Pipeline News September 2014

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PIPELINE NEWS :HZRH[JOL^HUÂťZ 7L[YVSL\T 4VU[OS`

September 2014

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Volume 7 Issue 4

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B1 Ceres Northgate Commodity Logistics Hub nears completion A8 Gibson Energy CEO talks crude-by-rail A3 Viking drilling outpaces Bakken dƾŜÄšĆŒÄ‚ ĹśÄžĆŒĹ?LJ DÄ‚ĆŒĹŹÄžĆ&#x; ĹśĹ? >Ĺ?ĹľĹ?ƚĞĚ͛Ć? Ä?ĆŒĆľÄšÄžͲÄ?LJͲĆŒÄ‚Ĺ?ĹŻ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ Ä‚Ćš ĆŒŽžÄžĆŒÍ• DÄ‚ĹśÍ˜ Ä?ĂžĞ ŽŜůĹ?ŜĞ Ĺ?Ĺś ^ĞƉƚĞžÄ?ÄžĆŒ ĎŽĎŹĎ­ĎŻÍ• ĂŜĚ Ĺ?Ć? ĞdžƉĞÄ?ƚĞĚ ƚŽ Ć?ĞĞ Ĺ?ĆšĆ? Ä?ĂƉĂÄ?Ĺ?ƚLJ Ĺ?ĹśÄ?ĆŒÄžÄ‚Ć?ĞĚ ƚŽ ϲϏÍ•ĎŹĎŹĎŹ Ä?ƉĚ Ä?LJ ƚŚĞ ĞŜĚ ŽĨ ƚŚĹ?Ć? Ç‡ÄžÄ‚ĆŒÍ˜ ĆŒŽžÄžĆŒ Ĺ?Ć? ĹŠĆľĆ?Ćš Ä‚Ä?ĆŒĹ˝Ć?Ć? ƚŚĞ Ä?Ĺ˝ĆŒÄšÄžĆŒ ĨĆŒŽž ^Ä‚Ć?ĹŹÄ‚ĆšÄ?ĹšÄžÇ Ä‚ĹśÍ• ĞĂĆ?Ćš ŽĨ ZÄžÄšÇ€ÄžĆŒĆ?Í• ĂŜĚ Ĺ?Ć? ƚŚĞ Ä?ĆŒĆľÄ?Ĺ?Ä‚ĹŻ ƉŽĹ?Ŝƚ ŽĨ Ĺ˝Ĺ?ĹŻ ĆšĆŒÄ‚ĹśĆ?Ć‰Ĺ˝ĆŒĆšÄ‚Ć&#x; ŽŜ Ĺ?ŜĨĆŒÄ‚Ć?ĆšĆŒĆľÄ?ĆšĆľĆŒÄžÍ˜ Photo by Brian Zinchuk

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PIPELINE NEWS September 2014

INSIDE SECTION A 4

ATCO Lodge Estevan closes

12 Technical talks

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17 Bakken area sees big land sale

6

Editorial

18 Bruderheim terminal might be sold

7

Opinion

20 Kerrobert eyes camp

8

Gibson CEO talks crude-by-rail

31 AER blames leak on CNRL steam strategy

11 Edmonton crude-by-rail terminal to double

36 OmniTRAX kyboshes Churchill crude shipments

SECTION B Ď­

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

3

Northgate Hub design explained

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22 Ruins cause stop-work order

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26 A heart-racing test

10 Crescent Point leads crude-by-rail charge

30 Long Creek Railroad

PIPELINE NEWS :HZRH[JOL^HUÂťZ 7L[YVSL\T 4VU[OS`

Oct. 2014 Focus

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PIPELINE NEWS September 2014

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TOP NEWS Viking out-drills Bakken play By Geoff Lee Pipeline 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 KindersleyDodsland 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 horizontal 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 barrels produced in Viking. The Viking though is clearly the provincial hotspot 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 continues 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 variable in its geological makeup. “The Viking can be best described as a bioturbated siltstone-sandstone sandwiched between two marine shales; 700-800metres deep,” said Yurkowski. 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 heterogeneous unit,” explained Yurkowski. The Viking is an extensive formation that covers 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 Mannville so there is no sand produced with Viking oil. The API of Viking oil ranges from 35 to 39, almost 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 Dodsland areas, but Yurkowski said those are heavy oil plays. “That’s a separate system all together. The Bakken play in the southeast corner of the province is

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 interpretations 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 Tempco Drilling Company, a private oil and gas drilling to understand the regional geology of the Viking,” contractor based in Nisku Alberta has had several of its said Yurkowski. rigs drilling for oil in the Viking play over the past few “That will help industry understand their reserLJĞĂƌƐ͘ /Ŷ ƚŚŝƐ ĮůĞ ƉŚŽƚŽ͘ ƌŝĐ >ĂŶŐ ƚŚĞ ĐŽŵƉĂŶLJ͛Ɛ ŐĞŶĞƌĂů voirs a little bit more and put it into context. So he’s is seen standing in front of Rig 2 that was undergoing a ƌĞƚƌŽĮƚ͘ dĞŵƉĐŽ ĐƵƌƌĞŶƚůLJ ŚĂƐ Ă ŇĞĞƚ ŽĨ ĞŝŐŚƚ ĚƌŝůůŝŶŐ ƌŝŐƐ going to be doing the regional work on it.” “It’s a matter of our geologist taking a look at ĐŽŶƐŝƐƟŶŐ ŽĨ ƚŚƌĞĞ ƐŝŶŐůĞ ĐŽŶǀĞŶƟŽŶĂů ƌŝŐƐ ĂŶĚ ĮǀĞ ƌĂŶŐĞ all the cores and sort of putting a story together.” 3 top drive rigs. While it’s not Yurkowski’s job to forecast the life expectancy of the Viking play she said, “I just very different than the Bakken play in the Kinders- know there’s still a lot of infill drilling that can be ley area. That’s a different story. done. “The Viking play is the Viking formation.” “They are also drilling sort of the edge of the More than 8,000 vertical wells have been pools as well. I notice there’s sort of a halo effect. drilled in the upper zone of the formation. “So some wells have been drilled sort of on the Yurkowski said production from the Viking was edges of some of the pools.” steady from the 1950s up to 1984 when there was a The initial oil in place in the Viking is estimatbit of an increase then production dropped back to ed at just under 2.8 billion barrels. pre-1984 levels. The total reserves that could be recovered using “It’s just been since 2011 and 2012 that we conventional technology total 294 million barrels. started to see an increase. That was when they “To date we have recovered over 208 million brought in the horizontals and the fracking,” she barrels of oil and that leaves 85.6 million barrels to said. be recovered,” said Yurkowski.

A4

PIPELINE NEWS SEPTEMBER 2014

BRIEFS 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. The price is about $88 million, including 1.5 million Crescent Point shares and assumed net debt, based on a five-day weighted average share price of $45.36 per Crescent Point share. Closing was expected in midAugust. The assets produce 700 boepd and include more than 24 net sections of land. Crescent Point said the assets offer excellent rates of return and include 53 net low-risk drilling locations and significant exploration potential in multiple horizons.

Crescent point locks up land On July 30, Crescent Point Energy Corp. closed an agreement to buy assets in the Viewfield Bakken and Flat Lake plays in southeast Saskatchewan from an unidentified producer for $99.1 million in cash. The Flat Lake assets are producing about 825 boe a day and include more than 54 net sections of land. These assets are next to Crescent Point’s Viewfield and Flat Lake lands, and include 38 net low-risk drilling locations. Briefs courtesy Nickle’s Daily Oil Bulletin

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

ATCO Lodge Estevan closes around the time it expected to Estevan housing situation not as tight as before „ By Brian Zinchuk Pipeline 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 five years. It’s now 2014, and it appears that five years is nearly up. Back then, George Lidgett, then-executive vice president operations and field 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 fly-by-night style.� Asked how long the company planned on having the camp at Estevan, he responded, “We’re there for the long haul - five 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 five weeks. The Estevan location is no longer listed on the ATCO Structures and Logistics open camps web page. The closure coincides with the wrapping up of the SaskPower 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 Boundary Lodge during the summer of 2013. The 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 establishment of a new facility that will replace its Waskada, Man. camp. The 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 timeline.� 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 flood the market. The big difference now compared to recent years is, “We have product,� she said. Now the purchase market is neither a buyers’ nor sellers’ market, according to the broker. “We have rental property available,� she added. There 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. That’s still enough for a revenue property investor to make money, but they won’t see the higher returns they were getting before. There’s still a good return on the investment, according to Chipley. “There 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. The key is to get the word out that there are places to rent now in Estevan. “There’s definitely 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 accommodations 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. The volume-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.

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PIPELINE NEWS September 2014

A5

Lac-Mégantic report cites BRIEFS Penn 18 factors in disaster West under À QDQFLDO scrutiny

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Lac-Mégantic, Que. – The Transportation Safety Board is calling for new physical measures to prevent runaway trains and for more complete audits of railway safety management systems. The TSB made the two recommendations with the release of its final report on the Lac-Mégantic Quebec rail disaster on Aug. 13 The report cited multiple factors that led a runaway train carrying crude oil to derail and ignite into a large fire 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.” The 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 evening of July 5, 2013. The engineer applied just seven of 17 to 26 brakes needed to secure the train and did not follow rules requiring him to test the effectiveness of the hand brakes. “What we are saying is the rules aren’t enough. They are not sufficient; no matter what the rules are you can improve the rules. You can beef them up,” said Jean Laporte, TSB’s chief operations officer. “There 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.” The 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 fireball. TSB officials said new defences against runaway trains could include introducing wheel chocks for parked trains or installing new, more modern braking technology to prevent trains from moving. “This accident has really brought about and will bring about a sea change I believe in terms of the thinking of the train industry, the shippers and the regulators,” said Tadros. The investigation found MMA was a company with a weak safety culture that did not have a functioning safety management system to manage risks. The TSB also learned that Transport Canada did not audit MMA often and thoroughly enough to ensure it was effectively managing the risks in its operations. Furthermore, the investigation found problems with training, 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. “This investigation and its findings are complex, but our goal is simple: we must improve rail safety in Canada,” added Tadros “This is about governments, railways and shippers doing everything in their power to ensure there is never another LacMégantic.”

Windsor, Ont. – Penn West Petroleum Ltd. is being investigated by Sutts, Strosberg LLP, a law firm that represents investors in securities class actions. The Ontario based law firm with offices in Windsor and Toronto reported on July 30 that is investigating the accuracy and adequacy of some of the Penn West’s historical financial statements. The investigation comes as a result of Penn West’s announcement on July 29 that it is conducting a review of certain of its accounting practices and it has concluded that certain of the company’s historical financial statements must be restated. Sutts, Strosberg LLP is a leading class action law firm that has recovered over $1.5 billion for its clients.

Briefs courtesy Nickle’s Daily Oil Bulletin

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A6

PIPELINE NEWS September 2014

PIPELINE NEWS

EDITORIAL

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.

Publisher: Brant Kersey - Estevan Ph: 1.306.634.2654 Editorial Contributions: SOUTHEAST Brian Zinchuk - Estevan 1.306.461.5599 SOUTHWEST Swift Current 1.306.461.5599 NORTHWEST Geoff Lee - Lloydminster 1.780.875.5865 Associate Advertising Consultants: SOUTHEAST SASK. & MANITOBA R5 -. 0 (5g8ifl8lij8hlkj Cindy Beaulieu Candace Wheeler Kristen O’Handley Deanna Tarnes Teresa Hrywkiw R5 ,&3& 5g8ifl8jki8hkhk

NORTHWEST SASK. & ALBERTA R5 &)3 '#(-. ,5g8mnf8nfn8imfl Krista Thiessen CENTRAL Al Guthro 1.306.715.5078 SOUTHWEST R5 1# .5 /,, (.5g8ifl8mmi8nhlf 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 contributing reporter. Subscribing to Pipeline News: Pipeline News is a free distribution newspaper, and is now available online at www.pipelinenews.ca Advertising in Pipeline News: Advertising in Pipeline News is a newer model created to make it as easy as possible for any business or individual. Pipeline News has a group of experienced staff working throughout Saskatchewan and parts of Manitoba, so please contact the sales representative for your area to assist you with your advertising needs. Special thanks to JuneWarren-Nickle’s Energy Group for their contributions and assistance with Pipeline News.

Published monthly by the Prairie Newspaper Group, a division 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 submitted 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 permission 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 information 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.

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 August, 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 activity 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 production 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 Saskatchewan 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 storage 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 expansion 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.

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Lots of shipping options 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 overcome 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 existing facilities (Hardisty, Cromer), and those in the works (Kerrobert, Northgate), then throw in all the little sites here and there (Maidstone, Dollard, Wilmar, 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 pipeline 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-byrail 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 capacity, the recently added crude-by-rail capacity, and Energy East, it will be theoretically possible to ship every drop of oil produced in southeast Saskatchewan 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 supertankers. Is that a better solution? A safer solution? Probably 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 brian.zinchuk@sasktel.net.

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Send employees to heavy oil shows 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 exhibitors, 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 companies and industry and where the new technology is being used. There is no better place to network and establish key business and professional contacts with buyers and sellers of oil and gas products and services that can help your company grow. For sales and management employees, these shows are the best way to establish face to face contact with new and existing customers and prepare the ground work for new sales or business. These shows are also great way for all employees to bone up on the state of the industry by talking 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 unless 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 exhibitors 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 sending 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 companies so regional oil and gas workers can attend as a group to save money and time. Having lots of employees at these shows is important 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 looking 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 benefit of industry. Employee attendance should be a no brainer.

