PIPELINE NEWS SASKATCHEWAN’S PETROLEUM MONTHLY Canada Post Publication No. 40069240
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Where have all the drilling rigs gone? FLEET SHRINKS BY 300 IN FIVE YEARS, MAY SHRINK ANOTHER 100
Canada produces more oil now then it did five years ago, but we’re doing it with 300 fewer drilling rigs. Currently the Canadian Association of Oilwell Drilling Contractors (CAODC) has 515 on the books, but their president and CEO thinks that number could fall another 100. Photo by Brian Zinchuk
DEEP completes 2 wells, plans 3 more
CAODC on declining rig fleet A3
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Mike Heier on drilling rig evolution A8
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PIPELINE NEWS February 2020
DEEP geothermal project completes two more wells, plans three wells more by spring breakup By Brian Zinchuk Torquay – Saskatchewan’s geothermal electricity power generation project is heavy into its winter drilling program, with two wells done and three more planned before breakup. One of those well broke their own record for the deepest well in Saskatchewan, at 3,632 metres true vertical depth. DEEP Earth Energy Production Corp. (DEEP) announced on Jan. 20 that the 2019-2020 winter drilling and testing program is underway. DEEP intends to drill up to five stratigraphic wells by the end of March 31, 2020, to further define the field’s geothermal reservoir parameters. Drilling contracts have been awarded to Weyburn-based Panther Drilling Corporation. The first of these new wells, Border-02A, was completed in December. It was drilled from the same surface location as DEEP’s first well, Border-01, directionally to the southwest with a bottom hole located 1,500 metres from Border-01. It was drilled to a depth of 3,834 metres measured hole depth, (3,490 metres true vertical depth from surface). Panther Rig 2 did the drilling. DEEP’s third well, Border-02B has been
drilled to a depth of 3,898 metres measured hole depth, (3,632 metres true vertical depth from surface) on January 19, 2020. Border-02B was drilled from the same well bore as Border-02A as a whipstock that enabled the acquisition of additional data between Border-01 and Border-02A at a reduced cost compared to drilling a separate well from surface. Border-02B exceeded the record depth of Border-01 by an additional 102 metres true vertical depth, giving title to this new well as the deepest ever drilled in Saskatchewan, the company said. Border-03, 04 and 05 will be achieved with two drilling rigs in order to complete the program prior to spring road bans. DEEP president and CEO Kirsten Marcia noted on Jan. 20, “Plans are evolving by the minute.” The wells in this winter program may be used for monitoring or injection, but they will not be used for producing the hot brine, the resource necessary for geothermal power production. Marcia said, “They are too small to be production wells.” They want to drill full production wells later this year. The first three wells
(01, 02A, 02B) were drilled from the same pad, and the next well might be drilled from that pad as well. However, wells 04 and 05 are planned to be drilled from two separate, distinct sites within a few kilometres of the original location. Drilling is expected to proceed within the next couple weeks, Marcia said on Jan. 20. Each well is projected to take roughly 30 days. A loop test is planned for this spring, using well 01 and one of the other wells. Which one has not been determined yet. DEEP noted this winter drilling program will greatly increase the confidence in the geological model and test the recently acquired 3D seismic data. It will also test regional airborne magnetic data geological interpretation. The multi-well program will achieve flow testing and injection testing to optimize the locations and design of full-sized production wells planned to be drilled later in 2020 and 2021. The wells from this winter program will also have significant value in monitoring the reservoir response during and after large scale drilling development required for full geothermal field development. “We just did a huge
As the DEEP Earth Energy Production Corp. project south of Torquay continues, Panther Drilling Rig 2 just drilled the deepest hole in Saskatchewan. Photo by Brian Zinchuk core,” Marcia said, noting they’ve been analyzing it in Calgary. Logging is underway now, she added. In August 2019, DEEP completed a flow and pressure build up test on Border-01 to assess reservoir pressure and well deliverability. The pressure data affirmed the existence of fracture flow contributions often sought after in geothermal projects. The stimulated maximum production rate for this well supports the potential for an economically viable project.
Following the flow and build up test, a series of injectivity and fall-off tests were conducted. These tests further affirmed that a significant portion of the fluid contribution produced from the well is sourced from a fractured reservoir system. Upon completion of these tests, the remaining brine in the tank farm was disposed into the well which accepted the fluids at high rates, limited only to the capacity of the injection pump. This test confirmed the reservoir’s capability to flow in both
directions – to produce as well as accept injected fluids. The results of the winter drilling and testing program will provide detailed data required for the final subsurface and facility design required for full construction. The reservoir data will be incorporated into a full-scale simulation model to design the full production wells, optimal well spacing and full field development. This data will also be implemented to optimize the final surface power facility design.
The drilling rig industry is shrinking, fast, and yet we’re producing more oil than ever By Brian Zinchuk Estevan – Over the last ten years, and specifically the last five, there have been two consistent trends in the Canadian oilpatch. First, Canadian oil production has seen a continual trend upward, from 2.5 million barrels per day (bpd) in 2010 to 4.4 million bpd in 2020. With the exception of seasonal fluctuations and a short-term dip in 2016, this trend has been remarkably consistent. For the first five years of that decade, the Canadian drilling rig fleet had been relatively consistent in size – around 800 rigs. But when the downturn hit
in late 2014, that number started to drop, and it is continuing its downward trend. According to the Canadian Association of Oilwell Drilling Contractors (CAODC), the end of the 2019 saw Ensign Drilling Inc. delist 17 rigs, Precision Drilling Corporation delist seven, Nabors Industries delist six and Akita Drilling delist one it was moving to the U.S. The CAODC’s 2020 forecast, released in November, anticipated the drilling rig fleet could decrease to below 500 – falling 48 to 497 this year. During the same five year period, oil production
in Canada has grown approximately 400,000 barrels per day. To put that in perspective, all of Saskatchewan produces about 501,000 bpd, as of November 2019. While most of Canada’s growth in oil production has been from the oilsands, 53 per cent of that production comes from in situ projects, e.g. drilling. So what is happening? We are clearly producing a lot more oil with a lot fewer rigs. For the most part, this is not being accomplished with new drilling rigs. Very few new rigs have been deployed over the last five years. The last brand new
drilling rigs deployed in Saskatchewan were likely Betts Drilling Rig 4 and Stampede Drilling Rig 3, the last two to come out of the now defunct Do-All Industries, which had built most of the rigs for southeast Saskatchewan’s small, independent contractors. Red Dog Rig 5, a rebuild of Rig 1, deployed in late 2014. And even then, many of those contractors have been amalgamated into Stampede Drilling. Their fleet now includes the iron of Stampede, Vortex Drilling, Red Dog Drilling and D2 Drilling. In Saskatchewan, in
mid-January, there were 68 drilling rigs working. This number is consistent with 2018, and a bit better than 2017 and 2019 for the same period. The first 2.5 months of the year constitute the bulk of Saskatchewan’s drilling activity, with substantially higher rig utilization. From 2011 to 2014, Saskatchewan would consistently see close to 95 rigs working in those first two months, sometimes as many as 105. The Saskatchewan drilling fleet, as listed by the CAODC, hovered around 120 to 130, which meant most of the fleet was working. Now the fleet in
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Saskatchewan has shrunken to 109. This edition explores just what is happening. Dramatic increases in drilling rig efficiency is one of the key factors. Reduced investment and reduced capital budgets is another. And of course, underlying all this is an oil price that can’t get its groove back. On Jan. 27, WTI was as low as US$52.25 per barrel in intraday trading. One thing is for certain, the drilling industry in Canada is going through likely its biggest shakeup since the introduction of horizontal drilling a generation ago.
