​Sometimes you lead and sometimes you follow in the dance of oil and gas cost-reduction innovation

This is the first article in a five-part series from Oilweek’s Innovators issue.

Innovate or die.

It’s a message business people have been hearing from consultants for years.

But the old adage has become critical for Canadian energy producers as low commodity prices and high supply costs have destroyed balance sheets and, in some instances, once-thriving companies.

So who plows the road for innovation in the oil and gas industry?

It is lot like dancing—sometimes you lead and sometimes you follow, according to a broad spectrum of resource explorers.

For Crescent Point Energy, the tendency is to lead in trying new things, simply because the company operates in shallow plays like the Bakken and Shaunavon, characterized by low capital costs of $1.3 million or $1.4 million per well to drill, meaning the company drills somewhere between 500 and 600 wells per year.

“That gives you the ability to try a lot of new things,” Trent Stangl, senior vice-president of investor relations and communications at Crescent Point, told the TD Securities Calgary Energy Conference.

“I think where we are definitely a leader is on the tight-rock-waterflooding side,” he added. “We are not relying on service companies or anything for that expertise. That is us trying things. We will do 120 injection wells this year, and that is up 70 per cent from last year, and so that gives us the ability to try a lot of new things. You’re not risking a lot when you are risking one in 120 injection wells.”

Where Crescent Point’s situation involves a lot of cheaper wells that allow for the company to lead with innovation, NuVista Energy’s Montney operations are more expensive so being a leader is not always advisable.

“We are very happy to lead on certain things,” said Jonathan Wright, president and chief executive officer of NuVista. “We like to take baby steps, and we don’t want to be serial number one on brand new ‘rocket science’ where there is a huge risk to a $10-million or $5-million well. But at the same time, we don’t mind being serial number one if there is a small innovation that we can try out and move along.”

“For us, we have shown quite a bit of balance there in terms of a willingness to innovate, be nimble and try different things,” he explained. “I can name certain types of drilling bits and fluids where we were the first in Canada to run them, and then I can name a whole bunch of things where we were probably the 21st or 50th in Canada to run them, and there were different reasons for where we got to in our experimentation.”

In every situation, deciding whether to lead or follow on the innovation front involves doing the engineering, looking at what works for a particular play and deciding whether or not the situation calls for the company to be a first in trying something new.

“If you don’t innovate, you’re going nowhere. You have to change, but it is just a matter of how quickly and how much risk you are willing to take,” he said.

Crescent Point has focused a lot on improvements on the completions side in the past few years, first working on the mechanical side with cemented liners and sliding sleeves and now concentrating more on fluid factors.

“Lately, we are spending more time on the fluid side, really using chemical and molecular advances to drive our access to get better access to the rocks, scrubbing more oil from the rock,” Stangl said. “That is really what we have been talking about in the last year or so.”

“Probably the biggest thing for us is on the waterflood side—tight-rock waterfloods in the Bakken and Shaunavon where the first several years were really about proving the concept of the waterflood on the tight-rock side,” he added. “Now we are a lot more into the science of the waterflood and how the water moves, controlling the movement of water, measuring it, monitoring it and dispersing it in different ways. There has been a lot of change on that side.”

Ken Woolner, president and chief executive officer at Velvet Energy, noted the integration of subsurface understanding with tangible equipment has been a major innovation for his company in recent years.

“What I’ve seen is a huge amount of differentiation that can happen on the subsurface side of the business—whether it be geochemistry, geomechanics, petrophysics—and really understanding exactly where you are in the source rock migration window of your play, which ties up very much into the mechanical or cost side of the business,” he explained.

How much of cost savings are innovation versus pricing pressures?

While plenty of innovation has been happening as companies recreate themselves to manage lower prices, there is some question about how much of the savings is coming from innovation and how much is from the good old fashioned grinding of service company margins—and whether those cost-savings will continue when activity ticks up.

