Pipeline May 2016

PIPELINE NEWS Saskatchewan’s Petroleum Monthly

FOCUS

May 2016

Canada Post Publication No. 40069240

FREE

Volume 8 Issue 12

RESEARCH & DEVELOPMENT

Showing our Oil Respect

Representatives from Sun Country Well Servicing, MayCo Well Servicing, Diamond Energy Services, Rearden Well Servicing, Red Hawk Well Servicing, Independent Well Servicing, Precise Well Servicing, Alliance Drilling, Red Dog Drilling, Crusader Drilling and Enform gathered in the Independent Well Servicing yard in Estevan on April 7 to show their support for the Canadian Association of Oilwell Drilling Contractors Oil Respect campaign. Photo by Brian Zinchuk. See page A3.

In This Month's Issue...

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Millenium Stimulation Shuts Down

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Packers Plus closes Estevan doors

Industry's R&D demand shifting: SRC

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PIPELINE NEWS May 2016

Aquistore achieves CO2 breakthrough at observation well n By Brian Zinchuk Estevan, Regina – The Petroleum Technology Research Centre’s Aquistore project has successfully achieved CO2 breakthrough at its observation well.

Aquistore is a $30 million research project, injecting compressed carbon dioxide (captured at the Boundary Dam Integrated Carbon Capture and Storage Project) deep underground. A second well, drilled nearby, was set up to observe and record the flow of carbon dioxide underground from the injection well.

'There has been confirmed breakthrough at the observation well 150 metres away,” said Erik Nickel, senior project manager with the PTRC. “What that means is that the modellers can now much more accurately predict how widespread that plum spread.”

The breakthrough was confirmed by logging.

“The reason why break-

through is important, ultimately, it gives a concrete data point as to how fast the CO2 is moving through the reservoir and how big the plume is. Then you can take those two data points, your point zero injection, how much you injected to reach breakthrough, and you can history-match that and then make a predictive model of what the plume will look like.”

While breakthrough is interesting, the more interesting items are the research that comes afterward, according to Nickel.

As of March 31st, 53,000 tonnes of carbon dioxide have been injected into Aquistore. For January, February and March, they averaged 496, 200 and 450 tonnes per day. The rest is going to the Cenovus oilfield.

Only 15,000 tonnes had been injected by the end of December, thus 2016 has seen a dramatic increase in carbon dioxide available for injection. The capture plant went online in the fall of 2014.

Ongoing seismic surveys is a

major part of the research, monitoring the spread of carbon dioxide deep underground.

“In the last two weeks of February, major seismic work was done,” said Norm Sacuta, communications director with the PTRC. He pointed out that a lot of work was done at the site over those ten days, around 300-person days, generating employment in a real way.

“There’s more testing to come.”

The work included testing the distributed acoustic signal and how that varied from the existing seismic array. Vibroseis equipment were also used.

“The data we collected over those ten days is being looked at now by the research scientists,” Sacuta said. “It’s going to be compared, ultimately, with the models and other baselines that were done before CO2 injection began.

Soil gas sampling was also done at the same time, as well as ongoing groundwater sampling.

er Service Ltd. k c i P s ’ y l r u C Mark T.ke(Curly) Hirsch S r e r c v i ice Ltd. P s ’ y l r u C

On Feb 23 the Aquistore injection well had wireline work done as part of ongoing research into the deep saline storage scheme for CO2.

Photo courtesy Petroleum Technology Research Centre.

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A3

TOP NEWS

We demand Oil Respect n

By Brian Zinchuk

Estevan – In the sentiment of Twisted Sister’s 1984 song We’re Not Gonna Take It, the oil industry is standing up and demanding respect.

In February, the Canadian Association of Oilwell Drilling Contractors launched its Oil Respect campaign.