PIPELINE NEWS February 2020
Canada’s drilling rig fleet has dropped by 300 in five years, and could drop another 100 By Brian Zinchuk Estevan – In mid-January 2010, there were 531 rigs working in Canada of 803, or 66.1 per cent utilization. In Oct. 2014, the Canadian Association of Oilwell Drilling Contractors (CAODC) listed 811 drilling rigs on its books. Now, as of Jan. 23, 2020, that fleet has contracted to 515, and hasn’t hit bottom yet. Rig utilization, of the much-reduced fleet, was just 52 per cent. Over the last five years, Canada’s oil production has grown from just under 4 million barrels per day to just under 4.5 million bpd. Saskatchewan’s production has remained relatively flat, close to 500,000 bpd. Thus, Canada is producing more oil with dramatically fewer rigs compared to five years ago. (Note: currently oilsands production is 53 per cent in situ, which requires drilling, while mining, 47 per cent, does not.) Pipeline News spoke to CAODC president
and CEO Mark Scholz in Estevan on Jan. 16 about this dramatic contraction in the drilling fleet, and what it means. “There’s been material change in how the business is supplied. The good news is we have 260 rigs working across Western Canada,” he said. He noted that’s an improvement. Last year, that number was 230 for mid-January. In 2018, it was 348. Where did the 300 rigs go? “There’s a number of buckets the decline in the rig count would fit in. Your high-spec, most desirable rigs would have left for the United States or other jurisdictions,” he said, with nearly all of those going to the U.S. “We’d be looking at 30 or so high-spec rigs across the Western Canadian Sedimentary Basin were sent to the United States. The rationale for that is you’ve got a foreign exchange difference. You’re paid in U.S. dol-
There are literally acres of rigs parked east of Lloydminster. In the last five years, the CAODC has seen roughly 300 rigs delisted across Canada. File photo lars versus the Canadian dollar, so there’s a 30 per cent difference. Secondly, you can work year-round. You can literally work in the Permian or other parts of Texas 365 days a year, whereas in Canada, if you can get 120 days, you’re working for a fairly consistent producer and you’ve got a really good crew. It’s fairly rare that you would see that,” Scholz said. Seasonal measures restrict us from drilling year-round in Canada. A lot of areas in Alberta simply can’t be worked in unless the roads are fro-
Scholz went on, “The other attraction of the U.S. is rates are 30 to 40 per cent higher, on top of the foreign exchange considerations. So when you look at rig, sitting in Canada, a $15 to $20 million asset, you can have a better regulatory environment, (where it’s) easier to get approvals, the turnaround for getting a well approved to a drilling rig out is fractions of what they are here in Saskatchewan and Alberta – all these things play into a different business environment.”
Cannibalization “The other reason is the marketability of the rig,” he said. “There were some rigs that are just not marketable or capable of drilling the wells we do today,” he said. Walking rigs or pad drilling are desirable. Those that can’t do that are less so. “The majority of the rigs that have come off are just not marketable anymore,” he said. “Because rates are so low, because the market has been hemorrhaging so much, it’s very difficult for a drilling rig or service rig company to put money
back into servicing equipment. So you have a lot of cannibalization, we call it. One of your pumps goes down. Well, one of your rigs hasn’t been working for a while, let’s take the pump off that. You have an engine that goes down. Let’s take the engine off of that, put it on the rig that’s working. So you have all these different components salvaged off of rigs, and it gets to the point where, we’ve taken all the components off so we need to deregister that rig. But we’ve kept this other rig working a little bit longer before we’ve ► Page A6
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PIPELINE NEWS February 2020
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Will we lose our industrial capacity to build new drilling rigs? The United States Navy is very particular about their nuclear submarines. They are not only extremely expensive, and their ballistic missile boats are most deadly weapons created in the history of mankind, but they must be built perfectly. Their building techniques must be flawless, lest one failed weld, anywhere on the submarine, cause the loss of the boat and all aboard her when a pipe lets go at 800 feet below the surface. This actually happened in 1963 with the lead ship of one of their hunter-killer submarine classes, the USS Thresher. The Thresher had been built with brazing as opposed to welding in some of its construction, and it sunk two years into its career as a result. Since then, maintaining the skillset of those who build submarines, especially the welding, has been critical for the future of the US Navy. That is why they never, ever totally stop building them, because if they lose that skillset, it will be very difficult to regain it. We need to start asking ourselves if Canada is going to be in a similar boat when it comes to building critical equipment for our oilpatch, in particular, drilling rigs. In the last five years, we’ve built something like five, and surely no more than 10 drilling rigs. This is but a sliver of what we built in the five years before that. How many rig builders have survived, and kept their workforces intact? And how many will continue to survive, as we see a continued contraction of our drilling fleet? In October 2014, there were 811 drilling rigs listed with the Canadian Association of Oilwell Drilling Contractors (CAODC). Now, there are 515. Their president, Mark Scholz, whom we spoke to in Estevan on Jan. 16, thinks its possible we could lose another 100. If we may lose that many, we surely aren’t going to be building many, either. We will just keep working with what we have. And some of that iron can work a long time. In driving through the Fast Trucking Service yard at Carnduff, Dennis Day pointed out a triple derrick that had worked over 50 years. Bob Betts of Betts Drilling said a well-looked after rig could last 50 years. But the focal point of this edition has been how increased efficiency with drilling rigs has essentially put half of the fleet out of business. With hundreds fewer rigs, and even less actually drilling, we are still producing as much oil (in Saskatchewan) or more (nationwide) than we were with 811 rigs. Mike Heier, founder of Trinidad Drilling, said, “It takes a generation to lose total know-how. Schools can only teach book smarts. The spirit of the know how comes from street smarts, passion and a wickedly huge entrepreneurial spirit.
That all being said, our Canadian Laurentian Liberals and our generic bureaucrats being federal, provincial or municipal seemed to have conveniently and gleefully destroyed all that.” He noted how a large proportion of the hardware the oilpatch uses used to come from North America, but now the majority of manufacturers are Chinese. We’ve seen this movie before. Remember the Avro Arrow, and what happened when it was cancelled? We lost a huge sector of our aerospace industry, never to return. Canada used to have a substantial shipbuilding capability (so did the U.S., for that matter). Now the few remaining shipyards between our two countries primarily build for their respective navies, and ours hardly even do that. They’re constantly struggling against bankruptcy and layoffs. Shipbuilding is now dominated by South Korea, China and Japan, with South Korea being the go-to place for pretty much anything except warships. You want a tanker? LNG carrier? Floating LNG production platform? Car carrier? Container ship? Go to South Korea. If you wanted to build a truly large commercial ship in Canada, you couldn’t. We don’t have the facilities, technology or expertise. If we don’t retain our knowledge base and industrial capacity in building rigs, could this happen to us in the oilpatch as well? Will Canadian companies have to go to the U.S. or China for its next generation of rigs, maybe five or ten years from now? Will those who build rigs hold out until then? A similar question could be asked on the service rig side. Pipeline News has only seen one new service rig deployed in Saskatchewan in the last five years. Perhaps there are more, but we’re not seeing them. As discussed in several stories in this edition, a longsitting rig can be reactivated. It takes time, and more importantly, a lot of money. The longer they sit, the more problems you’re going to have. Assuming these hundreds of decommissioned rigs don’t all end up being cut up and melted down into pipeline pipe at EVRAZ Regina in short order, there’s a huge amount of iron that could potentially be deployed. It won’t be the sexy new tech, driven by joysticks with top drives and automated pipe handling. But it does exist, and will exist for at least a while. There’s a lot iron sitting in Carnduff, Lloydminster, and fields here and there that could, potentially, work. And if any of that were to be redeployed, say if oil suddenly shot up to US$110 per barrel and stayed there, it still wouldn’t get us new rigs. No, if oil does ever end up in the stratosphere again, we need to get those rig builders back at it, lest we lose their capability for good.
