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August 2018

Vol. 11/3


Lloydminster Heavy Oil Show preview


Vertex buys Three Star Trucking


Whitecap resumes drilling in Weyburn Unit

for the Saskatchewan Geological Survey Professional geologist Dr. Jim Christopher has been with the Saskatchewan Geological Survey for most of its existence. Even after his retirement in the late 1980s, he's maintained an office there where he's worked, on his own time, on Saskatchewan geology for the last three decades. See related story Page A3.

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Vertex acquires Three Star Trucking By Brian Zinchuk Alida, Sherwood Park, Alta. – On July 13, Vertex Resource Group Ltd. announced that it has acquired Three Star Trucking Ltd., an Alida-based trucking company providing fluid hauling service, pressure truck services, hot oilers and combo vac services throughout Western Canada. The deal went through on July 12. The acquisition of Three Star will add over 270 pieces of equipment to Vertex’s fleet, making the company’s fleet one of the largest in operations serving Saskatchewan, the Montney, and the Duvernay resource plays of Alberta and British Columbia, Vertex said in a release. This isn’t the first time Three Star has been sold. In October 2011, a majority stake was sold to Provident Energy. Provident was then sold to Pembina Pipeline Corp. As a pipeline company, their trucking operation wasn’t a fit. “They didn’t want to be in trucking, so they gave us a deal,” said Ken Boettcher, one of the owners, in August 2015. Thus, in August 2014, the Boettchers bought back the part of the business they had sold just a few years before. But now, with this sale to Vertex, the Three Star name will be gone for good. Three Star was established in 1962. It was started with three partners, Jim Boettcher, George Connelly and John Hall, each with one truck with a 50-bbl. capacity. By 1969, the Boettchers had bought out their partners, and the company continued on as a family business, with several generations taking part. It is currently licensed to haul condensate, NGL, butane and propane between Canada and the United States, holding federal transportation licenses in five states. The acquisition will allow Vertex to continue to develop its customer base and service offerings within the company’s current operating locations while further expanding

into new service offerings and geographical markets including further expansion into the United States. The acquisition includes numerous high-pressure fluid hauling trailers that will enable Vertex to begin offering propane, butane and NGL fluid hauling services. Terry Stephenson, CEO and president of Vertex, said in a release, “Through acquiring Three Star we are adding an experienced management team and operators to Vertex in addition to strengthening our service lines in Saskatchewan and the United States. Three Star’s proven customer base, experienced management team and safety program allows us to confidently expand this service line. With the completion of this acquisition, Vertex will be the leading provider of fluid hauling services in western Canada and will have the capacity and experience to continue serving these clients while growing Three Star’s United States operations.” The acquisition was completed for a purchase price of $8.9 million consisting of 2.6 million common shares being issued at $1.00 per common share, $4.4 million in cash, and $1.9 million in non-interest bearing promissory notes payable over two years and assumption of $10.2 million in long-term debt offset by positive working capital of $6.3 million. Vertex will use its approved $20 million senior secured accordion credit facility to fund the acquisition. Three Star’s EBITDA over the last 12 months was $5 million. The Three Star acquisition is Vertex’s fifth this year. On Jan. 2, they bought Sonic Oilfield Services for $4.5 million. HMA Land, a land company focused on pipeline utility and mineral land, based in Calgary and Sherwood Park, was bought Feb. 1. On June 7, they bought Manitoba-based TSL Industries for $4.55 million, which includes the assumption of $1.3

In this 2012 file photo, the Boettcher family had been in the fluid hauling business for since the late 1950s. In 1962 Jim Boettcher teamed up with two partners to form Three Star. From left are Tim, Ken, Mary and Jim Boettcher. Behind them is a copy of the first truck Jim ever owned. million of debt. The remaining $3.25 million was paid with a $2.5 million non-interest bearing promissory note pay-

able over two years and $750,000 in cash. TSL provides vacuum, hydro vac, fluid hauling, hot oiling and pressure truck

services in Manitoba. The sale was effective May 31. A private hydrovac company in Edmonton was picked up July 3.

That purchased doubled Vertex’s existing hydrovac fleet to that point, adding 11 units. The sale went for $4.3 million.

Lloydminster Heavy Oil Show coming Sept. 12-13 Lloydminster – There’s still some room to get in as an exhibitor for the upcoming Lloydminster Heavy Oil Show, which takes place Sept. 12-13. The bi-annual event takes place at the exhibition grounds on the north end of the Border City. John Sanyer, head of the organizing committee, said there were 171 exhibitors booked so far, compared to 198 two years ago, so there was still some space available for late entries. Two years ago, he said, “We had just under 4,000 people.” He noted it was quite a bit lower than previous years due to the oil downturn. That downturn was at its lowest depths that year. “You adjust to what you’ve got and you make the best of it,” he said. The theme this year is opportunity and innovation. The keynote speaker for the opening ceremonies is Alberta United Conservative Party leader Jason Kenney. He will be speaking on Tuesday night. There will be a social night the following evening with Tim Nutt providing entertainment. The Society of Petroleum Engineers will be having technical presentations on the Wednesday morning. For more information, go to

The Lloydminster Heavy Oil Show will be a chance to see all the latest and greatest in the heavy oil industry. File photo

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Geologist Jim Christopher laid the foundation for billions in development today throughout Saskatchewan By Brian Zinchuk Regina – In many ways, the history of Dr. Jim Christopher, PhD, professional geologist, is that of the Saskatchewan Geological Survey. He’s been there most of its 70-year existence. And at age 93 as of July 30, he is still there, despite having retired in 1987. Deep in his office, behind massive piles of books and papers, he’s still plugging away, for free, in a 31-year-long period of post-retirement work that has been longer than most people’s careers. Christopher’s work is notable for much more than his longevity, however. His research in the Jurassic in the southwest and the Bakken has been fundamental in literally billions of dollars of development work in recent decades. Thousands of jobs in Saskatchewan today are the result of the foundational work he did in these areas, because, after all, it all starts with the rocks. And if that’s the case, the next step is the person who interprets them. Pipeline News spoke to Christopher at length on

Feb. 9 in preparation for this edition. In late June he was still in his office at the Saskatchewan Subsurface Geological Laboratory, also known as the core lab, still plugging away. Indeed, at the start of the interview, his fellow geologists pulled out one of Christopher’s seminal papers on the Mannville formation, published in 2003, 15 years ago. And that was completed long after he had retired. He came in 1959 Christopher started working in Saskatchewan in 1959 with the Department of Mineral Resources. He was born in Philadelphia, raised in Jamaica from ages nine to 18, then returned to the U.S. According to his biography listed in the Saskatchewan Oil Patch Hall of Fame, Christopher worked as a migrant farm labourer before joining the U.S. military, and he arrived in the European theatre of war in time to become a member of the U.S. Army of Occupation. After demobilization, Chris worked as a

civilian employee with the U.S. Army Map Service in Washington, D.C., but eventually returned to his family home in Jersey City where he took employment in the manufacturing industry. At the same time, he began university night classes at the community college level and moved on to Columbia University, graduating with a bachelor’s degree in geology, which he completed in 1951, attending on the G.I Bill. Armed with his bachelor’s degree and scholarship funding, including the John Hay Whitney Fellowship, and John A. Bownocker Scholarship, he proceeded to Ohio State University to continue his geological training toward his masters in 1955 and doctorate in 1959. His doctorate was in contemporary sedimentation, working on landslides in the bluffs along Lake Erie and the movement of sediments along the shore in eastern Ohio, impacted by the rise and fall of the lake level as well as the climate. He married his late wife Dora in 1957. They

were married for 45 years before her passing in 2002. They had six children, three boys, three girls. None took up geology, however. Upon completion of his doctorate, Christopher and family came straight to Saskatchewan. “I collected my diploma, gathered up my belongings, put them in a car and drove up here. I saw a job advert on the bulletin board at Ohio State. It was from the department here,” Christopher said. All they had fit in that ’53 Plymouth. The job was in research geology in sediments. “It was the beginning of the research group in the department.” “There were three of us – Don Kent, who was already here, he’s a Canadian, and then Llewelyn Jones. He moved on after six years. He came the same time I did.” John Brindle was the supervisor at the time. There was just the four of them for sedimentary geology, and others for the geological records section. The core lab building

Dr. Jim Christopher holds up a copy of his original report on the Saskatchewan Bakken, from 1961. was built in 1957, and he’s worked there ever since 1959. He became a Canadian in 1967. Foundational work on the Bakken The early 60s saw a boom going on. “When we drove up from the border

