Saskatchewan and Utah are our big-gest operating areas.”

Th ey also have production in Alberta and North Dakota. In Alberta; they have a smaller rail facility. In North Dakota there are a number of third-party rail facilities that are available.

Generally speak-ing, they have 50 to 100 per cent of rail shipping capacity with respect to local production. Added up, their total rail shipping capacity is over 70,000 barrels per day. Th is correlates with approximately 125,000 barrels production of oil and natural gas liquids company-wide.

Stoughton has 45,000 barrels per day loading capacity. Th at’s not enough to fi ll a unit train in one day, but then again, they don’t need to do it in that short of time. Th eir facility is situated on the shortline Stewart Southern Railway, a

company from which they get “excellent ser-vice,” as Stangl put it.

“We do mostly unit trains out of there, but we also do manifest as well,” Stangl said.

Near Shaunavon, they’re near 15,000 bpd in capacity.

At Alliance, Alta, they can load 3,000 bpd.

In Utah, Crescent Point has 10,000 bpd capacity.

Th e company has recently added storage capacity at Dollard, near Shaunavon. “We added 100,000 barrels capac-ity, the same as in the southeast,” Stangl said.

A typical unit train will run around 60,000 to 70,000 barrels, de-pending on the rail line it is destined for.

“We’re probably go-ing to add more storage for southeast Saskatch-ewan as well,” he said, adding that is for opera-tion use beyond crude-by-rail.

“Arguably, you want to have more storage capacity, not less. You’re

never going to have as much as you’d like to have.

“We meet all the standards right now for testing. We made a con-scious decision to not bring in third-party bar-rels so we can demon-strate we’ve done all the appropriate testing and can verify the quality of the product on rail.”

Th e Stoughton facility now has a pipeline connecting the crude-by-rail facility a few kilometres north-west of the town to their main Viewfi eld plant, a few kilometres southwest of the town. Th ere’s now a header system that allows rail cars to be loaded from that pipeline. It still uses the trailer-based trans-loading systems when loading from the pipe to the rail car. It’s not a true rack system.

“Th at was really an attempt to become more effi cient in loading. We still do truck into our rail facility, but we have the ability to load from

pipe directly from our storage facilities. It adds effi ciencies and reduces the number of trucks

that are on the road in southeast Saskatch-ewan,” he said.

Th e pipeline also

gets around road ban weight restrictions in springtime.

Page B12

The yellow pipe is the new header system that allows Crescent Point to forego the


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Is Stoughton part of a second phase of crude-

by-rail, from tanks to railcars as opposed to trucks to rail cars?

“I think so,” Stangl

responded. “I think what people are real-izing is infrastructure that’s in the ground, and

has been in the ground for many years, is in the wrong place going to the wrong places instead of where it needs to be. Th e amount of time it is taking to put new infrastructure in the ground is way longer than anticipated.

“What that means is rail is going to be a part of the delivery landscape for quite some period of time, so companies are now prepared to spend more money on rail infra-structure knowing it is going to be an ongoing part of their business for years to come,” he said, referring to main-line pipelines like the delayed Keystone XL.

Asked if crude-by-rail has been looked at for the company’s emerging Flat Lake play along the U.S. border in southeast Saskatchewan, he said, “It’s sort of built into our Stough-ton strategy. We’ll have optionality to either

deliver by pipe from Flat Lake or to truck up to Stoughton.”

As for the possibili-ty of using a third-party transloading facility on the Long Creek Rail-road which runs near their Flat Lake area, Stangl said, “We tend to use our own facilities when we can. Flat Lake is a big enough area for us that it’s important to maintain control over those operations. We wouldn’t do it through a third party facility.”

With regards to the future of crude by rail in the coming years and what impact has Lac-Megantic and Cas-selton, N.D. had on this future, Stangl replied, “Crude-by-rail is go-ing to be around for a long time. Even when some of these major infrastructure projects get built – Keystone XL, Northern Gateway, Energy East or market expansion – there’s still going to be markets that are not pipeline-connected. Th e U.S. Northeast is an example. California is an ex-ample. Th ere’s still an opportunity to have rail in the portfolio long-term.

“I think there’s go-ing to be more rail as a portion of the total North American crude delivery than in the past, prior to 2010. I think it’s going to play a bigger role until those major pipelines get built, and

then it will be a little more niche, a little more strategic after that.

“What Lac-Mé-gantic has done is really put the focus on safety of crude-by-rail. I think that’s a good thing. I think the regulations they are putting in place are good regulations and it will improve the safety of crude-by-rail. You will increase the cost of crude-by-rail, but not to the extent where it will shut down crude-by-rail.

“Long-term, when some of these major pipelines get built, it’s going to be the most effi cient rail operations that operate. If there’s a loading facility and unloading facility that have to cross over three or four shortlines and trunk lines for rail, those aren’t very effi cient to run. Th ose are the ones that are not likely going to continue in a world of more pipeline capac-ity.

“Th e effi cient ones, with one rail line and a quick turnaround, those ones will continue.”

Stangl concluded saying, “Th e industry is evolving so rapidly, the sources of supply, the sources of demand are changing quickly. Rail gives you the ability to react quickly, whereas pipelines take longer to build and longer to expand. Rail is an im-portant delivery source at the margin.”

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By Brian ZinchukCromer, Man. – Nestled off the beaten path several kilometres from Manitoba

Highway 256, and just east of Cromer, Man., is one of the most signifi cant additions to the crude-by-rail game.

Located approximately six kilometres east of Tundra Energy Marketing Lim-ited’s growing Cromer terminal, one fi nds their new crude-by-rail facility.

Th ere are no large tanks on site, no lines of semi tankers waiting to unload us-ing trailer-mounted transloading systems pulled behind pickups. Th is is the most substantial crude-by-rail facility in the region to date, at least until the completion of the Ceres Northgate Commodity Hub on the U.S. border. It may not yet have the capacity of the Crescent Point Energy Corp Stoughton-crude-by-rail facility, but it does have the hardware.

Its initial loading capacity is 30,000 barrels per day, or 50 rail tanker cars. Th ere are two tracks adjacent to the CN track which runs east and west.

Pipeline News spoke to Dale Clark, vice-president of marketing for Tundra Energy Marketing Limited, by phone on July. 29.

Pipeline News: Can you explain the distinction between the two sides of Tundra now? Which are you?

Dale Clark: Tundra Oil & Gas is the upstream parent of Tundra Energy. Two-and-a-half years ago, Tundra Energy Marketing Limited was spun off as a wholly-owned subsidiary of Tundra Oil and Gas.

P.N.: Is the terminal at Cromer the upstream business or you guys?D.C.: Th at’s Tundra Energy. Basically we own the midstream assets. Tun-

dra Oil & Gas focuses on the exploration and production of crude oil and we focus on the logistics of bringing crude oil to market, and the marketing of the crude oil. Tundra Oil & Gas only amounts to about 50 per cent of the total oil we handle as a midstream company.

P.N.: What have you built at Cromer?D.C.: Presently we have a truck terminal at Cromer that can receive oil

from batteries and wells that are not connected to the feeder pipeline network. We have some day tanks to handle the truck receipts. If you were out there, you probably saw some rusty brown tanks (they have not been painted yet), the new tanks are 205,000 barrels each. We have another tank that is a 70,000 barrel tank. We have just under 500,000 barrels of total storage capacity.

P.N.: Satellite pictures from Google are relatively recent and show foun-dation work for a third 205,000 barrel tank.

D.C.: Th at’s correct. We’ve just let the contract to construct the third new tank. In a year’s time, we’ll be commissioning that tank.

P.N.: Can you describe the rail terminal? Page B15

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Page B13D.C.: We’ve also built a rail terminal. The rail

terminal is connected by a six kilometer long pipe-line. It’s essentially built on a spur from CN Rail. Its position is such that it’s on a flat grade and easy for a locomotive to service it.

We put a lot of thought into our facility. We have a small footprint there, but we think we can do a lot with it.

There are some truck-to-rail that are in the area as well. They’re easy to set up and to take down as well. We felt rail was going to be there for the lon-ger term, and we didn’t want to be in the truck-to-rail business. We’d much rather load from tanks. It’s more cost-effective than a truck-to-rail operation. You don’t have the trucks waiting. If the train’s late, you can store the oil in the tanks.

P.N.: There is no truck-to-rail transloading then? What comes by truck or pipeline goes into tank, then by pipeline to the rail facility and gets loaded onto rail, correct?

D.C.: Correct. We are not doing truck-to-rail. Others in the area are doing truck-to-rail, but you can talk to them.

We did it initially to understand the opportuni-ties in the rail market, two or three years ago, before we opened our facility. The facility we have was commissioned in last September. It was designed for 30,000 barrels a day, but we are working to increase it to 60,000 barrels per day.

P.N.: What sort of timeline are you looking at for that?