Since then CAODC president Mark Scholz has travelled the country, speaking to everyone from parliamentarians to chambers of commerce. On April 7, Scholz and CAODC vice-president John Bayko came to Estevan. There they had meetings with local service rig and drilling rig contractors, members of the CAODC. “It really started from a growing concern from our industry. In a time when we are seeing unbelievable challenges and uncertainty in our industry, a time when over 100,000 people have lost their jobs, that we continue to see our industry painted in a very negative, misguided and untruthful manner.” Scholz said.

“We started thinking about this in late 2015 about what we could do to better promote this industry. One of the areas that we have always seen as a gap is that industry does a particularly good job highlighting innovation, highlighting technology, our equipment, our robust regula-

tory systems, and the energy industry as a whole. But up until now, we have not really tried to humanize this business and this industry.

“When you look at the standards our industry has to live up to, who is ultimately accountable to do that? It’s the men and women who work, in the field, day in and day out, in minus 40-degree and plus 30-degree temperatures. (They) ultimately work very hard and give our industry the international reputation it has today – the most environmentally responsible, sustainably developed oil and gas development in the world,” he said.

“We have to start really educating people in a way that says, ‘Look, these are just regular, hard-working Canadians who are losing their jobs in an industry that all Canadians benefit from. Yet, we still get the rhetoric from radical environmentalists, grandstanding politicians and foreign celebrities who come out here and present untruthful, misguided information about the industry.’”

Scholz said the campaign has three objectives and they unapologetically support the oil and gas industry.

The first is addressing misinformation spread about the industry by those who oppose oil and gas

development and its consumption.

Second, they want to give regular, hard-working Canadians who are employed in the business, unemployed, or have family in the business a voice.

Thirdly, they want to remind the media, the public and the government that the reason Canada has one of the highest standards of living in the world is from affordable oil and gas that is developed responsibly in Western Canada.

Scholz pointed out there are systemic issues, too. “Our products do not command world prices.”

“We don’t even get WTI, let

alone international pricing.”

Our product goes to one market, America, and that market has also become our biggest competitor.

Quebec also imports 90 per cent of their oil, and 37 per cent comes from countries with much lower environmental, labour and human rights standards than Canada’s. “That’s why Energy East is so important,” he said, referring to TransCanada’s proposed pipeline that would supply most of Central and Eastern Canada with Western Canadian oil.

The campaign can be found online at oilrespect.ca.

IconOil drills two wells in Saskatchewan oilsands n

By Brian Zinchuk

At the tail end of the winter drilling season, IconOil Exploration & Development Ltd. did something no one has done in Saskatchewan for quite a whiledrill wells in the oilsands. Pipeline News interviewed IconOil’s CEO and chair, Grant Strem via email while he was in Europe on April 25.

Pipeline News: Can you tell us a little about Icon?

Grant Strem: We invest into transformative resource and tech-

nology plans that we consider to be environmentally helpful. Our operations are in Western Canada and Europe.

P.N.: We haven’t seen much, if any activity, in the Saskatchewan oilsands region since Cenovus bought the assets of the defunct Oilsands Quest. What is Icon doing in the region?

G.S.: We drilled and abandoned 2 shallow wells.

P.N.: Can you describe where it is?

G.S.: Northwest of Meadow Lake, Saskatchewan.

P.N.: You seem to be showing

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P.N.: Is there anything you’d like to add?

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PIPELINE NEWS May 2016

PIPELINE NEWS

EDITORIAL

Mission Statement: Pipeline News’ mission is to illuminate importance of Saskatchewan oil as an integral part of the province’s sense of community and to show the general public the strength and character of the industry’s people.

Editorial Contributions: PUBLISHER Jim Ambrose - Estevan 1.306.634.2654 EDITOR Brian Zinchuk - Estevan 1.306.461.5599 Associate Advertising Consultants: SASKATCHEWAN & MANITOBA • Estevan 1.306.634.2654

Cindy Beaulieu

Candace Wheeler

Deanna Tarnes

Teresa Hrywkiw • Carlyle 1.306.453.2525

Alison Dunning NORTHWEST SASK. & ALBERTA • 1.306.460.7416

Harland Lesyk

To submit a stories or ideas: Pipelines News is always looking for stories or ideas from our readers. To contribute please contact your local contributing reporter.