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Kyboshing CO2 capture for BD4 and BD5 a missed opportunity for oilpatch This month has been one of contrasts when it comes to carbon dioxide capture and its role in carbon dioxideenhanced oil recovery (CO2-EOR). At one end of the pipeline, the user is not only enthusiastic about continuing to use CO2, but would like to eventually deploy more. At the other end, SaskPower seems to have blinked, and will not be retrofitting the next two units at the Boundary Dam Power Station, Units 4 and 5 (BD4 and BD5) with carbon capture. They will be retired instead. And in the meantime, an act of God, a particularly nasty storm that hit the Boundary Dam Power Station has taken the one unit there capable of producing CO2, BD3, offline until repairs are sorted out. A truly imperfect storm for the CO2 business, as it were. From the Saskatchewan oilpatch perspective, more carbon capture and storage (CSS) has broad implications. In this whole carbon tax debate, capturing large amounts of carbon dioxide is a major bargaining chip. But it also will cost a lot of money. BD3 cost $1.5 billion, and while SaskPower promises they can do the next project cheaper, BD4 and BD5 are each the size of BD3. However, the broader context has little to do with the whole carbon debate (how does the “dioxide” part keep getting dropped off ?). For our industry, it will be the availability of CO2 for enhanced oil recovery. Right now the Weyburn Unit is producing just under 23,000 bpd of oil, in large part due to CO2-EOR. It has extended the life of the field, over 60 years old now, for nearly two decades since it was implemented, and likely several more decades to come. We need to consider what will happen with our other major oilfields in this province, like the Viewfield Bakken around Stoughton. A few years ago, you couldn’t swing a dead cat, so to speak, without hitting several drilling rigs within site of the Stoughton elevator. As of July 19, there were three in the general Stoughton vicinity. Let’s face it – the Bakken boom is well over, and that field’s production peaked several years ago. While Crescent Point has long been developing that field into secondary recovery with waterflood, the next step is CO2-EOR. One might think that CO2-EOR might not work in the Bakken, and that one might be wrong, if you go by the way North Dakota Governor Doug Burgum is talking. Here’s what he said at the Williston Basin Petroleum Conference in Bismarck in May: “Yes, we’re on track to break our record that we set a few years ago for oil production per day, as Ron (Ness) mentioned. I believe, as I did a year ago, with the innovation and the leadership of this group, that we will see the day when North Dakota is producing two million barrels

a day,” Burgum said. “One of the ways we’re going to get there is through enhanced oil recovery, including the potential to use carbon dioxide that is captured from our very productive lignite coal plants and using that to squeeze even more product out of the shale. This technology is the opportunity to potentially to add even billions of more oil to our state. We’re getting closer to advancing this innovation. “I’ll make another prediction today: we’re going to become so effective at using carbon for enhanced oil recovery that we’re actually going to be at a spot where we don’t have enough carbon in our state and there’ll be a day when people are importing carbon into the Bakken,” Burgum added. Now, those are bold statements for a governor whose state does not even have one commercial-scale carbon capture unit in place. But it’s obvious he’s been looking at what’s been going on north of the border, to Boundary Dam and the Weyburn and Midale Units, and seeing the potential it has for his state. North Dakota, by the way, is now the second largest oil producer in the union. So North Dakota may soon be going great guns into CO2-EOR. The question is, who’s going to pay for it? Will it be forced upon the coal plants by a federal government, or will it be a measure to thwart a federal carbon tax (ring any bells here?) Not likely. It won’t be a state-owned Crown corporation. So who will pay? Will it be the oil companies who will pay a pretty penny for the CO2, making retrofits viable? Where does Burgum’s model come from? He didn’t say. But he did suggest they’re going to need all the CO2 they can get. The decline rates on a Saskatchewan Bakken well are atrocious in the first year before levelling off. The same applies down south, too. But CO2-EOR and some hard work on optimization in the Weyburn Unit has reduced that field’s decline rate to just 3.5 per cent, albeit in different geology. That’s not just good. It’s astonishing, especially since there hadn’t been any drilling in the unit for over three years, pushing four. Imagine what life we could breathe into the Steelman field? What if the Saskatchewan Bakken production could climb again? How about the Viking play near Kindersley? Could CO2 from the Battle River Generating Station in Alberta, if it were ever retrofitted with carbon capture, add another 40 years to that field, especially where the old vertical wells were drilled? We might get more CO2 many years down the road, if the Shand Power Station ever sees carbon capture added to it. North Dakota is looking to a CO2 future. We should too.



The true rock stars of the oil industry

By Brian Zinchuk

He also did similar work on the Jurassic in the Shaunavon play, another substantial play for this province. I don’t know how many billions have been invested in these regions, but I’m certain it is in the tens of billions. That’s money that had fed families, and paid for

doctors and highways, for generations. Dr. Gary Delaney, the chief geologist of Saskatchewan, likes to say, “It all starts with the rocks.” And he’s absolutely right. We would not have any sort of petroleum industry in Saskatchewan today were it not for the geolo-

gists who squint through the loops hanging around their neck, trying to determine if this rock or that rock will produce billions in oil, or a dry hole. They sit in shacks on wellsites, analyzing the drill cuttings brought to them in muddy cups by roughnecks. The geologists are

the true rock stars of this industry. I was glad I got to spend a morning with their Elvis, or perhaps more accurately, Ray Charles. Brian Zinchuk is editor of Pipeline News. He can be reached at brian.zinchuk@




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engineer, but as a geological engineer. It would have been interesting work, but work punctuated by the poverty line every time there’s a downturn in the industry. Geology gets the axe really hard when there’s a downturn in the industry, and this downturn is one for the record books. But I digress. One of the stories Melinda suggested was Dr. Jim Christopher, her good friend whose office is just a few doors down from her. I knew very little about him before, and had occasionally seen him at the lab, but I never really knew much about him. That was until I spent a whole morning with him in February, talking about his life’s work. In all the years of my journalism career, talking with Dr. Christopher has got to be one of the top 10 highlights. A more fascinating man will be hard to find. Dr. Christopher still hangs out at the core lab pretty much every day. He likes to go for a beer on Friday with friends. He was 92 when I spoke to him, and just after this paper goes to press, he will be 93. He still works diligently at his geological research, despite having retired 31 years ago. Let me be clear – other than an initial contract for a couple years, and a few contracts from industry, he has largely worked for free for about three decades, contributing greatly to the knowledge of this province’s geology. He spent 15 years on one gargantuan study on the Mannville, post-retirement. That was completed 15 years ago! As we talked about his early work, numbers started clicking off in my head. Those numbers were the estimated billions of dollars of investment that were built on his geological work. Having come to Saskatchewan right after getting his doctorate at Ohio State University, he arrived here in 1959 and went to work on the Bakken. This man actually named the Torquay formation, where, just a few weeks before the interview, I had seen nine drilling rigs working within a singular township. His work on the Bakken, decades ago, was important down the road when the boom hit.



Back in January, my phone rang. On the other end of the phone was Melinda Yurkowski, assistant chief geologist, petroleum geology, who looks after the sedimentary division of the Saskatchewan Geological Survey. It turns out that this year would mark the 70th anniversary of the Survey. She asked if I was interested in doing a story on it. I told her I would focus an edition on it. Melinda is one of my favourite people in this industry. She’s gregarious, with the widest smile you can put on a human face. Her countenance often has that very smile on it, accompanied by her characteristic chuckle. She and I will sometimes sit together at conferences for lunch, and every time I have posed even the oddest question to her, she has never failed to come back with an answer. That might have been about natural gas production at Kamsack eons ago, or helium in southwest Saskatchewan today. How could I possibly turn her down? Over the years I’ve gotten to know a number of the people who work with Melinda at the core lab, properly termed the Saskatchewan Subsurface Geological Laboratory. It’s been home, since 1958, to Saskatchewan’s priceless repository of core, drill cuttings, and well logs. The warehouse in the back has been expanded numerous times. It looks, in a way, like the ending from Raiders of the Lost Ark, except much more tidy and orderly. The boxes of core are marked with the names of many companies who have come and gone, and yet the core, and the geology, remains. I like to joke that I write about Melinda’s crew of geologists as “rock stars,” because that’s what they are, and I am their biggest fan. The Grateful Dead had their Deadheads. The Survey has me. Rock on, dude. Of all the engineering physics, math, chemistry and materials classes I took in two years of an incomplete engineering program, the one class I use, today, on an almost daily basis, was geological engineering 110. I sometimes wonder what it would have been like if I had completed my degree, and not as a mechanical