D.C.: Hopefully by the end of the year, we’ll be at 60,000 barrels per day. We found hydraulically, we’re not constrained in terms of loading at 30,000 barrels per day. We think we can do 60,000. What was constraining us was the amount of tank car

storage. That’s all we’re doing is adding more track.P.N.: How much of this facility is for Tundra’s

oil, and how much for other producers?D.C.: One of the things we’ve made an an-

nouncement on is we’re connecting into the En-bridge feeder system that comes in from southeast Saskatchewan, which will allows us to have access to additional oil to allow us to go to the 60,000 barrel per day rate. We don’t want to go entirely to rail with our crude. We have connections into the Enbridge mainline today. We plan on maintaining some crude into there. We’re working on agree-ments with other producers to tranship their oil via the Enbridge feeder system into rail cars.

We’re trying to be a bit of a hub for producers in the area to give them a mainline option, a storage option, and a rail option.

I want to be specific: it’s off the feeder system, not the mainline. We’ll be able to take oil off EPSI (Enbridge Pipelines (Saskatchewan) Inc.) , but not the mainline.

P.N.: Where is that oil coming from, since roughly all of Manitoba’s daily production could fit on one unit train? You’re drawing Saskatch-ewan oil as well?

D.C: That is exactly what we plan. The rail facility, we have an agreement with Enbridge to do a joint venture with them on it. As part of that agreement was providing connections to the EPSI system as a source of oil. We have to meet some conditions to be able to have Enbridge joining us in that joint venture. We’re working towards meeting those conditions, but haven’t met them at this point in time. We are getting the connection.

I don’t know if construction has started yet or not, but it’s scheduled to be complete for early next year. With the flooding, it could be delayed.

P.N.: Is this facility designed only for outgo-ing crude-by-rail, or could you receive oil and transfer it to your tankage and then the mainline pipeline?

D.C.: It’s designed for outgoing oil. For incom-ing oil, we’d have to truck it to tankage. It’s a one-way pipeline. Our focus is getting oil out.

P.N.: There is no tankage visible on site. Is this all taken care of at the main terminal, and then pipelined to the rail facility?

D.C.: That is correct. We didn’t want tanks down there, and the engineers were able to work out the water hammer and the control circuits so there’s no tankage required.

I don’t know if they were loading when you were there, but because all the pumps are at the terminal end, when I’ve been there, it’s completely silent. You can hear birds.

P.N.: Tundra has embarked on a massive tank building program at Cromer. Two large tanks ap-pear near completion, and satellite pictures show foundation work for a third. When do you expect them to be in-service?

D.C.: The first of the two large tanks was put in service at the end of December and the second one in January. The third one will be I think in August 2015.

P.N.: Are these tanks meant primarily to service the crude-by-rail terminal, or mainline pipelines, or a bit of both?

D.C.: A bit of both, as well as to provide some storage flexibility if the rail is delayed. That’s happened. In the wintertime, rail service was a bit challenged with the cold weather we’ve had this last winter. Also, Enbridge has been known to shut down every so often due to constraints on their system. Page B16

Capacity to be expanded to 60,000 bpd by year end


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Could there be a tie to Energy East?

Page B15The worst thing that can happen

to a producer is to shut in production. P.N.: TransCanada’s Energy

East pipeline includes plans to build a 60 kilometre lateral from Cromer to Moosomin, with an “on-ramp” to the pipeline at Moosomin. They have not said where that line starts at Cromer. Are they hooking up to your facility?

D.C.: We’ve had discussions with TransCanada, but there’s no plan in place at this time. We would like to hook in, but they have not made the final routing decision on that pipeline going into Moosomin. It might go into Cromer, it might not.

All I can tell you is there’s no agreement today. There may be an agreement in the future.

There’s no agreement between TransCanada and ourselves at this point in time. We’ve had discussions, but they’re nowhere near completion.

P.N.: This planned Energy East lateral is expected to have 200,000 to 300,000 barrels per day capac-ity. That’s not far off from the total oil production currently in south-east Saskatchewan and southwest Manitoba, most of which currently goes into the Enbridge mainline (i.e. EPSI, Westspur system, Virden system). With the addition of the proposed Energy East lateral, your

crude by rail facility and others also under construction, that would result in a dramatic increase in ship-ping capacity from this region. (Put in context, Between EPSI, Energy East lateral and Tundra, Crescent Point Stoughton and Ceres North-gate Commodity Logistics Hub, there would theoretically be enough capacity to ship the entire region’s daily production almost three times over.) Are you anticipating similarly dramatic increases in production from this region?

D.C.: I don’t know.I would be happy if production

held constant, that the drilling pro-grams going on are able to maintain production.

Here’s a consideration for you: Energy East, if it was approved today, with the existing timeline, the first barrel going into Energy East I think would be early 2018. We have a

shortage of pipeline capacity, today, to move our barrels.

Energy East may remove the need for rail facilities in 2018 when it gets up and running. The one thing about projects, pipeline projects in particular, is there’s the planned time-line, then when things happen, the timeline gets extended. The best case scenario is it’s there in 2018.

The existing mainline pipeline systems do not have the capacity to move all the crude out of Western Canada. Let’s say Energy East is the only project that gets built, and it’s sufficient to move all the crude, then all the rail facilities will shut down and switch over to pipelines.

Some Alberta projects that I’ve heard about are timed to come online about the same time as Energy East, and that that crude will go into En-ergy East, and the rail volumes will partially continue. Page B17

Two large 205,000-bbl. tanks, right, will be joined by a third within the next year.



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Th is is a chart taken from CAPP’s annual Crude Oil Forecast (it’s on their Website), each one of the new pipeline projects are going to face challenges in being approved and constructed to meet these start-up timelines. Rail loading facilities are needed to bridge the gap between increased production and pipe-line startups. As well, they may continue indefi nitely due to the ability to reach markets not accessed by the pipeline network.

P.N.: One of the things they’ve found in North Dakota is fi rst they thought crude-by-rail would be a bridging strategy, but they found as new pipeline capacity came on, it wasn’t taken up nearly as quickly as they thought. Th at was because companies were fi nding markets for crude-by-rail they couldn’t get to with pipelines. One person said, “We’ve saved the east coast refi ning business, and now we’re going to save the west coast.”

D.C.: Th at’s correct, yes.P.N.: Do you think that rail, by nature, being continent-wide, gives you

more fl exibility as a marketer?D.C.: Yes it does. Th e interesting thing is there is this light crude versus

heavy crude discussion taking place around North America right now. North America is short of heavy crude, and net importing heavy crude, but is progres-sively reducing imports of light crude following production increases in the shale oil. You know the Bakken play, Eagle Ford, Niobrara – all of those are all light crude. As that production continues to ramp up, there will be less and less light crude imported into North America. It may turn around that we actually have a surplus of light crude in North America.

Th e question is, which barrel should get to tidewater and which barrel should get exported. Th ere’s a debate going on. In some cases, the barrel that will get exported will be within the decision making power of the person that’s made the 20 year take-or-pay commitment to pipeline space. He’ll decide which barrel goes.

P.N.: When you put it on a train, shipped from Cromer, where has it gone?

D.C.: It has gone east and south. It’s gone to the eastern seaboard, both Canada and the United States, and the Gulf Coast.

Th e Gulf Coast is fl ooded right now with their own production. Th ere are no imports of light crude any longer on the Gulf Coast.

Page B16What we’ve focused on is constructing an effi cient rail-loading facility that

can weather the ups and downs, and perhaps function as a bridging strategy to move crudes out of the producing areas until such time there is suffi cient pipeline capacity. But it’s still a question of what pipeline capacity will be avail-able, when it comes on line, and when do we see suffi cient pipeline capacity to replace rail movements?

Virden YardRobert B. Somerville has been working out of this yard near Virden, Man., for a 20 kilometre project on Enbridge's Line 3. Photo by Brian Zinchuk


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Oxbow – In the wake of the flooding in late June and early July that devastated portions of the extreme southeast

corner of Saskatchewan, a flood aid benefit con-cert is being held.

The event will take place at the Oxbow Prairie Horizon School on Sept. 14. There will be an auction viewing at 4 p.m. followed by the auction at 4:30 p.m.

A cold plate supper and musical entertain-ment will follow. Music starts with concert pianist David Hyman at 6:30 p.m. Next up will be Product of Canada and then Jimmy G and the Cable Guys.

There is a cash bar at the event.

Tickets can be

purchased by calling Safe-Tee Management 306-483-2480. Tickets will go for $30 individu-ally or $220 for a table of eight.

Shirley Galloway of Safe-Tee Management, one of the organizers, said, “The auction items are fantastic…from a brand new 2014 car to a 60 inch TV, hand-made quilts, way too much to mention. It’s going to be a fantastic night!”

Proceeds will be split between the towns and RMs of Carievale, Gainsborough, Carn-duff, Storthoaks, Alida and Redvers.