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Special thanks to JuneWarren-Nickle’s Energy Group for their contributions and assistance with Pipeline News.

Published monthly by the Prairie Newspaper Group, a division of Glacier Ventures International Corporation, Central Office, Estevan, Saskatchewan.

Advertising rates are available upon request and are subject to change without notice.

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The Glacier group of companies collects personal information from our customers in the normal course of business transactions. We use that information to provide you with our products and services you request. On occasion we may contact you for purposes of research, surveys and other such matters. To provide you with better service we may share your information with our sister companies and also outside, selected third parties who perform work for us as suppliers, agents, service providers and information gatherers.

Glimmers of hope on pipelines From Premier Notley, Prime Minister Trudeau and NEB After years of fighting against the tide, midApril started to show the first signs of promise for Canada’s beleaguered pipeline industry.

Alberta Premier Rachel Notley seems to have found religion, and that religion is steel pipe. A $10 billion deficit will do that for you, apparently.

She’s been pushing hard on TransCanada’s Energy East, and may have even warmed up to the Enbridge Northern Gateway.

Northern Gateway, which has National Energy Board approval, appears stillborn right now as the Trudeau government has promised a moratorium on oil tankers off the northern British Columbia coast. But even on that front, we may have received a few glimmers of hope from the federal government that all is not lost.

Enbridge has apparently been looking at alternatives to Kitimat as its delivery point for Northern Gateway. Any change would, of course, result in a new regulatory review. But Kitimat or bust seems to lead to bust, so it would be good if they considered other options. As we’ve noted editorially before, any prairie boy with five minutes on Google Maps can see Prince Rupert, with its near instant access to open ocean, is a much better idea than tying a tanker to a tugboat and running it down the long, narrow Douglas Channel. Enbridge deciding to switch to Prince Rupert could be the very thing to revive this near-dead, yet approved, project.

Indeed, Prime Minister Justin Trudeau may,

too, have found religion on pipelines. It seems when you’re looking at budget deficits to the tune of $29.4 billion per year, all of a sudden pipelines, and the growth they allow, and the diversified markets they will beget, start to make sense.

Funny, that.

On April 25, the National Energy Board approved Enbridge’s Line 3 replacement. This project would be the biggest one Saskatchewan would see in a generation. The last major pipeline project in Saskatchewan was Enbridge’s Alberta Clipper in 2008-2009. After Line 3 is replaced, it might be the last major project for another 8 or so years, perhaps until Enbridge or TransCanada start retiring and replacing some of their other lines that will be old enough to start collecting CPP. In a few weeks time, we should also hear what the NEB has to say about the Kinder Morgan Trans Mountain Expansion project. The sensible folks that they are, the NEB will likely be in favour of that project, too.

So now, we just need to get building these projects. The long-awaited boom time for pipeliners could, hopefully, be at hand. But we’ve heard that before. Line 3 Replacement was supposed to fire up this summer. Energy East was supposed to be in service by 2018.

We’ll be waiting with bated breath. Hopefully the industry doesn’t run out of oxygen in the meantime.

PIPELINE NEWS May 2016

If there is oil near Hudson Bay, where else could it be?

Let me start by saying this entire enterprise is predicated by one great big “if.” Huge if. CAPITAL LETTERS IF. As of midApril, the big question is if, indeed, Saturn Minerals has found oil southwest of Hudson Bay, Sask., as they say they have. Their core taken had not yet arrived at the Saskatchewan Subsurface Geological Laboratory (a.k.a. core lab) in Regina.

Even when it does, the geologists there can’t talk about it for a year while it’s under a confidentiality period.