But innovation isn’t simply about lowering service prices; it is ultimately about lowering costs per barrel equivalent produced.

“It is not necessarily about cutting costs, but also looking at how we are doing operations, what are we doing on drilling and completing, and whether it is the right way to do things,” Bruce Jensen, chief operating officer at Bonavista Energy, said.

John Williams, president and chief operating officer at Trilogy Energy, said the current downturn has provided his company with a chance to re-engineer every single process within the organization, cutting general and administrative costs and trimming operating costs as effectively as possible.

“We focused in on how we spend our capital dollars. There has been a lot of cooperation from our service providers. The last 18 months have been a great learning experience, and a lot of the efficiencies that we have implemented are here to stay,” he said.

“It is unfortunate to think about how much money we spent at $100/bbl oil now that we have new processes in place where we will be able to do things more efficiently moving forward,” he added.

As commodity prices fell, Crew Energy was able to reduce its operating costs quite dramatically—down about 23 per cent from 2015 to 2016 and before that down about 23 per cent from 2014 to 2015.

“That is a big component of where we are going for cost structure, and a lot of that is sustainable going forward,” Dale Shwed, president and chief executive officer of Crew, told the conference. “As far as the capital costs are concerned, we have seen reductions from roughly $5.5 million per well down to between $3 million [and] $3.5 million per well. That has really helped our costs.”

Each initiative Canyon Technical Services considers in a downturn must be permanent, and things cannot just return to how they were before commodity prices fell, said chief operating officer Todd Thue. “We are very concerned about how we can keep the balance sheet in good shape so we have the working capital available to get our fleet back up where it needs to be—back into the field. We think it will be a long, slow process.”

Canyon operates in an environment where a low cost is needed for its customers to be prosperous and, therefore, for Canyon to prosper.

“As there are more requirements for our services then the utilization will come up,” added Thue. “Along with that, we will be very cautious in how we put more equipment to work and more people to work because there does have to be some price appreciation for us to be successful long term.”

At its peak, the Canadian equipment fleet had about 2.1 million horsepower, said Thue. He suggested only about half of that is currently staffed and able to go to work. Of the fleet that is idle, perhaps half is obsolete for the sorts of operations now required.

Even when the industry returns to more normal levels of activity, Thue does not expect all the service sector horsepower that went offline with the downturn will be available right away. “It is probably going to be a lot slower and more difficult ramp up than people anticipate.”

However, said Trilogy’s Williams, growth under current strip pricing will be modest, which gives Canyon and its competitors time to step up and rebuild some of the equipment that is obsolete.

“I believe that as we do move into this, it is a slow evolution, and Canyon and its competitors will be able to keep up. We will definitely share activity levels with them so that they are prepared six months in advance,” he explained.

At Tourmaline Oil, more than half of the 30 per cent reduction in drilling and completion costs relates simply to getting better at how it drills and completes those wells, said Mike Rose, president and chief executive officer. “A lot of it has to do with multiwell pads, so when things pick up again, we are going to keep somewhere between 50 per cent and 60 per cent of the reductions we have seen that have nothing to do with service costs.”

As Tourmaline won’t be giving back its service cost reduction right away, it estimates that it will keep half of that, so it probably will maintain 75 per cent of the reductions for an extended period of time, he predicted.

Bruce Beynon, executive vice-president of Raging River Exploration, said his company thinks about two-thirds of its cost savings might be “sticky” to the producing side, so it is going to keep a fair bit of them. “At [US] $50/bbl we are seeing a return that we used to get at $90 in our old cost structure,” he noted.

Northern Blizzard Resources has cut about $45 million out of operating costs over the past two years, mainly by doing things differently, said John Rooney, president and chief executive officer. “And that will be sticky for awhile because there isn’t enough activity to cause inflation.”

Like this? Check out the latest issue of Oilweek.

Advocacy & Opinion


U.S. & International


Renewables


Special Report