This rig, working close to Cromer, Man. is proof that the Tundra terminal is right in Photo by Brian Zinchuk

By perhaps happy coincidence, Enbridge’s mainline and terminal just happen to be smack-dab in the middle of what has become, in recent years, Manitoba’s most prolific oilfield. The Sinclair-Daly field, which has seen the most drilling activity in the province over the past six or so years, is dominated by Tundra Oil & Gas Partnership. Both sides of Highway 256 are lines with multi-well pad sites in both directions, both north and south, of Cromer.

In 2013, Sinclair-Daly had 187 of Manitoba’s 532 wells drilled that year. This was just above the 169 in the Waskada field, and miles ahead of the dis-tant third-place Pierson field at 91.

Manitoba’s success rate for development wells is 99.6 per cent over 515 wells in 2013. A further 17 exporatory wells has an 82.4 per cent success rate for an overall success rate of 96.4 per cent, according to statistics from the Manitoba Petroleum Branch.

Of those 532 wells in 2013, Tundra Oil and Gas Partnership accounted for 160 wells. Red Beds Resources Limited, and subsidiary company of Tundra, drilled a further 27 well.


Willmar – A lonely siding beside the hamlet of Willmar, south of Arcola, is the site of one of the first crude-by-rail loading facilities in Saskatchewan. It is operated by Petrogas. Tom Mitenko, Petrogas spokesper-son, detailed via an e-mail interview what they have been doing there for the last several years. He responded on Aug. 19.

Pipeline News: The Willmar crude-by-rail facility was one of the first, if not the first, trans-loading facility of its kind in Saskatchewan in re-cent years. How long has Petrogas been involved with Willmar? Has it been from the get-go?

Tom Mitenko: Petrogas became involved at the request of CN due to our long term facility operating and shipper history on CN. We have operated this particular facility for over three years, but have utilized the facility to transport crude for around four years.

P.N.: What led to your establishment of this service in that region? What were the factors behind going with this service?

T.M.: Petrogas has owned and operated crude pipeline terminals in southeast Saskatchewan long before the advent of crude by rail. Marrying our railway terminal operating and logistics expertise with our existing crude business in southeast Sas-katchewan was a natural progression.

P.N.: It is our understanding that, at least initially, a fair bit of North Dakota oil was being trucked to Willmar so that it could be shipped out by train. Is that still the case?

T.M.: North Dakota crude oil continues to move across the border, albeit to a lesser extent re-cently due to the development of rail terminals and pipelines in North Dakota.

P.N.: We saw Petrogas tanker trucks in the area. Are you providing trucking service in addi-tion to transloading services?

T.M.: Yes, we have an integrated crude busi-ness including trading, marketing, hedging, railcar supply, trucking, trans-loading, pipeline terminal operations, pipeline shippers and railway shippers. Owning and controlling many pieces of the supply chain enables Petrogas to deliver on commitments (with little or no reliance on third parties) and pro-vides flexibility to producers and refiners.

P.N.: Broadly speaking, where does it go? T.M.: West Coast, East Coast, mid-continent

and U.S. Gulf Coast.P.N.: We see you have a car spot for about 30

standard tanker cars. What is your loading capac-ity there?

T.M.: The site can hold 40 railcars with a ca-pacity of approximately 25,000 barrels per day.

P.N.: Do you have other crude-by-rail facili-

ties in Canada or the U.S.?T.M.: Yes. P.N.: Where do you see the future of crude-

by-rail in the coming years?T.M.: The longevity is dependent upon how

quickly pipeline projects come to fruition and crude prices sustaining production growth.


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Maryfield – One of the key factors in mainline pipeline construction these days is the environment. Enbridge held an open house in Maryfield on July 31 to discuss their upcoming Line 3 replacement project. The environment was one of the major is-sues up for discussion.

Dan O’Neill is the environmental supervisor for the Line 3 replacement project.

“I work on the environmental component. We put together an environmental and socio-economic impact,” he said.

Some of those considerations include commu-nities, landowners’ soil, wildlife and water crossings.

Line 3 is not the oldest pipe in the mainline system, yet it is the one being replaced. The differ-ence it was constructed with polyken tape for its coating.

“The amount of maintenance has come to a point where, commercially, we came to an agree-ment with our shippers to replace the pipeline, to return it to its original capacity, and decommission the existing line.”

Several smaller NEB-regulated pipeline construction projects in recent years, including the Vantage pipeline and Enbridge’s Bakken expansion saw nearly every low spot and water course bored with horizontal directional drilling. While that is doable with smaller pipe, 36 inch pipe is another story. Those areas will generally be open cut on Line 3 Replacement, just as they were for the 2008-2009 Alberta Clipper project.

“The open cut on Alberta Clipper, we’ve been able to reclaim quite successfully.”

Minimal disturbance practices in wetlands has shown these wetlands prove to be quite resilient and come back quickly.

One area on the mainline not far from

Glenavon, Saskatchewan, has been something of a challenge on the last two mainline projects. In the past it has been dug using a Sauerman, a tow-based cable dragline system. This had been because con-ventional excavator ditching would not work and a bore would not be practical. It’s not in the works for this project, however.

“Right now we’re not planning on using a Sauerman, but it is an option,” O’Neill said. “It’s for a very specific soil and wetland situation to be effec-tive.”

In other areas, wetlands are either isolated or worked through in the winter.

Since at least 2008, not one big-inch NEB regulated pipeline project in Saskatchewan has started in June and progressed through the sum-mer, the time of year when the most work can be accomplished in the least amount of time.

“One big thing is we have migratory bird tim-ing restrictions now that limit us to when we can really start,” he said.

“Typical restricted activity periods are April 1 to August 15 for general work, a little longer for wetlands,” O’Neill explained.

“Generally We schedule our work to start Aug. 1. In some time of grassland ee do bird nests sweeps with a biologist ahead of the crews. If we find something, we put in a protective buffer and apply a no-work area.”

“We’re planning to apply (to the NEB) for the project this fall. The regulatory process will take about two years. We wouldn’t be breaking ground until August 2016.”

Some smaller portions were applied for earlier, and work has been taking place near Cromer, Man. By expanding the project to replace the entire pipe-line, it means a lot more work has to be done before actual construction commences.

Biosecurity“Biosecurity is a big issue for the agricultural

community, and the health of the local communi-ties” O’Neill said. Page B22

Dan O’Neill is the environmental supervisor for the Line 3 replacement project. Photo by Brian Zinchuk

Environmental considerations for Line 3 replacement


Page B21

“Biosecurity is a set of measures to prevent the spread of crop pests both between and within properties. It deals mostly with things like weeds and club root, other crop diseases and pests that could be affected by our type of operation.

“We do a full weed survey. The next phase that’s happening now is doing soil sampling for club root. We use a risk-based approach where we consider high risk areas where we do sampling. If we find the club root DNA in the soil we implement a cleaning strategy at that quarter-sec-tion. We pressure-wash and disinfect the equipment that goes through there.

“We just started our sampling program. It’s considered very low in

both Saskatchewan and Manitoba at this time, but it’s a big concern because of the way it’s spread in Alberta.”

An over-arching strategy includes a wash and bleach for all equipment at the start of a spread. As they cross municipal boundaries, there will be wash stations for equipment.

Soil “Soil conservation has been an

issue in the pipeline industry in any construction practice. We want to make sure we salvage topsoil prop-erly.” O’Neill said.

“Our typical practice is full-width stripping to protect the integrity of the topsoil. The rest of the equipment travels on the subsoil, graded out level. We would use minimal width (stripping) on sodded soils and native prairie.”

Bio security considerations

Cromer, Man. – The rains came down, the floods came up, and work on the Enbridge Line 3 replacement project east of Cromer, Man. got a stop-work order from the National Energy Board (NEB).

That 20-kilometre area of pipe was a high priority for replacement. Initially Enbridge had only planned on replacing segments of Line 3, including this segment, but eventu-ally it changed its mind and decided to replace the entire length of Line 3. The 20 kilometre segment ended up being a separate project that received NEB approval in 2013.

While the other parts of the proj-ect won’t see dirt scratched for several years, this area, which had been ap-proved for replacement, couldn’t wait.

Pipeline contractor Robert B. Somerville had been working out of Virden, Man. on the project. Pipe strung out along the right-of-way was visible from Highway 83. Then the rains hit.

The area under construction was right in the hardest hit area of south-

west Manitoba when torrential rains came down in late June. It caused flooding that shut down nearly every road in the area and damaged almost all the bridges. Even in mid-August most of the bridges in the region were still being repaired or under weight restrictions, including almost all the bridges on Highway 83, the main route through the region. The entire region was put under a state of emer-gency during the time of the floods.

Rob Barkley is the senior project coordinator for the Line 3 replace-ment project. His area of responsibil-ity is essentially half of the project, from the mid-point in Saskatchewan at Craik to Gretna, Man., where the pipeline crossed into the United States. He spoke to Pipeline News in Maryfield on July 31 during an open house regarding the entire Line 3 replacement project.