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Work done in 1961 laid framework for Bakken boom ◄ Page A3 would say,” Christopher said. “The first thing I worked on, of all things, was the Bakken, which was totally discounted at the time. So the report on the Bakken became the fundamental report for the big boom of the 2000s. The huge crush now, you could put it back to 2008,” he noted. His original, basic study of the Bakken was done in 1961, the same time Jones did one on the Viking formation in west central Saskatchewan. Christopher said his study roughed out the framework for the Bakken basin. He visited all the outcrops in Montana for the Bakken. “Most of the outcrops come to the surface in Montana. Much of the early history of the Bakken was done by the U.S. Geological Survey (USGS) in the early 1890s,” he said. These were week-long trips, going from outcrop to outcrop, using expertise from the USGS. “The Little Rocky Mountains was the closest, five hours south of the border. The rest were further afield, and west,” he

said. Other explorations in the Bearpaw Mountains looked at outcrops of the Jurassic and Cretaceous periods. “None of the rocks we studied really outcropped in Saskatchewan. Montana has all the outcrops and North Dakota has all the oil,” he said. He explained that the outcrops of the Bakken are very consistent with core drawn from it. “It’s a sandwich – upper shale, middle sandstone with silt, and lower is black shale, and is thicker, usually two or three times thicker than the upper shale. But it’s not really thick, as far as formations go. Sixty feet is a lot of shale. The structure maps he pulls out are maps he, himself, drew of the Bakken. Christopher noted that in North Dakota, they produce directly from the shale, whereas in Saskatchewan, Bakken production is mostly from the sandstones. The early reports on the Bakken were based on drilling chips and some cores from early wells. “And then you guess, by God, between points. That’s what you call prospecting,” he

said with a laugh. “This one (study) had only 440 wells, from the Manitoba border to 14W3, down towards Swift Current, and mostly south of township 30, because there’s no Bakken north of there. His conclusion, back then, described the basin, depth, the type of environment the sediments were laid down in, and a prediction of old shorelines, if there were any. “In terms of the oil, we described all the oil shows found, the well depths, there in the report, and described all the cores present that were used. And we had a chapter on economic possibilities. “The economics was mostly in the sandstone, at the time. The oily nature of the shales were observed, but not considered recoverable at the time.” The USGS came out with big numbers for the Bakken North Dakota and Montana, back in the 1980s, but it still took another two decades to develop. Along the way, Christopher worked on the Torquay formation, which has, in recent years, become

Somewhere deep behind this pile of books, papers and maps, one can find Dr. Jim Christopher, still working on his research. Photo by Brian Zinchuk one of the hottest plays in Saskatchewan. At the time of the interview, Crescent Point Energy Corp. had nine drilling rigs working in one township, just southwest of the village of Torquay and along the U.S. border. “I named the formation,” he said, matter-offactly. “It’s part of the Bakken report. I described the Torquay.” Manitoba and North Dakota call the same formation the Three Forks.

Asked why he named it the Torquay, he replied that the original Three Forks included the Bakken and the underlying shales. “I interpreted the Three Forks group and then I separated out the Torquay as a separate unit,” he said. The name Torquay was a matter of convenience, chosen from a well that was fairly completely cored, and named the formation after the nearest town or village, if it was not preempted by another name or formation.

Jurassic in the southwest After his initial work on the Bakken, he then worked on the Jurassic in southwest Saskatchewan around Shaunavon. “That came out in ’64, I guess. That was a very lively time, in terms of drilling and prospecting,” he said. “There was a lot of pressure on that one to get it out. When we started with that report, the Bakken, the companies didn’t believe us, didn’t believe we were real, because all ► Page A7


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Jurassic study in southwest Saskatchewan took eight years, but turned assumptions upside down ◄ Page A6 knowledge resided in Imperial Oil or Shell, and the government couldn’t contribute anything. Back then the government approached one of the companies, I won’t say which one, and asked, ‘How can we help you in terms of geological studies?’ This is why they wanted to form this division. “They said, ‘Oh well, you could have those guys put points on the map and we’ll draw the lines in between.’” Imperial and Shell had big study groups that studied whole basins, he noted. They didn’t have much use for government. Christopher noted the CCF had recently come in as the government, and companies each had their own ideas of what they wanted to do. Asked if his 1964 study spurred any activity, he smiled and said, “Oh, did it ever!” He said an American celebrity was brought in to see the facilities, and that celebrity was introduced to him as “the geologist responsible for a million dollars in land sales.” “This was a hectic time. I couldn’t keep up with the data coming in so fast. And the communication between the industry and department were very good in those days.” “That was what distinguishes Saskatchewan from lots of other places in the States, in that we have this central core repository, and this data is available.” The first Jurassic study

was for the Shaunavon area, looking at the middle Jurassic. The second study, looking at the upper Jurassic around Swift Current, was completed 10 years later, in 1974. He put about eight years into that study. It incorporated all the southwest portion of the province. “The deputy minister wanted to know what was holding this report up,” he said. There was a controversy between two oil companies at the time, Ashland and Mobil. His preliminary paper reversed some ideas held at the time, and Ashland was not happy about it. His report settled the matter. “After the Shaunavon report, my reputation was strong enough to be accepted by the major companies,” he said. In the latter half of the 1970s, he worked on the Mannville formation. “Companies start with these reports and build their prospects on it. That was our mandate, for exploration in the province,” he said. “So we have lots of these reports, of other formations. He was one of the initial organizers of the Williston Basin Petroleum Conference. In the 1970s and 80s he was supervising field parties that went into the Athabasca basin in northern Saskatchewan. He would dispatch them from Regina and check up on them from time to time. His time became more consumed with administration as he worked

up through the ranks, rising from senior research geologist to principle research geologist in charge of the research section and on to chief geologist of the sedimentary geology division and eventually to director of the Saskatchewan Geological Survey in 1982. There were 55 people working under him at the time. His tenure as Saskatchewan’s chief geologist took place during the time of the Grant Devine administration. The energy minister for a time, and Christopher’s boss, was none other than Colin Thatcher. Among his many honours, he was in the first batch of inductees into the Saskatchewan Oil Patch Hall of Fame, in 1989. Christopher took early retirement in 1987 but continued to work with enthusiasm on his favourite topic, the Lower Cretaceous rocks of Saskatchewan. That work

reached fruition in 2003 with the release of S.I.R. report 223 – “Jura-Cretaceous Success Formation and Lower Cretaceous Mannville Group of Saskatchewan.” Even after seventeen years of ‘retirement’, he continued to act as a geological consultant to oil and potash companies, and was involved in two regional mapping projects, the Weyburn CO2 storage and sequestration project, and TGI. Retirement, or not so much He retired in 1987. Well, sort of. He’s continued to often put in five days a week, going for beer on Fridays, ever since, except without the government paycheque. He was a victim of the big oil downturn at the time. “In ’87, there were big government cutbacks. So that’s when the Geological Survey lost ten members, including me,” he said. He was offered a two-year

Dr. Jim Christopher has made a life out of examining rocks at the core lab. Photo by Brian Zinchuk bridge to his retirement. The Mannville report actually took 15 years of ► Page A8

contract to work on the Mannville, which he had already started on, on his own time. It was to be a



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Meili agrees with shutting down BD4 and BD5 By Brian Zinchuk Saskatoon – Saskatchewan NDP Leader Ryan Meili agrees with SaskPower not pursuing carbon capture and storage with Boundary Dam Units 4 and 5. He spoke to Pipeline News about this on July 12. Pipeline News: What are your thoughts on SaskPower not proceeding with CCS on BD4 and 5? Ryan Meili: I think it makes a lot of sense. The amount of investment in the first round, in BD3, has not been paying off in terms of the operating of that facility at the level it was expected to. To put that kind of money into furthering down the road of what continues to be an expensive, experimental approach for reducing carbon, the case for that is not strong when you compare it to other ways of reducing our emissions. P.N.: There are serious indications that it may proceed, eventually, with CCS on Shand. What do you think of that? Meili: One of the things I think wasn’t done well enough the first time around was our homework. And this, hopefully, will be an exploration, and an actual exploration, where they won’t proceed for political reasons, but they’ll proceed if it’s actually a good project, where it will reduce emissions and do so in a way that is affordable. P.N.: We’ve been hearing of this “equivalency agreement” for a long time. I thought it was done, but apparently not. Is this ever

going to happen, or is this a pipe dream? And if it doesn’t happen, that means BD4 and 5 shut down in 17 months. What do you think about that? Meili: I think it’s a real risk that they be shut down in 17 months. We should be preparing for that possible eventuality. We don’t have that agreement. I don’t know why. We should by now. Has this government’s reluctance to communicate in any meaningful way around the pan-Canadian framework on climate change made that more difficult? It’s not for me to say, but it seems like a real possibility that’s the case, where it’s hard for the federal government to say, “Yes, we’ll see that as an equivalency and account for that,” while there’s resistance around working together on any other aspect of this. I do have real concerns that the way the provincial government has managed that federal-provincial relationship has made it harder for us to do that, and it’s accelerating the process that has to happen, but could be happening in a way that puts us in real danger. If we have those go offline quickly, without having the time to increase the capacity, through gas or renewables, we could be in a situation of having inadequate electrical power. P.N.: Is this a case of, because we’re not playing ball on the carbon tax, that’s why we’re not getting any equivalency agreement?

