Skip to content

Getting into the deep thinking behind drilling and shut-in decisions

Caprice Resources’ Michael Mainil explains thought processes
Michael Mainil
Michael Mainil is vice president of Caprice Resources when he's not on the curling rink.

Weyburn– When oil prices drop over 70 per cent from what the industry has become used to over the last five years, there are a lot of considerations for oil companies as to what they should do now. This is especially important for junior oil producers, small operations were individual wells make a difference.

On Feb. 17 Pipeline News spoke to Michael Mainil of Weyburn-based Caprice Resources Ltd., a longtime family-owned and operated junior producer. The company has 50-60 wells.

“It started out as some offset well drills. We acquired some land offsetting production and drilled it,” he said. That was done by company president (and Michael’s father), Jerry Mainil, and some partners back in the early 1980s. The company was fairly inactive for a number of years until Jerry decided to drill some more and bought out his partners.

The company has four battery facilities. They have five office staff plus additional contract operators.

“Our main area is southeast Saskatchewan. Our main production is south of Weyburn. We’ve expanded to Macoun and north of Estevan in the View Hill area.

“We would target three to five wells a year to drill, depending on opportunities,” Mainil said of their activity levels before the crash in prices.

In November and December 2014, when oil prices took a nosedive, he said, “You could tell the industry put the brakes on.

“We didn’t really alter anything, really. We weren’t overly aggressive. At that time it was still US$60 oil, which was still decent return. We finished our drilling plans for the near term then reviewed 2015. Breakup hits and you don’t do anything during it. We were at a point where I think we planned to drill at least two wells. We had some expiries. We cut that down to one.

“We were usually three to five, we cut it to two, and only drilled one.”

It was drilled in November 2015. Everything since then has been on hold, as Mainil said, “Until we know what’s going on.”

What price level do they need to see to resume drilling?

“I wouldn’t put a dollar figure on it. You need to see where it’s going, and where the bottom is. No one wants to drill now, and have $20 oil in three months. Once you start seeing it stabilize, and a slight increase … You want to see some stability in the price so you can do the math and calculate the return,” he said.

(The day of this interview, the price of WTI oil had just climbed above the US$30 point, before dropping below it again, two days later.)

Hypothetical examples

As a thought exercise, he went over some scenarios that go into the thinking behind whether or not you should drill a new well.

When we discussed this it was an exercise in risk management. The point was would you except a higher risk if the well had the ability to produce at a higher rate(all or nothing scenario) or is it better to drill a safer well and knowing the odds you would likely produce the well is at a lower rate?

(These numbers are not based on actual Saskatchewan probabilities. They are simply for discussion purposes, to analyze the thought processes.)

In this exercise, a really good parcel, Parcel A, would have an expected 30-day initial production (IP30) of 250 barrels per day. “You’ve got a one in ten chance of hitting a well (like that), Would you drill it?” he asks.

Parcel B, still a good parcel, with an expected IP30 of 120 bpd, is more of a 50-50 chance.

Parcel C, at with an expected IP30 of 60 bpd, is more of a 90 per cent probability.

Which one of these scenarios would you pick depends on your risk tolerance, according to Mainil.

Most of the production, and money, is made early with a new well.

“They decline fairly rapidly. That’s part of the economics. We don’t have any product in the Bakken, but say a production well in the Bakken will IP at 250 barrels per day, but in six months, it could be 40, or even less than that. So in your six month window, the price of oil can’t be $20.”

The final result could be any combination of these scenarios. “These are scenarios, as you’re working up plays, you would rank them.”


Then there is also the very real possibility of a “duster.”

“Any of these could be a duster,” he said.

A lot of companies put out statements of 100 per cent drilling success, or number close to that. But is that realistic?

“The first question you ask: are they talking to investors, or the industry? If you’re talking to investors, you hear a lot of ‘We didn’t drill one duster in the Bakken field.’ A drill-and-abandon well, where you drill it and abandon it right away, that’s a duster. But if you drill it, and you produce it, that’s a success, right? Well, define a success. It’s being produced after you drilled, so it’s not a drill-and-abandon, it’s a producing well. However, if that well ever pays out or not, that’s the question.