But the question I’ve been asking every geologist I could find is this: IF oil was found near Hudson Bay, and IF all the oil in the Williston Basin is believed to have formed in the “kitchen” around Williston, North Dakota, how did it get up to Hudson Bay? Could there be oil found elsewhere in the roughly 300-kilometre gap from the northernmost oil wells in southeast Saskatchewan to Saturn’s discovery well?

The consensus has been, “It’s possible.”

Let me step back for a minute. The theory behind oil creation is that it is created in “kitchens,” where the depths, pressures and temperatures are great enough to “cook” kerogens into light oil. That oil travels underground until it collects in traps, which is where we find it, drill a well, and put a pumpjack on it. If the oil is degraded enough via contact with water, it becomes heavier.

Thus, all the oil in Alberta is believed to have formed in the last 65 million years. That’s when the creation of the Rocky Mountains pushed down enough material in the foothills region to create a kitchen and produce all of Alberta’s, and western Saskatchewan’s

light, medium, heavy oil and bitumen.

In the southeast corner of Saskatchewan, the kitchen is in the heart of the Williston Basin, around its namesake, Williston, N.D. Our Canadian geologists often thank the Americans for sending their oil north of the border, thank you very much.

Since the shallow sedimentary depths around Hudson Bay likely discount the possibility of oil being produced locally, it most likely came from Williston.

The formation Saturn is talking about is Ordovician (pretty close to the PreCambrian basement). The closest Ordovician production in Saskatchewan is near Tyvan, north of Weyburn.

There’s about 300 kilometres of space between Tyvan and the discovery well southwest of Hudson Bay, near Porcupine Plain.

What we do find in that giant gap is the bulk of the Saskatchewan potash ore body, known as the Prairie Evaporite. The Ordivician formation is found well below the Prairie Evaporite.

This brings about several questions. That large band stretching northwest to southeast across the province has probably had more seismic shot than you can shake a stick of dynamite at, with regards to the quest for potash. In their enormous quantities of seismic data, have the potash companies, perhaps, found structures where we could have prospective oil? If so, why haven’t they done anything about it, e.g. spinoff their own oil companies to develop it?

The big reason would likely be that potash and oil development do not mix, at all. Oil drilling is banned wherever potash could potentially be developed. A

well penetrating into an underground mine could lead to flooding, the loss of the mine, and the loss of life. So, if you are a potash company, you don’t want any pesky oil wells around, period. Even suggesting oil production in potash areas becomes a very political question that many people don’t want to touch.

It’s also not very easy to drill oil wells through potash, either, I’m told.

Seismic imaging also doesn’t work very well through large salt bodies.

A5

OPINION FROM THE TOP OF THE PILE

Maybe the potash companies haven’t been able to see much below their ore body, after all. And why would they? If they’ve found potash, why look for oil below it?

Even if Saturn’s discovery well doesn’t turn up much oil, if it does in fact have oil at all, that means that the possibility still exists for oil to exist all throughout east central Saskatchewan, down to southeast Saskatchewan. We know natural gas used to be produced at Kamsack. Wildcatters

By Brian Zinchuk

have looked throughout the region over the decades.

We shouldn’t forget that Nordic Oil and Gas had an operating oil well near Sturgis for a short time a few year ago. So really, this question may have already been answered.

If there’s oil up north, then there should be some oil, somewhere, between here and there.

There hasn’t been an entirely new oilfield found in Saskatchewan since the 1950s-1960s, one that wasn’t

relatively close to an existing oilfield. If Hudson Bay does turn into something, this could be one of the most significant developments in the Saskatchewan oilpatch in our lifetime. And if there’s anything in the gap in between, it could be a lot bigger than that.

Again, it’s all a great big IF. Brian Zinchuk is editor of Pipeline News. He can be reached at brian.zinchuk@ sasktel.net.

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PIPELINE NEWS May 2016

Millennium Stimulation shuts down

Life in the Patch n By Tasha Woroschuk Weeks before road ban and all through the shop, Not an employee was stirring, not even the mop, Three rigs as they were all tucked in their beds, While visions of higher oil prices danced in their heads.