Meili: I’m not in those rooms, so I don’t know for sure, but one has to wonder. I would really hope the federal government would not put us in a situation where we might actually be struggling to provide sufficient energy for our public. At the same time, you have to see the way the provincial government has managed that federal-provincial relationship has made it much harder for these things to proceed properly. P.N.: The net result of shutting down Units 1, 2, 4 and 5 means Boundary Dam, in a few years, will be using about half the coal that it was a few years ago. That’s already meant a partial reduction in mining, and will result in a further reduction. What does this mean for Estevan and its coal mining economy? Meili: We are seeing a world that is moving away from coal. Whatever the pace of that is, and the pace matters; whatever the pace of that is, we need to be looking at what’s our way out of this. Trying to force that continue when it isn’t the best way to produce power, isn’t wise. So what are the things we can do to be looking at? Where can the people, who are currently working in that industry, see themselves working in a few years. What I am frustrated about is that this government has done nothing. And we have seen a little bit of discussion from the federal government, coming around and having community meetings, but absolutely

nothing from this government looking at how do we plan for a transition that is actually a just transition. A transition that people have good, mortgage-paying, quality jobs that reflect their experience and their skills, in the area they live. I think there are huge possibilities for that, including in the renewable energy field. As well as being the coal belt, it’s also a sun and wind belt. There’s lots of opportunities in that area. No one is having that conversation right now. P.N.: Should SaskPower convert BD4 and 5 to natural gas? Meili: That’s a little bit beyond my knowledge level on how easily that conversion can be done and if it’s the right way to do it. Maybe I’ll say it this way. We should be looking, as we’re looking to replace power, also to replace employment in the area where that employment already exists. I would say you put an emphasis, a premium, on whatever kind of development needs to be done, in the southeast, so that we’re not, as we’re doing this change, disproportionately harming an area that has been such an important part of our economy and such an important source of energy over the years. P.N.: SaskPower Minister Dustin Duncan has strongly hinted that more natural gas power generation is in the future. What do you think about this? Should we be building natural gas power plants,

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and if so, where? Meili: We should be moving as quickly as possible to increasing our capacity in renewable energy. There are some ways we can do that in a really ambitious fashion that will both increase our capacity for energy production as well as opportunities for local revenue generation and employment. Gas is going to be part of the mix, but that wouldn’t be my top priority. My top priority would be moving us

towards a more economically and environmentally sustainable approach with a really strong emphasis on renewables. P.N.: Can you give me specific examples? Are you talking wind, talking solar? Meili: I’m talking wind. I’m talking solar. We could look at geothermal, we could look at incineration. We could look at all sorts of models. That’s got to be led by the engineers and those ► Page A9

They stopped paying him, but he never really left for 31 years, and counting ◄ Page A7 off and on work. The government supplied the office and facilities. “But all the map work, and all the core sections, I did by hand. The government finally digitized it, and it was the first of the digitized reports,” he said. Thus, instead of a thousand printed copies, only two were made, one for the library, and one for him. He put in tens of thousands of hours into this report, unpaid other than his pension. Companies who sought to have certain areas studied would hire him to do that, and it would find its way into the report, so there was some pay from that, but it was primarily for use of the lab, as opposed to income. It was essentially a labour of love. “It grew because of the circumstances, there was no money to publish it to begin with, and so I added to it. Each time it was submitted for the editorial process, there would be delays, so I kept adding to it. So finally, I think in self defence, they published it,” he laughed. Not only is the Mannville formation key for heavy oil production in northwest Saskatchewan, it’s also the formation that has a tendency to flood potash mines, he noted. “What distinguishes the Mannville is it covers every formation, or blankets the edge of every formation in Saskatchewan, from the border

to the sedimentary edge, because it’s laid down on an old land surface which infilled,” Christopher said. It can be anywhere from 20 to 200 metres thick, thicker to the northwest. Fundamentally, he was the guy who never knew when to go home. “That’s what it came down to,” he said. “It was not only work, but a hobby, also. But everything I knew about the Mannville, I put in there. The idea was to make it as useful as possible, whether it be for oil or solution for potash problems, or water quality.” That report was completed 15 years ago. Since then he’s also worked on federalprovincial agreements, including working on the geology for the Weyburn-Midale Project, and a joint ManitobaSaskatchewan mapping project. Currently he’s mapping the formations of the Colorado, to try to standardize the nomenclature, and to explore aspects of its deposition. He’s hoping to publish his results this year. “I don’t plan to do anything more than that,” he said. Is he calling it quits? “I think so. It’s getting harder and harder to get out,” Christopher smiled. So 31 years after he retired, Dr. Jim Christopher might actually retire. “Might” is probably the operative word. Don’t count on it. There are still lots of rocks to explore.



Six months in, Whitecap investing in Weyburn Unit By Brian Zinchuk Goodwater, Calgary – A little over six months since Whitecap Resources purchased the 62.1 per cent controlling (and operating) stake in the Weyburn Unit, the CEO is happy with the acquisition and the company is starting to substantially invest in it. Grant Fagerheim, who fills the roles of president and CEO, spoke to Pipeline News on July 17. “It’s a good asset, with such good people,” he said

by phone. “Now that we’ve had some time to work closely with them, I think you have to emphasize how impressed we are with the depth of knowledge and the integrity of the people out there.” Asked how things are going, six months in, Fagerheim replied, “Exceptional. I would have to say as good or better than what we were anticipating.” He noted that integration includes taking over the assets, bringing

in the individuals in the office and the field, and then there’s integrating the processes. Finally, he said the application of technology is the last component. “Our processes were quite a bit different than Cenovus, as you could well expect,” he said. “We will continue to advance the technology side. That’s not to say we’re better, we’re just different, than what they were using. “That has gone far better than we anticipated.

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Why I say that is it goes back to the people. The people working in the field, right in the Weyburn office, as well as the people we brought over in the head office, here in Calgary, it has worked very well. Fagerheim said, “The performance of the asset has been extremely strong.

They’ve done a very consistent profile to the asset. On a relative basis, to the cashflow being received from the asset, because the commodity prices are higher, and the Canadian dollar is weaker, there’s more cashflow being generated off of this. He noted they just started into their capital

projects. This improved performance is despite the reduced carbon dioxide available. A major storm that hit the Boundary Dam Power Station in June. Boundary Dam Unit 3’s (BD3) carbon capture facility is one of two carbon dioxide sources for the ► Page A10

Meili concerned shutting them down too early could lead to shortages ◄ Page A8 capable of assessing both the cost and what energy production opportunities are. I so see, with the cost of solar having dropped so quickly in recent years, there’s a real opportunity there to get more and more residential, small community, on reserve, on farm solar capacity being produced, creating more of that energy closer to where it is used, and also creating opportunities for revenue generation. P.N.: The other element of CCS is its use in enhanced oil recovery.

Being that SaskPower is not doing this, it also means there is no future source, in the near future, for carbon dioxide for enhanced oil recovery. That’s a limiting factor for the southeast Saskatchewan oilpatch. What do you think of that? Meili: It certainly is something that needs to be looked at. Is it the role of government to be putting taxpayer dollars – to date, $1.5 billion – including tens of millions in penalties directly to Cenovus for the times they have not been able

to deliver, is that really how we should be operating this? I find it quite strange that a government that is so focused on the free market and industry taking the lead, would be looking at continuing a model there. We’re putting in a big investment into basically subsidizing those private case for it. If there’s really a business case for it, then maybe Cenovus or somebody else steps up and connects to an existing plant, but they’re doing the development of the carbon capture.


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$100 million being spent on Weyburn unit this year ◄ Page A9 Weyburn Unit, the other being Dakota Gasification Company (DGC) in Beulah, N.D. Fagerheim said BD3 is not expected

to be online until some time in August. As a result, they were able to increase their take from DGC during this period of time. Overall,

Grant Fagerheim is president and CEO of Whitecap Resources Inc. In 2017 he was inducted into the Saskatchewan Oil Patch Hall of Fame. File photo

it means a little bit less CO2 than normal. “But we’re still getting exceptional performance from the asset,” Fagerheim said. The decline rate is 3.5 per cent. The maintenance profile – the acquisition of CO2, as well as optimization activity, is just shy of $40 million. The development program is pegged at $20 to $24 million. “The approximate capital, net to their working interest, is about $60 million right now.” Since their working interest is 62.1 per cent, it means their partners in the unit are spending approximately $40 million, totalling roughly $100 million being expended on the asset this calendar year. “Cenovus had no development since mid2015,” he noted. They’re in the process for planning for the next three years. While they don’t have the details yet, as the budget process is just underway now, he said, “The development capital program will be higher next year than this year, for certain. Number 1, our netbacks

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are stronger as a result of higher prices. When we bought this asset, it was US$53 WTI oil. The Canadian dollar was running around 80 cents at the time.” Now, with oil prices around US$68-70 per barrel, and the Canadian dollar around 76 cents US. The difference of 76 cents versus 80 cents is about C$4.50 more, per barrel, that they receive. With oil in the current range, it means they have more capital to spend into the asset. “Our preference is to redeploy it around the existing asset,” Fagerheim said. This year they have one drilling rig, Precision Drilling Rig 275, working. That rig had previously earned a 20-year safety award working in the Unit. Asked if they planned on bringing in a second rig next year, Fagerheim said it was better to have a continuous program with one. “The more continuous programs you can have, the better it is. If you can run that rig all year long, run it this year and continue to run it all year, the following year, that’s probably the most efficient as opposed to jumping all over the place,” he said. Regarding that long safety record, he said,

“That goes back to where we should be. This is what people should be focused on. Not only are we doing things in a very technically

advanced manner, but a very safe (manner); safe to the people, safe to the environment, safe to the surroundings. I have ► Page A11