PIPELINE NEWS INVITES OPPOSING VIEW POINTS. EDITORIALS AND LETTERS TO THE EDITOR ARE WELCOME. Email to: brian.zinchuk@sasktel.net

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PIPELINE NEWS September 2014

dŚĞ ÄŽ ĆŒĆ?Ćš ĆšÇ Ĺ˝ Ď°ĎŹĎŹÍ•ĎŹĎŹĎŹ Ä?Ä‚ĆŒĆŒÄžĹŻ ƚĂŜŏĆ? ŽƾĆš ŽĨ Ć?Ĺ?dž ƉůĂŜŜĞĚ Ć?ĆšĹ˝ĆŒÄ‚Ĺ?Äž ƚĂŜŏĆ? ŽĨ Ç€Ä‚ĆŒĹ?ŽƾĆ? Ć?Ĺ?njĞĆ? Ä‚ĆŒÄž ƾŜÄšÄžĆŒ Ä?ŽŜĆ?ĆšĆŒĆľÄ?Ć&#x; ŽŜ Ä‚Ćš 'Ĺ?Ä?Ć?ŽŜ ĹśÄžĆŒĹ?LJ͛Ć? ,Ä‚ĆŒÄšĹ?Ć?ƚLJ ĞĂĆ?Ćš ĞdžƉĂŜĆ?Ĺ?ŽŜ Ć?Ĺ?ĆšÄžÍ˜ ĎŽĎ° Ĺ?ĹśÄ?Ĺš ƉĹ?ƉĞůĹ?ŜĞ ĆšĆŒÄ‚ĹśĆ?Ͳ ĨÄžĆŒĆ? Ä?ĆŒĆľÄšÄž Ĺ˝Ĺ?ĹŻ ĨĆŒŽž ƚŚĞ ,Ä‚ĆŒÄšĹ?Ć?ƚLJ dÄžĆŒĹľĹ?ŜĂů ƚŽ 'Ĺ?Ä?Ć?ŽŜÍ›Ć? ĹśÄžÇ Ä?ĆŒĆľÄšÄž Ä?LJ ĆŒÄ‚Ĺ?ĹŻ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ ÄŽ ǀĞ ĹŹĹ?ůŽžÄžĆšÄžĆŒĆ? ĞĂĆ?Ćš ŽĨ ƚŚĞ ĆšÄžĆŒĹľĹ?ĹśÄ‚ĹŻÍ˜ dŚĞ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ Ä?Ä‚Ĺś ůŽĂĚ ĆšÇ Ĺ˝ ƾŜĹ?Ćš ĆšĆŒÄ‚Ĺ?ĹśĆ? Ä‚ ĚĂLJ Ĺ˝ĆŒ Ď­ĎŽĎŹÍ•ĎŹĎŹĎŹ Ä?Ä‚ĆŒĆŒÄžĹŻĆ? ŽĨ Ĺ˝Ĺ?ĹŻ Ć‰ÄžĆŒ ĚĂLJ Ç Ĺ?ƚŚ ƉůĂŜĆ? ƚŽ ÄšŽƾÄ?ĹŻÄž ƚŚĞ Ä?ĂƉĂÄ?Ĺ?ƚLJ Ĺ?Ĺś ĎŽĎŹĎ­Ďą Ç ĹšÄžĹś ĹśÄžÇ Ć?ĹšĹ?Ć‰Ć‰ÄžĆŒ Ä?ŽžžĹ?ƚžĞŜƚĆ? Ä‚ĆŒÄž ĹŻĹ˝Ä?ŏĞĚ Ĺ?ĹśÍ˜ WŚŽƚŽ Ć?ĆľÄ?ĹľĹ?ĆŠ ĞĚ

Gibson on track for unit train growth „ By Geoff Lee Gibson Energy Inc., a Calgarybased independent integrated service provider, is undertaking a multi-year build out of its new unit train facilities at its Hardisty Rail Terminal and its Edmonton Terminal. The unit train facility at Hardisty is a development project between Gibson and U.S. Development Group. The rail facility was commissioned 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 every quality of crude oil that produced in Western Canada shows up there almost every day, kind of thing.

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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 soliciting customer support to backstop the expansion from 120,000 barrels a day to 240,000 barrels a day. Depending on how quickly we can solidify that support and enter into a binding contract with our committed customers – that will sort of determine when we are able to tell the market that we are in fact going to double the capacity. I said in our investor call earlier last week (Aug. 6) that we would certainly 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.: The 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 diluent 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 material on a railcar. That’s the valuable material that a U.S. Gulf Coast refiner would want to see. They 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 first part of the facility. The 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. They 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 flow 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 first facility, but it’s certainly going to be a significant capital expenditure. ɸ Page A9

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PIPELINE NEWS September 2014 ɺ Page A8 P.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 facility. 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 associated 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 immediately 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 development of the Hardisty Terminal? S.H.: In terms of growing volumes yes. Certainly 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 commitment 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 going 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 pipelines 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 volumes 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 really 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 elsewhe re? ɸ Page A10

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TransCanada on track for crude-by-rail Calgary – TransCanada Corp. continues to work behind the scenes to develop crudeby-rail options as it prepares to file for federal regulatory approval to build its $12 billion Energy East pipeline. Shipping Alberta crude by rail to U.S. customers is also a possibility for TransCanada with continued regulatory delays in the approval of its proposed Keystone XL crude oil pipeline. The $5.4 billion Keystone XL pipeline, has been awaiting U.S. government approvals for more than five years amid strong opposition from environmental groups. The Nebraska Supreme 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 executive of liquids pipelines during TransCanada’s second quarter conference 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 infrastructure to transport oil to delivery points in North America. “On the party development side on the engineering – the siting – we’re progressing well in that regard and then on the market development side we’re dealing with a number of parties here to

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anchor those facilities,” said Miller. “And it just takes time to corral a number of parties around a common project so we continue that effort but don’t have further updates at this point.” The National Energy Board reports crude-by-rail shipments out of the country reached a new high of 160,000 barrels per day in the first quarter of 2014. That’s an increase of more than 50 per cent over the same period a year ago. The Canadian Association 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 contracts with uploading terminals in Western Canada.

TransCanada is exploring shipping crude by rail from its pipeline and oil storage facilities at Hardisty, Alberta the starting point for the Keystone XL and Energy East pipelines. Meanwhile, the company is expected to file its application to build the Energy East project with the National Energy Board any day now. “We’ve announced that we’re going to file that in the third quarter so you can expect to see that filing come in really in just a few weeks from us likely,” said Alex Pourbaix chief executive of developments at the conference call from Calgary. Energy East pipeline will transport 1.1 million barrels a day of oil from Alberta and Saskatchewan to eastern Canadian refineries and export terminals. The Energy East Pipeline project in-

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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 involve the construction of a tank farm at the Moosomin compressor 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 lateral pipeline between the Moosomin and Cromer, Manitoba to feed Manitoba light oil into the Energy East pipeline system.

Gibson CEO on crude-by-rail ɺ Page A9 S.H.: I think it’s going to be largely a non-event. The way our facilities work is that the shippers, the people who have contracted for capacity, have the obligation and the responsibility 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 fleet. 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 going 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 viewpoint to operate crude by rail facilities? S.H.: I think from the PR perspective absolutely. Transportation of dangerous goods by rail is an economic reality 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 environmental stewardship etc continue to improve, and on any day you do the best to ensure you do no harm.

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Kinder Morgan Energy Partners L.P. and 50-50 joint venture partner Imperial Oil Ltd. plan to add 110,000 barrels per day capacity to the Edmonton Rail Terminal. First phase Ä?ŽŜĆ?ĆšĆŒĆľÄ?Ć&#x; ŽŜÍ• Ç ĹšĹ?Ä?Ĺš Ä?ÄžĹ?Ä‚Ĺś ĹŻÄ‚Ć?Ćš ÄžÄ?ĞžÄ?ÄžĆŒÍ• Ĺ?Ć? Ć?ĹšĹ˝Ç Ĺś in this aerial photo. The terminal could eventually expand to a capacity of 250,000 bpd. Photo courtesy Kinder Morgan

Edmonton crude-by-rail terminal to double Edmonton – The Edmonton Rail Terminal will more than double its capacity to handle over 210,000 barrels of crude of a day by rail in the first quarter of 2015 and potentially up to 250,000 bpd. Kinder Morgan Energy Partners L.P. announced 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. The first phase was originally designed to be capable of loading one to three unit trains per day totaling 100,000 bpd. The impetus for the Phase 2 expansion came from additional take or pay (a penalty) agreements the project secured with several unnamed major oil producers. “The continued interest in this facility, and additional volume being contracted for with this announcement, further demonstrates how important it is for our customers to secure crude oil take away capacity using a variety of transportation options, including both pipeline and railway capacity to ensure crude oil reaches market,� said Kinder Morgan Terminals president John Schlosser in a news release. The 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 refineries. The rail terminal is being constructed and will be operated by Kinder Morgan, and will connect to both Canadian National and Canadian Pacific mainlines. Including the addition of the expanded capacity, Kinder Morgan’s investment in the project now totals approximately $232 million.

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PIPELINE NEWS September 2014

Lloyd oil show books technical talks „ By Geoff Lee Lloydminster – There will be four heavy oil technical presentations during the 2014 Lloydminster 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 topics.� 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 everywhere. We had people from as far as away as California who wanted to speak,� said Bacon. “We are looking for things that would apply a little more to the Lloydminster area. “Some of the ideas out there were really in-

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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 presentations will be held in Prairie Room at the Lloydminster Exhibition Grounds, the site of the oil show. The sessions will begin 11 a.m. on Sept. 10 with a topic by Noralta Technologies Inc. titled, Increasing Netbacks by Applying Digital Oilfield Technologies to Heavy Oil Operations. Tartan Canada will deliver the next presentation at 2 p.m. called Developing a Win-Win Maintenance Strategy. Blue Spark Energy will wrap up the first day of technical sessions with a talk titled Shake ‘n’ Rake Your CHOPS Reservoir at 3 p.m. The event will conclude on Sept. 11 with just one presentation by NOV Mono Artificial Lift Systems at 11 a.m. That one’s titled,

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Mark Bacon, chair of the Lloydminster chapter of the SoÄ?Ĺ?ĞƚLJ ŽĨ WÄžĆšĆŒŽůÄžƾž ĹśĹ?Ĺ?ĹśÄžÄžĆŒĆ? ĞdžƉĞÄ?ĆšĆ? Ć?ĆšĆŒŽŜĹ? Ä‚ĆŠ ĞŜĚĂŜÄ?Äž ĨŽĆŒ ĨŽƾĆŒ ƚĞÄ?ŚŜĹ?Ä?Ä‚ĹŻ Ć‰ĆŒÄžĆ?ĞŜƚĂĆ&#x; ŽŜĆ? ƚŚĂƚ Ç Ĺ?ĹŻĹŻ Ä?Äž Ä‚ Ć‰Ä‚ĆŒĆš ŽĨ ƚŚĞ ĎŽĎŹĎ­Ď° >ůŽLJĚžĹ?ĹśĆ?ĆšÄžĆŒ ,ĞĂǀLJ KĹ?ĹŻ ^ĹšĹ˝Ç ^ÄžĆ‰ĆšÍ˜ ϭϏͲϭϭ͘ File photo

Extending Production Life of Heavy Oil Wells Using Hydraulic Pumping Units. Bacon said the plan to hold three sessions on the opening day and just one on the final 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 flights and hotels, so when we ran our exhibitors later in the second day, the interest went down,â€? said Bacon. ɸ Page A13

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PIPELINE NEWS September 2014

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 addressing the banquet during 2012 oil show at the Lloydminster džŚĹ?Ä?Ĺ?Ć&#x; ŽŜ 'ĆŒŽƾŜÄšĆ?͘ File photo

Éş Page A12 “We found the best time for speakers was on the first day when everybody was really primed and they’re out to learn something.â€? The 2012 heavy oil show was the first time the technical presentations were held in conjunction with the oil show. On alternative years, the Lloydminster SPE

normally holds its own heavy oil technical symposium depending on interest from speakers and audience participation. More than 300 people attended the technical sessions during 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. That’s definitely going to be strength,� said Bacon. “The last time was the first 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 operations 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 flying in at the last minute Bacon said, “Last time I checked, flights 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 technical 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 Lloydminster Exhibition Grounds from Jan. 27 to 28, 2015. The workshop with focus on determining what proactive discussions should be started now looking towards the challenges the industry will face by the year 2020.

Check the workshop links on the SPE Lloydminster website for a detailed look at the workshop schedule. The 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 discussions have been held already on who might carry the torch next.

A13

“We are kind of building a transition plan right now. I’ve been chair for two years now. We normally try to rotate them out every once in awhile,� he said about executive positions. “There 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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A14

PIPELINE NEWS September 2014

Gibson aims to double Hardisty rail volumes

'ŝďƐŽŶ ŶĞƌŐLJ ŝƐ ĐƵƌƌĞŶƚůLJ ĐŽŶƐƚƌƵĐƟ ŶŐ Ɛŝdž ŶĞǁ ĐƌƵĚĞ Žŝů ƐƚŽƌĂŐĞ ƚĂŶŬƐ Ăƚ ƚŚĞ ĞĂƐƚ ƐŝĚĞ ŽĨ ƚŚĞ ,ĂƌĚŝƐƚLJ dĞƌŵŝŶĂů ƚŽ ƉŝƉĞ Žŝů ƚŽ ƚŚĞŝƌ ,ĂƌĚŝƐƚLJ ZĂŝů dĞƌŵŝŶĂů ůŽĐĂƚĞĚ Į ǀĞ ŬŝůŽŵĞƚĞƌƐ ĞĂƐƚ͘ dŚŝƐ ƉŚŽƚŽ ƐŚŽǁƐ ƚŚĞ Į ƌƐƚ ƚǁŽ ϰϬϬ͕ϬϬϬ ďĂƌƌĞů ƚĂŶŬƐ ƵŶĚĞƌ ĐŽŶƐƚƌƵĐƟ ŽŶ͘ dŚĞ ŝŶŝƟ Ăů ϭϮϬ͕ϬϬϬ ďĂƌƌĞů Ă ĚĂLJ ĐĂƉĂĐŝƚLJ ŽĨ ƚŚĞ ĐƌƵĚĞͲďLJͲƌĂŝů ĨĂĐŝůŝƚLJ ďĞŝŶŐ ĚĞǀĞůŽƉĞĚ ďLJ 'ŝďƐŽŶ ĂŶĚ h^ ' ĐĂŶ ŚĂŶĚůĞ ƚǁŽ ƵŶŝƚ ƚƌĂŝŶƐ ƉĞƌ ĚĂLJ ĂŶĚ ŝƐ ĞdžƉĞĐƚĞĚ ƚŽ ĚŽƵďůĞ ŝŶ ƐŝnjĞ ƚŽ ϮϰϬ͕ϬϬϬ ďƉĚ ŝŶ ϮϬϭϱ͘ ZĂŝů ĂŶĚ ŝŶĨƌĂƐƚƌƵĐƚƵƌĞ ĞdžƉĂŶƐŝŽŶ ŝƐ ĂůƐŽ ƵŶĚĞƌ ǁĂLJ Ăƚ 'ŝďƐŽŶ͛Ɛ ĚŵŽŶƚŽŶ dĞƌŵŝŶĂů͘ WŚŽƚŽ ƐƵďŵŝƩ ĞĚ