“The NEB issued a stop-work or-der. Landowner complaints initiated an investigation. We had a few non-compliances. We had slight admixing, basically the topsoil mixing with the

subsoil (clay),” Barkley said.Asked if it was caused by an oper-

ator spinning his tracks, he said, “We honestly can’t say. It’s too wet to get back out on the right-of-way. With the stop-work order, we’re limited to what we can do. We’re addressing landowner concerns, of course.”

“We’re well on our way right now. I believe we’re just about complete on addressing the land owner concerns such as spraying the right-of-way with weed control, opening up access points to get their equipment out.”

Barkley referred to the standard practice of leaving gaps in berms crossing fields so that farmers can access all their land. “They were left there. Somerville did a good job of it. But the wet spring and eight inches of rain left most of them unusable.

“The ‘misplaced silt fences’ were placed properly by the (environmental consultants), but with eight inches

of rain, all the wetlands doubled and tripled in size. Of course, our silt fence was in water.”

The silt fences were simply over-whelmed with the water, he noted.

“In the spring, (from) the inspec-tion I did personally with two other guys, it was looking well. The silt fences worked correctly for the spring run-off.”

That changed with the flood. “At one point in time, there was

only one road we could use to access the right-of-way. Roads were washed out, bridges were washed out. It was difficult for a while.”

“The municipalities and govern-ment did an awesome job. In days we had access again. They worked hard.”

“The bulk of it was definitely weather-related.”

As of Aug. 19, work had not yet resumed and the stop-work order was still in place.

These joints of pipe, on the west side of Manitoba Highway 83, are meant for the Line 3 replace-ment project. This region has been the subject of a stop-work order issued by

in late June. Photo by Brian Zinchuk

The rains came and the work stopped


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Maryfi eld – While waiting to get going on the next bid project, Enbridge is still working on ensuring everything is copasetic with the last one.

Rob Barkley is the senior project coordinator for the Line 3 replacement project. His area of responsibility is essentially half of the project, from the mid-point in Saskatchewan at Craik to Gretna, Man., where the pipeline crossed into the United States.

All the people working under Barkley are contractors, as opposed to En-bridge personnel.

In Saskatchewan he expects three contractors will be working on building the replacement line. In Manitoba typically one contractor is used.

In the past it has typically been union contractors that work in Saskatch-ewan.

Currently he deals with some of the smaller local contractors for remedia-tion work, in addition to a larger contractor, Robert B. Somerville, which is working on the fi rst phase of the Line 3 replacement.

Work has already begun on at least some of the project, the 20 kilometre stretch east of the Enbridge Cromer terminal. Barkley noted that their inspec-tion program revealed that it would have required extensive repairs, up to 70 dig-ups per kilometre.

“Th e eff ort, the disturbance to the land, would have been equal to putting a whole pipe in, so it would made sense for the landowner for the least distur-bance, and for Enbridge, to replace the pipe,” Barkley said.

Th e plan was to have it wrapped up and in operation by Oct. 1, but work did not resume in mid-August as a stop-work order was issued following the heavy rains at the end of June. (See related story Page B22)

Remediation takes longer. “It will go on until the landowners are happy with our eff orts,” he said.

In some cases, a little bit of settlement here or a little crop loss there will show up. He spent the last year-and-a-half dealing with remediation issues from the 2008-2009 Alberta Clipper project.

Th ere are several places where the right-of-way deviates from the original several pipelines due to space constraints. Kipling, for instance, was side-skirted with Alberta Clipper and will be again with this line. Regina was also circum-

vented on the previous job.“I believe we’re still negotiating with landowners,” he said.Th e vast majority of the line will follow the existing right-of-way. “I’d like to reaffi rm we do have the landowners interest in heart. We’re not

going to walk away. Case-in-point, I’m still working with Clipper issues, until they’re happy and I’m happy. With rain, especially after that eight-incher, we’ll still get settlement on Clipper. Th e dirt moves a little. We have crop loss issues that we have to remediate.

“I hear that a lot, that we’re going to walk away. Th at’s absolutely not true. We will continue until they are happy,” Barkley concluded.

The Line 3 replacement project passes throughout Saskatchewan and the southwest corner of Manitoba.

of the project. Photo by Brian Zinchuk


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Maryfi eld – En-bridge is replacing Line 3 before Lines 1 or 2, even though the fi rst pipe was built during the early 1950s and Line 2 came in the 1960s. Line 3 was built in the late 1960s.

So why Line 3? It comes down to coating.

“It’s got the tape coating. Th ere’s issues in certain areas with instal-lation at the time. Tent-ing on the side with the tape coat traps water and creates corrosion,” Barrie Ryan said.

Ryan is manager of pipelines services, cen-tral region, while Mar-tin Stribrny is manager

of pipeline engineering from Regina to Gretna, Man. Th ey were two of the experts on hand at the Enbridge Line 3 replacement open house in Maryfi eld on July 31.

Stribrny said, “Th at’s the problem.”

“Over time it’s cor-roding, and we want to replace it. Currently the pipeline is operating at reduced pressures, as a precaution,” Ryan said. “We’re doing a lot of integrity digs, and mil-lions of dollars worth of smart tool runs to check integrity. Th e smart tool runs tell us where to go for integrity digs.”

(A “dig” or “dig-up” is pipeline parlance for digging up a pipeline to do a maintenance repair on it.)

Stribrny noted that

the segment east of Cromer was identifi ed initially for replacement, before the decision was made to replace the entire line.

Ryan said, “Basical-ly, the tape coat may not have been installed cor-rectly at the time. Right now, it’s not in good shape. I don’t know how it was installed, but obviously there’s issues. Th at’s a fact.”

“Th e majority of the digs have been on Line 3. It’s the only one with the tape coating.”

Th e earlier lines had a coal tar coat-ing, “Probably the best coating we have,” Ryan said, but it was a health hazard to install. “As far as coating, it was excel-lent coating.”

Page B25

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Page B24

More modern pipe-lines are coated with epoxy. Th e new pipe will have FBE epoxy coating, the standard coating for at least the last 20 years.

On other gathering systems, tape coating was not a problem, ac-cording to Ryan. “Th ey have lots of lines with tape coat on it, and there’s nothing wrong with them. You can’t even peel it off . You have to blast it off . Un-derneath, the pipe is in perfect condition.”

Th e original Line 3 was built with 34-inch pipe, what is now a non-standard size. Th e new line will be built with 36-inch pipe, making it much easier to use off -the-shelf pipe, components and parts

for things like valves. For 34-inch pipe, all replacement parts had to be custom made, ac-cording to Stribrny.

“Th irty-six is just a common size,” Ryan said.

Since it is basically a one-for-one replace-ment, the project should not have the issues of a new pipeline like Trans-Canada’s Keystone XL has dealt with.

What are they do-ing to ensure they don’t end up with another problem child of a pipe-line?

Stribrny said, “We’re following pro-cedures and standards. We will be doing a few things extra, caused by Northern Gateway, in B.C.. Some engineering standards were upgrad-ed and it’s fl owing into other issues.

“Th ere is some strengthening of things. For example, when crossing other pipelines, the minimum clearance is one foot. What we are doing now is two feet, and in some circum-stances, three feet.”

Contractors will typically provide more clearance than just the minimum, he noted.

“It’s coming from Gateway.”

Th e detailed design is just starting now, ac-cording to Stribrny.

“We’re designing to the most modern, up to date codes, not 1960s,” Ryan said.

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By Brian ZinchukMaryfield – Imagine you are an operator re-

sponsible for a pipeline moving hundreds of thou-sands of barrels of product each day. Now imagine the alarms going off, indicating a leak. What do you do?

In the wake of Enbridge’s Kalamazoo River spill on its Line 6B in 2010, leak detection has become a new religion at the mainline pipeline operator. It’s such a high priority, they’re willing to run full-bore shutdown drills to ensure the pipeline control centre is on its toes.

The Kalamazoo River spill occurred near Mar-shall, Mich.

Ron Threlfall is supervisor of leak detection maintenance and integration. He was one of the ex-perts on hand at the Enbridge Line 3 replacement open house in Maryfield on July 31.

How important is leak detection on this proj-ect?

“Extremely important, as it is on all projects,” Threlfall replied. “The Marshall incident was a wakeup call for all of Enbridge. July 26 was the fourth anniversary.

“Enbridge has really stepped up their game as far as leak detection goes. Post-Marshall they authorized over $250 million in additional leak detection instrumentation, primarily flowmeters, additional pressure measurements, temperature, density, viscosity. The leak detection department has quadrupled in size.”

These efforts have been deployed throughout the entire fleet of lines.

“Enbridge deploys multi-layers of leak detec-tion. Each technology used to find leaks has some strengths and some weaknesses. By deploying mul-tiple layers, we ensure good resiliency and we end up with a more robust overall system. That ranges from overhead flybys to what my area my team focuses on, the real-time transient model.

“By applying multiple layers, it’s better than any one layer could be.”