OPEC, price cuts and layoff woes for more than a year, Depression-filled doom and gloom is all we now hear.

Auctions are busy, the patch slowing down, It’s really no wonder why our faces now frown.

“Hang On”, they say, “It’ll only get better”; Could it get much worse for the common debtor?

Those that have spent hard-earned money on toys and loot, Are now collecting EI and dust on their boots.

Those who have endured it before shake their heads in dismay, “That’s life in the patch,” is all they can say.

No real explanation why we can’t level things out, We all watch in horror as corporations scream and shout, “Cut back your costs, your rates and your spends,” Do it now or your business might end, Up on the auction block amongst many others, Some of them wishing they’d followed their druthers, To be something else and follow their dreams, Instead of this patch life full of losses and schemes.

Please bow your heads, for if we all pray, We might see it through to another bright day.

The patch is my life, the one that I love, I’m not quite ready to toss in my gloves.

For on these feet my boots they will stay, Cuz I’m made of tough stuff God made me this way.

n By Brian Zinchuk

Estevan, Calgary – Four years after it fired up operations, Millennium Stimulation has now shut down.

Millennium Stimulation Services started as a conventional hydraulic fracturing company in early 2012.

The company’s original operational focus was set primarily in southeastern Saskatchewan, Bakken territory. Throughout the short time in operations, the company expanded into Manitoba and southeastern Alberta.

In the last two years, the company had been developing its energized fracs using liquefied natural gas, instead of large amounts of fresh water. These fracs were called ENG, or energized natural gas.

If successful, the net result would have been a dramatic reduction in the usage of fresh water in hydraulic fracturing – long considered a

matter of concern for the industry. They had just done their first few jobs with the new technology earlier this year when they ran out of runway, financially speaking, and the bank foreclosed.

Millennium Stimulation Services Ltd., was placed into receivership by its lender, Alberta Treasury Branches, on March 24.

KPMG Inc. has been appointed as the receiver by the Court of Queen’s Bench of Alberta in Calgary on

March 24.

Pipeline News spoke to Mike Heier, founder, president and CEO on April 5, Heier, who was also founder and former CEO of Trinidad Drilling (and still is its chair), has always been one of the most forthright and straightforward interviewees this paper has interviewed. That hasn’t changed.

“Our bank petitioned us into receivership,” Heier said by phone from Calgary. He

noted it goes back over a year, as they had been trying to finance their energized natural gas initiative. “That’s where all the future was.”

“As you can well imagine, there’s been zero to negative profit on the conventional fracking side. When you look at everyone’s financials, it suggests it’s a war of balance sheets.

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USTOMS ROKERS Page 6 primary funder, a Chinese outfit that were all things LNG in China, they were making a big business footprint in North America. They needed a base. We were effectively going to be it.

They were going to be the lead in equity funding. They exited North America in December,” Heier said.

That led to Millennium looking at strategic alternatives in January.

“When we had all bids back in the middle of March, the bank basically stepped in and said, ‘We can finish the job from here,’” he said.

That shut down the company, and the remaining staff were laid off in late March.

KPMG is running a sale process.

The total owed to ATB was $17.1 million. That included a $5 million mortgage on its Estevan properties – its initial frac operations base, and subsequent sand storage facility completed a year ago.

Heier said about $10.5

million had been spent on those two properties.

The trade payables was under $2 million.

Their staff had been wound down to the high-50s range, mostly part-time at this point, before the shut down.

Millennium had operated two frac spreads and two coil tubing units. A year ago the company effectively shut down its spread that had been working out of Estevan due to lack of work in the area, but had still been working out of Medicine Hat. Millennium had shaken up its pay structure back in October to a variable compensation scheme. The fourth quarter of 2015 and first quarter of 2016 had looked reasonable, “until you actually got into them,” he said. “Dozens and dozens of wells on our books to do, and it became less than 10, overall.”