Precision Drilling Rig 275 is back at work in The Weyburn Unit



Pipelines needed: Whitecap losses about C$9.5 per barrel, for every barrel produced, due to discounts ◄ Page A10 to attest to the people who work in southeast Saskatchewan are so attuned to that. The staff that we’ve brought over and have had working with us right now, we can’t compliment them enough for their attitude towards health, safety and environment.” Further CO2-EOR A few days prior to this interview, SaskPower announced it would not be putting carbon capture on Boundary Dam Units 4 and 5, but hinted it might, at a later date, do it at the Shand Power Station. Asked about what the implications of that decision are, Fagerheim said, “We would like to continue to expand our footprint onto additional pools. But part of that is pool identification, and then to have the comfort for long-term CO2 sequestration in order to put it into the reservoir.” That long term supply is key. Right now they have plenty of supply. “Would we have, on other pools, depending on the

size of the pools, the duration? We’ll work closely with SaskPower and the Saskatchewan government on this as well. We do want to expand our footprint to other assets.” He said that would mean beyond the existing Weyburn Unit, to other pools. Beyond Whitecap, he thinks there may be interest in CO2 from other entities. “What you have to factor in is the cost of getting the CO2. You still have to build the infrastructure, the pipelines, to the pools. You have to work that into your economics. We already have, from Boundary down to Weyburn. We own that pipeline. DGC has the pipeline into Canada. So they would like to see other areas contacted as well. You’d really have to look at the economics. You really have to look at what is the financial capability. Can you actually do it? What are the timeframes for the economic parameter around that. “We think, having a beachhead of the CO2,

and (being) principal controller of the CO2 in that area, that it is a definitely a head start on anybody else, if they’re even considering it,” Fagerheim said. In May, North Dakota Governor Doug Burgum predicted the state would, in a few years, hit 2 million barrels per day of production, and part of that would be based on carbon dioxide enhanced oil recovery. Fagerheim cheers them on. “I think it’s the right thing to do. If that’s the avenue they start going down, that’s what they should be doing.” He noted that it’s important to go from primary production to secondary (waterflood). “But to get on that path, that’s the right thing to do. Kudos to them if they believe they can actually develop and advance down that pathway,” he said. “We are considering, for 2019, a more substantial capital program, with an additional natural gas liquids (NDL) recovery

project. We’ve got scoping and economic analysis underway. That would be a fairly substantial step up in capital, up from what we’re doing developmentally,” Fagerheim added. “We’re shooting a big 4D seismic program over the asset as well. 4D seismic refers to repeatedly shooting seismic programs over the same area, with time as the fourth dimension. “We’re out for permitting right now. We hope to be in the field, collecting data, in October,” he said. Those programs are used to monitor the advance of CO2. Southwest and west central In addition to one drilling rig working in the Weyburn Unit, Whitecap has three rigs working in the Kindersley-Kerrobert area, and another two in southwest Saskatchewan. “All of Saskatchewan programs are working very well. We’re running six of our seven rigs right now in Saskatchewan.”

They will go to a maximum of nine drilling rigs, with six in Saskatchewan. “Two years ago, we were running one rig in Saskatchewan, prior to 2016,” he noted. On July 20, Whitecap was tied for fifth place overall for the most active drilling rigs in the country, with eight rigs working. In southwest Saskatchewan they’re pursuing the Atlas, Upper and Lower Shaunavon, Cantaur, Roseray and Success zones. The Atlas, Upper Shaunavon and Cantaur are the primary focus. The depths for the Altas run from 1,000 to 1,100 metres, and the Upper Shaunavon is around 1,200 metres vertical depth. The horizontal legs are 1,400 metres. Drilling times are five to six days. In west central Saskatchewan, the focus is solely on the Viking. There’s 700 metres of vertical depth, and their horizontal legs run between 600 to 1,200 metres. These wells take three days to drill.

Every single well is horizontal. Pipelines Fagerheim said of pipelines, “We are not, at this time, being apportioned. But market access is critically important for not just people from Saskatchewan, but all Canadians. We get a discount for our price as a result of not having pipeline access to tidewater. There’s no other way to say it.” For Whitecap, that amounts to about US$7, or C$9.50 per barrel, for every barrel produced. Asked if they would use the now-cancelled Energy East pipeline to Eastern Canada, had it gone ahead, Fagerheim said, “That’s where we should be. That’s where Canadian production should be going, to the East Coast or the West Coast, to our own refiners,” he said. Recent American tariffs on steel has seen prices on their steel go up 12 to 15 per cent. On vendor pricing, he said, “We’ve definitely seen some cost creep, back to 2015.”



20th Annual Estevan OTS Oilwomen’s Golf Tourna

This year was the 20th Annual Estevan Oilfield Technical Society Oilwomen’s Golf Tournament, held at the TS&M Woodlawn G 20. They had 95 golfers take part, bolstered by opening up the field to those who are married to people in the oilfield, if not wor themselves. The cowgirl theme was present in the many hats and outfits worn. Photos by Brian Zinchuk

Rebecca Renard of Axis Services, left, is cheered on by her teammates, Carmen Heier, Nicole Miller and Brookelyn Hientz.

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Monique Lischka’s ball lifts off her iron.

Monica Eagles of TS&M winds up.

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Golf Course on July rking in the patch

Crystal Wilson, right, of Wil-Tech Industries, has her stroke rated by her teammates. From left are Cheryl Larter, Torc Oil & Gas, Kim Greening, Black Diamond Rentals, Cathie Haines, Prairie Mud, and Carla Friess, Gillis Casing Services.

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Saskatchewan Geological Survey celebrates 70 years By Brian Zinchuk Regina – “It all starts with the rocks.” That’s something you’ll often hear from Dr. Gary Delaney, chief geologist of Saskatchewan. And he’s had the opportunity to say it a lot this year, with the 70th anniversary of the Saskatchewan Geological Survey (SGS) of which he is the head. The SGS is part of the Saskatchewan Ministry of Energy and Resources, and until recently, had been part of the Ministry of Economy. The ministry names have changed a few times over the years, but the Survey has always had a foundation role in the development of the province’s mineral and petroleum sectors. Delaney has been doing presentations throughout the year to various organizations about the history of the Survey and the key role it has played in providing geological information that has supported the growth of the province’s minerals and oil and gas sectors which are key pillars of Saskatchewan’s economy. “It was back in the late 19th and early 20th century when some of the

earliest geological surveys were done in the province. Those were very much regional reconnaissance work by the Geological Survey of Canada,” he said on June 7. “Their geologists went up north, and canoed along all the major rivers, to see what was going on in terms of the geology. “The government of Saskatchewan first got into the geology of mineral resources back in 1920, when the Saskatchewan Bureau of Labour and Industries was established to survey and promote industrial resources. Subsequently, the University of Saskatchewan was engaged and began pioneering work on the geology of Saskatchewan. Key players were J.B. Mawdsley, who led several geological mapping expeditions in northern Saskatchewan, and F.H. Edmunds, whose work focused on understanding sedimentary rocks that underlie the south,” Delaney said. “The seminal point for the province’s resource sector was October 1, 1930. That’s when the Dominion of Canada transferred ownership of mineral resources (both miner-

als and oil and gas), to Saskatchewan. This is not unique as in Canada today, natural resources: minerals, oil and gas, belong to the provinces and territories,” Delaney said. Subsequently there was a flurry of geological mapping that started in southern Saskatchewan in 1930. Then, during the period 1934-40, the Geological Survey of Canada undertook some mapping, in the Precambrian shield of northern Saskatchewan. By 1947, they released the first geological map for the whole province, replete with holes due to missing information in places. In 1947, the thenSaskatchewan Department of Mineral Resources created a Mineral Resources Branch. “They started doing prospector schools up in La Ronge and various other assistance programs. But the real seminal event was in 1948, when the Saskatchewan Geological Survey was established. Its mandate was to map the northern mineral areas, as well as carry out geological surveys of potential gas and oil areas and other economic minerals of southern Saskatchewan,” he said.

Dr. Gary Delaney, left, is the chief geologist of the Saskatchewan Geological Survey (SGS). Behind him, are staff of the SGS and geology undergraduate students who are participating in a core logging short course. Photo by Brian Zinchuk That dual mandate has carried on since then. In the 1950s it was put under the administration of a chief geologist. Resident geologist offices were established in Goldfields, near Uranium City, and Prince Albert. Several geologists were added to petroleum geology as well. “About this time an interest was developed in archiving the various petroleum drill cores that had been collected. Some were stored up in Saskatoon in the basement of a Saskatchewan liquor board

store. These were moved to an abandoned chicken processing facility in Regina which became the province’s first core lab,” he said. That building was a precursor to the current Subsurface Geological Laboratory, which was built in 1958. It has been expanded numerous times since then. It was the first such facility in Canada, and one of the first in North America. “Someone realized that core was a valuable resource, so we started col-

lecting and archiving it,” Delaney said. The facility currently stores core from 22,644 wells. If you lined those cores up end to end, it would stretch 640 kilometres, almost exactly the length of the TransCanada Highway from the Manitoba to Alberta borders. It fills 426,793 boxes. There’s another 5.5 million vials of drill cuttings from over 41,000 wells. In the 1960s there was a lot of geological work done by the Survey on ► Page A16