By Geoff Lee Calgary – Gibson Energy Inc. will have a lot to celebrate when it officially opens its Hardisty Rail Terminal in a ceremony expected to take place in September. Plans are already in the works to double the capacity of the unit train facility to 240,000 barrels of crude oil per day in 2015 – just weeks after the first 120,000 bpd phase began operating on June 30. The facility, located five kilometers east of the main Hardisty Terminal has a current capacity to load up to two unit trains per day on the Canadian Pacific 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.” The 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, blending, and injection assets in both locations. The Hardisty crude-by-rail facility is a development partnership between Gibson and U.S. Development Group (USDG), a Houston based developer of rail logistics and terminal facilities. The rail Phase 1 rail terminal specs called for a fixed loading rack with 30 railcar loading positions plus a unit train staging area and loop tracks capable of holding up to five unit trains. The 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. The first 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 first 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 expansion,” 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 firm shipper agreements. “Efforts to market the Phase 2 of the unit train will commence now that the first phase is operating,” Hanlon told the conference. The Hardisty rail site includes 143 acres of undeveloped land for expansion with 32 acres of undeveloped land for expansion at the Edmonton Terminal. The Hardisty unit train facility is set up to handle all qualities or crude oil while the Edmonton Terminal is a manifest facility for handling multiple products. ɸ Page A15

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PIPELINE NEWS September 2014 Éş Page A14 “We handle NGL (natural gas liquids) and LPG (liquid propane gas); we handle refined products, and we handle crude oil at our Edmonton facility,â€? 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.â€? The Edmonton Terminal currently handles 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. The 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 condensate services. “The 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,â€? explained Hanlon. “We foresee building additional facilities for that as well.â€? Gibson signed a long term contract with Statoil to build infrastructure at the Edmonton Terminal with construction announced in July 2013. The new facilities will provide Statoil with multiple delivery options for its crude production to points across North America. The new infrastructure at Edmonton emulates the business model of Gibson’s Hardisty Terminal and rail facility that provide storage, flexible delivery 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 production 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 upgrading and replacement capital in 2014. “In the first half we invested $161 million on growth capital and $23 million on upgrade and replacement projects,â€? 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 upgrade and replacement spending.â€? 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

A15

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

No Pipeline or Pipeline Capacity Flexible Rail Options

Pipeline (at capacity) $3/barrel Pipeline (doesn’t exist) & Barge No Cost Available

HARDISTY, AB Rail - Manifest $10-$14/barrel

Rail - Manifest $16-$20/barrel

Rail - Unit Train $8-$11/barrel

Rail - Unit Train $13-$16/barrel

Pipeline (at capacity) & Barge $5-$6/barrel

Rail - Manifest $16-$20/barrel Rail - Unit Train $13-$16/barrel Pipeline $7-$11/barrel

Rail - Manifest $17-$21/barrel Rail - Unit Train $14-$17/barrel

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A16

PIPELINE NEWS September 2014

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PIPELINE NEWS September 2014

A17

Bakken play sees August land grab Regina – Could it be that another land rush is happening in the EstevanWeyburn 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 annual 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,â€? Economy Minister Bill Boyd said in an Aug. 15 new release. â€œHowever, we’re equally pleased about land acquisitions in the heavy oilprone areas of the province that are consistent in sale-after-sale, year-afteryear. “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.â€? The next sale of petroleum and natural gas rights will be Oct. 6 Weyburn-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 Bakken 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 area The 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 Rockwell 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 Federated 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 area The 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 Whiteside Viking Sand Oil Pool, 35 kilometres west of Kindersley. The top price paid for a single licence in this area was $49,740 by Canadian 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.

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A18

PIPELINE NEWS September 2014

Bruderheim crude-by-rail terminal might be sold 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 loading unit trains on CN and CP tracks. Canexus’s new president Doug

Wonnacott appointed on July 2 announced 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-byrail 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 providing 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 facility to right its financial ship. During the question period Wonnacott wouldn’t say if they are looking to “entertain a majority position or a 100 per cent sell off ” of the Bruderheim facility “So we are continuing to explore and have conversations with interested parties but at this point in time there is not a clear path,” Wonnacott told a conference call. The transloading site has potential to use existing salt caverns for storage, or to back-hauling condensate among many possibilities Wonnacott listed to increase value of the transloading business. Wonnacott went on to tell a caller that if they were to seek an investment partner for the rail facility they would look for the interested party to certainly bring value. “Capital is one of those value

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buckets. Operating expertise is the other bucket that we would consider,” said Wonnacott. About 60 to 70 per cent of current 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 operations 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. ɸ Page A19

PIPELINE NEWS September 2014

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This is an aerial shot of the 480 acre crude oil transloading facility owned by Canexus and serviced by CN and CP rail taken in November 2013. The Calgary-based chemicals 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 expected to wrap up by the end of August. The company is considering selling the facility and/or some of its chemical assets to improve its balance sheet. WŚŽƚŽ Ć?ĆľÄ?ĹľĹ?ĆŠ ĞĚ

Éş Page A18 “The shutdown is progressing well and we expect to be back up and operating by late August,â€? said Wonnacott. He went on to state, “2014 is the year that will position Canexus for the future.â€? 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 expansion. The 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 first and second quarter by a cold winter and a shortage of labour in Alberta. The company reported an operating profit of $29.2 million in the second quarter. Wonnacott warned the third quarter will be will be impacted by summer shutdown of the facility 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 transporting crude oil and ethanol. “We will remain engaged to understand the potential impact on its operations and their rail customers,â€? said Wonnacott.

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A20

PIPELINE NEWS September 2014

Kerrobert eyes work camp for Torq crews By Geoff Lee Kerrobert – 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 barrels 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.

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. WŚŽƚŽƐ ďLJ 'ĞŽī >ĞĞ

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 accommodations 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. ɸ Page A21

PIPELINE NEWS September 2014 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

A21

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

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ɺ Page A20 We 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 Kelordan 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 situation. 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

Erhard Poggemiller writes out an invoice at his Kep Industries repair shop where business is brisk these days. As the mayor of Kerrobert, Poggemiller reports work is ƉƌŽŐƌĞƐƐŝŶŐ ŽŶ ĐŽŵƉůĞƟŶŐ Ă ĐŽŵŵƵŶŝƚLJ ƉůĂŶ ƚŽ ƉƌŽǀŝĚĞ new housing. The town is bracing for an expected rush ŽĨ ŶĞǁ ŽŝůĮĞůĚ ǁŽƌŬĞƌƐ ŝŶ ƚŚĞ ĂƌĞĂ ƐƚĂƌƟŶŐ ǁŝƚŚ ƚŚĞ ĞdžƉĞĐƚĞĚ ĐŽŶƐƚƌƵĐƟŽŶ ƐƚĂƌƚ ŽĨ ƚŚĞ <ĞƌƌŽďĞƌƚ ZĂŝů dĞƌŵŝŶĂů this fall by Torq Transloading Inc.

coming to an end with that now. A lot of the approvals 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 different contractor – they

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PIPELINE NEWS September 2014

PIPELINE NEWS September 2014

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Kindersley stares growth in the face

Kindersley Mayor John ŜŜĆ?ͲtĹ?ŜĚ Ĺ?Ć? ŚĂƉƉLJ ƚŽ Ć?ĞĞ ƚŚĹ?Ć? Ć?Ĺ?ƚĞ ĚĞǀĞůŽƉžĞŜƚ Ć?Ĺ?Ĺ?Ĺś Ĺ?Ĺ˝ ƾƉ Ä‚Ćš ,ŽůůĂŜĚ WÄ‚ĆŒĹŹ ĨĆŒŽŜĆ&#x;ĹśĹ? ,Ĺ?Ĺ?ĹšÇ Ä‚Ç‡ Ďł Ç ÄžĆ?ĆšÍ˜ ĂŜĂůƚĂ Ç Ĺ?ĹŻĹŻ Ä?ĆľĹ?ĹŻÄš Ä‚ ĆšĆŒĆľÄ?ĹŹ Ć?ƚŽƉ ĂŜĚ Ä‚ ĹśÄžÇ Ď´Ď° ĆŒŽŽž ŚŽƚĞů Ä‚Ćš ƚŚĞ Ä?ŽžžÄžĆŒÄ?Ĺ?Ä‚ĹŻ Ć‰Ä‚ĆŒĹŹÍ˜

A new 100-room hotel will also be build on land recently sold to West Fraser 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 hotels. “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 indoor 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 including 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 provincial and federal government officials to lobby for viable changes to the Temporary 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.�

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„ By Geoff Lee Kindersley – Growth in oil and gas activity in the light oil Viking play continues 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 depending 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 different 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 Marathon 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 popping 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 Kindersley Inn that will add 76 single and double rooms to its footprint sometime in 2015.

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+XVN\ SURĂ€ WV IURP WKHUPDOV LQ TXDUWHU Calgary – Production gains from heavy oil thermal projects in the Lloydminster area helped Husky Energy to generate a second quarter profit of $628 million, up from $605 million a year ago. “We’ve had another quarter of steady consistent performance and we continue according to plan,â€? said CEO Asim Ghosh in a conference call from Calgary on July 24. “Our continued investment in longerwavelength projects such as heavy oil thermals, resource plays and oil sands provide steady production and more predictable cash flow to support our growth projects in the Asia Pacific and the Atlantic regions.â€? Production in the quarter was boosted by new high-yield thermal projects in the Lloydminster region and strong results from resource plays in Western Canada and the startup of the Liwan Gas project. Upstream production 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 momentum over the second quarter with production reaching about 44,000 barrels of oil per day. The company has a goal to produce 80,000 bpd from thermal by 2019 as new and existing short term, midterm and long term projects in the region come into play. “We are seeing exceptionally strong performance from our latest thermal project at Sandall,â€? said Ghosh. Sandall came online ahead of schedule in the first quarter and is exceeding its design capacity of 3,500 bpd that with an average production rate of 5,300 bpd. “Sandall is part of a long line of thermal projects either in production or in planning with a lot of running room in terms of attractive metrics,â€? said Ghosh.

“These are longer wave projects that underpin the rest of our portfolio by providing a steady production base and more predictable cash flow.� Meanwhile construction of the 10,000 bpd Rush Lake thermal project sanctioned in 2013 is 55 per cent complete. “We’ve completed drilling the first two pads and have confirmed the excellent quality of this reservoir as we work towards first 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 advancing 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 beginning with Edam East.� Husky also drilled four horizontal heavy oil wells in the Lloydminster area in the quarter bringing the total to 27 wells drilled to date in 2014. The company’s Western Canadian operations 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 underway for an additional four-well pad at Ansell later this year Results from a fourwell 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 productivity and efficiency. 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 horizontal gas wells were completed with further development drilling scheduled later in 2014. Three horizontal oil wells were drilled and three completed in the second quarter, with activity primarily focused on the Viking and Cardium oil resource plays. A four-well pad at Wapiti Cardium is delivering good results, and the Husky has expanded its land position on the play to add more drilling locations. The first phase of the Sunrise oilsands project is progressing towards startup this year with all of the regulatory 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 operations Husky expects construction progress during the quarter on two 300,000-barrel storage 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 thermal production from Rush Lake, Edam West, Edam East and Vawn. Throughputs at the downstream refineries and the Lloydminster upgrader were 304,000 barrels per day in the

quarter compared to 317,000 bpd in the second quarter of 2013. The Lloydminster upgrader will undergo a partial 42-day outage scheduled this fall with operating capacity to be maintained at about 80 per cent. The Lloydminster upgrader contributed $49 million to net earnings in the second

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quarter compared to $88 million a year ago. “This takes into account a longer than anticipated ramp up in April as well as lower upgrading differentials driven by higher feedstock costs,� said acting CFO Darren Andruko. “The higher heavy oil price was in turn captured in the upstream business.�

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Vermilion – The 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. “The system will allow power to flow 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 first of two open houses in Vermilion on Aug. 7 AESO held open houses in various regional communities from Aug. 5 to 27 to seek public support for the need to build two 240 kilovolt transmission lines. The proposed lines will connect five 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 Heartland 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.

The needs assessment includes a proposed 120 megawatt Grizzly Bear wind farm by E.ON southwest of Vermilion and a 150 MW Mainstream Wainwright wind project. There are also plans from Rocky Mountain Power for the Alberta Saskatchewan Intertie Storage (ASISt) project in Lloydminster. Rocky Mountain plans to consume electricity when prices are low and use a salt cavern to store compressed air that would generate up to 160 MW of power from a turbine when prices are high. The main regional coal-fired power plant near Battle River generates 700 MW, but Gray said the demand in the area peaks at 880 MW. The 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 developing power generation to satisfy the demand for power in the area, you see that also burdening the system,â€? 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 different things that we look at when we’re doing it. “These include economic indicators and population and industry growth. We also see demand increasing from regional centres – towns growing and that sort of thing along with some residential growth.â€? Gray noted AESO is seeing growth and power demand along the Highway 41 oilfield corridor that runs from the Wainwright and Provost areas north through Vermilion towards Bonnyville. ɸ Page A27

PIPELINE NEWS September 2014 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. “They will coming back and knocking on doors telling people where exactly the lines will be built,� said Divi. The routing process is expected to begin in 2015 and take about a year to complete with more public consultation to follow. Once AUC approves the project they will issue a permit and a licence to ATCO and AltaLink to build the lines with an expected in-service date sometime in 2017 or 2018. The AUC approved the first 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.

