Brian Zinchuk is editor and owner of Pipeline Online
This is basically how multi-lateral wells look. While the drilling rig is not to scale, this is a representation of what they look like underground. Now imagine these with laterals two and eventually three miles long. This example is from northwest Saskatchewan near Waseca, courtesy Chinook Geosteering. Check out their LinkedIn page to see plenty of graphics much, much more intense than this one. Photo illustration by Brian Zinchuk
Editor’s note: My stomach has been tied up in knots for months as to whether I should write this story. In Saskatchewan, most of the oilfield jobs are in the oilfield services. And I’ve had more conversations than I can count as to “why things are slow.” It’s not just oil prices, which aren’t great. There is a major technological change that is happening that is impacting much of the industry. I finally decided people need to know what is actually going on in as fulsome way as possible.
I’ve always told my kids, “Do you want me to sugar coat things or tell it to you straight?” They’ve always wanted it straight. So that’s what I’m doing here.
ESTEVAN – Change, specifically technological change, may be the one constant in the universe. If not the universe, at least the oilpatch. And there’s a major change that’s been taking place in drilling in recent years that could easily be considered “the next big thing.”
That would be large-scale multi-lateral wells, also known as open hole multi-laterals, (OHML).
Multi-laterals have been around for decades. Back in 2009, for instance, PetroBakken’s standard well design was a two-leg well. Other well designs going back many years before that had numerous legs, or laterals, as well. But the recent developments are much, much more extensive.
If a vertical well is represented by a dot on a map, and a horizontal well is a line, the current large-scale multi-laterals are essentially taking a crayon and filling in the square, with many laterals and often extended length. Their impact is being felt, especially by the oilfield services dependent on new drilling.
To be blunt, they’re hurting, badly. And as this new well design is increasingly adopted, it doesn’t look like things will turn around for those services any time soon.
It’s a technique that has seen massive adoption in the Alberta Clearwater play and in other basins and has now spread to Saskatchewan.
This story is the result of numerous conversations over many months from a very broad range of the industry, all the way from titans of the oilpatch to ancillary industry players. I’ve spoken to several oil company CEOs, drillers, and a wide variety of oilfield services. In nearly every instance, I’ve asked, “Am I full of it? Tell me if I’m wrong.”
And the universal answer has been, “You’re not wrong.”
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Incentives
It’s been over a year since Saskatchewan implemented its Multi-Lateral Oil Well Program, and the impacts being felt may not be what the province has been seeking.
At the time it was announced, then Minister of Energy and Resources Jim Reiter noted it was expected to open up areas that otherwise likely would not be developed. And to an extent, that has indeed happened northeast of Stoughton in the halo of the Bakken play. It’s notably also reinvigorated cold heavy oil production in the Lloydminster region.
But multi-laterals are rapidly becoming the standard in the fairways of major plays, such as the Frobisher. Their benefits, as laid out below, make them the obvious next evolution of drilling. And the incentives, in place for four years, dramatically improve the economics that can make up most if not all of the cost of drilling that well.
One of the goals of the program was to increase oil production by 50,000 barrels per day.
On Sept. 28, there were 34 active drilling rigs in Saskatchewan. One was drilling of potash near Esterhazy, another for helium south of Pontiex. The rigs working closest to Lloydminster are likely drilling mutlilaterals, as well as most of the rigs in southeast Saskatchewan. RiggerTalk.com
Despite broad adoption of large multi-laterals, the rig count has not picked up. As of Aug. 25, according to RiggerTalk.com, there were just 11 drilling rigs working in southeast Saskatchewan. In southwest Saskatchewan, just one rig was working, and it was drilling for helium. Six rigs were working in west central Saskatchewan, and 10 in the northwest. That’s just 28 in total, a low number for this time of year. On Sept. 16, there were 36 rigs working across the province, with 15 in southeast Saskatchewan, two in the southwest (one helium), six in west central and 13 in northwest Saskatchewan.
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Oil prices in the low US$60s have certainly been a large factor in low drilling numbers, but it’s not the only factor.
Secondly, overall oil production in Saskatchewan has not seen a notable uptick, either.
According to the Government of Saskatchewan’s online dashboard monitoring numerous economic metrics, oil production has been largely flat since the spring of 2021. But those numbers are just starting to show the impact of the loss of two SAGD plants at Rush Lake due to a blowout that occurred in early May. If both are shut down for good, the 32,000 bpd impact will mean a loss of roughly seven per cent of Saskatchewan’s total daily oil production.