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Province gaining control of minerals spurs exploration ◄ Page A14 the Prairie Evaporite formation in support of potash exploration. “The discovery of potash in that formation really happened as a result of the interest in our oil and gas resources. Potash was

discovered in south central Saskatchewan in 1942, near Radville, at a depth of 2,332 metres,” Delaney said. Another discovery happened the next year near Ogema. A third, cored well in 1946 found 21.6 per cent K2O,

Dr. Gary Delaney, chief geologist Chief Geologist Dr. Gary Delaney has been with the Saskatchewan Geological Survey since 1986, initially doing geological mapping in northern Saskatchewan. “I walked thousands of kilometres up there. I did a lot of detailed work around what’s now known as the Seabee Gold operation. It’s our only gold producer right now. In 1986, I started at what is today the mine site, developing a series of very detailed geological maps for that whole area. There’s been many gold discoveries in that area and I’d like to think that my work helped inform some of those discoveries,” he said. His PhD research focused on the sedimentology and stratigraphy of a sequence

of Precambrian sedimentary rocks in the Yukon. “I’m passionate about what we do here. We’ve got a really good team. We’re really important to developing the province’s mineral and petroleum resources. Like I said, it all starts with the rocks. You don’t know what you’ve got, where it is, how to get it. We’re the foundation of economic development in our resource sector,” he said.

the active ingredient in potash, over 3.35 metres at a depth of 1,056 metres. The first attempt at potash mining was in 1951 at a solution mine near Unity, and a shaft mine that failed a few years later in 1968. Patience Lake, near Saskatoon, began mining in 1958 as an underground mine, but flooding resulted in it becoming a solution mine. Today there are 11 underground or solution potash mines which account for about 30 per cent of the world’s production. As Saskatchewan contains 45 per cent of the world’s potash reserves, Delaney said this industry has a long future. Coal mining has been ongoing for many years along the U.S. border. Petroleum Drilling in the Western Canada Sedimentary basin began in the 1870s. Natural gas was encountered near Lloydminster in January 1934. That led to the discovery of the Lloydminster gas pool, which is still producing. During the 1930s, there were 103 wells drilled, including 11 successful gas wells. “Oil was first noted in 1935 in the Lloydminster area, but it wasn’t com-

Dr. Colin Card, in white on the right, shows different core characteristics to SGS staff and summer students on June 7. Photo by Brian Zinchuk mercially viable. A lot of exploration took place in the 40s, and new gas pools were discovered in the Unity area. We started to produce a significant amount of natural gas. Commercial quantities of heavy crude oil were discovered in the Lloydminster area in 1943 in Alberta and 1944 in Saskatchewan,” Delaney said. “The Geological Survey was formed in 1948. Some of our geologists started studying the nature and context of these oil and gas reserves. We started collecting technical informa-

tion, archiving data and core from drill holes. We took that role that a government geological survey can do, of putting together more of the provincial picture, the big with some detail of what are the nature and context of these resources, and where do you find them. That work has been carried on to today,” Delaney said. Dr. Chao Yang, for instance, a research geologist with the Survey, did a lot of foundational geology that helped companies go out and explore for the most recent round of potash ex-

ploration and development that’s taken place over the last decade. “We’re really the folks that establish that geological framework for the province. If you don’t understand the geology, it’s hard to explore, be it coal, be it oil and gas, minerals or whatever. A lot of big, big companies will have a lot of resources, but a lot of the smaller guys have really relied on us.” The Survey builds the geological architecture, providing a picture of where the units are, and ► Page A17




USTOMS ROKERS Supporting industry’s exploration activities ◄ Page A16 their shapes. For example a work by Milt Holter in the 1960s supported a lot of the early potash exploration and development. Dr. Jim Christopher and Dr. Don Kent also put together maps showing where various units were in Saskatchewan. (See related story, Page A3) Supporting exploration Delaney joined the Survey in the mid-1980s. Over time he said there’s always been a few people working on potash, both more and more the focus of their work in southern Saskatchewan has been on petroleum geology. “The work that’s been done here has led to the development of a number of oil pools. Our geologists can look at the whole picture. They will research an idea, put

it out in papers and the Prospects series and present it in technical sessions at various conferences. This work helps industry think of new ideas and places to explore. The Prospects series are small publications that highlight focused research in particular areas. They are routinely produced by the Survey’s geologists on an ongoing basis. To keep mineral claims in good standing, companies must provide technical reports on their exploration programs (confidential for three years). “We literally have millions of pages of these reports, going way back. Two years ago we undertook an initiative that scanned that information, so somebody coming in that wants to work on a

Next generation of geologists

mineral project, can go online and find reports and maps from previous industry work.” Maintaining the province’s geological information, be that cores, technical reports or maps, is one of the Survey’s key roles. “We are the keepers of the provincial geological database,” Delaney said. “You have to look at geological data as infrastructure. You have roads, you have power lines, but we understand the geological architecture of the province. We take that to build 3D models, research papers, maps and so on. That’s infrastructure. We have all that information. We make it freely available. It contributes to the province’s competitiveness.”

Underbalanced drilling makes a comeback

While the interview with Dr. Gary Delaney was going on, a number of summer students were being briefed in the examination area of the core lab. Standing between the roller racks upon which countless core have been closely examined by squinting geologists, the fresh faces represent the next generation of geologists for the industry. “These are undergrads in geology programs at Saskatchewan’s two universities. Working for us during the summer gives them some great technical training. Some of them may end up joining us and be supported to obtain graduate degrees. We really have a fundamental role in training the next generation of geologists,” he said. “We also do a lot of international cooperation,” he said, noting they have cooperation agreements with geological surveys in China and Australia. Delaney pointed to

Dr. Colin Card, an adjunct professor with the University of Regina, and a member of the Survey’s staff. Card was the man briefing the students. Delaney said, “Years ago, he worked for me as a summer student, up in northern Saskatchewan.” Pointing to another person in the room, he said, “Peter Hill, he’s been working for us for a few years now after spending some time in industry. He just completed his masters degree. We supported that as part of his work plan.” Dr. Kathryn Bethune, chair of the Geology Department of the University of Regina, was also present. She said, “The University of Regina, and University of Saskatchewan, to some extent, work very closely, with the Survey especially in terms of research and training students. A lot of the research we do is field orientated. We work collaboratively on those field projects,”

She noted the Survey’s and universities’ personnel work closely to train students in geology field techniques. Delaney and Bethune noted University of Regina geology students use the core lab in their lab classes. “The students can come here and see the rocks,” Bethune said. Students are able to access cores free of charge. “There is a really good synergy between the University of Regina and the Saskatchewan Geological Survey,” Bethune said.

ton commercial, it really was a case of they liked it so much, they bought the company, or at least the hardware. “At the time, we were the only customer other than Cenovus,” Matt Cugnet, who heads up Intel-

lidrill, as well as Valleyview Petroleum, said. “We had used the equipment and were impressed with the job it did and were happy with the results.”

Matt Cugnet is a geologist by trade and president of Valleyview Petroleums. He’s a true believer in underbalanced ► Page A18

Dr Kathryn Bethune

rders & Consultants By Brian Zinchuk Goodwater – There was a time when underbalanced drilling was pretty popular in Saskatchewan, back in the 1990s, but these days it is in danger of becoming a lost art. However, as Whitecap

Resources Inc. began drilling in the Weyburn Unit in June (after a long hiatus from previous operator Cenovus), underbalanced drilling has made a comeback. And that’s good news for Weyburn-based Intelli-


drill Solutions LP, owned by the Cugnet family. They acquired the hardware for underbalanced drilling in the fall 2014, as the previous owner, Weatherford, was about to disperse it for auction or scrap. Like the old Reming-

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Intellidrill fires up again in the Weyburn Unit ◄ Page A7 drilling, having done it on Valleyview wells. That was a prime consideration in their buying the equipment and setting up the company. The Cugnets stepped in, and purchased the equipment, with the key factor that Travis Lund, who has been doing underbalanced drilling for 25 years, tag along to run the outfit. He did, but the oil downturn hit hard, and they did a bit of work in 2015 and 2016, but none in 2017. The workers, including Lund, had scattered to the winds, so to speak, finding other work as mechanics or farm workers or other areas. Lund went back to his Griffin-area farm. But when things fired up in June of this year, all but one of their nine people

came back, and they’re working on the last one. Cugnet noted that when they bought it, the intention was to drill with it any day, but that any day has now turned into four years of not drilling. “We wanted to make sure it was held onto. We wanted to make sure it was available when we wanted to drill.” The process has been refined and tweaked continuously over the decades, according to Lund, on July 10, providing Pipeline News with a tour of their operation south of Weyburn. And it’s honestly one of most complex processes this paper has come across, shy of oil refineries and gas plants. The whole idea of conventional mud-based oilwell drilling is to have enough mud weight to keep the well from flowing

while drilling. Underbalanced drilling does just the opposite – it allows the well to flow, and does not use mud. Instead, it uses nitrogen to lighten the fluid, which is typically water, but it can be invert (diesel) or even crude oil. And deriving that nitrogen is one of the key tricks of Intellidrill’s setup. While other underbalance setups capture nitrogen from the atmosphere, their very rare system uses engine exhaust gases. The system has massive V-12 Caterpillar engines to provide compression, one with a reciprocating pump, the other with a screw pump. But these engines don’t burn diesel, they burn propane. The exhaust from burning propane turns out to be 87 per cent nitrogen.