Ramaiah Divi, the lead planner with the Alberta Electric System Operator’s East Central Alberta Transmission Development plan explains the need to construct two 240 Kv transmission lines to meet the growing demand for Ć‰Ĺ˝Ç ÄžĆŒ ĨĆŒŽž ƚŚĞ ƉĹ?ƉĞůĹ?ŜĞ ƉƾžĆ‰Ĺ?ĹśĹ? Ć?ƚĂĆ&#x; ŽŜĆ? ĂŜĚ ĹśÄžÇ Ć‰Ĺ˝Ç Í˛ ÄžĆŒ Ĺ?ÄžĹśÄžĆŒÄ‚Ć&#x; ŽŜ Ĺ?Ĺś ƚŚĞ ĆŒÄžĹ?Ĺ?ŽŜ͘

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. The oil and gas industry are the major drivers for load growth in this region. “It provides the energy capacity not only for the current projects, but we are looking beyond 2030 to 2050 periods. “The two 240Kv will serve the area for a long

Éş Page A26 “There is an oil transportation corridor there that is contributing to the demand forecast,â€? he said. Comments received from the open house will pave the way for AESO to submit its needs application to the Alberta Utilities Commission 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,â€? said Ramaiah Divi, AESO’s

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A29

TransCanada donates Energy East training pipe 2018 Commissioning and In-Service to Saint John

Q4, 2015 Final Regulatory Approval

dƌĂŶƐ ĂŶĂĚĂ ŽƌƉ͘ ŚĂƐ ůĂƵŶĐŚĞĚ Ă ŶĂƟ ŽŶĂů ƉŝƉĞůŝŶĞ ƚƌĂŝŶŝŶŐ ƉƌŽŐƌĂŵ ǁŝƚŚ ĂŶ ŝŶƚĞƌŶĂƟ ŽŶĂů ƚƌĂĚĞ ĂƐƐŽĐŝĂͲ Ɵ ŽŶ ƚŽ ƉƌĞƉĂƌĞ ǁĞůĚĞƌƐ͕ ƉŝƉĞĮ Ʃ ĞƌƐ ĂŶĚ ĂƉƉƌĞŶƟ ĐĞƐ ŝŶ ĂĚǀĂŶĐĞ ŽĨ ďƵŝůĚŝŶŐ ƚŚĞ ŶĞƌŐLJ ĂƐƚ Žŝů ƉŝƉĞůŝŶĞ͘ /Ĩ ƚŚĞLJ ĂƌĞ ƚŽ ŵĞĞƚ ƚŚĞ ƚŚĞ ƉƌŽƉŽƐĞĚ Ɵ ŵĞůŝŶĞ͕ ĂƐ ƐĞĞŶ ŝŶ ƚŚŝƐ ŐƌĂƉŚŝĐ͕ ƚŚĞLJ ĂƌĞ ŐŽŝŶŐ ƚŽ ŶĞĞĚ ŵŽƌĞ ƚƌĂŝŶĞĚ ǁĞůĚĞƌƐ ĂŶĚ ƉŝƉĞĮ Ʃ ĞƌƐ͘ Ɛ Ă ƌĞƐƵůƚ͕ ƚŚĞ ĐŽŵƉĂŶLJ ŚĂƐ ĚŽŶĂƚĞĚ ũŽŝŶƚƐ ŽĨ ϰϮͲŝŶĐŚ ƉŝƉĞ ƚŽ ƚƌĂŝŶ ŽŶ͘ /ŵĂŐĞ ƐƵďŵŝƩ ĞĚ

2013

Q2, 2013 Launch of Consultation Program

Calgary – TransCanada Corporation is helping to train welders, pipefitters and apprentices across Canada in advance of constructing its proposed Energy East oil pipeline. The 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 program in Canada. TransCanada is donating 24 sections of 42inch 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 significant workforce needs of the pipeline industry,” 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, Thunder Bay, Sarnia, Montreal, Miramichi and Dartmouth. Highly-skilled welders will be a key part of important pipeline projects such as Energy East. The UA has a significant role in preparing future generations for important job opportunities as pipeline professionals with expertise in their field. This new national program will enable welders, pipefitters 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. “The considerable amount of pipe that TransCanada is offering our training schools across the country will allow our journeymen and apprentices to cut and weld pipe as if they were working in the field,” said John Telford, director of Canadian affairs for the UA. “This donation also allows the UA to redirect a large portion of its training monies towards increasing the number of instructors to train a new generation of outstanding pipeline welders, journeymen and apprentices.” TransCanada submitted an initial project description of Energy East to the National Energy Board in March 2014 and expects to submit an application to the board seeking regulatory approval this summer. The Energy East pipeline will transport 1.1 million barrels of oil per day from Alberta and Saskatchewan to refineries and port terminals in Quebec, Nova Scotia and New Brunswick. The $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 create 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.

2014

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2014 Regulatory Applications Filed

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2018 Commissioning and In-Service to Québec

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A30

PIPELINE NEWS September 2014

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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 oilƐĂŶĚƐ ŽƉĞƌĂƟ ŽŶƐ͘ ƵƌŝŶŐ Ă ŵĞĚŝĂ ƚŽƵƌ ŽĨ ƚŚĞ ƐƉŝůů ƐŝƚĞƐ ůĂƐƚ ƵŐƵƐƚ͕ EZ> ƉƌŽũĞĐƚ ƐŝƚĞ ůĞĂĚĞƌ͕ ZLJĂŶ ĂŵĞƌŽŶ ĞdžƉůĂŝŶĞĚ ƚŚŝƐ ƐŚĂůůŽǁ ĚŝƚĐŚ ŚĞ ƐƚŽŽĚ ŝŶ ǁĂƐ ĚƵŐ ƚŽ ĐŽŶƚĂŝŶ ƚŚĞ bitumen emulsion seeping to the surface. File photo

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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 independent 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 Ă ůĂŬĞ Ăƚ EZ>͛Ɛ WƌŝŵƌŽƐĞ ŽŝůƐĂŶĚƐ ŽƉĞƌĂƟ ŽŶƐ͘ File photo

AER blames leaks on CNRL steam strategy Calgary – The 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 Primrose South will remain in place pending action by CNRL to provent further seepages. The 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 regulator on June 27. The AER has determined the two main enabling factors are CRNL’s steaming strategy and wellbore issues. The 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 flow-to-surface events can be prevented if proper mitigation measures are put in place,” said AER president and CEO Jim Ellis. “That said, the AER is not prepared to approve a return to full operations at these sites until all potential risks are addressed and proper requirements are in place to avoid a similar incident. “This will require a gradual, step-by-step approach that allows us to manage those risks.” Crews have recovered over 7,421 barrels of bitumen emulsion from four surface leaks at Primrose reported to AER since last spring. The bitumen release affected 20.7 hectares at the east and south sections of CNRL’s Primrose project is contained but cleanup efforts are ongoing. The AER ordered CNRL to suspend and restrict steaming operations at the four sites last July until the cause of the leaks could be determined. At a site tour last August CNRL officials told the media and the regulator they believed the cause

SAFE & SOUND

of the seepage to be a mechanical failure of wellbores similar to a 2009 leak at Primrose. CNRL produces bitumen at Primrose East and Primrose South using cyclic steam stimulation with just one horizontal wellbore required for steaming and production on alternating cycles. Wells are steamed for several weeks to mobilize the heavy oil followed by a production phase of several months. Erin Flanagan, an analyst at the environmental Pembina Institute, said the AER findings “call into question whether high-pressure cyclic steam stimulation activity should be permitted at the CNRL Primrose facility. “This technical report confirms that CNRL’s project design and operation are the root cause of bitumen emulsion coming to the surface,” he said in a news release. “The first such flow-to-surface event happened in 2009, and the leaks currently in question started in June 2013. ɸ Page A32

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A32

PIPELINE NEWS September 2014

Volumes and spacings key to leaks Éş 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 stimulation project. “This will help ensure that

Cenovus grows crudeby-rail transportation

the public and the environment is protected from the risk of similar accidents.� The AER investigation is ongoing. CNRL's and the panel and the panel that conducted the independent 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.

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This is a recent photo of well pad at Cenovus’s steam-assisted gravity drainage operaĆ&#x;ŽŜĆ? Ä‚Ćš ĹšĆŒĹ?Ć?Ć&#x;ŜĂ >Ä‚ĹŹÄž Ĺ?Ĺś ŜŽĆŒĆšĹšÄžĆŒĹś ĹŻÄ?ÄžĆŒĆšÄ‚Í˜ dŚĞ Ä?ŽžĆ‰Ä‚ŜLJ ƉůĂŜĆ? ƚŽ Ć?ĹšĹ?Ɖ žŽĆŒÄž Ĺ˝Ĺ?ĹŻĆ?ĂŜĚĆ? Ć‰ĆŒĹ˝ÄšĆľÄ?Ć&#x;ŽŜ Ä?LJ ĆŒÄ‚Ĺ?ĹŻ Ĺ?Ĺś ĎŽĎŹĎ­Ď°Í˜ WŚŽƚŽĆ? Ć?ĆľÄ?ĹľĹ?ƊĞĚ

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 sidetracked 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,â€? said John Brannan executive vice president and CEO. “Overall our quarter was sound and we continue to focus of delivering dependable performance.â€? ɸ Page A33

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PIPELINE NEWS September 2014 Éş Page A32 Cenovus more than tripled its profits to $615 million from $179 million a year ago. Oilsands production driven by the Christina Lake project averaged 125,000 bpd net in the second quarter, up 33 per cent from the previous year. The company is also hiring new transportation expertise to its leadership team to help it move some its growing thermal oil production in northern Alberta to market by rail. “One of our prime areas of focus is improving marketing access. We have recently strengthened our leadership in this area,â€? said Brian Ferguson Cenovus’s chief executive.

Ferguson told the quarterly conference that Robert Pease had joined Cenovus in June as the executive vicepresident, markets and transportation. Pease brings to the job 34 years of experience in refining, marketing and transporting oil. He responsible for developing and executing strategies that will help Cenovus maximize the return it receives for its products. Kent Avery has also recently joined Cenovus’s management team as vice-president of rail. Avery will support Cenovus’s growing capacity to ship crude oil by rail to access higher value markets. He has extensive experience in rail

JDM Petroleums Inc. asset sale JDM Petroleums Inc. ( JDM) has engaged NRG Divestitures to market its producing properties in southeast Saskatchewan. The package presents an assortment of properties in Corning, Kisbey, Benson, Outram, Wilmar, and Wauchope South, producing approximately 80 bpd. The wells are producing from the Bakken, Frobisher, Midale, and Ratcliffe Formations, and several of the lands offer additional Bakken horizontal potential. The properties are generating a combined cash flow of approximately $700,000 per year.

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operations and business development involving the transportation of oil and other petroleum products. In pipeline transportation, Cenovus and ConnocoPhillipps have a transportation agreement 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. These deliveries are expected to increase over the next few years as the company’s diluent needs grow. The agreement also includes future diluent deliveries to the Narrows Lake project. The 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 deliveries on the Cold Lake

expansion are expected to commence in early 2015. The agreement also includes future oil blend shipping capacity from the partnership’s Narrows Lake project.

A33

Cenovus has committed to ship 75,000 bpd on Enbridge’s Flanagan South system and expects to start moving an initial 50,000 bpd in the second half of 2014.

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PIPELINE NEWS September 2014

Saturn orbits Saskatchewan oil pools 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 Exploration 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, Winnipegosis, 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 exploration wells into the multi-stack targets. Saturn has also made three shallow bituminous coal discoveries since 2009 with coal seams ranging in continuous vertical thickness from nine to 89 meters. Saturn has a strategic ownership in Inowending Exploration & Development Corp., a First Nations 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 Nation and Yellowquill First Nation. Each founding partner including Saturn holds

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a 20 per cent interest in Inowending touted as being first mineral exploration company to be coowned 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.

Tuscany funds drilling near Macklin Calgary – Tuscany Energy is currently drilling a series of five new heavy oil wells in west-central Saskatchewan flush with cash from the recent closure of $3 million in financing. The new drilling program will build on Tuscany’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 update 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 property 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 approximately 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 commence drilling on its portfolio of new prospects before the end of the year.

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A35

&DPSEHOO 2LOĂ€HOG 5HQWDOV PRYLQJ WR (VWHYDQ WUXFN E\SDVV ORFDWLRQ 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 Campbell’s Lampman location, 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 southeast Saskatchewan since 2009. Frederick said the new location, is “more centralized, with supplies at our fingertips ĂžƉÄ?Ğůů KĹ?ůĎĞůĚ ZĞŜƚĂůĆ? ŚĂĆ? Ä‚ ŇĞĞƚ ŽĨ Ç ÄžĹŻĹŻĆ?Ĺ?ƚĞ Ć?ŚĂÄ?ĹŹĆ? ĹŻĹ?ĹŹÄž ƚŚĹ?Ć? ŽŜĞ͕ Ä?ÄžĹ?ĹśĹ? ŚĂƾůĞĚ instead of driving to town.â€? ĆšĹšĆŒŽƾĹ?Ĺš >ĂžƉžĂŜ Ĺ?Ĺś ÄžÄ‚ĆŒĹŻÇ‡ ĆľĹ?ĆľĆ?ĆšÍ˜ The new location Lampman – Across ers doing grading work construction crew could will have a yard twice the road from the on the new Estevan be found. They were their current size. Along scrapers and bulldozTruck bypass, another laying 14 inches of with a larger yard will be

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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 centrifuges 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, according 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 breakup,� he said.

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PIPELINE NEWS September 2014

2PQL75$; SRVWSRQHV LQGHÀQLWHO\ LWV FUXGH E\ UDLO SODQV OLQNLQJ WR 3RUW RI &KXUFKLOO By Carter Haydu (Daily Oil Bulletin) Churchill, Man. – OmniTRAX Canada is suspending plans to ship crude oil through to the Port of Churchill for the foreseeable future, the company announced in midAugust. “I don’t even want to hear about oil for the next two to five years,” Merv Tweed, president of OmniTRAX Canada, told the Bulletin, a sister publication 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.”