PIPELINE NEWS February 2020
I hate Bell Let’s Talk. But some people really do need to talk Jan. 29 was Bell’s Let’s Talk Day. It’s the day when one of the largest companies in Canada encourages the nation to speak about mental health. More and more companies, agencies and individuals are taking part every year. I hate it. I hate it because it reminds me of my sister, Melanie, a registered nurse of 14 years who left her workplace, Saskatoon City Hospital, in the middle of a shift on May 3, 2015. She bought some rope, drove out of town to a secluded spot, and subsequently hung herself. I hate it because despite my efforts, my mother’s and Melanie’s boyfriend’s efforts, we failed in stopping her. She succeeded in ending her life. I hate it in that she was actually in a facility with every mental health resource available to her, even a psych ward, and she purposely left that place to do this to herself. I hate it because I miss her terribly, despite the fact we rarely got along. And every January, Bell’s Let’s Talk Day reminds me of this. And yet, as much as I truly hate this, hate the darkest chapter of my life being brought forward again and again every January, I think it’s necessary. That’s because there are others who continue to struggle with their own mental health. A few months ago, a friend asked me to look into mental health support for the oilpatch. He pointed out there’s a farm stress line, but nothing he knew of for the oilpatch. He spoke of how difficult the last five years have been since the downturn took hold. This afternoon I got a phone call for a University of Regina professor, ask-
ing about the impact of the downturn on the oilpatch since he didn’t think the statistics told the full story. He got an earful, and may have been late for class. There’s a lot to say. I told him about all the companies who cut their staff by half from 2014 to 2017, about wage cuts to the tune of 20 per cent that were nearly universal. I told him about 20 per cent vacancy rates in towns that used to have zero vacancy. What I did not have time to tell him was how all this financial pain has caused psychological pain. So at my friend’s request, I set about looking for what sort of help is out there. You’ll see the stories online at pipelinenews.ca and eventually in print. I found that, from the health district perspective, they see things in a more general manner. But there is support there, and an intake phone line that acts something like a triage for people in need of help. I found out there’s a website called 211 Saskatchewan (sk.211.ca) that is chock full of links for all sorts of programs, including mental health, and crisis lines. They might not be oilfield specific, in the way the farm help line is, but it’s something. I also found that the health district didn’t really see a profound distinction in mental health cases directly tied to the oilpatch and its downturn. But local, private counselling service Envision Counselling and Support Centre, most definitely did. And Envision offers and employee assistance program that many people don’t even know they might have coverage for, in their health benefits package from work. When you get that little book of benefits, you might notice how much
Fighting for Saskatchewan's Oil Industry Lori Carr, MLA Estevan Constituency Office
coverage you get for your kids’ braces or glasses. You might notice you can see a chiropractor a certain number of times a year. You might even be reassured if you break your leg or have a heart attack in Minot, North Dakota, you won’t go bankrupt. But did you know you might also have coverage for counselling? I didn’t know that, and I don’t think my friend did, either. Envision has most definitely seen the stress of the downturn affect its clients. Its clientele is now nearly half male, and that is a big change from several years ago. Such counselling may not be effective for everyone. It wasn’t for Melanie. She talked to someone on the phone whom she never met, and never would. So it didn’t work for her. But that doesn’t mean a support line won’t work for someone else.
FROM THE TOP OF THE PILE
By Brian Zinchuk
This downturn takes a toll on you, having spent the last five years struggling to keep afloat, not just businesses, but individuals. You wonder if the doors will stay open one more year, if you can make your mortgage payments one more month. No one I know ever thought in 2014 we would see five years of this. Today, oil again dropped to US$52 a barrel. The February edition of Pipeline News explains
how the drilling rig fleet has dropped from 811 to 515 in five years, and might drop another 100. I see the strain in people’s faces, in their conversations. I increasingly see it in myself. I know that this downturn has had an impact on me. I feel it every day. I spent seven years asking people how great everything was. The last five years, not so much. I’m a strong believer the best social program is a job. And maybe there’s
not much we can do right now to ensure job security. But there are services and people out there who can and do help those who need it. I just wish Melanie would have gone down that path, instead of the one she chose. We live with that pain every day, and it never goes away. Brian Zinchuk is editor of Pipeline News. He can be reached at brian.zinchuk@ sasktel.net.
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PIPELINE NEWS February 2020
The drilling fleet may soon be half of what it was in 2014 ◄ Page A3 had to do some serious retrofits.” Of the deregistered rigs that didn’t leave the country, Scholz estimated probably 70 per cent were not marketable, and 30 per cent cannibalized. Smaller rigs not as attractive “A lot of the rigs in our arsenal were not capable of a 7,000 metre well,” he said. “They just didn’t have the hook capacity.” That’s an important factor in a rig’s marketability. Lower-spec rigs are not as marketable. “The high-spec rig market is actually relatively tight right now,” he said, because there’s a good deal on their rates compared to several years ago. “It’s very compelling to take those out of the country.” A “high spec rig” would be a triple derrick, AC-powered, 1,600 horsepower pumps, top drive and a walking system for pad drilling, with a joystick control. “You have 515 rigs left on the drilling side. It’s a simple supply and demand equation. I think
we have a little more runway. Maybe we get to 280 rigs (working). You’ve got 280 working in an elevated area of activity, of 515. I think there’s still more equipment that could be retired. I think, generally speaking, the basin can sustain 400 rigs. I think you could easily see another 100 rigs leave the inventory,” Scholz said. “Back in 2006, we would have had around 950 rigs.” Labour a restriction “The biggest restriction I think for going anything beyond 300 rigs, or whatever we cap out at, is people. We’ve lost a significant amount of key talent that we’re going to have to grow again. I still think there’s going to be job opportunities in the industry. Will it be smaller? Yeah, for sure,” he said. Some larger companies are advertising right now, looking for workers. “They could be looking for relief crews or getting an incremental rig out the door,” Scholz said. “What I’m hearing from some of my guys, at least on the drilling side, is they’re getting calls to book for
CAODC president and CEO Mark Scholz was in Estevan on Jan. 16. Photo by Brian Zinchuk the summer. That’s unusual. It’s been unusual in the past four or five years that has happened. So there are some positive signs that are happening that would indicate a further tightening on supply.” Asked what the future of a kelly rig in Canada is, Scholz said, “It is a customer-driven preference. There are still some customers that swear by you don’t need all the bells and whistles to have an efficient operation. You can still get away with a lower-spec rig that
has a really, really competent crew. He said, “The majority would have a top drive, but it really boils down to customer preference.” Kelly rigs are still working in southern Saskatchewan, he noted. Desirable features “We still do skid rigs on pad wells, but if there was anything a company had on their list of what we need to make it more marketable, it’s not a bad business to be in if you have a rig with a walking system doing batch drilling throughout the year,” he said. “A walking system would be one of the first things I would do. “We’re always constantly hearing that operators are looking for greater pumping pressure, so 7,500 PSI. You’d have to have the mud pumps to go with that. 1,600 horsepower is going to help get to that pressure.” Top drives are where most companies would be at, he said. Automation like mechanized pipe handling is another desirable feature. But none of this comes cheap. Scholz
said, “One of the things to keep in mind with all of this is that this all costs money, and this industry doesn’t have the money it used to for research and development.” He expects to see more advancements in downhole tools and directional equipment. How fast can you drill? Are we rapidly reaching the limit of how fast you can drill, given you can’t trip out and trip in any faster? “That’s a tough question to answer. Let’s put it this way. We’d be kidding ourselves to put caps to the limits of our innovation. I know it’s shocking that wells that used to be drilled in 45 days can now be drilled in seven. You ask anybody 10, 15, years ago, ‘Do you think we could get there?’ “And they’d say, ‘No, that’s impossible, the equipment would never hold up. You can’t trip that fast.’ “I would never put limitations and say it can’t happen,” Scholz said. “You’re going to have a level of diminishing returns, trying to optimize existing technology, but I
would say additional productivity can always come from deploying new technologies as opposed to optimizing existing ones. Maybe there’s a widget or a set of tools that will be introduced five years from now.” More rigs than needed “With the existing inventory in Canada, we still have more rigs then we need. You can throw in productivity increases as one of the other reasons why we see a gradual decrease of equipment,” Scholz said. The CAODC now prefers using operating days as a metric as opposed to rig count. He explained its “how many days has the entire fleet generated, and then within each company, because that’s our billing metric. If we know how many days have been drilled, we know how many billable days we’ve had as an industry. Here we’ve had this nice popup of 260 rigs, but what does that mean on an annualized basis? Okay, we got up to 260, but how many days ► Page A7
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PIPELINE NEWS February 2020
High spec rigs are active, but lower spec rigs aren’t as marketable ◄ Page A6 did the inventory actually accumulate?