Cal Connelly started working with underbalanced drilling when he was 18. Now he’s 36. As service gas supervisor, he’s an integral part of the Intellidrill team. The engine behind him is key. It burn propane, and its exhaust is captured and compressed as the source of nitrogen. Photo by Brian Zinchuk Therefore, the exhaust does not go out a smokestack to the atmosphere, but is captured and is ducted directly into the very compressors those engines are turning. Catalytic converters take care of any remaining oxygen in the exhaust stream – a key thing, because oxygen combined with the already-present hydrogen sulphide leads to corrosion which can chew up a drill string in months when drilling in a carbon dioxide flood area, such as the Weyburn and Midale

Units. And that’s another factor – while its implementation used to be widespread before carbon dioxide floods were implemented in the Weyburn and Midale Units, it is particularly important in drilling in these areas, according to Cugnet. He noted that well licenses require appropriate precautions must be taken when drilling in a CO2 flood, which means there must be a process facility at surface. There are other

benefits. Cugnet said, “The reason we did it wasn’t necessarily to drill a better well, when we crunched the economics, it was cheaper to drill an underbalance well, because there was no completion. We don’t have to swab or evaluate. You run a well and you pull swabs for maybe four days, maybe ten days. Maybe you got oil, maybe you got water. You’re trying to figure out where the water is coming from, because it looked good the entire time you ► Page A19

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Live-testing the reservoir while drilling ◄ Page A18 drilled it. With this, you’re live-testing this reservoir every minute of the day. So if you’re making two cubic metres of oil an hour and all of a sudden you hit 20 cubes of water, there’s no messing around. You know where you hit that crack. You set a packer and you can shut it off. “To me, that was it. It was data. It was knowledge. And when we were drilling, we live-tested that reservoir before we put in a jack, before put in a lease or anything. We knew what that well was capable of making,” he said. Cugnet noted how oil

companies will often look at different areas, like the upfront costs, separately, instead of as a whole. “The drilling guy typically worries about his department, and the service rig guys are left to clean up whatever happens.” He noted that on their last three wells drilled, when things were still expensive during the boom, the underbalanced drilling added $90,000 per well, but saved $220,000 per well on the completion side. Since those wells were drilled seven years ago, they haven’t required a service rig on any of them over that timeframe. They also haven’t

required corrosion inhibitor, either. Cugnet said, “It’s an interesting thing. We ultimately want a well to flow and produce as much fluid as possible, but for the first week of its life, we’re doing everything possible with drilling mud to keep it from flowing. And ultimately, that damage is never 100 per cent undone.” Process The gas and fluid is used as a two-phase system, with the gas (nitrogen) lightening the liquid going down the drill column. “You don’t want any hydrostatic pressure in the annulus. You want that to

flow at all times,” Lund explained. What comes back from the well goes through a four-phase separator – oil, gas, water and solids. The separation system includes a large separator vessel which is connected to a tank farm. Lund noted how that tank farm, part of the separation system, has been continuously tweeked over time, and includes a conical tank. Oil that flows goes into one tank, and the water and solids go into others. The solids are returned to the shaker table. Gas is flared off. If they encounter carbon dioxide while drilling,

it is possible to shut off or phase back the nitrogen and revert to what’s called “managed pressure drilling.” Another important element is how the underbalance system handles the cleanout. This particular well was being re-entered and re-drilled because the asphaltines had basically asphalted-off the well over time. The iron and process has changed hands a lot over the years. UDSL came up with the concept. It was initially Northland Production Testing, then Precision Energy Services, followed by Weatherford SDS before Intellidrill was set up in

2014. Intellidrill, itself, was a transformation of a former Cugnet company, Petrotherm, a rod-rig outfit which shut down early into the downturn. Through it all, Lund has been a part of it. “We’ve been doing this since at least 1992. I started in 1993,” Lund said. “We used to do it all over in the 1990s. We had eight packages back then.” Intellidrill has two full underbalance packages and a spare exhaust gas package. “We’re very happy to be working for Whitecap and we’re doing the best job we can for them,” Cugnet concluded.

Weyburn Unit seeing action after three quiet years By Brian Zinchuk Goodwater – The names of the companies operating the Weyburn Unit have changed over the decades (Central Del Rio, PanCanadian, EnCana, Cenovus), but they’ve always been successor companies – essentially a continuation of the same company under a different name due to mergers or a company split. In mid-December that changed, when Whitecap Resources Ltd. purchased Cenovus’s operating interest in the Weyburn Unit. The change meant instead of being part of a larger company, the Weyburn Unit is now in the

hands of a smaller, more nimble company. Darcy Cretin, area superintendent for the last 21 years, and Ron Bartlett, construction coordinator, sat down with Pipeline News at their Goodwater facility on July 11. Bartlett has 28 years in the Unit. “The day we got CO2 approved, I was transferred,” Cretin said, referring to the carbon dioxide enhanced oil recovery (CO2-EOR) program in place in the Unit. It began in 2000, pumping CO2 as a miscible flood, increasing oil production and extending the life of the field for nearly two decades to date and more decades to come. The process is called

WAG, or water-alternating-gas. It means that portions of the field have wa-

ter pumped underground in a typical waterflood fashion, and then car-

bon dioxide (gas) is then pumped in. The process is regularly switched between

the two. This is evident in the apparatus Bartlett ► Page A20

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Optimization reduced the average annual decline rate to just 3.5 per cent ◄ Page A19 showed in one of the small fiberglass dome huts at an injector site, where one side of the injector wellhead was CO2, and the other was water. While carbon dioxide floods have been in place in West Texas since the 1970s, Cretin noted that those

In those small fiberglass domed huts are the injector wells. One side pumps in carbon dioxide, and the other pumps in water. A valve in the middle determines which goes in the well.

used naturally-occurring CO2. This was the first to use anthropogenic (manmade) CO2. “We modeled off the floods in the States,” Cretin said. Cretin heads a group of 60 people now. There had been 75 back in 2014, before the downturn. The Unit saw two rounds of corporate-wide layoffs under Cenovus. All but five people carried on to Whitecap. He noted they are a much smaller company now, with a much smaller organization chart. That goes from the head office right down to the field level. A lot of centralized health and safety, procurement, human resources, information technology, is now done locally, he noted. “We do it ourselves.” It’s meant a lot more autonomy at the field level. The first six months let the dust settle. “The next six months are our opportunity to deliver,” Cretin said. CO2-EOR The Weyburn Unit, along with the then-Apache operated Midale Unit, gathered enormous attention as the Weyburn-Midale Greenhouse Gas project. The Intergovernmental Panel on Climate Change was one of the first tours to

visit, Cretin noted, showing off their signatures in the guest book. (That group would, in 2007, be awarded the Nobel Peace Prize jointly with former Vice President Al Gore). Much of that attention, with its waves of scientists, media, and politicians, has dropped off now. The Petroleum Technology Research Centre in Regina quite literally wrote the book on the best practices for geological storage of CO2, based on the research done in the Weyburn and Midale Units. What has not died off has been the focus on producing oil. And in recent years, the oil downturn meant Cenovus had stopped all drilling in the unit for several years. But that interval provided the operating staff the opportunity to really hone in on their optimization. For instance, they found that a well-placed horizontal injector and a well placed horizontal producer produces more oil. At the end of 2014, Cenovus more or less suspended all capital activities. Cretin noted that was the last year a new CO2 pattern had been implemented. A CO2 pattern looks

something like a tic-tactoe grid, where the squares are made up of injectors and producers. The centre square is initially converted to an injector, then eventually the number of injectors are increased. Additional patterns are added in this manner, and the CO2 flood grows in size. The last three years, 2015-2017, were three full years of no new development beyond buying carbon dioxide and pumping it into the flood. “We had a static field to work in. Exploitation engineers really learned the flood,” Bartlett said. Oil wells generally produce less today than they did yesterday, a phenomena, when graphed, referred to as the decline curve. But without any drilling during that time, the operators of the Weyburn Unit were able to reduce the decline rate to just 3.5 per cent. Bartlett noted “It’s really a business choice between buying CO2 and drilling. Sometimes more CO2 is better.” There are currently 82 injection patterns in the unit. They’ve already surpassed the original plan of a 75-pattern flood. The Unit has a total of 150 patterns.