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.” ɸ Page A37

The company was considering plans to make the Manitoba Hudson Bay seaport a northern export 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 decision to suspend crude-by-rail initiatives, partially based on the fact grain shippers are willing to commit 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

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PIPELINE NEWS September 2014

A37

“I don’t even want to hear about oil for the next two WR Ă€ YH \HDUV Âľ ² 0HUY 7ZHHG 3UHVLGHQW OmniTRAX Canada

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Éş Page A36 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. “They could again change their mind next shipping season and start trying to put their plan into action,â€? 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 difficult 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.â€? According to Reder, there are multiple governments 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 everyone to say, ‘Oh, we have this cheap energy right here, right now.’ The climate-change reason for deciding to not ship oil through this region is a big deal, and the people in the North feel that climatechange impact.â€? 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 “bittersweetâ€? 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 company to find new opportunities, and we were encouraged 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 focused on the oil side.�

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PIPELINE NEWS September 2014

CORROSION-RESISTANT PIPELINE SYSTEMS

Flexpipe Systems’ FlexPipe Linepipe (FPLP) is hard at work in Southwestern Saskatchewan on a large gathering system for a prominent oil and gas company. The project tied 31 oil wells to seven central testing facilities. As many as 17 lines were run in one ditch with a right of way (ROW) of only 20 meters. Chosen because of reduced installation, lifecycle and land costs, Flexpipe Systems is the answer to your next pipeline project

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PIPELINE NEWS September 2014

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Gas, chips, coffee and coveralls 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 interesting 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 fireretardant 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 liners. 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 convenience 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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,ÄžÄ‚ĆšĹšÄžĆŒ WÄžŜŜLJ ůŽŽŏĆ? Ä‚ĹŒÄžĆŒ ƚŚĞ Ç Ĺ˝ĆŒĹŹ Ç ÄžÄ‚ĆŒ Ä?ůŽƚŚĹ?ĹśĹ? Ä‚ĆŒÄžÄ‚ ŽĨ ƚŚĞ ĆŒÄ?ŽůÄ‚ ŽͲŽĆ‰Í›Ć? Ä?ŽŜǀĞͲ ĹśĹ?ĞŜÄ?Äž ĂŜĚ ĹšÄ‚ĆŒÄšÇ Ä‚ĆŒÄž Ć?ĆšĹ˝ĆŒÄžÍ˜ :ĆľĆ?Ćš Ä?ĞLJŽŜÄš ƚŚĞ ÄŽĆŒÄž ĆŒÄžĆšÄ‚ĆŒÄšÄ‚ĹśĆš Ä?Ĺ˝Ç€ÄžĆŒÄ‚ĹŻĹŻĆ? LJŽƾ Ä?Ä‚Ĺś ƉĹ?Ä?ĹŹ ƾƉ Ä‚ Ä?Ä‚Ĺ? ŽĨ Ä?ĹšĹ?ƉĆ? ĂŜĚ Ć?ŽžÄž ĹŠÄžĆŒĹŹÇ‡Í˜ Photo by Brian Zinchuk

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PIPELINE NEWS September 2014

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6N\OLIW DGGV WRQ FUDQH WR Ă HHW “It comes out of the Demag factory in Germany. Every nut and bolt came from Germany,â€? said Dwight Packer, owner. The new crane is an “all terrain crane.â€? It’s not as off-road as a “rough terrain crane,â€?

but it’s more mobile and more agile than a “mobile crane.� The configuration is a hydraulic crane on a wheeled carrier. It uses a “pinning boom.� The cylinder pushes out one section, which is then pinned into place.

It then pulls back and pushes out the next section. It’s a little slower than having all sections able to move at once, but there are advantages to the trade-off in speed. “The Europeans started putting one

cylinder the boom to extend every section,â€? Packer explained. There are six live sections. “The advantage is you don’t have all that weight. You have a hollow boom and more capacity.â€? ɸ Page A42

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A42

PIPELINE NEWS September 2014

dĹšĹ?Ć? ĹśÄžÇ ĎŽĎ°ĎąÍ˛ĆšŽŜ Ä?ĆŒÄ‚ĹśÄž ŚĂĚ Ĺ?ĆšĆ? Ä?ŽŽž Ä‚ĆŠÄ‚Ä?ŚĞĚ ŽŜ ĆľĹ?͘ ĎąÍ˜ ^ŏLJůĹ?ĹŒ ^ÄžĆŒÇ€Ĺ?Ä?ÄžĆ? Ć?ŽŽŜ Ɖƾƚ Ĺ?Ćš ƚŽ Ç Ĺ˝ĆŒĹŹÍ˜ Photo by Brian Zinchuk

Unified under one brand. We are pleased to announce that Carson Energy Services is now conducting business under the URS banner. Although our brand has changed, our commitment to safety excellence, backed by our solid reputation of supporting oil and gas development, remains the same. At URS, we believe that success is ultimately determined by what we help our customers achieve. So whether it’s pipelines, horizontal directional drilling, fabrication, maintenance, or ďŹ eld facility construction, you can continue to rely on us to provide solutions across the entire energy life cycle. We are URS

Twice the capacity of their previous heavy-lifter

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Éş Page A41 The 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

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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 bigger 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 involves 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 consideration for the new crane was its ability to work without a lot of support vehicles. It has sufficient 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 heavylift scenario requires an additional semi with one trailer and a second 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 counterweight (rating),� he said. The new crane went into operation in early August. Including cranes and boom trucks, Skylift has 16 units in operation, from the tiny “spider� crane to the new 245-ton.

PIPELINE NEWS September 2014

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A43

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PIPELINE NEWS September 2014

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PIPELINE NEWS

SECTION B September 2014

>ĞŶŐƚŚƐ ŽĨ ƌĂŝů ĂƌĞ ďƵƩ ͲǁĞůĚĞĚ ƚŽŐĞƚŚĞƌ ŝŶƚŽ ƐƚƌŝŶŐĞƌƐ͘ dŚŽƐĞ ƐƚƌŝŶŐĞƌƐ ĂƌĞ ƚŚĞŶ ĚƌĂŐŐĞĚ ŝŶƚŽ ƉŽƐŝƟ ŽŶ͘ dŚĞLJ ůŽŽŬ ůŝŬĞ ƐƉĂŐŚĞƫ ƵŶƟ ů ƚŚĞLJ ĂƌĞ ƐĞĐƵƌĞĚ͘ Photos by Brian Zinchuk

Ceres Northgate Commodity Logistics Hub nears completion By Brian Zinchuk Northgate – This fall will see the Ceres Northgate Commodity Logistics Hub go into operation after nearly a year-and-a-quarter of work on the site. The 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. This provides shippers, both exporting and importing, a third option beyond the Canadian Pacific and CN railways, and a much broader access to American markets. The 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. There are provisions for crude-by-rail loading, frac sand, and numerous other commodities, both inbound and outbound. Ceres underwent a change in its management team and board just as Pipeline News began preparation 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 questions. 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: The Northgate Commodity Logistics Hub will ease the bottleneck of getting commodities, including grains and energy products, 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 eventually 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 significant experience 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 leading commodity has become unit trains of crudeby-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 commodities, 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 transportation strategy, we’re currently examining opportunities 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? ɸ Page B2

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PIPELINE NEWS September 2014

Connected to BNSF, a third option to CN and CP Éş Page B1 P.N.: How much investment has gone into this project so far, and how D.S.: No. This facility will be used to ship Canadian products such as grain much more do you forecast in the future as later phases are developed? and energy products to North American markets, and potentially could be used D.S.: The total capital cost of this project is approximately $90 million, and to ship American energy-producing supplies to Canada. we expect the facility will be built out over three years. P.N.: What will the crude-byP.N.: Lac-MĂŠgantic, and then rail capacity be at first, and will that Casselton put something of a chill increase in the future? If so, when? on crude-by-rail, and has caused a D.S.: We’re focussed on the grain great deal of concern in the puboperation at the moment and finallic. Have these incidents had any izing plans for the energy side of impact on your project, either in the Northgate. economics, interest of shippers, or P.N.: Will the focus be on unit design? trains? If so, why? D.S.: Safety and environmental D.S.: The site has been designed protection has been foremost in the to handle unit trains, but limited design of the Northgate Commodity shipment volumes in the early stages Logistics Hub. All of the facilities at may dictate using a smaller number Northgate will meet all provincial and of cars. Northgate has the flexibility federal standards. We place the highto handle both. est priority on employee and public P.N.: If you loaded a unit train safety, environmental protection and of crude oil in Northgate, where is it good stewardship of the facility. likely to end up? P.N.: Ceres is part of a major D.S.: Our connection to BNSF’s thrust in the development of crude32,000 mile railway network, will give by-rail facilities throughout Sasshippers direct access to customers in katchewan, Manitoba and Alberta 28 states, numerous Pacific and Gulf capable of handling unit trains. ports, and Mexico. Additionally, we If everything that was announced will have access to strategic interior in 2013 gets built to its full specilocations and Atlantic ports. fication, Saskatchewan will have A worker grinds the welds securing to lengths of rail together. P.N.: Why Northgate? How does enough crude-by-rail capacity to the choice of being on the BNSF factheoretically ship every drop of oil it tor into the location? produces, plus an additional “Bakken boom,â€? without ever seeing a pipeline. D.S.: Northgate provides a lot of opportunities for Western Canadian Is that much capacity needed and/or sustainable? farmers to market their grains. Connecting to BNSF’s extensive rail network We believe Northgate’s location provides a competitive advantage and the will provide an additional strategic marketing outlet for Western Canadian hub will be very attractive to farmers and energy producers. Northgate will farmers and energy producers – especially in light of recent grain and energy enable Saskatchewan energy producers to access a cost-competitive point-oflogistics bottlenecks in the region. entry into the lucrative US market.

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B3

Ceres Northgate Commodity Logistics Hub design explained „ By Brian Zinchuk Northgate – Large scale rail facilities like the Ceres Northgate Commodity Logistics Hub don’t get built every day on the wind-swept Canadian prairie, especially ones that expect to see a broad array of commodities beyond just grain. Douglas Speers, chairman of Torontobased 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-byrail, 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 conducting the normal review of strategy and operations

you’d expect in this kind of changeover. Pipeline News: What goes into designing a crude-by-rail facility? What are the considerations? Douglas Speers: Designing a crude-byrail 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 foundational 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 determine the size of tanks

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and the loading rack configuration. If the site is on a branch line, loading limits for the line must also be taken into consideration, as these dictate the amount of oil which can be transported by each car. P.N.: What were the challenges in building on this site? D.S.: Given the cross-border nature of this site, we had to look at how customs processes would affect 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 telecommunications abilities, housing and support facilities, but also that we were at the tail end of the SaskPower grid. As such, we required new services to be provided from 11 miles away. ɸ Page B4

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PIPELINE NEWS September 2014

Grain shipments expected to begin this fall Éş Page B3 The 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.: The site is designed to accommodate multiple commodities, including energy products, grain, frac sand, pipe and casing, and other products. The inside “loopâ€? of the site will be used to load unit grain from a grain elevator, and the outer “loopâ€? can be used for unit oil loading. The 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 conflicts 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 movement of the rail cars is important. As per railroad requirements, unit trains may not be “brokenâ€? 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/unloading location. This 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 operation at once, i.e. grain handling, frac sand and oil loading? D.S.: The facility can handle more than one train per day. There is room to grow the facility beyond this based on business volumes. P.N.: Can you go into detail on the crude-byrail handling? Will it be truck-to-rail transloading, or truck to tank, then to rail etc.? D.S.: The final design has not been determined at this time. ɸ Page B5

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PIPELINE NEWS September 2014 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 regulations change further, Northgate will comply with all these changes. We place the highest priority on employee and public safety, environmental protection 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 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 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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Éş Page B4 P.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.: This site is right on the U.S. border. How did that affect the design, i.e. customs, border 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 adhered to the railroad regulations of both Canada and the United States. P.N.: In the wake of LacMĂŠgantic and Casselton, were there any additional design considerations

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PIPELINE NEWS September 2014

PIPELINE NEWS September 2014

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Northgate contractors

This unloading tunnel will allow the grain elevator to unload cars as necessary.

Numerous companies 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 elevator and will be operating the final, much larger grain handling facility once it is constructed. 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 Solutions is the programming engineering firm for the project, and has worked closely with Ceres in developing the concept. Clifton Associates of Regina provided the civil engineering, geotechnical work, surveying 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 Ontariobased rail contractor, and North Dakota based R&R worked as a joint venture on the construction of the actual railway, including 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 upgrading its track from Minot to Northgate.

Northgate commodities, both inbound and outbound Northgate – The Ceres Northgate Commodity Logistics Hub will have the capability of exporting and importing numerous commodities, should the need warrant and the appropriate facilities are built. The facility has a unique feature: Highway 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 Esterhazy 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 throughout. Outbound Outbound shipments 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 replaced by a much larger grain facility which is

still being worked out. Crude-by-rail facilities are in the works, but its implementation has been re-evaluated based on the production 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 shipping natural gas liquids (NGLs) from Northgate 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 northwest, 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. Inbound Train 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 tubular 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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PIPELINE NEWS September 2014

There’s unit trains, and then there are unit trains „ By Brian Zinchuk Northgate – There’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 difference in efficiency according to an American rail consulting firm 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 efficiency, 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 efficient. The adoption of unit trains has literally changed the landscape of Western Canada. They have driven the construction of massive concrete and steel inland terminals, and the corresponding demolition of small wooden grain elevators. That, has in turn, led railroads to abandon huge lengths of branch lines, and as well as the towns built along them. ɸ Page B9

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PIPELINE NEWS September 2014 Éş Page B8 Chicago area-based Engineered Rail Solutions, LLC provided a background explanation 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 firm for its construction. When inland terminals were built in Canada, they were typically built with two to four tracks alongside the elevator in a siding or forked spur. This 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. They 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 different approach. They broadly adopted loop tracks. A unit train stays as a unit the entire time and is never disassembled. Additionally, the engines stay with the cars instead of being dispatched elsewhere. BNSF has incentives for having loading completed within specified

times – not just a 24 hour turnaround like you might see at a Canadian grain terminal, but eight or 10 hours. The shorter the time, the higher the incentive. An eight-hour loading 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. There’s another compelling reason as well. BNSF collectively realized that disassembling trains in cold weather is problematic. That’s because the rubber seals on the airbrake gladhands become stiff in cold weather, making it difficult to “air up� the entire train after reassembling 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 issue. The differences in methodology could perhaps account for the difficulties Canadian Class 1 railroads reported last winter when confronted with the largest harvest in Saskatchewan history and long periods of cold weather. Those differences also account for a

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greater number of turns that a railcar can make between the origin elevator and the destination. If you can turn a railcar every two weeks instead of every month, this is twice the efficiency 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 Commodity Hub has two loop tracks in its design, plus additional straight tracks. The inner loop is dedicated for grain loading, the outer one is meant for crude oil. There is also room to add a third loop track on the outside if the need arises.