With regards to the real-time transient model, all that instrumentation he mentioned, if any of the values change, they report up to the control centre approximately every five seconds.

“That information is then sent from the system that’s controlling the pipeline to the leak detection system, where we create a mathematical hydraulic model of the system known as the real-time tran-sient model.”

It calculates the hydraulic state of the pipeline every few seconds.

“Any discrepancy between the model and the readings show up as discrepancies. They can be caused by configuration errors of the model, poor instrumentation that has failed, batches moving through the pipelines, where the real batch is mis-aligned with the model, as will a leak.

“If there’s a leak happening in the pipeline, we start to see major discrepancies in the model,” Threlfall said. “If those discrepancies match the pattern of a leak and are of a sufficient size, it will generate an alarm. We have people in the control centre 24/7 that are trained experts in analyzing those alarms.”

Page B27

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Page B26Th at control centre

is in Edmonton. Th e control centre in Es-tevan that looked after the Enbridge Pipe-lines (Saskatchewan) Inc. (EPSI) gather-ing system as recently been shut down, with the control now solely taken care of in Ed-monton.

“I think the major-ity of them transferred,” he said of the Estevan operators.

“Th e Edmonton control centre is a centre of excellence for pipeline operations, with very rigorous pro-cess and procedure for all that they do. Th ere’s additional training capability for operators. Th ey’ve ramped up a very robust environ-ment that is diffi cult to do in a small control centre.”

What is the small-est thing they can detect?

“Th at’s where the multiple layers come in. Th ere is a lower limit of what this technology can fi nd, on the order of a few per cent of fl ow. Smaller than that will not be detected by this technology (the real-time model).

“Th ere’s a grape-fruit-sized ball they can send through that’s not a pig in the conven-tional sense. It doesn’t touch the wall, it kind of bobs along. It has acoustic sensors that can fi nd a pinhole leak. It has a characteristic sound. We have tested that technology and proven it can fi nd pin-hole leaks.

“We’re also do-ing the potential next generation of leak detection. Th ere are a number of vendors claiming they can detect leaks with vari-ous technologies, with vapour-sensing tubes and fi bre-optics in

particular. Enbridge has spent several hundred thousand dollars to building a test appa-ratus to evaluate this technology.”

It’s a boxcar-sized container with a pipeline going through it. Th e technology is deployed around it at diff erent positions around the pipe. Th e fi bre optic sensor has 20 kilometres of fi bre spooled on each end so it can work like a 40 kilometre segment.

Th ey are looking at which position with re-spect to the pipe would be best for detection. Th e sensors would go in the trench with the pipe in the real world.

Th ere’s a 32 ki-lometre test planned for the U.S. next year where they will look for real-world experience with these technologies.

“Th is is not cheap technology.”

One of the ways the fi bre optic works detects temperature changes, whereas another detects strain within the pipe. Both could detect the leak and very accurately locate it.

Testing“We regularly test

the (leak detection) system, and can dem-onstrate signifi cant year-to-year improve-ments in sensitivity and reliability.”

“Th ere’s three dif-ferent types of tests,” he said. One is parameter testing. An example would be feeding a leak detection model with a decreased fl ow downstream of a leak to mimic what a leak would look like.

Every model is tested twice a year with that type of test.

A second type of test is using a hydraulic simulation which is used for a number of things, including some-

thing analogous to a fl ight simulator, except for pipeline operators.

“You can mimic all kinds of problems and test that people know how to react.

“We have an exten-sive library of abnormal operating conditions we can pre-program into the simulator.”

Marshall is one of the scenarios used.

Th e simulator is also used to train leak detection analysts to distinguish a bad in-strument from a leak.

“Part of the train-ing of a leak detec-tion analyst is to play through a wide variety of historic leaks. We can actually simulate a much larger set of leaks.”

Real world drillTh e third level

is the most compre-hensive expensive and intense, a fl uid with-drawal test.

“We remove fl uid from the pipeline. Th ere’s two variations. In some cases, we tell the operator we’re doing to test things, and in some cases, it’s an unannounced test, where the pipeline operator doesn’t know we’re going to do a test, and the leak detection analyst doesn’t know we’re going to do a test.

“On Line 3, we

did one of these at the end of May. It was a real validation of the system. Th e software worked, and detected the leak and alarmed. Th e control centre operator, independently of the leak detection analyst, when he saw the alarm said that looked like an leak and shut down the pipeline, for real. Th e leak detec-tion analyst, in paral-lel, determined it was a real leak and called the control centre and said please shut down.

It was already going down,” said Th relfall.

“Th e leak detection analyst also engaged our second level backup support and that person also independently said it was a leak.

“Th ree independent people all recognized it was a leak and shut the line down. It was an extremely successful test that no one knew was happening.”

“It’s a heart-racing moment for all those involved,” Th relfall concluded.


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Since 1925, Canadian engineers have long been given a ring as a rite of passage when they fi nish their schooling known as the “ritual-calling of the engineer.”

Th e iron ring, which according to myth, was originally made from iron from a bridge that collapsed in Quebec in 1907, killing 75, due to poor en-gineering. As Wikipedia notes, “Accepting the ring is not a prerequisite to

becoming a Professional Engineer, but is instead worn as a constant reminder to graduates of their responsibility to the public.”

Enbridge has taken this to heart. As noted by one of the panels at their Maryfi eld open house for the Line 3 replacement, the ring was explained like this:

“Th e Enbridge ring is crafted from steel from Line 6B in Michigan. It is a solemn reminder to all Enbridge personnel of our shared duty to protect the safety and integrity of our operations and to earn and defend the trust of every-one who depends on us.

“Th e ring represents every incident Enbridge has ever experienced across our businesses and it highlights our obligation, individually and as an organiza-tion, to make our operations as safe as reliable as possible.

“Th e Enbridge ring is and will remain a lasting and recognizable symbol of importance of safety, the emphasis we place on integrity of our systems and actions and our enduring commitment to those values.”

Each current and new employee is given one of these rings.

The Enbridge ring

Look uppower lines near Kisbey. Photo by Brian Zinchuk


By Brian ZinchukEstevan – The story of Long

Creek Railroad has had a few curveballs thrown into it. From its first inception as a way for farmers to save a local rail line, it took 14 years to get off the ground. When it did, the leading commodity shipped on the line that runs from Brom-head to Estevan was not grain, but crude oil. Now in their third year of operations, things have flipped on their head yet again.

Long Creek hasn’t shipped a drop of oil in the past year, but the disappearance of oil manifests were compensated for by the largest har-vest in Saskatchewan history.

That doesn’t mean oil is off the agenda, however. Last spring Crescent Point Energy Corp. CEO Scott Saxberg indicated that their Flat Lake play, near Lake Alma, has the potential to be as big as their Viewfield play. Crescent Point has been one of the leaders in the shift to crude-by-rail transportation, and has its own facilities or access to third party facilities in nearly all of its main operating areas.

Bob Holden, general manager of Long Creek Railroad, has been around since it started operations. Glenn Pohl, manager, joined August 2013. Both have long histories with Class 1 railroads, but have made the transition to the world of shortlines.

“We’ve got two of us doing 14 people’s jobs,” joked Holden.

Pohl said, “We’ve got two mainte-nance people, an administrator, and the two of us.

“We’ve got a board of 13.”Long Creek Railroad is based in

Estevan.Torq Transloading established a

crude-by-rail truck-to-train transload-ing site near Bromhead, a small hamlet northwest of Torquay and near the ter-minus of the railroad. Last summer, oil shipments dried up for the shortline.

“It was August last year, around the time of Lac-Mégantic, and the wet spell. It hasn’t fired up since,” Holden said.

“We had to diversify,” Pohl said.“They’re still looking for custom-

ers,” Holden said of their transloading partner.

At its peak, Long Creek Railroad was running 32 crude tankers a week. Those black rail cars usually run around 600 barrels, so that equated to 19,200 barrels per week. Most crude-by-rail statistics are done in barrels per day, so their average was 2,742 barrels per day.

“It wasn’t big, but it was fairly steady,” said Holden. “We were doing twice a week, Tuesdays and Fridays.”

Usually they would take 16 cars at a time.

Page B31

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“We can do up to the full 30 with our new locomotive,” Holden said, with Pohl noting they can haul up to 100 empties.

Th ose empties can be deceiving, since there are still an awful lot of black tanker cars seen on their sidings up and down the line. Long Creek has found a side-line business in provid-ing storage for tankers not in use.

Currently they are storing cars for J.P. Morgan and the Moose Jaw refi nery.

“We’re over 300,” Holden said of the number of empties on their sidings. “J.P. Morgan has 1,800 cars in their fl eet. Th ey can’t all be rolling at the same time. I’m sure they would give us more if we could handle it.”

But wasn’t there a shortage of oil tank-ers? Are there cars now

available?“Grain, no. Oil,

yeah, there’s cars avail-able,” Holden said.