Ron Bartlett has worked in the Weyburn Unit for 28 years. He currently looks after construction. Photo by Brian Zinchuk Cretin said, “Conceptually, there’s almost another 70 patterns to go.” Right now they’re targeting maybe 120 to 130 of those. The very first 19 patterns were implemented in 2000, and they are still continuing to optimize those. Eighteen years later, they are still injecting in those areas. In some areas the progression of primarily production, waterflood and CO2 flood has them pushing a 50 per cent recovery factor. They are operating approximately 800 wells – 500 producers and 300 ► Page A21

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Collapsed caves in west central Sask may hold oil reservoirs By Brian Zinchuk Regina – In early July, the world was enraptured with the plight of 12 Thai soccer players who were led by their coach four kilometres deep into a cave, only to be trapped by rising waters from heavy rains. Their rescue, and the tragic death of one of their rescuers, brought caves very much into the public eye. But long before that wayward journey into darkness, Dan Kohlruss, research geologist with the Saskatchewan Geological Survey, has been looking at caves for an entirely different purpose: how they may figure into the petroleum systems of west central Saskatchewan. On Feb. 9, he spoke to Pipeline News about his work. “Right now I’m working on the Success formation in west central, in the same area I was working on the Viking,

but at a greater depth,” Kohlruss said. The specific area is around Kindersley and Kerrobert – Marengo, Flaxcombe, Smiley, where several drilling rigs could often be found. “I’ve been describing the various types of rocks there, and I’m finding they’re formed by karsting, and some of them are the result of cave development in the rocks.” Karst features are the result of rocks that were dissolved, as a product of rainfall or water getting into fractures or cracks, according to Kohlruss. “When it rains, rain is always slightly acidic, and sometimes it comes into contact with limestone, and it will dissolve it along surfaces like cracks.” This can result in vertical or horizontal caves. This project idea has been at the top of his list for nearly 10 years, he noted. “You have a lime-

stone formation, the Madison. At its surface, you get karsting occurring and you basically get a rubble developed at the top. There’s been known oil shows in that for a number of years, and there’s been production,” he said. From Milton through North Hoosier, the reservoirs are part of this type of karst. “There’s also a collapsed cave that’s a reservoir. That’s cool, in my books.” “I was able to map the collapsed cave system,” he said. “It starts with the Madison limestone that was deposited in a sea, but then the sea went away, and you have a long period where the limestone is basically exposed to the elements. Just through rain and natural activity, you get these karsts forming. So the caves you see down in South Dakota, the same thing – but now those are in the subsurface and the caves have

Geologist Dan Kohlruss thinks collapsed caves in west central Saskatchewan may contain oil. Photo by Brian Zinchuk collapsed, but you can still get oil trapping in them.” His paper is done, and now he’s working on showing the trapping model of karst-controlled reservoirs. To identify this, he looks for angular beccia, or broken rock. “For it to have been like this, there was basically no lateral

transportation, it’s all vertical collapse, otherwise it would all be rounded. The cave walls had fallen inward, the ceiling had fallen down. Since the collapsed cave would be largely breccia, it would make for lots of porosity and permeability. “What I’m finding, is where the caves are end-

ing, you have oil trapped. Or, where some of the main part of the Madison is preserved, where the surface karst terminates against it, you have oil trapped,” he said. The cave system Kohlruss is looking at would be in excess of 30 kilometres long. ► Page A22

4D seismic survey program planned this year ◄ Page A20 injectors. Geology Cretin said, “The geology is quite variable from west to east.” The geology is all Midale beds, focussing on the Marley and Vuggy, each with three to four layers. It’s all tidal deposition, like the current coast of Belize, according to Cretin. The depth is around 1,450 metres. There is a 4D seismic survey program planned (the fourth dimension is time). The last one was done in late 2016. Since the density of the carbon dioxide is different from the baseline survey, it allows Whitecap to determine where the carbon dioxide has reached. He noted they have water injection “fence wells” to keep the CO2 confined within the Unit. Drilling program This summer saw drilling resume in the Weyburn Unit, with Whitecap bringing back Precision Drilling Rig 275 back to work, now equipped with a top drive. The program includes six horizontal injector wells, seven new horizontal producers, three re-entries and five cleanouts of existing wells. In the 90’s, a high percentage of the horizontal wells in the Unit were done by re-entering existing vertical wells, Cretin noted. The drilling will result in one small half-pattern

being added. They’re scouting wells for next year. Due to the complexities of the CO2 flood,



Bartlett noted that there’s probably as much facility work as there is drilling, with upgrading to stainless steel and fibreglass

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pipe that can withstand the corrosive effects of the sour carbon dioxide.

In addition to new drills, a field that size also has its share of abandon-

ments. They do five to 15 per year. “A lot is development driven,” Cretin said.



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Helium drilling supported by Sask. Geological Survey By Brian Zinchuk Regina, Consul – In the very southwest corner of the province, Savanna Drilling Rig 629 was

drilling for a natural gas, but not the one you might think. No, it wasn’t methane, CH4. It was helium, He.

North American Helium Inc. was the company doing the well. The drilling was northeast of Consul, just south of Cypress Lake. Melinda Yurkowski, assistant chief geologist, petroleum geology, with the Saskatchewan Geological Survey, has been working on the geology of helium exploration for several years. Speaking to Pipeline News on July 17, she said there were 14 helium wells in Saskatchewan. Yurkowski said that North American Helium has six wells completed, with one planned and one abandoned. Royal Helium has one well. Weil Group has two wells near Mankota, where they opened a helium

production facility two years ago. Canadian Helium has two wells, and the City of Medicine Hat has one. Historically, Saskatchewan had helium production in the 1960s and 1970s. But prices dropped in the late 1970s and the bottom dropped out of the market. Oil and gas companies found it during their explorations in the 50’s, and three areas were identified – the Wilhelm, Battle Creek and Mankota structures. In this decade, as the United States government sold off its strategic reserve, prices and demand for helium began rising again, fuelling the interest in helium in this province.

“We’ve seen at least 10 wells drilled in the last four to five years,” Yurkowski said. The development is now moving away from those three identified structures. “I’m continuing to work on it. I did a report in 2016, and I’m hoping to do a new report soon,” she added. She presented her work on helium at the Williston Basin Petroleum Conference in Bismarck, N.D., this past May. In 2018 there were 17 helium permits issued. In the year since July 28, 2017, 41 new permits were issued. Put in context, that’s nearly one quarter of the 171 helium permits and leases that are active with the province, most of which

are on their primary term. Yurkowski’s work on this new report focuses on the eastern part of Saskatchewan, having already looked at the southwest corner. This involved looking at gas analysis and compiling data for helium, nitrogen and carbon dioxide. Those last two, if occurring naturally, can be telltale indicators for possible helium. Asked about her preliminary findings, Yurkowski said, “I’m seeing some elevated shows throughout the stratigraphic column.” At this time, she can’t explain those shows yet. She is hoping to release her results in the fall.

Flattened caves may hold oil in them

Assistant chief geologist Melinda Yurkowski is researching possible helium resources in southeast Saskatchewan. Photo by Brian Zinchuk

◄ Page A21 “It may be more than one cave system that eventually coalesced,” he said. The depth would be around 800 metres now. It would be 150 to 110 million years old. For this project he looked at about 3,000 well


logs, but only had about 16 cores that actually go through these intervals. “It’s almost impossible to core. They pull up the core barrel and its gone, it’s so rubbly,” he said. Kohlruss presented his findings in Salt Lake City and Calgary this past May.

“I’ve been talking about this to several companies in the area, and they’ve been waiting for me to publish the info. It’s going to change, I think, a few of their interpretations of how to look for the oil,” he said. For instance, one com-

pany had been looking for fluvial (river channel) systems in the area. Kohlruss is suggesting it may not be river channels, but rather collapsed caves. The oil in question is heavy oil, not light oil, he noted, which has an impact on its production.

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Where is all the oil being trucked into North Dakota coming from? By Brian Zinchuk Bismarck, N.D. – North Dakota reports that nearly 100,000 bpd of oil is coming into their state from Canada, by truck, but folks in southeast Saskatchewan have been telling Pipeline News they don’t know where that’s coming from. So we reached out by email to Justin Kringstad, director of the North Dakota Pipeline Authority, which put out those numbers. He replied on July 20. The answer: it’s sour, heavy oil, coming in through North Portal/Portal. “You are correct that the numbers make most folks do a double take. The data I use in my chart comes from US International Trade Commission online database,” he said. “I wanted to try and double check the numbers and have found similar data through the US EIA. The charts below compare the ITC and EIA data for both imports and exports. “The top (imports) chart shows very close relationship between the US ITC and US EIA data for imports into ND. This is encouraging and helps add some confidence in the numbers. “The second chart

(exports) compares the EIA PADD 2 (all of the Midwest) exports to Canada. You can see that the total EIA Midwest exports trend with the ITC ND data. (The difference in the EIA and ND ITC would be all other PADD areas). This correlation, again, adds confidence to the export numbers from North Dakota.” Kringstad added, “I do not have any North Dakota facility/terminal details on where the imported crude from Canada is delivered, but I have been able to deduce the following as I have explored the topic: -The majority of the imports come through the Portal, N.D., area. -The majority of the crude being imported to ND is a heavier barrel approximately 20API gravity -The majority of the crude being imported to ND is a sour barrel approximately 3 per cent sulfur.” Kringstad concluded, “While I cannot confirm with absolute certainty, I would speculate that most the heavier, sour, barrels are being blended with light sweet ND barrels and most are being marketed by rail and lesser amounts by pipeline.”

These charts show that Canadian oil is pouring into North Dakota. Graphic courtesy North Dakota Pipeline Authority


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