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PIPELINE NEWS September 2014

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 yellow pipe is the above-ground header for loading rail cars directly from the pipeline. Photo by Brian Zinchuk

Crescent Point leads crude-by-rail charge in Saskatchewan „ By Brian Zinchuk Calgary, Stoughton – Crescent Point Energy Corp. has been leading the charge when it comes to crude-byrail in Saskatchewan. Indeed, not only is it the first company to develop its own capacity to ship unit trains out of southeast Saskatchewan, it has adopted the strategy well beyond that region to all of its major operating 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 southeast Saskatchewan, the Enbridge Saskatchewan system leading into the Enbridge mainline system, leading into the PADD II market. “That always caused us some concern in that if something happened to the Enbridge Saskatchewan or Enbridge mainline system, we would be in a difficult position to move our crude. We wanted to put

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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 effective insurance policy to ensure our crude will have a delivery option to get it to market.� And thus, they turned to rail. Stangl said, “That 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 first rail cars out of southeast Saskatchewan.� What started out as an insurance policy soon turned into a marketing opportunity, as the PADD II market in the U.S. Midwest had become saturated. “What we realized with the rail is once you’re on the rail, you can go anywhere.

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Where a pipeline starts in one place and ends in one place, rail can go anywhere in North America,â€? he said. “That opened us up to a number of different markets, be it the East Coast, Gulf Coast or West Coast, or even the mid-continent as well. You can move to different markets in different 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.â€? Crescent Point now sells oil all over the continent. “We do have some main markets that we go to that are competitive,â€? he said, but noted they don’t talk about where that is. “Number two, it gives us flexibility. It gives us the ability to get to different markets in different time periods to get better pricing.â€? ɸ Page B11

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The yellow pipe is the new header system that allows Crescent Point to forego the ĆľĆ?Äž ŽĨ ĆšĆŒĆľÄ?ĹŹĆ? ĂŜĚ ůŽĂĚ ĆŒÄ‚Ĺ?ĹŻ Ä?Ä‚ĆŒĆ? Ç€Ĺ?Ä‚ ƉĹ?ƉĞůĹ?ŜĞ ĨĆŒŽž Ĺ?ĆšĆ? sĹ?ÄžÇ ÄŽ ĞůĚ Ć‰ĆŒĹ?ĹľÄ‚ĆŒÇ‡ ĨÄ‚Ä?Ĺ?ĹŻĹ?ĆšÇ‡Í˜

Éş Page B10 Stangl said they weren’t making a negative comment on Enbridge Saskatchewan or Enbridge mainline. Effectively they didn’t want all their eggs in one basket. “We have facilities in all of our main operating areas now – southeast Saskatchewan, southwest Saskatchewan and Utah are our biggest operating areas.â€? They 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 speaking, 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. This correlates with approximately 125,000 barrels production of oil and natural gas liquids company-wide. Stoughton has 45,000 barrels per day loading capacity. That’s not enough to fill a unit train in one day, but then again, they don’t need to do it in that short of time. Their facility is situated on the shortline Stewart Southern Railway, a

company from which they get “excellent service,� 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. The company has recently added storage capacity at Dollard, near Shaunavon. “We added 100,000 barrels capacity, the same as in the southeast,� Stangl said. A typical unit train will run around 60,000 to 70,000 barrels, depending on the rail line it is destined for. “We’re probably going to add more storage for southeast Saskatchewan as well,� he said, adding that is for operation use beyond crudeby-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 conscious decision to not bring in third-party barrels so we can demonstrate we’ve done all the appropriate testing and can verify the quality of the product on rail.� The Stoughton facility now has a pipeline connecting the crude-by-rail facility a few kilometres northwest of the town to their main Viewfield plant, a few kilometres southwest of the town. There’s now a header system that allows rail cars to be loaded from that pipeline. It still uses the trailer-based transloading systems when loading from the pipe to the rail car. It’s not a true rack system. “That was really an attempt to become more efficient in loading. We still do truck into our rail facility, but we have the ability to load from

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PIPELINE NEWS September 2014

Insurance plan becomes marketing option Éş Page B11 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 realizing is infrastructure that’s in the ground, and

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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. The 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 infrastructure knowing it is going to be an ongoing part of their business for years to come,� he said, referring to mainline pipelines like the delayed Keystone XL. Asked if crude-byrail 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 Stoughton strategy. We’ll have optionality to either

deliver by pipe from Flat Lake or to truck up to Stoughton.� As for the possibility of using a third-party transloading facility on the Long Creek Railroad 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 Casselton, N.D. had on this future, Stangl replied, “Crude-by-rail is going 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 pipelineconnected. The U.S. Northeast is an example. California is an example. There’s still an opportunity to have rail in the portfolio longterm. “I think there’s going 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-MĂŠgantic 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 efficient 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 efficient to run. Those are the ones that are not likely going to continue in a world of more pipeline capacity. “The efficient ones, with one rail line and a quick turnaround, those ones will continue.â€? Stangl concluded saying, “The 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 important delivery source at the margin.â€?

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dƾŜÄšĆŒÄ‚ ĹśÄžĆŒĹ?LJ DÄ‚ĆŒĹŹÄžĆ&#x; ĹśĹ? >Ĺ?ĹľĹ?ƚĞĚ͛Ć? Ä?ĆŒĆľÄšÄžͲÄ?LJͲĆŒÄ‚Ĺ?ĹŻ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ ĹśÄžÄ‚ĆŒ ĆŒŽžÄžĆŒÍ• DÄ‚ĹśÍ˜Í• Ä?Ä‚Ĺś ŚĂŜĚůĞ ĎŻĎŹÍ•ĎŹĎŹĎŹ Ä?ƉĚ ĆŒĹ?Ĺ?Śƚ ĹśĹ˝Ç Í• Ä?ƾƚ ƚŚĂƚ Ĺ?Ć? ĞdžƉĞÄ?ƚĞĚ ƚŽ ÄšŽƾÄ?ĹŻÄž ĹŻÄ‚ĆšÄžĆŒ ƚŚĹ?Ć? Ç‡ÄžÄ‚ĆŒ Ç Ĺ?ƚŚ ƚŚĞ ĂĚĚĹ?Ć&#x; ŽŜ ŽĨ žŽĆŒÄž ĆšĆŒÄ‚Ä?ĹŹ Ć?ƉĂÄ?Ğ͘ Photo by Brian Zinchuk

Tundra crude-by-rail up and running at Cromer „ By Brian Zinchuk Cromer, Man. – Nestled off the beaten path several kilometres from Manitoba Highway 256, and just east of Cromer, Man., is one of the most significant additions to the crude-by-rail game. Located approximately six kilometres east of Tundra Energy Marketing Limited’s growing Cromer terminal, one finds their new crude-by-rail facility. There are no large tanks on site, no lines of semi tankers waiting to unload using trailer-mounted transloading systems pulled behind pickups. This 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. There 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.: That’s Tundra Energy. Basically we own the midstream assets. Tundra 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 foundation work for a third 205,000 barrel tank. D.C.: That’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? ɸ Page B15

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B15

Capacity to be expanded to 60,000 bpd by year end ɺ Page B13 D.C.: We’ve also built a rail terminal. The rail terminal is connected by a six kilometer long pipeline. 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 longer term, and we didn’t want to be in the truck-torail 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 opportunities 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 announcement on is we’re connecting into the Enbridge 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 agreements 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 Saskatchewan 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.

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P.N.: Is this facility designed only for outgoing 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 incoming oil, we’d have to truck it to tankage. It’s a oneway 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 appear 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. ɸ Page B16

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PIPELINE NEWS September 2014

Could there be a tie to Energy East? Two large 205,000-bbl. tanks, right, will be joined by a third within the next year. dŚĞLJ ĂƌĞ ƉĂƌƚ ŽĨ dƵŶĚƌĂ ŶĞƌŐLJ DĂƌŬĞƟŶŐ >ŝŵŝƚĞĚ͛Ɛ ƌŽŵĞƌ͕ DĂŶ͘ ƚĞƌŵŝŶĂů͘ Photo by Brian Zinchuk

ɺ Page B15 The 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 capacity. That’s not far off from the total oil production currently in southeast 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

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SASKATOON, SK

crude by rail facility and others also under construction, that would result in a dramatic increase in shipping capacity from this region. (Put in context, Between EPSI, Energy East lateral and Tundra, Crescent Point Stoughton and Ceres Northgate 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 programs 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 timeline, 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 Energy East, and the rail volumes will partially continue. ɸ Page B17

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PIPELINE NEWS September 2014

B17

ɺ Page B16 What we’ve focused on is constructing an efficient 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 sufficient pipeline capacity. But it’s still a question of what pipeline capacity will be available, when it comes on line, and when do we see sufficient pipeline capacity to replace rail movements?

Virden Yard

Robert 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

This 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 pipeline startups. As well, they may continue indefinitely 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 first 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. That was because companies were finding markets for crude-by-rail they couldn’t get to with pipelines. One person said, “We’ve saved the east coast refining business, and now we’re going to save the west coast.� D.C.: That’s correct, yes. P.N.: Do you think that rail, by nature, being continent-wide, gives you more flexibility as a marketer? D.C.: Yes it does. The 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 progressively 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. The question is, which barrel should get to tidewater and which barrel should get exported. There’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. The Gulf Coast is flooded right now with their own production. There are no imports of light crude any longer on the Gulf Coast.

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B18

PIPELINE NEWS September 2014

/RFDWLRQ ORFDWLRQ ORFDWLRQ This rig, working close to Cromer, Man. is proof that the Tundra terminal is right in ƚŚĞ ĹľĹ?ĚĚůĞ ŽĨ DÄ‚ĹśĹ?ƚŽÄ?Ä‚Í›Ć? Ć‰ĆŒŽůĹ?ÄŽÄ? ^Ĺ?ĹśÄ?ĹŻÄ‚Ĺ?ĆŒͲ ĂůLJ Ĺ˝Ĺ?ĹŻÄŽÄžĹŻÄšÍ˜ 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 distant 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.

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corner of Saskatchewan, a flood aid benefit concert 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 entertainment 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 individually or $220 for a table of eight. Shirley Galloway of Safe-Tee Management, one of the organizers, said, “The auction items are fantastic‌from 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!â€? Proceeds will be split between the towns and RMs of Carievale, Gainsborough, Carnduff, Storthoaks, Alida and Redvers.

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PIPELINE NEWS September 2014

B19

Willmar crude-byrail facility 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 spokesperson, 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, transloading facility of its kind in Saskatchewan in recent 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 Saskatchewan 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 recently 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 addition to transloading services? T.M.: Yes, we have an integrated crude business 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 provides flexibility to producers and refiners. P.N.: Broadly speaking, where does it go? T.M.: West Coast, East Coast, mid-continent

dŚĞ tĹ?ĹŻĹŻĹľÄ‚ĆŒ Ä?ĆŒĆľÄšÄžͲÄ?LJͲĆŒÄ‚Ĺ?ĹŻ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ Ç Ä‚Ć? ŽŜÄž ŽĨ ƚŚĞ ÄŽĆŒĆ?Ćš ƚŽ Ä?ÄžĹ?ĹśĹ? Ĺ˝Ć‰ÄžĆŒÄ‚Ć&#x;ŽŜĆ? Ĺ?Ĺś ^Ä‚Ć?ĹŹÄ‚ĆšÄ?ĹšÄžÇ Ä‚ĹśÍ˜ Photo by Brian Zinchuk

and U.S. Gulf Coast. P.N.: We see you have a car spot for about 30 standard tanker cars. What is your loading capacity there? T.M.: The site can hold 40 railcars with a capacity 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 crudeby-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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PIPELINE NEWS September 2014

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www.tremcar.com

PIPELINE NEWS September 2014

B21

Environmental considerations for Line 3 replacement

Dan O’Neill is the environmental supervisor for the Line 3 replacement project. Photo by Brian Zinchuk

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 issues 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 communities, 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 difference it was constructed with polyken tape for its coating. “The amount of maintenance has come to a point where, commercially, we came to an agreement 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 conventional 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 effective.� 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 summer, 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 timing restrictions now that limit us to when we can really start,� he said.

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“Typical restricted activity periods are April 1 to August 15 for general work, a little longer for wetlands,â€? 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.â€? “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.â€? Some smaller portions were applied for earlier, and work has been taking place near Cromer, Man. By expanding the project to replace the entire pipeline, 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 communitiesâ€? O’Neill said. ɸ Page B22

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PIPELINE NEWS September 2014

The rains came and the work stopped

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 eventually 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 project won’t see dirt scratched for several years, this area, which had been approved 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 emergency during the time of the floods. 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. 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 order. Landowner complaints initiated an investigation. We had a few noncompliances. We had slight admixing, basically the topsoil mixing with the

subsoil (clay),� Barkley said. Asked if it was caused by an operator 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

These joints of pipe, on the west side of Manitoba Highway 83, are meant for the Line 3 replacement project. This region has been the subject of a stop-work order issued by ƚŚĞ EÄ‚Ć&#x;ŽŜÄ‚ĹŻ ĹśÄžĆŒĹ?LJ Ĺ˝Ä‚ĆŒÄšÍ˜ dŚĞ Ä‚ĆŒÄžÄ‚ Ä‚ÄŤÄžÄ?ƚĞĚ Ç Ä‚Ć? Ĺ?Ĺś ƚŚĞ ĹšÄžÄ‚ĆŒĆš ŽĨ Ç Ĺ˝ĆŒĆ?Ćš ŇŽŽÄšĹ?ĹśĹ? ÇŒŽŜÄž ĨĆŒŽž ĆšĹ˝ĆŒĆŒÄžĹśĆ&#x;Ä‚ĹŻ ĆŒÄ‚Ĺ?ĹśĆ? in late June. Photo by Brian Zinchuk

of rain, all the wetlands doubled and tripled in size. Of course, our silt fence was in water.� The silt fences were simply overwhelmed with the water, he noted. “In the spring, (from) the inspection 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 government 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.