“Th ese are the old fl eet. Th ey’re not the newest, shiniest fl eet,” Pohl noted, refl ecting on the shift away from older DOT-111 certi-fi ed cars that are seen as less safe than cars that meet newer standards. Regulatory changes and pricing structures by Class 1 railroads that charge a fi nancial penalty for using DOT-111 cars are apparently sidelining some of them.

Pohl said, “Th at fl eet is pretty near done. Th ey’re getting out of them.”

Holden said crude-by-rail “was a good start. We had to shift focus after a while, to grain and storage.”

Torquay is the next hot play

Th e Torquay forma-tion, which is known as the Th ree Forks formation in the U.S.,

is rapidly growing in importance. At the Wil-liston Basin Petroleum Conference in Bismarck, N.D., in May, there was a common theme in the drilling plans unveiled by the largest produc-ers in North Dakota. Sure, they may be still be drilling Bakken wells, but their ultimate goal in fully-developed sites is to drill as much as three-times as many Th ree Forks wells as they do Bakken wells on the same spacing unit. It

is that formation which Crescent Point is now focussing on.

Th e Torquay (Th ree Forks) only exists in Saskatchewan right along the U.S. border and in a small area along the Manitoba border.

A look at the active

drilling rig maps on Rig Locator (riglocator.ca), a sister publication of Pipeline News, shows the border area near Tor-quay and Oungre to be one of the most inten-sive drilling areas in the province right now, with most of those rigs work-

ing for Crescent Point. And it just so happens that Long Creek Rail-road runs right through Torquay and the Brom-head transloading site is the closest crude-by-rail facility to this growing play.

Page B32


Page B31Asked if they’ve been pursuing opportunities there, Holden said, “It’s not

that we haven’t off ered. We haven’t heard back.“We are open for business. Maybe in due time...” Pohl said.

2013 isn’t over yetPipeline News spoke to the pair on July 31, the last day of the 2013 crop

year. With farmers greasing their combine headers for this fall’s harvest, Long Creek is still in 2013, so to speak.

“We’re still dealing with the harvest of 2013. We’re 1,000 grain cars behind right now,” Pohl said on that day.

Th ey went so far as to get their own cars to deal with the surplus.“We’ve leased 50 cars to move grain,” he said, adding that other shortlines

are 2,000 to 3,000 cars behind in their shipments.“If we didn’t have those 50 cars...” Pohl said, his voice trailing off , before

adding, “Th ey kept us moving.”Th ere may be 52 weeks in a year, but when it comes to the 2013 crop year,

that’s not where they were at. “On the orders year, we’re on week 27. We should be on week 48,” he said.

“We get list from the grain commission (of ) who’s up every week,” he said of the next grain producer in line to ship.

Long Creek was founded around the principle of producer cars, a right en-shrined in legislation that allows farmers to sidestep the country grain elevator system and load entire grain cars themselves on rail sidings. Th e shortline has moved 410 grain cars from January to the end of July on just 40 miles of track.

“We’ve got a really good grain buyer out of the States,” Pohl said. While they are still contending with last year’s crop, by the time this goes

to press, this year’s crop will be coming in. “Our area is looking at a bumper crop,” Holden said. Th e company has grown beyond its shareholders, and is attracting business

from grain producers as far as Radville. “It took a lot of phone calls,” Pohl said. Page B33

Shortline still contending with last year’s harvest as new one comes in

Photo by brian Zinchuk


Page B32Holden added, “We’ve got four good loading sites. A lot is done by (grain)

cart loading. Drive to the ramp by the siding and dump.“Th ey’re seeing results from marketing their own grain.”

Shortline vs Class 1Over the last few decades, Class 1 railways like CN and Canadian Pacifi c

have increasingly been pushing unit trains as their preferred method of op-eration, leaving shortline operators on their former branch lines to aggregate small-scale shipments.

“Th ey make more money picking it up and running it,” Holden said.When it came to crude-by-rail, the Class 1 operators lost some interest

after the tragic Lac-Megantic incident in July 2013. “After Quebec, they backed off a bit,” Holden said. “I still think there’s rail in our future,” Pohl said. “Th ere’s a lot of facilities

going up, but we’re in the heart of oil and grain country. We’re in a lull right now. It will open up. You think about how much oil we can haul in one day, it’s impressive. I still think the future is rail.”

Frac sandNearing completion in Estevan is a new frac sand facility. It’s being built

for Millennium Stimulation not far from their main yard and where Long Creek Railroad originates. Th ere are two tall sand silos and a bucket elevator alongside.

“It’s going to be good for us,” said Holden. “It’s right in our yard.” “I think it’s going to grow. If you get enough volumes it will pay for itself.

It’s another commodity to move. Maybe cement is next?” Pohl said.New shop

Long Creek Railroad moved into a new shop just off their line in late fall 2013. Th ey have one spur track leading into one side of the building, and soon will be adding another switch and a second siding to lead into the other. Th ere are plans for cementing parts of the fl oor with the track in place.

Having somewhere to work inside when doing maintenance makes life a lot easier, especially in winter.

“It’s nice to keep the locomotive warm,” Holden said. It’s new to them

Remember that more powerful locomotive? It’s kind of new, at least new to them. Th at is, if you consider a 1965 General Motors locomotive new in any way, shape or form.

“We bought a GP35 last year, 2,500 horsepower, 16-cylinder, two-stroke diesel,” said Pohl.

“We hope to add another engine. We’re on the cusp (of going ahead)” Holden said. “Th e more you grow, the bigger trains are more effi cient.”

As for unit trains, he noted, “We can be creative. We are our only traffi c. We can load on the mainline.”

Th e Bromhead crude-by-rail facility has enough room for 26 cars, but there’s an additional mile of track nearby that would allow them to go up to a unit train in size.

Rail in the bloodHolden is a former CP railroad man. “I was maintenance,” he said.Holden spent 36 years with CP. Well, maybe a bit more than that.“It was longer than that. I spent summers in high school,” he said. He comes from a long line of railroad men. “My grandfather was in the

bridge building,” he said.Pohl was also with CP, but in the running trades, e.g. train crews, as an

engineer and conductor. He spent 17 years with railroads, initially with CP and then two years with Bethune-based Mobile Grain, another shortline, before joining Long Creek.

His roots in railroads go even deeper than Holden’s. “For me, I am fourth generation. My great-grandfather was one of the fi rst engineers out of Moose Jaw,” he said.

“Th e shortlines have created all sorts of opportunities. You’re not just a conductor or a track guy.”

While Pohl said he was “a good Teamster,” he doesn’t miss the restrictions of working within a highly defi ned workplace, where if you had one job, that’s what you did, and you didn’t stray from it.

“My fi rst dealings with shortlines, I was in heaven. When you had an idea, it was implemented. When front-line guys are listened to, it makes you care more about the company.”

A second switch will soon be added allowing another track to be run into their new shop.


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By Brian ZinchukVirden, Man. –

Virden Meter Services Ltd., a sister company of

Estevan Meter Service Ltd., didn’t take long to outgrow its original home. Originally es-tablished in November 2012, by May 2014 they needed a new home.

“Th ere was no room. I didn’t have room for my guys,” said Mark Kessler, president and one of the partners in the limited company.

Th e new building is right next door to the old one. But instead of 20 x 80 feet, they now have 80 x 60 feet, or three times as much fl oor space.

Over the last year the instrumentation specialist company has gone from four employ-

ees to six full-timers and one more part-timer.

“Build it and they will come,” Kessler said, when asked about the reason for growth. “Th ere’s stuff happen-ing everywhere. Th ere was no real support for instrumentation around here before.”

Increased drilling activity has been a factor as well.

“Our repair shop is now the size of our complete old shop,” he said. “We’re going to need more room if it keeps going.

“Decent product, good guys, the work just keeps coming in.

“We stock a little more inventor than we used to. We’ve got a little more room,” he said.

“People are realizing Virden Meter is more than meters.”

Th ey carry supplies, fl anges, relief valves and pumps, as examples.

Virden Meter is supplying more ma-terials now for treater turnaround. One wall in the warehouse is lined with a variety of pres-sure vessel gaskets, for instance. When a treater package is sent out, it has everything they think might be needed so that crews aren’t held

up by a missing item. Th en when the project is done, whatever isn’t needed is brought back.

“You can do a turn-around, come and get a treater package where we send out gaskets, all the supplies and anodes for the turnaround. After that, we send the combustion guys around for treaters and free water knockouts.

And example he provided was an eight by 30 foot forcefl ow treater. Th e package for that would include everything from gaskets to rags. “Everything you need, with one phone call,” he said. “Th e only thing we don’t supply is the crew.

“Every company has treated us fairly,” Kessler said of the local oil producers. “Our fi eld

tech is out all the time. Another is in the shop. We have two shop tech-nicians and one shipper/receiver. Morris will do our fi eld service runs.

“We pretty much do everything Estevan does,” he said, refer-ring to sister company Estevan Meter. Virden Meter is a fully-certifi ed valve shop and NIST-traceable meter proving facility.