“Even utilization, I find to be a bit of a misleading target, because
Drilling rig certifications extended The Canadian Association of Oilwell Drilling Contractors (CAODC) recently extended its intervals for inspections. Most significantly, the most intensive inspection, a Level IV, is now required after 2,500 operating days. It used to be 1,000. Mark Scholz, president and CEO of the CAODC said on Jan. 16, “We did a robust analysis of certifications within our recommended practices. CAODC self-governs its members on providing direction on best practices for certification. It used to be 1,000 operating days with a 125-day extension with the approval of an engineer,” Scholz said. “API, the American Petroleum Institute, is 3,600 days for a Level IV.” “Is it reasonable for us to continue with 1,000 days knowing there are other international standards that provide additional flexibility?” he said. Scholz said the CAODC took a year sitting down with manufacturing shops and engineering teams to get a feel for where the industry is at. “We landed on 2,500 with an engineered Level III at 1,250. So an engineer would do the Level III, and it will be at the discretion of the engineer as to whether or not they felt you could get to 2,500 days.” Other intervals have been spread out as well. Is there a safety issue with this? “We wouldn’t have recommended it if we felt we were putting our people at risk, or jeopardizing our operations. We were comfortable with making that recommendation,” he said. If a rig averages 120 operating days a year, that means it can work almost 21 years at that rate before hitting the 2,500 day Level IV threshold. “If the professional engineer sees any sort of defects that needs to get addressed, it will be addressed at that stage,” he said of the beefed-up Level III inspections.
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the industry is in such a transition right now, and the fact I’ve already disclosed that I think that even at 515, right now, is too many to sustain in this market. “Utilization talks a lot about spare capacity, whereas operating days gives us a much better barometer of how many days did we actually drill?” Of those other 100 rigs, does Scholz expect them to ever work again, or to be cut up? “It depends on the
condition of the rig. It depends on if we’ve started to cannibalize that equipment. If it’s missing significant parts, you might not put capital into it,” he said. How many new rigs have been built in Canada since the downturn? “I wouldn’t say 10. Probably under five,” he said. As for the companies that built rigs, he said, “They went broke or they diversified outside of the country. That’s going to be the other challenge for
our industry. You’re not making enough money to allocate maintenance capital. You’re not making enough for repair and maintenance, to allocate for future repairs. It means those rigs are eventually going to have to be put on the fence. When you have the lack of facility to make those repairs, and eventually build new equipment, it’s kind of looking at a bit of recipe for disaster if at some point we see even further anticipation of activity
down the road,” he said. The institutional capacity is getting smaller and smaller, he said. For rigs that have been sitting for five plus years, will any of them work again? “Never say never, but the margins are so poor in this industry, that it’s going to take much better days an a long runway of better profitability for our industry to justify putting in the needed capital to put those rigs back to work,” he concluded.
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PIPELINE NEWS February 2020
Canada’s drilling fleet is overbuilt, says Mike Heier By Brian Zinchuk Calgary – Mike Heier has lived through the evolution of the drilling industry over the last three decades, and in his opinion, there’s a lot of iron out there that should be cut up, because it’s not going to work again. This wouldn’t be the first time he’s felt this way either. Heier is the founder of Trinidad Drilling, its former CEO and former chair. It had grown to be Canada’s third largest drilling contractors before being taken over in 2019 by Ensign Drilling. Heier noted on Jan. 14, “When I started Trinidad, there were 450 rigs, give or take, in the fleet. Of that, one third should have been scrapped, another third were outdated.” He said they built four of the heaviest teledoubles in existence at the time, and then built seven “singles on steroids,” which use Range 3 pipe as part of the go public strategy. “The industry was overpopulated with junk,” he said of the time, and that could also apply today. For instance, smaller cantilever (also known as “jackknife” rigs) “should be cut up,” he said. “You can outfit an older
rig with new parts and pieces,” he added, but only to a point. “These days, if you get 20 years out of a rig, you’re doing good,” he said. Drilling rigs have become increasingly efficient over the past two decades. Heier noted holes that once took 45 days to drill are now done in seven. “You can point to seven or eight things, but there are 20-plus smaller things,” he said, with respect to what has made the differences in efficiency. Enter the PDC drill bit Perhaps the most significant element has been the advent of the polycrystalline diamond cutter bit, or PDC. They have largely replaced the traditional tricone bit, whose roots run back to 1933 and SharpHughes Tool Company. Its ancestor, the bi-cone bit, was invented by Howard Hughes, Sr., in 1908. Nearly a century later, a PDC bit landed on Heier’s desk around 2000, and he realized it would change everything. It did. “We used to use tricone bits, and the odd diamond bit,” he said. “Cones would roll. Teeth would crush mother earth, and
N E OP
mud would bring up the cuttings. Penetration rates of less than 10 metres an hour were common. Sometimes down under 5 meters an hour. “I’m a millwright and machinist, so I get insert tools which a PDC is covered with. Around 19992000, a bit guy came into my office with a small PDC bit,” he said. He realized that each diamond insert could draw 20ish horsepower, and that meant the 20 cutters would draw 400 horsepower. This meant they would need new, much stronger drill pipe for starters. It meant the rig had to be redesigned from the tip of the bit back to the lease road. People had been telling him to get into coil tubing, but coils couldn’t take the torque, Heier said. “I felt they were obsolete when they were conceived and would be parked forthwith.” “As we started to work with the PDC we would see penetration rates that would be off the charts.” He explained that PDCs don’t really cut the rock so much as “they push the material off.” He said that it’s similar to how a Cat D9 dozer blade
works – it’s pushing the material off ahead of the blade and the uncut portion literally flows under the blade. The material has parted company with mother nature before it gets to the bit. But to do this, you would need “impressive fluid flow,” Heier said. With penetration rates now approaching 200 metres an hour up from 10 to 20 metres an hour, solids control is everything. This means you have to up the fluid rates as much as possible to move those cuttings to surface effectively. This meant going from 600 litres a minute to 2,000 or even 2,300 litres per minute (0.6 cubic metres to 2.0 or 2.3 cubic metres per minute) or more. Some people might think with such high volumes and pressures, you’re essentially water-jetting the rock. Not Heier. He said it’s more like a fast moving river through solid rock. It’s still solid rock. There’s no water-jetting. But that doesn’t mean one should remove the nozzles in a PDC, something he said some people do. That’s where their hole problems start. It’s the proper implementation of a PDC, with volume at its nozzles, and the proper implementation of torque, that makes a big
Mike Heier calls rigs like this “Singles on steroids,” running Range 3 pipe. File photo difference. As you’re cutting, at times, well over 10 times as much hole, you need to pick up the mud rate to keep the solids density down. If not, you will end up with a hole full of marmalade, other wise known as mud rings, he pointed out. He noted that in their typical US operations, after drilling surface casing, they were now drilling 13.5 inch intermediate hole in one day, something that used to
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take ten days with tri-cones. “Next stop, 1,500 metres,” Heier said. And they were often doing it with one PDC bit and no bit change. “The flow coming out of the well looked like a slow dump out of a gravel truck,” he said. Bigger pumps This necessitated a substantial growth in pumps. Drilling rigs might have had one 400 horsepower pump. Ten years ago, in southeast Saskatchewan, it was common to see one 800 horsepower pump on a new rig. That quickly grew. Trinidad’s rigs (in Alberta or U.S.) would have three 1,600 horsepower pumps with two going flat out, and the third for redundancy. Going to polymer muds, with crosslinking, was an improvement over gelbased muds, allowing the muds to better carry solids and still be pumpable. Another change, one that Trinidad used a great deal, was the change to Range 3 pipe. This meant using 15-metre joints instead of 10-metre joints, resulting in one-third fewer connections. Rigs with triple derricks were pulling double stands of pipe, but the same length. And as connections tend to be when you get stuck in the hole, that led to a reduction of that problem. “The PDC forced you to do that,” he said of all these advancements. “If you use a PDC properly, with proper torque and keep it clean, with nozzles in the bits, it’ll last a long time.” Top drives That increase in torque has been another factor. Rigs would be running eight, even nine times the amount of torque compared to before, from highs of 2,000 ft lbs to over 16,000 ft lbs. “The drill strings had to be ► Page A9