Saskatchewan oil production from April, 2021 to June, 2025. Saskatchewan Dashboard, Government of Saskatchewan
The Dashboard numbers reflect that loss. In March, 2025, daily production averaged 454,763 barrels per day – the highest point since the multi-lateral program began in the previous year, but just barely. It was essentially flat compared to the previous August, October and December numbers. That 454,763 barrels per day was also prior to the Rush Lake blowout. June production numbers came in at 420,330 barrels per day, reflecting almost exactly the loss of Rush Lake 1 and 2.
Minister of Energy and Resources Jim Reiter on April 30, 2024, announcing the Mult-lateral Well Program. Photo by Brian Zinchuk
When announced by then-Minister of Energy and Resources, now Minister of Finance Jim Reiter, it was anticipated the Multi-Lateral Well Program would lead to a growth of 50,000 bpd over the four year term of the program.
Under the Saskatchewan program announced in the 2024 provincial budget, there are two well designs that are applicable. The first is a pitchfork design. To maximize the benefits of the program, it needs at least five laterals a minimum of 500 metres in length. To max out the fishbone design, you need at least 10 laterals a minimum of 200 metres in length. Doing so in either case will result in the first 16,000 cubic metres of oil produced (100,637 barrels) seeing a royalty reduced from around 17.5 per cent to 2.5 per cent. If that full volume is produced, based on a US$70 WTI barrel, the amount of foregone royalties would total around $1.5 million. In many cases, that largely covers the capital cost of the well.
Image courtesy Chinook Geosteering Services, using publicly available data. This shows both the pitchfork and fishbone design, as seen in northwest Saskatchewan.
Adoption has indeed taken place. In February, Pipeline Online visited five rigs drilling in the Lampman area in one day, and three were drilling multi-laterals. Some companies have announced wells that have legs two miles long in southeast Saskatchewan, and three miles long in the Montney area. One company has now drilled a 2.5 mile multi-lateral in southeast Saskatchewan and is piloting a 3 mile well. On Aug. 25, the RiggerTalk.com map showed two rigs working near Lloydminster in an area that had seen little activity for about a decade.
But overall drilling has not grown much at all, nor has production. If anything, Saskatchewan is just treading water on both, if that.
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A well per week per rig, but not anymore
For most of the last 17 years, the southeast Saskatchewan oilpatch has been based on a typical drilling rig drilling a typical well in about a week. While that number has fallen to six days in many cases, let’s say a week to round things out. That means for every active drilling rig working, four times a month a new pad would be built by earthmovers after having been surveyed by the land surveyors. The rig movers would move the rig four times. Trucking firms would haul out four loads of casing. Casing services would run casing four times. Cementers would cement four wells. Service rigs would do four completions. Four pumpjacks or other artificial lift systems would be installed. Electricians and instrument techs would wire in those pumping units. Pipeliners would build a flowline. Eventually four leases would be cleaned up into teardrops.
A drilling rig in southeast Saskatchewan in early March. Photo by Brian Zinchuk
Now if a multi-lateral takes a drilling rig a month, that means each of those operations happens just once per month per active drilling rig – potentially up to a 75 per cent reduction in activity for numerous oilfield services. That’s a four-to-one reduction from just a couple years ago.
But now these multi-laterals are taking a month, or more. And they’re getting larger in number and longer in length. Pipeline Online has seen reports of up to 15 long laterals in a well. And as mentioned above in other cases, laterals that are up to two miles long. But three mile laterals are becoming common in other basins, and are certainly on their way here.
This is the heart of the Viewfield Bakken, just two miles west of Stoughton with Highway 13 on the north edge. Count all the wells in this two-section block highlighted in yellow. Half of those wells cover the other side of the road. The remaining are within these two sections. It is now possible to essentially replace all of those wells with just one, singlular open hole multi-lateral with two mile-long laterals. And three mile-long laterals are on their way, which would add one more section. In this case, there are 23 lease pads within that block (not counting the ones on the north side of the road). Similar exposure to the reservoir can now be done with just one lease pad. Google Earth.