As it turns out, pretty much the entire staff except for Kes-sler is musical, so the spare room upstairs is now a rehearsal space for them to jam. You’ll fi nd drums and guitars waiting for the evening when the instrumenta-tion work is done.

“I’ve got a really good group of guys. I’ve been lucky,” he said.



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Virden, Man. – Safety is a continually growing area of busi-ness for Safety Source and Discovery Safety Services.

Th ere are actually two sister companies based out of the same location in Virden, Man. Safety Source hands supplies, training, fi t testing, gas detection, consulting and servic-ing. Discovery Safety Services Ltd. takes care of fi eld medics, air safety trailers, confi ned space standby, battery turnarounds and vapour suppression.

Tundra Production Services also rents space at the same location

Th ey moved into their current location in September, 2012. It’s conveniently located right next door to the Tundra Oil and Gas fi eld offi ce in Virden. Tundra is by far the largest producer in Manitoba.

Th is location has double the retail space from what they had be-fore, one block away, ac-cording to Dale Lewis, president.

Th ey also have two classrooms now, one of which is tiered, which makes it better for lecturing. It is used for classes like ground disturbance.

Asked how they came about to choos-ing the current loca-tion, Lewis said it was available and had the size that they needed. However, they’ve almost outgrown it, and are looking to expand the facility for truck storage.

“We do have some room to expand,” Lewis said.

More room would be useful for a fi re extinguisher depot and possibly servicing.

“We want to be a one-stop safety shop,” he said.

Discovery Safety

Services and Safety Source merged on March 12, 2014

In addition to their Virden home base, Safety Source also has a Redvers, Sask. location, with two people work-ing there.

A third location is possibly in the works, but Lewis said, “I won’t say where.”

He did disclose that it would be in Manitoba and it would diversify their business beyond the oilfi eld.

“Safety’s not just the oilpatch. Safety’s everywhere,” he said. “Training is more and more important.”

Liability and insur-ance are other issues related to safety.

“We’ve got to tap into that other market,” he said.

“Th ings are going well. We’re continuing to grow every month. Th e industry looks

strong for the next seven to ten years, they tell us in southwest Manitoba and southeast Saskatch-ewan, and we’re going to continue to grow with hit.

At peak staffi ng, Discovery has 19 staff -

ers while Safety Source has eight.

Virden was ground zero when heavy rains hit at the end of June. As a business, it didn’t aff ect them, but as volunteers, it absolutely did.

“We closed the store down for a couple days and sandbagged,” Lewis said. “It was scary at the time. Th ere was water where we hadn’t seen before. To have that kind of water was crazy.”

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Regina – Back in January the Petroleum Technology Research Centre, or PTRC, hired a new CEO, Ken From. The position had previously been held on an interim basis by Neil Wildgust who left the PTRC in June to work for the Global CCS Insti-tute, establishing its new Calgary office. Wildgust had stepped in when former CEO Dr. Malcolm Wilson left the PTRC in 2013. Wilson’s departure was in the midst of a controversy surrounding sister organization IPAC-CO

2,, which Wilson had also

been involved with. He took early retirement in June 2013. Pipeline News spoke to From in June after four months on the job. PTRC Com-

munications manager Norm Sacuta added some background information as well.Pipeline News: You kind of came into a bit of a hornet’s nest in that

PTRC generally operates pretty quietly, but got a lot of press last year. Has all of that been resolved or have there been any issues in that regard?

Ken From: All I can speak to is since I’ve been here and what I’ve learned from the board – since I’ve been here, there are no issues historical in nature. I think all those issues were cleaned up or not even really there.

P.N.: What is your background?K.F.: Academic background: mechanical engineer, U of S. Employment

background: 26 years at SaskEnergy/TransGas, doing the full gamut, all the way from engineering services, planning, to senior vice-president of supply and business development.

P.N.: What does that mean as senior vice-president, that you made sure they got gas to their houses?

K.F.: I made sure they got it at a good price. Natural gas has evolved, as you know, from days when only three people were able to export gas out of Alberta – one was SaskEnergy, another was TransCanada. We had a portfolio where we had our own production with SaskPower. When it was deregulated in 1988 it went to contract. We needed to ensure we had adequate contracts to meet our load profile, and provide safe, secure supply with a price that is predictable for the consumers throughout the year.

Perhaps the first 10 years were spent on the engineering side, the last 15 on the gas supply side. Page B37

Ken From took over as CEO of the Petroleum Technology Research Centre earlier this year. Photo by Brian Zinchuk

New PTRC CEO used to run oil company


306-637-3460

Page B36P.N.: How old are you?K.F.: I’m 58, coming up.P.N.: After SaskEnergy you

worked in the private sector. When did you leave SaskEnergy?

K.F.: I left SaskEnergy in 2007. I and some colleagues in the geosci-ence industry decided we should set up our own oil company, so we founded Prairie Hunter Energy. We built that up from absolutely nothing and sold it to Renegade Petroleum in May 2010.

P.N.: Was that a privately held company?

K.F.: Yes, Prairie Hunter was pri-vately held, and Renegade was on the stock exchange at the time.

We had a partner we were 50/50 with. Our partner was totally silent; they were totally financial. They didn’t sell their half. We only sold our half. At the time of sale, our gross produc-tion was just a tad over 500 barrels per day. The gross value of that would have been about $40 million, and we got half of that, about $19.8 million.

We had many investors, but one company partnering with us. It was the largest company in Saskatchewan by revenue, with gas stations and grocery stores.

P.N.: Federated Co-op?K.F.: Yes. A nice partner to have.P.N.: They also purchased (an-

other junior producer) around that time?

K.F.: Just after that. When we sold, one of the guys that was my partner, Jon Hromek, went over to Federated and started running their oil division. As Federated found out, after we brought them prospects and some good management skills, (they looked at their old properties).

They had old properties going back to the 50s. They hadn’t looked at them for years. They were doing about 4,000 barrels per day at the time. So Jon proposed to them (we had divested

from Prairie Hunter), “Well, guys, I can tell you need a lot of work there.” He got hired and now they’ve built it up and bought more companies and are drilling like crazy.

When Jon and I started Prairie Hunter, one of the things we wanted to do was employ more people in Sas-katchewan. We wanted more of a head office, of a presence, of the technical skills, not just a field office. Let’s get some of the field engineering and geo-sciences to support that. With Prairie Hunter, we were never strong enough to do that, but at Federated, Jon has hired a ton of people.

P.N: From 2010, what did you do?K.F.: I started up and ran an orga-

nization called TSASK, the Technical Safety Authority of Saskatchewan. It was the provincial government, along with body looking at regulation simpli-fication throughout industry, recog-nizing the boilers and pressure, rec-ognizing that boilers, pressure vessels, elevators body that was doing all the approvals in government was not able to respond. So they took it out and set up a new, non-government, arm’s length agency called TSASK. They needed someone to run that, and some of the board members recruited me.

P.N.: So your job was to cut red tape or look for ways to cut red tape?

K.F.: Cut red tape, get rid of the bureaucracy, and put in a thing called customer service.

They had the inspectors, but everything else, such as payments, legal resources, legal, communications, were all within the industry. If you take out these 25 inspectors and say “Have at ‘er!” who does what? So that’s why they had outside people who’ve run (an organization with people) to say this is what we need to do.

I did it for two years. One of the things I’m kind of

happy about is that I spearheaded the search for a new building, to create

a new culture. We found some new office space outside of downtown so that welders coming in from out of province to get their tickets could park their vehicles. It’s an amazing transfor-mation.

I’m currently on the board of TSASK.

P.N.: And in the past few years, what have you done?

K.F.: Goof around, get back into the oil side, then this came up. It was a perfect opportunity to get back in the patch.

P.N.: One of the things sorely lacking in both government and non-governmental organizations like the PTRC is real business experience. At Prairie Hunter, what was your role?

K.F.: I was CEO, chairman of the board, chief bottle washer.

P.N.: That is almost an entirely different perspective than almost anyone else that probably works in the organization or in the ministry. Few provincial geologists have run an oil company. What sort of perspec-

tive does that give you when it comes to running an organization like the PTRC?

K.F.: Probably the most important thing is that it gives the view from a producer, looking at it from their perspective, being in their shoes. For PTRC, when we’re looking at research projects and new initiatives, what’s the value statement for the oil companies? Without understanding the oil compa-nies, how do make a good proposal on the value-added on what you are trying to do?

P.N.: Have you been able to incorporate that yet?

K.F.: We are formulating plans. We are winding up a few of the projects that will come to their natural ends anyways. We’re in a bit of a tran-sition period. Working with our board, we have identified areas we want to go into – what we want to do with CO2, and maintaining our strong presence in heavy oil EOR, adding projects to add real value.

Page B38


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I think we’ve changed a few things in how we are sending out re-search projects. We’re not just sending out a broad category and saying “Can you submit your ideas on how to solve industry’s problems.”