PIPELINE NEWS February 2020
Not many brawny farm boys left to work the rigs ◄ Page A8 able to handle that,” he said. That also meant the adoption of top drives, and much stronger ones, at that. Not the 150 horsepower, “toy system” top drives, he noted, but 1,000 horsepower units, and ones that can take the same rated hookload as the derrick accompanied with the required torque ratings. “Rotary tables are virtually gone. It’s pure top drives,” he said. You can do a lot more with a top drive, Heier explained. That includes backreaming on the way out. Directional control is much more sophisticated. “There’s so much more finesse you can do with a top drive you can’t do with a rotary table,” he said. “The bigger they are, the more you can do with them.” “Everything is now changed to withstand what the PDC could withstand,” Heier said. Rates of penetration got so fast, Heier said, “When we were drilling, you couldn’t have a cigarette between connections.” This, in turn, led to “the automation of everything on the lease, taking human touch out of it,” he said. All of this has essential-
ly meant bigger, heavier iron, where manhandling it became more mechanical than muscle. “Human fatigue is a factor, he said. “Everything became auto pipe handling.” That means automated pipe tubs, catwalks, lifting arms, top drives and iron roughnecks. “Those things are all critical, and have to interact with each other,” he said. While that isn’t as common in Saskatchewan, as they are in deeper plays, Heier thinks that’s where the future is. “There’s a lot of opportunity in subsalt plays in Saskatchewan,” he said, referring to below the prairie evaporite. There’s another reason for the trend to automation, he noted. Big, brawny men off the farm have largely disappeared. The younger generation of roughnecks, these days, come from a generation more used to computer games than wrenches. As a result, drilling consoles now are climate controlled, with air-ride seats, joysticks and touch screens. Reactivation of idle rigs There are now hundreds of rigs that have been deactivated in Canada, and hundreds more that are still sitting. Many have sat for
Mike Heier five years or more. Asked what are the issues with reactivating long-parked rigs, Heier said, “There’s a lot of things that cause failures. One of the things people don’t see is roller bearings and ball bearings.” He explained that corrosion happens from freezethaw cycles unless they are stored properly, filled with grease or storage oil. “That’s the No. 1 killer for rotating equipment that’s been sitting too long in northern environments. You’re constantly coming up and down below freezing,” he said. Condensation forming in air gaps results in corrosion. “Corrosion anywhere else, in electric motors, diesel engines, gearboxes, spaces that you have medium to high humidity, on cold
metal in warm conditions, any of those low clearance areas, pitting will form. It’ll run, it’ll start. And (it’ll run) a few hundred hours or a thousand hours later, but it’s not going 30,000 hours. Those are the early failure points. “Any electrical equipment that is poor in quality is more susceptible to corrosion,” he said. “You’ll have small elements of corrosion that will drive you crazy. “And then there’s basic rot. Anything that’s sitting in the sun will have UV deterioration. Plastic wires, plastic hoses, they all deteriorate when not in use.” “The metal may be okay, the paint may be okay, but then you’re going to go inside, and all the things that make it work, you’re going to have to clear out the en-
tire fuel system. Any grunge junk, anywhere, that could have settled out. Drilling mud might be stuck in stuff, all dried out. There’s just a myriad of problems. “To take a rig out of one to three years storage, a midsized rig, you might spend a million dollars on it. A significant portion of that is just the labour you’re going to put into it. You’re going to have a complete rig crew tear into it for two weeks or more. And that is notinvoiced labour. It’s just part of your expenses,” he said. The prairies are better off than coastal areas, he noted, because, “We’re basically a desert.” Too many rigs Asked what the future of tele-double Kelly drive rigs are, Heier said, “It’s getting skinny, getting really skinny.” The industry is oversupplied with tele-doubles, he said, and many were obsolete when they were built. “There was no reason they should have been built and put in the field,” he said. While there were hardly any new rigs built in Canada over the last five years, the five years before that saw a lot built. “In the last decade, there was probably 110, 120
tele-doubles, and you could have probably justified 10 of them.” He sees no future for conventional singles in Canada. “Small cantilevers are done. Cut them up for scrap. That was obsolete when I was living there (in southeast Saskatchewan) in the 80s,” he said. “The Canadian drilling fleet became oversized, obsoleting rigs that were out there that just happened to be maybe in a poor clientmanagement relationship than the guys that were building. It was driven by the investment industry. The investment industry lacked a lot of discipline. We were sitting there with the hot rods of the market, but somebody promised the client something, and all of a sudden, they were building a half dozen rigs for a client, and there was already a surplus in the industry. That was going on steady. “It was one thing if you had obsolete assets that needed to be scraped off the planet,” he said, noting institutional investors were aligning themselves with whoever they thought had the best deal of the moment. “Nobody had a long-term ► Page A10
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PIPELINE NEWS February 2020
Why is there breakup in Saskatchewan but not North Dakota? ◄ Page A9 strategy or approach to what is going on in the industry.” Heier places the blame on three camps – institutional investors, drilling contractors and the oil companies. “All were playing a role in that,” he said. Clients were constantly seeking lower bids that weren’t taking into account a 25-year asset. “In my mind, we should have never got past 600 effective rigs, in Canada, ever. Trinidad started killing dead stuff, early. Canada is an incredibly inefficient operating environment. Only when you are pushed to the extremes could you get a client to go year-round. Com-
mitted days contract beyond 250 annual operating days were rare. And they routinely talked about breakup, lose 1 ½ to 2 months. You experienced that all the time. “Why is it north of the 49th, you have breakup, and south of the 49th, you have nothing?” he posed. Indeed, North Dakota does not shut down for breakup like Saskatchewan does. For a brief period of time, in 2006-07, we got to a high utilization in the summertime, Heier said. “Your highest utilization should be June, July, August, September; not December, January, February, March. That’s the most expensive time to drill wells in the year, in the win-
tertime. And that’s when most things got pushed, because of those inefficiencies in Calgary. I will call a spade a spade on that one. It was horrible.” Future play? In addition to subsalt, another area Heier feels there’s potential for in Saskatchewan is the Porcupine Hills in northeast Saskatchewan. While there’s been a very small amount of wildcatting in the region over the last decade, nothing has come of it. “There’s big resources plays up there that, only now, people are starting to talk about doing stuff. And they’re not that deep. But it is a different type of resources that requires chemical re-
actions because the oil isn’t really fully cooked yet. “Some is strip-mineable. Some they might chase as deep as is 200, 300 metres. I know some people working on that stuff up there. But as the saying goes, nobody saves the best for last.” “It’s a big play. It’s a massive play, but it requires consistently higher oil prices with consistently better technologies brought to the table. We’ll see. Over time, all hydrocarbon resources will be accessed one way or another. What would he build today? If he was to start again today, what would Heier build?
“They would be deeper, heavier rigs. Go look at what Trinidad was primarily focused on building from the mid-2000s to 2014. They had some of the biggest land rigs on the planet, with automation taking people out of harms way and improving the cased hole cost of the wellbore.” Globally deployable, pad-capable, umbilicalequipped walking triples with three 1,600 horsepower pumps, with 1,000 horsepower top-drives running Range 3 tubulars are the global hot rod, he said. Rigs with those specs could access 90 per cent of the resources on the planet. For Saskatchewan, he said, a few more heavy
rigs could come into play for subsalt plays doing extended reach drilling. “You’ll want to drill any pool that you find and produce established reserves as soon as possible to reduce wellbore collapse risk in the salt,” he said. “You might see more top drives on the heavier rigs. The shallower rigs, you won’t see any changes,” he said. Range 3 singles with top-drives likely won’t change much. For western Saskatchewan, he doesn’t see a lot of changes. There might be a little more pump capability, a little more control of downhole tools. “Not a lot more sophistication. There’s nothing to warrant doing it.”