Bio security considerations Éş 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-section. 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 properly.� 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.�

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PIPELINE NEWS September 2014

B23

ZĹ˝Ä? Ä‚ĆŒĹŹĹŻÄžÇ‡ ůŽŽŏĆ? Ä‚ĹŒ ÄžĆŒ ŽƉͲ ÄžĆŒÄ‚Ć&#x; ŽŜĆ? ĨŽĆŒ ƚŚĞ ĞĂĆ?ĆšÄžĆŒĹś ĞŜĚ of the project. Photo by Brian Zinchuk

The Line 3 replacement project passes throughout Saskatchewan and the southwest corner of Manitoba.

.HHSLQJ DW LW XQWLO WKH ODQGRZQHUV DUH VDWLVĂ€ HG Maryfield – 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 Enbridge 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 Saskatchewan. Currently he deals with some of the smaller local contractors for remediation work, in addition to a larger contractor, Robert B. Somerville, which is working on the first 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 inspection program revealed that it would have required extensive repairs, up to 70 dig-ups per kilometre. “The effort, 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 disturbance, and for Enbridge, to replace the pipe,â€? Barkley said. The 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 efforts,â€? 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. There 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-

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vented on the previous job. “I believe we’re still negotiating with landowners,� he said. The vast majority of the line will follow the existing right-of-way. “I’d like to reaffirm 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. The 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. That’s absolutely not true. We will continue until they are happy,� Barkley concluded.

B24

PIPELINE NEWS September 2014

Engineering the Line 3 replacement Maryfield – Enbridge is replacing Line 3 before Lines 1 or 2, even though the first 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. There’s issues in certain areas with installation at the time. Tenting on the side with the tape coat traps water and creates corrosion,â€? Barrie Ryan said. Ryan is manager of pipelines services, cen Ä‚ĆŒĆŒĹ?Äž ZLJĂŜ Ĺ?Ć? žĂŜĂĹ?ÄžĆŒ ŽĨ ƉĹ?ƉĞůĹ?ŜĞĆ? Ć?ÄžĆŒÇ€Ĺ?Ä?ÄžĆ?Í• Ä?ÄžĹśĆšĆŒÄ‚ĹŻ ĆŒÄžĹ?Ĺ?ŽŜÍ• Ç ĹšĹ?ĹŻÄž DÄ‚ĆŒĆ&#x; Ĺś ^ĆšĆŒĹ?Ä?ĆŒĹśÇ‡ Ĺ?Ć? tral region, while Marmanager of pipeline engineering from Regina to Gretna, Man. tin Stribrny is manager

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the segment east of Cromer was identified initially for replacement, before the decision was made to replace the entire line. Ryan said, “Basically, the tape coat may not have been installed correctly at the time. Right now, it’s not in good shape. I don’t know how it was installed, but obviously there’s issues. That’s a fact.â€? “The majority of the digs have been on Line 3. It’s the only one with the tape coating.â€? The earlier lines had a coal tar coating, “Probably the best coating we have,â€? Ryan said, but it was a health hazard to install. “As far as coating, it was excellent coating.â€? ɸ Page B25

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of pipeline engineering from Regina to Gretna, Man. They were two of the experts on hand at the Enbridge Line 3 replacement open house in Maryfield on July 31. Stribrny said, “That’s the problem.� “Over time it’s corroding, 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 millions of dollars worth of smart tool runs to check integrity. The 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

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dŚĞ >Ĺ?ŜĞ ĎŻ ĆŒÄžĆ‰ĹŻÄ‚Ä?ĞžĞŜƚ Ć‰ĆŒŽŊÄžÄ?Ćš Ĺ?Ć? Ä?ĆľĆŒĆŒÄžĹśĆšĹŻÇ‡ Ĺ?Ĺś ƚŚĞ Ä?Žč ĞĞ ƚĂůŏ͕ Ĺ˝ĆŒ ŽƉĞŜ ĹšŽƾĆ?Ğ͕ Ć?ƚĂĹ?Ğ͘ /Ĩ Ä‚ĹŻĹŻ Ĺ?ŽĞĆ? Ä‚Ä?Ä?Ĺ˝ĆŒÄšĹ?ĹśĹ? ƚŽ ƉůĂŜ͕ LJŽƾ Ç Ĺ?ĹŻĹŻ Ć?ĞĞ Ç Ĺ˝ĆŒĹŹ ĹŻĹ?ĹŹÄž ƚŚĹ?Ć? Ć?ĆšÄ‚ĆŒĆš Ĺ?Ĺś ώϏϭϲ͘ File photo

Éş Page B24 More modern pipelines are coated with epoxy. The 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, according to Ryan. “They 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. Underneath, the pipe is in perfect condition.â€? The original Line 3 was built with 34inch pipe, what is now a non-standard size. The 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, according to Stribrny. “Thirty-six is just a common size,� Ryan said. Since it is basically a one-for-one replacement, the project should not have the issues of a new pipeline like TransCanada’s Keystone XL has dealt with. What are they doing to ensure they don’t end up with another problem child of a pipeline? Stribrny said, “We’re following procedures and standards. We will be doing a few things extra, caused by Northern Gateway, in B.C.. Some engineering standards were upgraded and it’s flowing into other issues.

“There 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 circumstances, three feet.� Contractors will typically provide more clearance than just the minimum, he noted. “It’s coming from Gateway.� The detailed design is just starting now, according to Stribrny. “We’re designing to the most modern, up to date codes, not 1960s,� Ryan said.

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„ By Brian Zinchuk Maryfield – Imagine you are an operator responsible for a pipeline moving hundreds of thousands 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 Marshall, Mich. Ron Threlfall is supervisor of leak detection maintenance and integration. He was one of the experts on hand at the Enbridge Line 3 replacement open house in Maryfield on July 31. How important is leak detection on this project? “Extremely important, as it is on all projects,â€? 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.â€? These efforts have been deployed throughout the entire fleet of lines. “Enbridge deploys multi-layers of leak detection. Each technology used to find leaks has some strengths and some weaknesses. By deploying multiple 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.â€? 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 transient model.â€? 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 misaligned 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,â€? 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.â€? ɸ Page B27

PIPELINE NEWS September 2014 Éş Page B26 That control centre is in Edmonton. The control centre in Estevan that looked after the Enbridge Pipelines (Saskatchewan) Inc. (EPSI) gathering system as recently been shut down, with the control now solely taken care of in Edmonton. “I think the majority of them transferred,â€? he said of the Estevan operators. “The Edmonton control centre is a centre of excellence for pipeline operations, with very rigorous process and procedure for all that they do. There’s additional training capability for operators. They’ve ramped up a very robust environment that is difficult to do in a small control centre.â€? What is the smallest thing they can detect? “That’s where the multiple layers come in. There is a lower limit of what this technology can find, on the order of a few per cent of flow. Smaller than that will not be detected by this technology (the real-time model). “There’s a grapefruit-sized ball they can send through that’s not a pig in the conventional sense. It doesn’t touch the wall, it kind of bobs along. It has acoustic sensors that can find a pinhole leak. It has a characteristic sound. We have tested that technology and proven it can find pinhole leaks. “We’re also doing the potential next generation of leak detection. There are a number of vendors claiming they can detect leaks with various technologies, with vapour-sensing tubes and fibre-optics in

particular. Enbridge has spent several hundred thousand dollars to building a test apparatus to evaluate this technology.� It’s a boxcarsized container with a pipeline going through it. The technology is deployed around it at different positions around the pipe. The fibre optic sensor has 20 kilometres of fibre spooled on each end so it can work like a 40 kilometre segment. They are looking at which position with respect to the pipe would be best for detection. The sensors would go in the trench with the pipe in the real world. There’s a 32 kilometre test planned for the U.S. next year where they will look for real-world experience with these technologies. “This is not cheap technology.� One of the ways the fibre 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 demonstrate significant year-to-year improvements in sensitivity and reliability.� “There’s three different types of tests,� he said. One is parameter testing. An example would be feeding a leak detection model with a decreased flow 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 flight simulator, except for pipeline operators. “You can mimic all kinds of problems and test that people know how to react. “We have an extensive library of abnormal operating conditions we can pre-program into the simulator.� Marshall is one of the scenarios used. The simulator is also used to train leak detection analysts to distinguish a bad instrument from a leak. “Part of the training of a leak detection analyst is to play through a wide variety of historic leaks. We can actually simulate a much larger set of leaks.� Real world drill The third level

is the most comprehensive expensive and intense, a fluid withdrawal test. “We remove fluid from the pipeline. There’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. The software worked, and detected the leak and alarmed. The 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. The leak detection analyst, in parallel, determined it was a real leak and called the control centre and said please shut down.

B27

It was already going down,� said Threlfall. “The leak detection analyst also engaged our second level backup support and that person also independently said it was a leak. “Three 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,� Threlfall concluded.

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PIPELINE NEWS September 2014

The Enbridge ring

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becoming a Professional Engineer, but is instead worn as a constant reminder to graduates of their responsibility to the public.â€? Enbridge has taken this to heart. As noted by one of the panels at their Maryfield open house for the Line 3 replacement, the ring was explained like this: “The 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 everyone who depends on us. “The ring represents every incident Enbridge has ever experienced across our businesses and it highlights our obligation, individually and as an organization, to make our operations as safe as reliable as possible. “The 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.â€? Each current and new employee is given one of these rings.

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PIPELINE NEWS September 2014

Ideally placed for new play, but „ By Brian Zinchuk Estevan – 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 Bromhead 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 harvest 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 Ĺ˝Ä? ,ŽůĚĞŜ͕ ĹŻÄžĹŒÍ• ĂŜĚ 'ĹŻÄžŜŜ WŽŚů ĆŒƾŜ ƚŚĞ >ŽŜĹ? ĆŒÄžÄžĹŹ ZÄ‚Ĺ?ĹŻĆŒĹ˝Ä‚ÄšÍ˜ dŚĞLJ Ä?ŽƚŚ ŚĂǀĞ ůŽŜĹ? third party facilities in nearly all of ĹšĹ?Ć?ĆšĹ˝ĆŒĹ?ÄžĆ? Ĺ?Ĺś ƚŚĞ Ĺ?ŜĚƾĆ?ĆšĆŒÇ‡Í˜ 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,â€? joked Holden. Pohl said, “We’ve got two maintenance people, an administrator, and the two of us. “We’ve got a board of 13.â€? Long Creek Railroad is based in Estevan. Torq Transloading established a crude-by-rail truck-to-train transloading site near Bromhead, a small hamlet northwest of Torquay and near the terminus of the railroad. Last summer, oil shipments dried up for the shortline. “It was August last year, around the time of Lac-MĂŠgantic, and the wet spell. It hasn’t fired up since,â€? Holden said. “We had to diversify,â€? Pohl said. “They’re still looking for customers,â€? 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,â€? said Holden. “We were doing twice a week, Tuesdays and Fridays.â€? Usually they would take 16 cars at a time. ɸ Page B31

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LCRR hasn’t shipped oil in a year is that formation which Crescent Point is now focussing on. The Torquay (Three 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

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Éş Page B30 “We can do up to the full 30 with our new locomotive,â€? Holden said, with Pohl noting they can haul up to 100 empties. Those 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 sideline business in providing storage for tankers not in use. Currently they are storing cars for J.P. Morgan and the Moose Jaw refinery. “We’re over 300,â€? Holden said of the number of empties on their sidings. “J.P. Morgan has 1,800 cars in their fleet. They can’t all be rolling at the same time. I’m sure they would give us more if we could handle it.â€? But wasn’t there a shortage of oil tankers? Are there cars now

available? “Grain, no. Oil, yeah, there’s cars available,� Holden said. “These are the old fleet. They’re not the newest, shiniest fleet,� Pohl noted, reflecting on the shift away from older DOT-111 certified 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 financial penalty for using DOT111 cars are apparently sidelining some of them. Pohl said, “That fleet is pretty near done. They’re getting out of them.� Holden said crudeby-rail “was a good start. We had to shift focus after a while, to grain and storage.� Torquay is the next hot play The Torquay formation, which is known as the Three Forks formation in the U.S.,

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is rapidly growing in importance. At the Williston Basin Petroleum Conference in Bismarck, N.D., in May, there was a common theme in the drilling plans unveiled by the largest producers 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 Three Forks wells as they do Bakken wells on the same spacing unit. It

drilling rig maps on Rig Locator (riglocator.ca), a sister publication of Pipeline News, shows the border area near Torquay and Oungre to be one of the most intensive 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 Railroad runs right through Torquay and the Bromhead transloading site is the closest crude-by-rail facility to this growing play. ɸ Page B32

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PIPELINE NEWS September 2014

Shortline still contending with last year’s harvest as new one comes in

dŚŽĆ?Äž ƚĂŜŏÄžĆŒ Ä?Ä‚ĆŒĆ? Ĺ?Ĺś ƚŚĞ >ŽŜĹ? ĆŒÄžÄžĹŹ ZÄ‚Ĺ?ĹŻĆŒĹ˝Ä‚Äš Ä‚ĆŒÄž ĚĞÄ?ÄžĹ?Ç€Ĺ?ĹśĹ?͘ dĹšÄžÇ‡Í›ĆŒÄž Ä‚Ä?ƚƾĂůůLJ ĞžƉĆ&#x; ÄžĆ? Ä?ÄžĹ?ĹśĹ? Ć?ĆšĹ˝ĆŒÄžÄš ŽŜ ƚŚĞ Ć?ĹšĹ˝ĆŒĆšĹŻĹ?ŜĞ͕ ŜŽĆš Ä‚ ĆšĆŒÄ‚Ĺ?Ĺś Ĺ?Ĺś ĆľĆ?Ä‚Ĺ?Ğ͘ dŚĞ ĆšÇ Ĺ˝ Ć?Ĺ?ĹŻĹ˝Ć? Ĺ?Ĺś ƚŚĞ ĹľĹ?ĚĚůĞ Ä‚ĆŒÄž ƚŚĞ ĹśÄžÇ DĹ?ĹŻĹŻÄžŜŜĹ?ƾž ^Ć&#x; žƾůÄ‚Ć&#x; ŽŜ ĨĆŒÄ‚Ä? Ć?ĂŜĚ ĨÄ‚Ä?Ĺ?ĹŻĹ?ƚLJ͕ ĹśÄžÄ‚ĆŒĹ?ĹśĹ? Ä?ŽžĆ‰ĹŻÄžĆ&#x; ŽŜ͘ Photo by brian Zinchuk

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“We’re still dealing with the harvest of 2013. We’re 1,000 grain cars behind right now,â€? Pohl said on that day. They went so far as to get their own cars to deal with the surplus. “We’ve leased 50 cars to move grain,â€? 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...â€? Pohl said, his voice trailing off, before adding, “They kept us moving.â€? There 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,â€? he said. “We get list from the grain commission (of ) who’s up every week,â€? he said of the next grain producer in line to ship. Long Creek was founded around the principle of producer cars, a right enshrined in legislation that allows farmers to sidestep the country grain elevator system and load entire grain cars themselves on rail sidings. The 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,â€? 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,â€? Holden said. The company has grown beyond its shareholders, and is attracting business from grain producers as far as Radville. “It took a lot of phone calls,â€? Pohl said. ɸ Page B33

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Éş Page B31 Asked if they’ve been pursuing opportunities there, Holden said, “It’s not that we haven’t offered. We haven’t heard back. “We are open for business. Maybe in due time...â€? Pohl said. 2013 isn’t over yet Pipeline 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.