We’re saying to industry, fi rst, “What would you like these research-ers to look at? What are the things that are causing industry problems?”

Th is year we’re sending out very distinct RFP (requests for proposals). Here’s the problem. Here’s what we want for outcomes. You guys (re-searchers) tell us your methodology and how much it’s going to cost and your deliverables.

A real example: we’re looking at some heavy oil wells. Th e question is how we do get the foamy oil back after it’s gone to post-CHOPS (cold heavy oil production with sand)? What kind of things can we do there? What kind of solvents? How do we work these things to get foamy recov-ery back?

Th e way that (RFP) was devel-oped, and that’s what was key to me, is the process we use – talk to indus-try. Get the committee we have, based on our advisory committee of oil companies, and base it on the kind of research they want.

P.N.: What is transitioning? K.F: STEPS (Sustainable Tech-

nologies for Energy Production Sys-tems) came to its natural end. Right now we’re busy doing all the ac-counting and reports for the funders, mainly the federal government.

Norm Sacuta: JIVE ( Joint Im-plementation of Vapour Extraction) ended in 2010. Th e more publicly available reports are coming out now.

It was using diff erent combina-tions of solvents in three fi eld trials. Th ere were four, but one of the wells watered out. Th e best results were with Husky, and they have since gone on. A lot of the stuff they are doing with CO2 is with information they got from JIVE in heavy oil reservoirs.

K.C.: I think JIVE was one of the most successful ones that we’ve had. It was fi eld trials. Secondly, some (companies) found something really good out of that and have taken it on their own and have taken it to a full-scale implementation. Th ey’re taking the initial research we did, the spark-plug, and found something they really like in their particular reservoir at the time of development, and they’re go-ing with development.

P.N.: What is the role now with Aquistore and SaskPower?

K.F.: It’s always been the PTRC’s intent that it would not own a physi-

cal asset that it cannot operate, the injection well. It was always the intention to transfer that asset over to SaskPower, because it’s part of the SaskPower operation. It needs people there who know when the valves are turning on and off , what the plant is doing, what the contract with Ceno-vus is calling for.

Our role with PTRC is to vali-date certain parameters within the geological storage. So we still mea-sure, monitor and verify what’s going downhole.

P.N.: So you’re still the science part?

K.F.: Absolutely. We are the ones that are going to be managing all the monitoring and verifi cation. Sask-Power will do all the operations, set up all their safety protocols, because SaskPower’s never done that. Th e

only one who has on a big scale has been Cenovus. SaskPower is cur-rently looking at that. Th ey’ve asked us to handle the MMV, measurement monitoring and verifi cation.

Th e other thing I should mention on Aquistore is there may be more ongoing research, and public outreach. We will play a big role in the public outreach. It’s SaskPower’s well, but we will do outreach on data that is eventually publically available.

P.N.: You have the permanent array of geophones, so that is still your job?

N.S.: We just collected the data recently.

P.N.: Let’s talk about the new stuff . What’s HORNET?

K.F.: Heavy Oil Research Net-work.

Page B39


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Page B38It’s our new branding of our heavy

oil research. We’re just now sending out RFPs. For the first time, we are actually defining a couple projects we want to look at, as well as give researchers the opportunity in other areas to use their creativity and in-novation to give us projects they want to look into.

P.N.: The initial mission of PTRC was primarily to look at heavy oil.

K.C.: We’re continuing with that on the heavy oil. We have other proj-ects as well.

One thematic area is wormhole identification. We’re still trying to find out ways to determine how big these things are orientations, what do they look like. If we can unlock that, maybe there’s a way to get another five per cent of oil out of the ground. The prize is large enough that we continue to work on that.

P.N.: How much of your focus is heavy oil? Seventy per cent?

N.S.: Of our EOR work, probably 70 per cent. But not of all PTRC’s work.

K.F.: Seventy per cent of our EOR work is in heavy oil. As you know, PTRC has built a very strong international reputation working with CO2 on enhanced oil recovery and CO2 for pure storage. I can’t help but think, seeing what’s going on with President Obama and coal-fired pow-er plants, you’ve got to think PTRC and Saskatchewan is in an extremely well positioned. Last night on CBC they even showed Boundary Dam and mentioned part of it would be stored underground. They didn’t even men-tion the EOR. That was the neat part.

When you look at what has been

done at PTRC, 14-odd years of very strong research into CO2-EOR, all of that is so much information on how you do the storage. Maybe, yes, it was for EOR, but the same things apply, and you learn so much from that. All that was done, not on a lab scale, but in the field.

P.N. For years Saskatchewan has been taking for years that we have this knowledge and the world will eventually beat a path to our door. Did Obama’s speech give the coal plants a kick in the pants to do some-thing about EOR?

K.F.: I can’t predict that kind of thing. But look at companies doing carbon capture. SaskPower is one, the first to do commercial-scale post-combustion carbon capture.

If you look at what private com-panies are doing, Hitachi paid a good portion of that test facility at Shand (Power Station). Hitachi will probably see some kind of demand for carbon capture using different technologies. They were happy to support that. The only thing they get from that is the first year, year and a half of exclusive use.

It’s a factor of five larger than the ITC (International Test Centre in Regina). It’s a mini-Boundary Dam.

P.N.: What are your efforts in light oil? Light, tight oil is starting to mature. You’re starting to see wa-terflood in the Bakken area. What’s next?

K.C.: Our work in the light side started years ago in STEPs, with a dozen or so projects.

One thing we found out at the Williston Basin Petroleum Confer-ence was that the Bakken and other tight oil formations is tremendous op-portunity. Everyone is starting to look

at if CO2 is a viable method to get more oil, not only as an EOR process, but can you use CO2 for fracking? Will it flush more out, using CO2 as a fracking fluid?

It’s an area where the potential is great. We’re still looking at where we find our niche in Saskatchewan on light/tights. We don’t compare exactly to other areas. We’re talking to oil companies about where there might be an area of interest to explore through research consortiums.

Our strength is leveraging money – government money, private money, putting together four or five compa-nies who want to share information until they get to a point where one or two want to take it and run with it.

Because of sharp declines and low recovery factors (in the Bakken), work needs to be done. It’s begging to be done. How we crack that nut is part of the challenge.

Whether southeast or southwest Saskatchewan or Lloydminster, to me the most sustainable way of extracting

oil is to get more of the original oil in place out. That way you’re not creating boom and bust communities. The in-frastructure’s there. You’re just getting incremental oil out.

The key is how do we do that economically? Or are you always trying for the next greenfield oppor-tunity. Our role at PTRC since we were mandated has been to increase recovery rates. When we were formed, the real issue was heavy oil. In recent years, I would argue it has included other areas, such as light/tights. Why not look at getting a bit more out?

I’m of the belief that some of these wells – a producer, even if marginal – you don’t want to abandon them, because new technology is go-ing to come out. New ways of doing things to increase that recovery.

The whole Bakken is on 10 or 11 per cent recovery. All that land rental, bonuses, is all up front. Now if you can go in there and do an EOR and get another five per cent, what is your full life cycle? Pretty darn good.


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Vermilion – Lake-land College generates $168 million in eco-nomic spinoff s to the local economy from its Lloydminster and Ver-milion campuses accord-ing to a study released on Aug. 18 in advance of the fall academic term.

Th e economic impact comes from the spending of Lakeland College, its employees and its students plus the impact of increased

productivity of former students employed in the regional workforce.

Th at’s one of the fi ndings of an economic spinoff s study recently completed by Economic Modeling Specialists Inc. (EMSI) using data from 2012-2013.

“Th is report high-lights a few of the many ways Lakeland College contributes to the well-being of our students, the local region and the

province,” said Tracy Edwards, president of Lakeland College.

“It shows that Lakeland College is an excellent investment for students and taxpayers.”

During the study year, Lakeland College served more than 7,500 full-time and part-time students.

Of this total, 4,249 relocated to the region to attend Lakeland. Th e EMSI study estimated that out-of-region student spending added $3.8 million in income to the region.

Lakeland College is also a major employer in the region, employing the equivalent of 430 full-time employees.

Th e net impact of college payroll plus day-to-day operational spending was $50.8 mil-lion in added regional

income during the year. Th e contributions

of former students now employed in the regional workforce amounted to

$113.4 million in added income.

Th e EMSI report notes taxpayers also receive a positive return for their investment in Lakeland College.

For every dollar that Alberta taxpayers spent on Lakeland during the year, society will receive $6.60 in added provin-cial income and social savings related to the improved lifestyles of students.

EMSI is a U.S. based company that turns labor market data into useful information that helps organizations understand the connec-tion between economies, people, and work.

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Study sums Lakeland spinoffs at $168 M


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NewsPiPeliNe seCTiON C

September 2014

Pipeline News was 2 sections this month.

stay tuned for next month focus: lloydminster Heavy Oil show/

Boundary Dam Carbon Capture

pipeline news september 2014

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