By Brian Zinchuk Estevan – Derrick Big Eagle spent much of his life around drilling rigs. That included building and eventually selling his own rig outfit, Eagle Drilling Services, which had eight rigs. All this means he has a unique perspective when it comes to analyzing the massive contraction in Canada’s drilling rig fleet, from 811 in Oct. 2014, to
515 today. It could potentially drop another 100, according to the Canadian Association of Oilwell Drilling Contractors, or CAODC, in a recent interview. Pipeline News quizzed Big Eagle about his thoughts on the drilling fleet on Oct. 24. A lot of this contraction has to do with the fact that drilling rigs have
become much more efficient. For instance, when asked how long it took to drill a Bakken well around Stoughton in 2008, Big Eagle said, “We were drilling them in seven to eight days.” “The first Bakken horizontal took 36 days.” Now, he said, “They’re down to five, five and a half. “Everyone’s pretty close now. You’ve still got
a few of the guys that are still running their old rig that they have before because they’ve used them for 10 years. But could they be more efficient? Absolutely, they could be.” Asked what has made the biggest difference in improving efficiency, Big Eagle replied, “The understanding of the PDC (polycrystalline diamond cutter) bit. The PDC bit
came in as new technology for everybody. It took a while to figure out. And once a few people did trial and error, did a little research and development on drilling techniques and procedures, they figured out they could push it. “Everybody thought it was just pump, pump, pump, and put the volume to it, but was really the drill bits that sped things up.
“And, the competitiveness. If you want to work, you’ve got to be the fastest.” There are many rigs in Saskatchewan, and throughout Western Canada, that have been sitting since the downturn hit five years ago. Many more have been sitting even longer. Asked what he would look for if he were looking to buy and reactivate a “cold ► Page A11
Big Eagle reflects on the contraction of the drilling rig fleet
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Once a rig has been sitting for five years, as many have, they’re going to need a lot of work to get going again ◄ Page A10 rig,” Big Eagle said, “Rig up time is No. 1. Is it set up to be rigged up and moved quickly? All of these (in southeast Saskatchewan) pretty much are. “I would want to know the last time everything was turned, everything was fired up. When was anything pumped through the lines? Because now you’ve got everything full of rust. That’s including air lines. How do you get the rust out of air lines? You’re really taking a chance.” If rotating gear has been sitting a long time without being turned, he explained that bearings can actually deform. He said, “Let’s say you’ve got a pump, and the bearing it is sitting on. This gear weighs 25,000 pounds, sitting on a couple of bearings. Eventually it’s going to squash them and make them flat. Now you’ve got to turn them and there’s a flat spot
on that bearing. Knock knock knock. The bearing wears out, and you’ve got a chance of wrecking the whole inside of that pump. Now you’ve got shavings in it. “Turning the equipment is really important. Seals, O-rings, air hoses, air lines. The elements are going to rot out the air lines and hydraulic lines.” The weather combined with sitting is the problem. The depreciation, he said, is, “huge.” One larger company, he noted, has a person whose job is to go around to their idle rigs and rotate everything that can turn, every few months. Cannibalization Then there’s cannibalization of rigs to keep others going. “It was the angle everyone was left in. When you’re working for $500 a day profit on a $9 million drilling rig, you’re not go-
ing to go to the store and buy yourself a $2,000 hose 2-inch hose, just because it makes it a little easier. You’re going to go to one of your rigs that you’ve got shut down and you’re going to take parts off of it because your trying to survive like that. “Unless you’ve got the ability to keep the rigs working. Then you don’t want to steal from another rig, because if you steal from another rig, you’ve got to replace it to get it going again. So, you have to be in a mindset – am I only going to run 60 per cent of my rigs? And there were companies that did that. “But you have to draw the line in the sand.” Is there a line where a rig’s been sitting too long? “I think if there’s been a four to five year sit, you’re going to have a pile of problems hit you in the face when you start it
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up. Two years time; a little bit of rust here and there. You’ve probably got a little more time before bearings become flat. But you’re still going to have hose issues. “Five years? You’ve almost got a full retrofit. Past a Level IV. You’re going to have change hydraulic hoses, air hoses.” The CAODC recently increased the interval for a Level IV inspection from 1,000 operating days to 2,500 operating days. Big Eagle doesn’t agree with that, saying the operating pressures are so high now, there’s too much risk for intervals that long. “The rigs are being run twice as hard as they used to be. I 100 per cent disagree.” And then there’s labour “How are they going to draw the people back? You can get the rigs going, but what’s going to be their draw?” Big Eagle asked. “Look at the evolution of technology over the last 10 years. Do you think a 25-year-old drilling consultant out of SAIT is going to want an old jackknife rig? Or he’s going to
Derrick Big Eagle has been around rigs much of his life. This photo was taken in 2010, when Eagle Drilling Service’s Rig 7 was coming together. Not many new rigs are being built these days. File photo want something pre-2010? Not a chance. They want new. They want technology. They want data.” Old school rigs don’t see much usage, he noted. The ultimate fate of an old rig is to be cut up for scrap. He noted larger drilling companies routinely cut up their old rigs. “There’s more value in eliminating a competitor, buying it, than what you get for scrap,” he said.
Is there a foreign market to take some of these idle rigs overseas? Big Eagle said there’s some interest. “I don’t think any have been successful,” he said, noting Alberta has hundreds more rigs to choose from, and they’re closer to a port, making those rigs more attractive. The whole fleet in Canada is overbuilt. “We’ve got too many,” Big Eagle said.
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PIPELINE NEWS February 2020
The rig fleet has shrunken dramatically, but Betts Drilling is a survivor By Brian Zinchuk Carnduff – During the boom years there were several small independent drilling contractors making hole in southeast Saskatchewan. But five years of downturn have caused several to shut down and be absorbed. Even then, a lot of the iron those small independents were running has spent much of the last five years racked. Betts Drilling of Carnduff has been one of the survivors. Canada is producing more oil than ever, but over the last five years, the drilling fleet has dropped by almost 300 rigs and may drop another 100. Asked what’s happening, Bob Betts, general manager, said on Jan. 17, “I think the older equipment’s getting parked, and I guess everybody that’s built newer equipment, those rigs are taking precedence. Those are the ones that are working. Of the 500 rigs out there, those that are working are the newest ones.” Indeed, by late January, Rig Locator was reporting 52 per cent of the remaining fleet of 515 was at work. Betts Drilling’s four rigs are among the newest in Saskatchewan. Rig 4 was the last new rig built before DoAll Industries shut down. “I think we were probably the last ones to build in Saskatchewan before the bot-
tom fell out of the market,” he said. “If you wanted to build a new rig, you might have to go to the U.S.,” he said. “You might be able to pull some guys out of Alberta to pull it off.” The CAODC says the number of new rigs built, in the whole country, is less than 10 in the last five years. Are we losing our industrial capacity to build new rigs? “I would say yes,” Betts said. He was recently talking to a top drive provider, and found out there was no one available to build a hydraulic pump unit for them. “The wait time to have something like that built is crazy right now.” They’re thinking about getting a top drive. “Our business plan was always to add a top drive to one of our rigs,” Betts said. “Somewhere along the line, we’ll probably add one. But the way the industry is right now, we’d probably have to land a job with it beforehand.” Top drives have been the trend through much of the industry, but southeast Saskatchewan is still largely dominated by kelly rigs. “The thing with a top drive is it’s $1.7 million to put it on your rig, and the oil companies won’t pay for it. You can’t charge extra for a top drive, is what I’m seeing right now. So if you can get
a rig with a top drive, for the same prices as a kelly drive, why wouldn’t you?” He said adding a top drive adds an extra engine, increasing fuel costs and carbon footprint. “You’re drilling the exact same wells in the exact same time, but you’ve added to your AFE because of the extra fuel,” he said. “It’s a hard decision to make, to add a top drive to a rig.” A top drive also adds another load to the rig move, and adds weight to the derrick load. He would like to do further analysis on the numbers between a top drive and kelly rig, but so far, he’s not convinced. Automated pipehandling, sometimes referred to as “iron roughnecks” (actually a trademarked name), is another trend. To that end, Betts was a leader before his time. The previous company he ran, Totem Drilling, had them installed on their rigs, but they were not successful. When CanElson Drilling bought those rigs, they removed the automated pipe equipment. “I tried to get them in, but I couldn’t get the oil companies onside,” Betts said. “To get the guys safer on the floor takes an extra 30 seconds of time to make a connection, and I couldn’t
get anybody to side with that. That 30 seconds was too much time to make a connection. In saying that, in four years time with iron roughnecks, we never had a lost-time accident. The technology is definitely there to make it safer on the floor.” “It was a hard sell,” he said. “I’ve got one rig going right now, and a couple more going out in February, but January’s been a tough month for us. December wasn’t too bad, we were pretty steady through December, but you could tell it started to slow down in December. All four of their rigs are “warm,” in that they are capable of going to work right away, and have been working. Many rigs in the region have become “cold,” parked for five or more years. There’s corrosion and rust.