“So when you say they’re all successful, they’re all drilled and successfully put on production, but the question is, at what payout? And it’s the price of oil, too. If it’s a marginal well and oil is $100, you can still make money at it. If the price of oil is $30, now your payout is that much more, if at all,” he said.

Will it be a good one?

Does the oil producer have a good idea of a new well will be a good one, before committing?

Mainil responded it comes down to odds. “You can minimize your risk by gathering as much information as you can. I would say there’s never a guarantee. Never. Back in the day, I can remember an infill well, drilled in the Weyburn Unit; they’ve abandoned it after logging. Surrounded by other producing wells, it just so happened to be that one spot. So there’s always that risk. The more work you put into it, the more geology, your seismic, experience of the geologist; you can minimize your risk, but there’s never a guarantee.

“If you’re in a producing area, you can have problems with your well and lose your wellbore. You could abandon and re-drill, but you lost the costs of that wellbore.

It’s possible to lose wells mechanically. Liners, for instance, add more complication to a well than open hole.

“I’ll estimate a new drill, off of offsetting production, of what my expectations are. I’ll do best case and worst case, and do the risk analysis. Each situation is different. You could have a 60 barrel per day well at one-to-ten odds then ask yourself, ‘Is it worth the risk?’”

Different formations give different volumes, and certain ones are less risky.

“If it was easy, everybody would be doing it,” Mainil said.

“The highest production is at the beginning of the well. Depending on how good the well is, long-term, will determine the length of the payout, and the price of oil.”

Do you drill an area with high expectations when oil prices are low to keep revenue coming in, or do you sit on that with the expectation you’ll go after the really good stuff when oil is higher?

Mainil replied, “I wish I could give you a straight answer, and I don’t mean to be evasive. Everybody’s different. It all depends. Did you just acquire the land today, and have five years to develop it? Or is it expiring at the end of March? If I’ve got a couple years, then, yes, I will probably wait. If it’s expiring now, then I’ll likely drill to hold the minerals.”

Some companies are getting work done now, while the oilfield services prices are low. Others aren’t doing any development work, accepting the lower payout and rate of return. As an independent, privately owned company, he said, “As long as banks aren’t knocking on our door, we can go through this time.

There are other things you can spend money on. Everybody talks about drilling. Well, there’s optimization. There’s abandonment as well that you have to spend money on as part of your obligations.”

With service work now typically less expensive, it means obligatory work can be done for less money. 

“There’s a level where optimization works. Do you do it now, or when the price is looking better?” he noted.

“We might be at a level now were even on optimization, it pays to wait.”

He pointed out a wariness of double, triple or even quadruple dips in the price of oil.

“I would say you, don’t want to risk revenue at a time like this.”

“It’s easier to accept higher risk when your rewards are higher.

“We manage ourselves to get through slow times like this. My father’s been through many of these,” Mainil said.

“I’m sure there are people in a survival mode, if they’re leveraged. If you’re not leveraged, you can just maintain production and, by all accounts, should increase your capital, because if you don’t, you’re in a worse situation then you need to be in,” he said.

There’s a fundamental principle – production always declines.

“A company will eventually deteriorate to nothing if it doesn’t drill or acquire land. It will eventually deplete itself. It will transfer resources into cash, whether it keeps the cash or distributes it,” Mainil said. Technology changes such as waterflood or carbon dioxide floods can reduce those declines.

What do you shut in?

There comes a point when producers may choose to shut in wells. That can be to reduce costs, or to defer production for times when the price is expected to be higher.

Early candidates for shutting in include wells that have the highest costs, such as those that have their production trucked instead of being tied in by flowlines.

There are many variables to consider. Wells that are marginal at low prices will still have fixed costs, even if shut in.

“You’ve got to be comfortable with risk. If you’re putting out a million dollars to drill a well, you could have an asset that pays off or a liability that costs you $100,000 to abandon,” he said.