As seen in the Google Earth image above, if you took a drive down Highway 47 or 13 near Stoughton during the Bakken boom days, you’d see a couple of wells every 400 metres or so – one going one direction for a mile, one going the other direction. But that meant for a section of land, it would be common to see four wells on four pads covering that section. But with two-mile long laterals, and lots of them, it is now possible to cover not one section, but two, from just one singular vertical wellbore. That means instead of eight wellbores and eight pads covering those two sections ten years ago, you’re looking at potentially just one vertical wellbore on one lease pad. That’s potentially a reduction of as much as eight-to-one.
If three mile laterals should become prevalent here, that could result in a 12-to-one reduction, or 92 per cent, from roughly 15 years ago.
As Pipeline Online has warned government officials numerous times over the last two years, unless more rigs get drilling, we could end up looking like the Newfoundland cod fishery.
What Pipeline Online has heard in recent months from numerous aspects of the industry is “how slow it is.” Everyone from dirt movers to electrical to casing to hotshot and trucking. And it’s being felt beyond the oilpatch – to auto dealers, for instance.
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This is an example of Bakken development near Stoughton, with a pad with two wells every 400 metres. One well went east, the other west, in this example. Now the area covered by eight, and possibly soon up to 12 of these wells could done with just one large open hole multi-lateral well. Photo by Brian Zinchuk
Pluses
There are pluses and minuses, winners and losers. The biggest winners are the oil companies, for whom some consider the Multi-Lateral Oil Well Program to be a game changer. Name another business that has seen a four-to-one or eight-to-one reduction in expenses to do essentially the same thing it was doing 15 years ago, with essentially the same equipment. It’s like taking a 2009 F-150 that got 20 miles to the gallon when you bought it, and now getting 80 miles to the gallon, with the same truck.
In northwest Saskatchewan, multi-laterals have reinvigorated cold oil production in the Lloydminster region. Little cold heavy oil production drilling has taken place over the past decade compared to years past, as very expensive thermal plays have become the focus. If you want to build a SAGD plant, plan on anteing up a quarter to a third of a billion, or more, for just one site.
Big multi-laterals allow much smaller players, with smaller chequebooks, to drill and produce heavy oil that was otherwise largely stranded. The technique also eliminates the sand production that was formerly characteristic of cold heavy oil production, dramatically reducing costs.
After a very tough decade, the drilling companies benefit from more drilling days per well. Fewer rig moves means less wear and tear on the rig and its equipment. But it’s not all sunshine and roses. If you can accomplish so much more with one drilling rig, that may mean less (or no) work for other rigs in your fleet. And indeed, the Canadian drilling rig fleet is already a shadow of its former self, with hundreds of rigs retired and cut up across the basin (admittedly, before these big multi-laterals became a thing.)
Directional drillers and measure-while-drilling also get a lot more days per well, as do landspreaders and water haulers.
From an environmental perspective, this is a huge reduction in the footprint of oil production, with dramatically less land disturbance. For the farmers, it means far fewer leases to drive around, but also far fewer surface lease cheques.
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Minuses
But as listed above, for surveyors, environmentalists, lease builders, rathole drillers, rig movers, BOP certification, casing hauling, casing running, cementers, service rigs for completions, pipeliners running flowlines and tie-ins, artificial lift (pumpjacks, progressing cavity pumps, etc), electrical and instrumentation, generator rentals, lease maintenance, and more, it’s a gut punch.
This also comes at a time when oil companies, facing lower oil prices, are still continually putting pressure on their service providers to lower prices. For many of those service companies, under strain from dramatically reduced activity already, cutting prices any lower would mean having to cut employee pay. That’s an unpalatable option when it is hard enough to attract staff in the first place and inflationary pressures impact both staff and the companies they work for.
Alternatively, they may have to close their doors. What is clear is you can’t have a 75 per cent reduction, or more, in activity levels and not see a contraction within the sector. “Efficiency” in this case means fewer companies and fewer jobs. Those oil companies seeking lower rates may soon find in some sectors there will be few, if any, service companies left to pick up the phone when they call.
This contraction did not happen overnight. Drilling rigs from 2012 to 2022 had already basically more than doubled their productivity, working more than half the fleet out of a job. The progression has been continual and gradual. But the advent of these big multi-laterals may prove to be a step-change for much of the service industry.
As one person who runs an oilfield services company described the feeling “like someone’s getting slowly choked out here and it’s shrinking. I mean, the oxygen is running out quick.”
The decade of darkness has not ended, and indeed, could be getting worse for many oilfield service companies.
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