By Brian Zinchuk Carnduff – With the drilling rig fleet in Canada having contracted by 300 rigs, and likely more in the coming years, that can be a real problem if your business is built around moving rigs, like Fast Trucking Service of Carnduff. Dennis Day, president, said they recognized the contraction early, and moved quickly to address it. More recently, they’ve diversified both geographically and in service lines as additional
measures. In the last year, two operations were bought into the Fast Trucking Service group of companies, each in their own way, which allowed the core company to keep more of its people and equipment working. “Since ‘05 we bought eight companies out, and they’ve all expanded,” Day said on Jan. 17. They didn’t buy Swift Current’s Dynamic Heavy Haul, per se, but rather hired all their staff, bought a good
chunk of their equipment, and took over the rent on the shop. “We really didn’t take the company over, but I hired all their men. When they sold their stuff at the auction, I bought a bunch of it back,” he said. That meant hiring 35 people and bringing them under Fast Trucking. Basically everyone except the previous ownership came over to Fast. Some iron from Carnduff was sent to Swift Current to work.
“They do quite a bit of service work, moving frac tanks, hauling tubing, stuff like that,” he said. This took place just before the 2019 Saskatchewan Oil and Gas Show in June. The Swift Current operation is primarily rig moving and service work. There are usually around five to six rigs working in the Shaunavon area. That many not seem like a lot, but those rigs are usually some of the most consistent working rigs in the Saskatchewan fleet.
Betts Drilling’s rigs are “warm,” and able to go to work, whereas many rigs in southeast Saskatchewan have sat for five years now. Photo by Brian Zinchuk A cold rig’s certifications will have expired, he noted, pointing out that a blowout preventor system (BOPS) needs to be recertified every three years. The Canadian Association of Oilwell Drilling Contractors has changed the intervals for Level III and Level IV inspections, with a Level IV moving from 1,000 operating days to 2,500. Betts supports that, as he said, “It’s great news for us. We can actually see where the equipment can wear out. You’re not changing equipment because someone put on paper 1,000 days. You can see when equipment will break down and you can adjust accordingly. And it’s a cost savings for everybody. “We still do our 250day inspections, and if something breaks down, you’re fixing and repairing it
instantly.” Asked what the life expectancy should be for a rig, he said, “If you keep it up, if you do your inspections, you should be able to get 50 years out of your rig, if you look after it. The paint’s come a long ways with Enduro paint, so corrosion isn’t getting to it like it used to.” He said they’ve been fortunate to have a lot of loyal customers that have been with them for years and year. “That’s what’s keeping us alive, our loyal customers.” “I think we still have an advantage over the bigger companies. If there’s a problem with the rig or anything, they just phone one number and get right to me. They don’t have to go through a bunch of loopholes to get the problem fixed. It gets fixed almost instantly.”
When you have fewer rigs, you have fewer rig moves While it was a bit sluggish for September and October, it’s since picked back up. “It’s busy out there now,” Day said. “We’ve got two rigs moving here, today, but three rigs moving up there (in Swift Current) today. So we’ve got some Fast guys from here (working there). So it helps the guys and helps the customers, too.” The operating area is south of the South Saskatchewan River, from Regina to the Alberta border.
Cara Dawn The second operation picked up in the last year was Cara Dawn Transport Ltd. out of Regina. Dave Wellings was the owner. “He’s been a buddy of mine for years. He phoned me and said you should take this company over,” Day said. “There was 40 people there, too,” he said. He had to move quickly in July, because other companies were trying to hire ► Page A13
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PIPELINE NEWS February 2020
The reduction of the drilling rig fleet has spinoff impacts ◄ Page A12 those men away. “I told these guys in July I would be taking over and buying some of the equipment back.” All the staff stayed. He went over to his friend Lenny Janz, who was working with a truck dealer in Regina, to talk to him about it. Janz asked who was going to run it, and Day said, “You.” Cara Dawn specializes in long distance heavy haul, with oversized loads being their specialty. “The reason we bought it was he has all his permits in place, and whatever you need to cross the border for hauling heavy equipment. That was something Fast didn’t have. So whenever we have a big job, we can lease our trucks (to Cara Dawn). Cara Dawn had an auction in its yard in October. “I just bought what I thought we needed,” Day said. This meant retaining about 70 per cent of the trucks and about 40 per cent of the trailers. But now some Fast, Sam’s, and Competition Trucks are working with Cara Dawn, leased on as needed. This was a way
to put men and equipment to work that otherwise may have been idle. It works the other way, too. “Today, for instance, there’s five Cara Dawn trucks in Swift Current helping the Swift Current guys move rigs today.” It was essentially a diversification out of the oilpatch. “Big time,” Day said. “I’m not operating against people doing flat decks, working for nothing. This is all specialty stuff. They haul D10s. We just hauled a Cat 24 grader that weighs 240,000 pounds. We’ve got 60-wheel trailer combination.” Another reason Fast took them over Cara Dawn is the fact it does a lot of work associated with Ritchie Bros. auctions. That’s a natural fit. “We are huge supporter of Ritchie Bros. sales,” he said. There’s a lot of work hauling items to sales and away from them. Contraction of rig fleet Dennis saw the writing on the wall with the oil price collapse at the end of 2014, and he talked to his father, the late Tony Day, about it.
“I saw it right away. I went and talked to Tony about it in January of 2015 and said oil is going to US$40 a barrel, and we might as well sell at least a third of our older fleet, when the prices are still reasonable at the auctions, and the next four or five years, we’ll be buying new stuff at half price. “That’s exactly what happened,” he said. He said in early December 2014, he warned their staff, “Oil is US$68 a barrel, and it’s going down to the low 40s.” He saw a contraction of the fleet in the 1980s, and again in 1998. “You’ve got to look at ’85, ’86, there were 40 rigs working here. That was a pretty big boom. And then it went down to 20, and then it went up with the Bakken play.” He showed a sheet from 2008, with 73 rigs working in southeast Saskatchewan and southwest Manitoba, combined. And many of the companies on that list no longer exist. “Lakota’s no longer around.