ŽžĹ?ĹśĹ?ŽŜ >ĞŜĚĹ?ĹśĹ? ÄžĹśĆšĆŒÄžĆ? WĹ˝Ç ÄžĆŒĹšŽƾĆ?Äž DĹ˝ĆŒĆšĹ?Ä‚Ĺ?ÄžĆ?

PIPELINE NEWS September 2014 Éş Page B32 Holden 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. “They’re seeing results from marketing their own grain.â€? Shortline vs Class 1 Over the last few decades, Class 1 railways like CN and Canadian Pacific have increasingly been pushing unit trains as their preferred method of operation, leaving shortline operators on their former branch lines to aggregate small-scale shipments. “They make more money picking it up and running it,â€? 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,â€? Holden said. “I still think there’s rail in our future,â€? Pohl said. “There’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.â€? Frac sand Nearing 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. There are two tall sand silos and a bucket elevator alongside. “It’s going to be good for us,â€? said Holden. “It’s right in our yard.â€? “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?â€? Pohl said. New shop Long Creek Railroad moved into a new shop just off their line in late fall 2013. They 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. There are plans for cementing parts of the floor 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,â€? Holden said. It’s new to them Remember that more powerful locomotive? It’s kind of new, at least new to them. That 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,â€? said Pohl. “We hope to add another engine. We’re on the cusp (of going ahead)â€? Holden said. “The more you grow, the bigger trains are more efficient.â€? As for unit trains, he noted, “We can be creative. We are our only traffic. We can load on the mainline.â€? The 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 blood Holden is a former CP railroad man. “I was maintenance,â€? 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,â€? he said. He comes from a long line of railroad men. “My grandfather was in the

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A second switch will soon be added allowing another track to be run into their new shop.

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 first engineers out of Moose Jaw,� he said. “The 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 defined workplace, where if you had one job, that’s what you did, and you didn’t stray from it. “My first 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.�

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PIPELINE NEWS September 2014

Virden Meter moves into new shop „ By Brian Zinchuk Virden, Man. –

Virden Meter Services Ltd., a sister company of

Estevan Meter Service Ltd., didn’t take long to outgrow its original home. Originally established in November 2012, by May 2014 they needed a new home. “There was no room. I didn’t have room for my guys,â€? said Mark Kessler, president and one of the partners in the limited company. The 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 floor space. Over the last year ĂǀĞ ŽƾÄ?ŚĂŜƚ Ĺ?Ć? Ä‚Ĺś Ĺ?ĹśĆ?ĆšĆŒƾžÄžĹśĆšÄ‚Ć&#x; ŽŜ ƚĞÄ?Ĺš Ç Ĺ?ƚŚ sĹ?ĆŒÄšÄžĹś the instrumentation DÄžĆšÄžĆŒÍ˜ ,Äž Ć?ĆšÄ‚ĆŒĆšÄžÄš Ĺ?Ĺś :Ä‚ŜƾÄ‚ĆŒÇ‡ ĆŒĹ?Ĺ?Śƚ ŽƾĆš ŽĨ ZĞĚ ZĹ?Ç€ÄžĆŒ ŽůͲ ĹŻÄžĹ?Äž Ĺ?Ĺś tĹ?ŜŜĹ?ƉĞĹ?͘ ,Ĺ?Ć? Ĺ?ĹśĆ?ĆšĆŒƾžÄžĹśĆšÄ‚Ć&#x; ŽŜ ƚĞÄ?Ĺš Ć‰ĆŒĹ˝Ĺ?ĆŒÄ‚Ĺľ ĆšŽŽŏ specialist company has gone from four employĆšÇ Ĺ˝Í˛Ä‚ĹśÄšͲÄ‚ͲŚĂůĨ Ç‡ÄžÄ‚ĆŒĆ?͘ Photo by Brian Zinchuk

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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. “There’s stuff happening everywhere. There 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.� They carry supplies, flanges, relief valves and pumps, as examples. Virden Meter is supplying more materials now for treater turnaround. One wall in the warehouse is lined with a variety of pressure 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

DÄ‚ĆŒĹŹ <ÄžĆ?Ć?ĹŻÄžĆŒ Ć?ĹšĹ˝Ç Ć? Žč ƚŚĞ ĞdžƉĂŜĚĞĚ Ĺ?ĹśÇ€ÄžĹśĆšĹ˝ĆŒÇ‡ sĹ?ĆŒÄšÄžĹś DÄžĆšÄžĆŒ Ĺ?Ć? ĹśĹ˝Ç Ä‚Ä?ĹŻÄž ƚŽ Ä?Ä‚ĆŒĆŒÇ‡ Ĺ?Ĺś ƚŚĞ žƾÄ?ĹšͲůÄ‚ĆŒĹ?ÄžĆŒ Ć?ŚŽƉ ƚŚĞLJ ĆŒÄžÄ?ĞŜƚůLJ žŽÇ€ÄžÄš Ĺ?ŜƚŽ͕ ŜĞdžƚ ÄšŽŽĆŒ ƚŽ ƚŚĞ ŽůÄš Ć?ŚŽƉ Ç ĹšĹ?Ä?Ĺš Ĺ?Ć? ĹśĹ˝Ç Ä‚Ç€Ä‚Ĺ?ĹŻÄ‚Ä?ĹŻÄž ĨŽĆŒ ůĞĂĆ?Ğ͘ Photo by Brian Zinchuk

up by a missing item. Then when the project is done, whatever isn’t needed is brought back. “You can do a turnaround, 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 forceflow treater. The package for that would include everything from gaskets to rags. “Everything you need, with one phone call,� he said. “The only thing we don’t supply is the crew. “Every company has treated us fairly,� Kessler said of the local oil producers. “Our field

tech is out all the time. Another is in the shop. We have two shop technicians and one shipper/ receiver. Morris will do our field service runs. “We pretty much do everything Estevan does,� he said, referring to sister company Estevan Meter. Virden Meter is a fully-certified valve shop and NISTtraceable meter proving facility. As it turns out, pretty much the entire staff except for Kessler is musical, so the spare room upstairs is now a rehearsal space for them to jam. You’ll find drums and guitars waiting for the evening when the instrumentation work is done. “I’ve got a really good group of guys. I’ve been lucky,� he said.

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Third Safety Source location in the works Virden, Man. – Safety is a continually growing area of business for Safety Source and Discovery Safety Services. There are actually two sister companies based out of the same location in Virden, Man. Safety Source hands supplies, training, fit testing, gas detection, consulting and servicing. Discovery Safety Services Ltd. takes care of field medics, air safety trailers, confined space standby, battery turnarounds and vapour suppression. Tundra Production Services also rents space at the same location They moved into their current location in September, 2012. It’s conveniently located right next door to the Tundra Oil and Gas field office in Virden. Tundra is by far the largest producer in Manitoba.

This location has double the retail space from what they had before, one block away, according to Dale Lewis, president. They 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 choosing the current location, 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 fire 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 working 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 oilfield. “Safety’s not just the oilpatch. Safety’s everywhere,� he said. “Training is more and more important.� Liability and insurance are other issues related to safety. “We’ve got to tap into that other market,� he said. “Things are going well. We’re continuing to grow every month. The industry looks

strong for the next seven to ten years, they tell us in southwest Manitoba and southeast Saskatchewan, and we’re going to continue to grow with hit. At peak staffing, 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 affect 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. There was water where we hadn’t seen before. To have that kind of water was crazy.�

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PIPELINE NEWS September 2014

New PTRC CEO used to run oil company „ By Brian Zinchuk

Ken From took over as CEO of the Petroleum Technology Research Centre earlier this year. Photo by Brian Zinchuk

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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 Institute, 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-CO2,, 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 Communications 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. ɸ Page B37

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PIPELINE NEWS September 2014 ɺ Page B36 P.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 geoscience 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 privately 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 production 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 (another 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 Saskatchewan. 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 geosciences 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 organization called TSASK, the Technical Safety Authority of Saskatchewan. It was the provincial government, along with body looking at regulation simplification throughout industry, recognizing the boilers and pressure, recognizing 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 transformation. 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 nongovernmental 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-

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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 companies, 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 transition 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. ɸ Page B38

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PIPELINE NEWS September 2014

Increasing recovery factors beats boom and bust Éş Page B37 I think we’ve changed a few things in how we are sending out research projects. We’re not just sending out a broad category and saying “Can you submit your ideas on how to solve industry’s problems.â€? We’re saying to industry, first, “What would you like these researchers to look at? What are the things that are causing industry problems?â€? This year we’re sending out very distinct RFP (requests for proposals). Here’s the problem. Here’s what we want for outcomes. You guys (researchers) 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. The 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 recovery back? The way that (RFP) was developed, and that’s what was key to me, is the process we use – talk to industry. 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 Technologies for Energy Production Systems) came to its natural end. Right now we’re busy doing all the accounting and reports for the funders, mainly the federal government. Norm Sacuta: JIVE ( Joint Implementation of Vapour Extraction) ended in 2010. The more publicly available reports are coming out now. It was using different combinations of solvents in three field trials. There were four, but one of the wells watered out. The 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 field trials. Secondly, some (companies) found something really good out of that and have taken it on their own and have taken it to a fullscale implementation. They’re taking the initial research we did, the sparkplug, and found something they really like in their particular reservoir at the time of development, and they’re going 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-

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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 Cenovus is calling for. Our role with PTRC is to validate certain parameters within the geological storage. So we still measure, 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 verification. SaskPower will do all the operations, set up all their safety protocols, because SaskPower’s never done that. The

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only one who has on a big scale has been Cenovus. SaskPower is currently looking at that. They’ve asked us to handle the MMV, measurement monitoring and verification. The 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 Network. ɸ Page B39

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PIPELINE NEWS September 2014 ɺ Page B38 It’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 innovation 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 projects 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 power 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 mention 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 something 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 postcombustion carbon capture. If you look at what private companies 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 waterflood 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 Conference was that the Bakken and other tight oil formations is tremendous opportunity. Everyone is starting to look

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oil is to get more of the original oil in place out. That way you’re not creating boom and bust communities. The infrastructure’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 opportunity. 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 going 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.

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 companies 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

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PIPELINE NEWS September 2014

Study sums Lakeland spinoffs at $168 M Vermilion – Lakeland College generates $168 million in economic spinoffs to the local economy from its Lloydminster and Vermilion campuses according to a study released on Aug. 18 in advance of the fall academic term. The 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. That’s one of the findings of an economic spinoffs study recently completed by Economic Modeling Specialists Inc. (EMSI) using data from 2012-2013. “This report highlights a few of the many ways Lakeland College contributes to the wellbeing of our students, the local region and the

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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. The 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.

ŽŜĆ?ĆšĆŒĆľÄ?Ć&#x; ŽŜ Ä?ŽŜĆ&#x; ŜƾÄžĆ? Ä‚Ćš ƚŚĞ ĹśÄžÇ ĹśÄžĆŒĹ?LJ ÄžĹśĆšĆŒÄž Ä‚Ćš ƚŚĞ >ůŽLJĚžĹ?ĹśĆ?ĆšÄžĆŒ Ä?ĂžƉƾĆ? ŽĨ >Ä‚ĹŹÄžͲ ůĂŜĚ ŽůůÄžĹ?Ğ͘ /Ĺś :ƾůLJ͕ Ä?ĆŒÄžÇ Ć? ĨĆŒŽž WĆŒÄ‚Ĺ?ĆŒĹ?Äž ĆŒÄ‚ĹśÄž Ä‚Ć?Ć?Ĺ?Ć?ƚĞĚ Ç Ĺ?ƚŚ ƚŚĞ ĹŻĹ?ĹŒ Ĺ?ĹśĹ? ŽĨ ƚŚĹ?Ć? ͲƚLJƉĞ Ä?Ĺ˝Ĺ?ĹŻÄžĆŒ Ĺ?ŜƚŽ ƚŚĞ ĹśÄžÇ Ä?ÄžĹśĆšĆŒÄž ƚŚĂƚ Ç Ĺ?ĹŻĹŻ Žĸ Ä?Ĺ?ĂůůLJ ŽƉĞŜ ŽŜ EĹ˝Ç€Í˜ Ď­Ď°Í˜ File photo

The net impact of college payroll plus day-to-day operational spending was $50.8 million in added regional

income during the year. The contributions of former students now employed in the regional workforce amounted to

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$113.4 million in added income. The 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 provincial 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 connection between economies, people, and work.Â

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OilďŹ eld Decks

Service Decks

Service Bodies

Welding Decks

Lube Trucks

PIPELINE NEWS September 2014

(204) 522-6542 L AW R E N C E

(204) 522-5436 C L AY T O N

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Email resumes to: Estevanrigjobs@iroccorp.com Or call: 306.634.8235 www.eaglerigjobs.com

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PIPELINE NEWS September 2014

B43

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Estevan, Saskatchewan 321 Imperial Avenue 306-634-5304

Virden, Manitoba 130 Anson Road 204-748-3704

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Pipeline News

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

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