​Canada’s drilling fleet is overbuilt, says Trinidad founder

Trinidad Drilling founder Mike Heier calls rigs like this “Singles on steroids,” running Range 3 pipe. Image: Brian Zinchuk/Pipeline News

Trinidad Drilling founder and former CEO 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.

“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 Of that, one third should have been scrapped, another third were outdated," said Heier.

Before being taken over in 2019 by Ensign Drilling, Trinidad had grown to be Canada’s third largest drilling contractors.

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 tri-cone bit, whose roots run back to 1933 and Sharp-Hughes 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 tri-cone bits, and the odd diamond bit,” he said. “Cones would roll. Teeth would crush mother earth, and 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 1999-2000, 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 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 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 gel-based 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 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 back-reaming 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 essentially 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 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 freeze-thaw 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 entire 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 mid-sized 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 not-invoiced 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 client-management 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 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. Committed 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 wintertime. 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 reactions 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, umbilical-equipped 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.”

– Pipeline News

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