Rigs have been racked by the hundreds, and most will never work again. Photo by Brian Zinchuk There’s no Totem, no Eagle, no Red Dog. There’s no Trinidad anymore, because Ensign took them out.” “Out of 16 companies in 2008, eight of them, half of them, are non-existent,” he said. Many rigs have been sitting since the downturn hit. “The sad thing is, those engines are worth a lot of money. But you keep thinking, in a month it’ll go to work. Next year, it’ll go to
work. After road ban, it’ll go. And it just kept going.” A fleet that’s shrunken by half only needs half as many rig movers. “Or less,” Day said. There’s 30+ rigs working in southeast Saskatchewan and southwest Manitoba. “If we can stay like this, it won’t be too bad,” he said. “We’re about the right size, because 15 of the trucks that were parked out back went to Swift Current. An-
other six are working out of Regina.” The first quarter looks good for Fast, and Day has been encouraging oil companies to do more work in the second quarter. It hasn’t been wet in the region in the second quarter for six years, he noted. There’s quite a bit more pad work, he said, but pad drilling means much less in the way of rig moving. ► Page A14
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PIPELINE NEWS February 2020
Offset frac monitoring offered by Level Best Estevan – Estevanbased Level Best Technologies has recently launched a new service that complements their bread and butter fluid level monitoring business. It’s called offset frac
monitoring. Dave Gallaway explained, “When they’re fracking a well in a field where there’s existing wells, they want to make sure they don’t damage the nearby wells, the ad-
jacent wells, whatever you want to call them. “When they’re doing the frac, they’ll shut those wells off and put equipment on to monitor the pressure on those wells. “That equipment has
Not much of a market for older drilling rigs ◄ Page A13 “There’s lot of multiple pads now. We’ve really seen that since the downturn, more pad work, from here to Alberta. There’s a lot of pad work in Swift Current. We have two moves tomorrow, and they are skids. “None of the rigs here walk. They just skid them. But it only takes a truck push, one bed and a tractor to usually move it. So instead of sending eight trucks to move a rig five miles, you’re sending three, and instead of getting eight hours, they’re getting four-and-a-half hours. Rigs for sale but not moving Tony Day had started buying rigs in the 1980s,
and they wheeled and dealed in that market for many years, through ups and downs. “We could buy cheaper than anybody else because we had the trucks to haul it,” he said. There’s about a dozen rigs in the yard for sale. The most recent acquisitions, made in Houston, didn’t work out as planned. “I thought we could flip it, but we didn’t,” he said. Some were bought back in 1997-1998 for scrap iron price, and then sold as a premium. But others were purchased, and haven’t sold. Some might end up as scrap. “In the last few years, everything’s changed. People want top drive
rigs,” Day said. “It’s all saleable, but there has to be demand.” “Most of the rigs are super singles or tele-doubles around here,” he said. “It seems like the ADR (advanced drilling rigs) and tele-doubles have more of the market, because that’s what was being built. “I’ve already got a surplus of equipment. I don’t need to buy anymore,” he said. There’s not much of an overseas market for older rigs, either, he noted as they are often looking for bigger rigs. “I’ve had guys come from Dubai, Russia, come look at rigs here. I’ve sold some trucks to Russia, but not any rigs,” he said.
communication on it so it will call out if there’s a bump in pressure,” he said. “It’s a pressure sensor.” It mounts on the casing side of the well via a screw-on fitting. “If you did have communication from your frac to that well, you could, right away, shut down your frac and stop pumping any more pressure to it,” Gallaway said. The gauge is programmed with two threshold levels. It will send a text or email within seconds, but that’s dependent on your cellular coverage. “We set it up so your frac operator and engineer and whoever wants to monitor it can receive a text or email or both, and they can watch it on a graph from the cloud. It will show what the pressure is on that well. Typically, you won’t see any change. But you don’t want to see any change, either,” Gallaway explained. These offset monitors would be set up on your wells and competitors’ wells up to a mile away. Typically the company
who is fracking would ask their neighbours to shut in their wells while the frac is going on. “They don’t want communication from one well to another,” he said. The sensor is equipped with a solar panel, pressure monitor and cellular
modem which sends data to a cloud-based system. “I just started doing it in the last few months,” he said. “So far, it’s been pretty good. It’s something new and different to add to our toolbox. It doesn’t take a lot of manpower.”
The black cylinder is an offset frac monitor, as used by Level Best Technologies. Photo submitted
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PIPELINE NEWS February 2020
Sask government’s take on the declining number of drilling rigs By Brian Zinchuk Regina – Saskatchewan is producing roughly the same amount of oil, 501,000 bpd, with about 30 to 40 per cent fewer rigs at any given time compared to five to ten years ago. Pipeline News asked the Ministry of Energy and Resources what this means for Saskatchewan, and received this email response from Minister of Energy and Resources Bronwyn Eyre on Jan. 23. Pipeline News: We’ve seen the drilling rig fleet in Canada drop from 811 about five years ago to 515 today. The Canadian Association of Oilwell Drilling Contractors thinks it could go closer to 400. Even with these reduced numbers, only half the fleet is working in Canada, during the busy season. PSAC recently forecast a 10 per cent reduction in wells for 2020, from 5,000 to 4,500. Yet Canadian oil production is growing and Saskatchewan oil production is relatively flat. Are rig counts and wells drilled the metrics we should be using today? Bronwyn Eyre: As of mid-January, 57 of 105 oil rigs were working, which is a utilization rate of 54 per cent, compared to Alberta’s 48 per cent and BC’s 45 per cent. Even though drilling numbers remain depressed for Western Canada, oil production is still growing due to oil sands production and increases in technology that drive production, independent of numbers of wells
drilled—for example, waterflood projects, Saskatchewan steam assisted gravity drainage (SAGD) projects and other types of enhanced oil recovery (EOR) projects. Rig counts and wells drilled are still important metrics, however, for production levels, employment and capital investment. P.N.: What metrics should we be using, going forward? Is metres drilled now king, over well count or rigs working? Or should we just look at final production numbers? Eyre: All these metrics are important factors when looking at the oil industry and should all be considered when reviewing the state of the oil industry in Saskatchewan, but the number of waterflood and EOR projects planned impact overall investment and production levels as well. For instance, CAPP’s data include investment in EOR. Our government also has set targets in Saskatchewan’s Growth Plan: The Next Decade of Growth 2020-2030, one of which is growing oil production to 600,000 bpd by 2030. P.N.: In Saskatchewan, six to ten years ago, we would see around 100105 rigs working. Today, it’s 65. Yet we’re producing roughly the same amount of oil. Can you explain what this means, from a government perspective? Eyre: Oil well drilling over the last couple of years became more ef-
Saskatchewan steam assisted gravity drainage (SAGD) projects like this one, seen north of Lashburn in 2018, are having an impact on oil production. Pad drilling, like what is seen here, has become increasingly common. File photo ficient with the move to longer horizontal sections and continued optimization of fracs, including the re-fracking of existing wells. The trend is similar to the initial move from vertical wells to horizontal wells, where one horizontal well could be drilled instead of multiple vertical wells, leading to fewer overall wells being drilled to produce the same amount of oil. We are seeing a greater emphasis on secondary (such as waterflood) and tertiary recovery (such as SAGD) which require fewer new wells to be drilled to produce the same amount of oil and an increase in the number of wells being converted to injection for the purpose of waterflooding the reservoir. Saskatchewan’s Waterflood Development Program (WDP) was established in December, 2019 to encourage the conversion of these injection wells, and the program started taking applications in December.
P.N.: There are hundreds of racked rigs, dozens of which are in Saskatchewan, many of which have been that way over five years. Do you expect any of those rigs to work again? Eyre: Our Government is hopeful that all of these rigs will be working again. The government has introduced programs such as the Saskatchewan Oil and Gas Processing Investment Incentive (OGPII), the Saskatchewan Petroleum Innovation Incentive (SPII) and the Waterflood Development Program (WDP) to help spur in-
vestment in the province, in addition to our stable and competitive royalty regime. P.N: Is there anything you would like to add? Eyre: Saskatchewan remains one of the top destinations in North America for high return oil production investment across many different plays and grades of oil; the Growth Plan’s oil production target and its many related commitments show that the Government of Saskatchewan is focused on taking steps to continue to help the sector develop and flourish. For example: The Scotiabank 2019 Playbook – A
Ranking North America’s Oil and Gas Plays, ranked Southeast Saskatchewan’s Mission Canyon Frobisher/Alida oil play as the No. 1 oil or gas play in North American based upon its leading metric of Profit Investment Ratio. Saskatchewan has two of the top 20 ranked plays in 2019 (Southeast Saskatchewan Mission Canyon Frobisher/Alida No. 1 and Southwest Saskatchewan Cantuar No. 7) compared to of the top 20 plays in 2018 Playbook. Saskatchewan has seven plays in the top 35 in the 2019 Playbook.
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