“It was a dramatic reduction in client programs. We would have normally five or six pretty decent-sized cli-

ents then about a dozen smaller guys that we would do a little bit here and a little bit there. We would have activity from south central Alberta to southwest Manitoba.

“Once oil started falling below that $40 range, clients’ workload would drop precipitously.

I would even say easily 60, 70 per cent was dropped off the working schedule. Of what was left, the narrative you would have going back and forth with the clients would be, “Gee whiz, you might say you would do it for cost, but this guy will do it for 10, 15 per cent less.’”

“So really, what you had going on was people willing to take on the work at a negative field margin,” Heier said.

This resulted in erosion of balance sheets across the frac industry peer group. To protect their balance sheets, he noted one company sold its overseas assets, while another raised funds recently. A third company is staring at a large deficit and debt. One

more sold off their assets and was broken up.

Millennium had tried to see a clear pathway through this, with their LNG frac business as the future of the company, but the bank stepped in, and that was that.

So what happens to their pioneering ENG frac technology? “It belongs to the company.

The company is controlled by the receiver,” Heier explained.

The patents are corporately held.

“The obvious place for the receiver is the best place for all stakeholders. The best answer isn’t necessarily a sales process until there is nothing left. They have fiduciary responsibilities to act on behalf of all stakeholders, the bank is just the largest right now,” he said.

Right now, all he can do is sit back and patiently watch. Heier said, “This isn’t something anybody gets to practice at. Certainly it’s a function of a lack of business, of profitable

business, that’s available in a downturn like this. Effectively, we just started getting our footing, getting operational.

Interestingly, most of our upside was on the ENG, not the conventional side. Before we could execute on it, you’re done.

“Truly unfortunate, but in the environment we’re in, I don’t know if there was a different narrative to play out.”

After having done a couple of ENG fracs, they had work lined up in Texas for December and January. But that evaporated when oil dropped below US$30 per barrel for WTI. Heier was in Lloydminster during the 1986 oil meltdown. “That was dramatic. It was brutal.

It was very long-winded.

What a lot of people don’t reflect on, is the fact that is it wasn’t until 2002 that we actually crawled out from that one.

He noted it wasn’t just oil-related, but natural gas was deregulated at the same time.

Natural gas dropped dramatically. Heier said, “That was murderous for everybody. Not only did you have the oil meltdown, you had the natural gas meltdown.

The same thing we’re going through right now, we went through back then. There’s a much greater story playing out here right now than most people realize. There’s a lot of really big Canadian names, they’re done, you just haven’t heard it yet.”

Heier said the business needs to see oil prices greater than US$50 per barrel to make a difference. It would have made a difference for Millennium. “We had stuff lining up in the $40 to $50 range on the ENG side,” he said, but there was no profitability on the conventional frac side.

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PIPELINE NEWS May 2016

Packers Plus closes Estevan doors n By Brian Zinchuk

Estevan – Back in 2010, Packers Plus was playing a key role in the Bakken boom. PetroBakken president and CEO R. Gregg Smith (who was named Saskatchewan Oilman of the Year in 2009), spoke highly of their technology at the Saskatchewan Oil and Gas Forum. Crescent Point’s website featured Packers Plus illustrations, and spoke proudly of their usage of Packers Plus products. This was unusual in that oil companies very rarely single out one of their suppliers in such a manner.

In 2010, they expanded their Estevan shop substantially. They had 42 people at the time working out of it.

In early April 2016, Packers Plus closed its doors in Estevan, laying off the last of its employees.

“It was hugely disappointing for Packers Plus,” said Tess McLeod,

Packers Plus’ manager for marketing and communications on April 21.

She noted Estevan was one of the company’s first shops, and it was “not an easy decision.”

“All companies have to adapt to survive,” McLeod said.

The company was founded in 2000 by Dan Themig, Ken Paltzat and Peter Krabben, opening their first office in Calgary, then Edmonton. The Estevan and Grande Prairie, Alta., service centres opened that same year, according to the company’s website. Their first system was installed in the Bakken formation in 2003.

Industry practices changed, though, not long after those heady days at the beginning of this decade.

Companies that had once sang Packer Plus’ praises switched to monobores: cemented liners that did away with the pricey “string of jewels,” as some

in the field called it, that were characteristic of ball-drop frac systems.

“Saskatchewan turned to a lot of coil tubing operations from open holes,” McLeod said.

Ball drops systems were out of vogue, and coil tubing was in. Over the past two years, the funk in oil markets has hurt the entire industry. Additionally, PetroBakken (now Lightstream Resources) was their biggest client in southeast Saskatchewan in 2010. In 2009, PetroBakken’s stock was worth $34.00 a share.

On April 21, as Lightstream, it was worth 32 cents, and over the last year it drilled 14 new wells in the Bakken, only one of which was in the fourth quarter, which is usually the busy the winter drilling season.

As of April, Packers Plus still had five Canadian locations (all in Alberta), 13 in the United States, and eight overseas.

The international company is still

seeking to spread its wings elsewhere.

On April 15, Packers Plus announced it and Schlumberger have entered into a global alliance, enabling the two oilfield service companies to become channel partners in key markets around the world.

“By combining the strength of Packers Plus’ technologies in multistage completions with Schlumberger’s impressive customer footprint, our two companies will be able to rapidly deliver best-in-class solutions to a wide variety of operators around the world,” said Packers Plus President, Ian Bryant.

As part of the alliance, Schlumberger will sell Packers Plus’ technology internationally and Packers Plus will sell complementary Schlumberger technology in Canada.

This is not an acquisition or merger, but a strategic alliance, according to McLeod, largely international in scope.

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Sanjel’s assets sold off, company broken up Calgary – Sanjel Corporation announced on April 4 announce the signing of two transformative agreements for its sale to two separate North American pressure pumping providers.

Sanjel has signed a definitive agreement for the sale of its Canadian fracturing, coiled tubing and cementing assets to STEP Energy Services Ltd., an ARC Financial Corp. sponsored company. STEP is a privately owned, technically focused, oilfield services company providing specialized coiled tubing and associated pressure pumping equipment and fracturing services.

Concurrently, Sanjel has also announced that it has signed a definitive agreement for the sale of its United States fracturing, coiled tubing and cementing assets to Liberty Oilfield Services.

Liberty is an innovative oilfield service company providing specialized stimulation services to optimize well production.

Liberty currently operates in the Williston, DJ and Powder River basins

and is headquartered in Denver, CO. Sanjel also announced on April 4 that it has initiated a Courtsupervised restructuring process to facilitate the closing of the two sale agreements. The company today obtained an initial order from the Court of Queen’s Bench of Alberta under the Companies’ Creditors Arrangement Act. The Court appointed PricewaterhouseCoopers Inc. as monitor of Sanjel during this process. The company has also applied for recognition of the Initial Order under Chapter 15 of the US Bankruptcy Code.

The creditor summary filed with the

court includes US$300 million in unsecured senior bonds, a further US$45.7 million in listed unsecured creditors, C$18 million in listed unsecured creditors and a further C$18.7 million in unsecured interest. Their secured credit facility was C$396.7 million. The total creditor summary is $779.1 million, although it is not indicated whether that is Canadian funds, American funds, or a blend of the two.

The originating application for the court action noted that Sanjel had issued US$300 million in unsecured senior bonds on June 18, 2014.

Those bonds, at 7.5 per cent, had semi-annual interest payments. On Dec.

19, 2015, they missed a US$11.3 million interest payment. “Sanjel Corp. had sufficient cash availiability to make this interest payment, but it decided not to do so given the extremely constrained working capital situation it was facing at the time and instead entered into possible restructuring discussions …,” it said.

Sanjel sought to negotiate with its lending syndicate, but the condi-

tions of those agreements were not met. On March 18, the syndicate demanded repayment.

In its April 4 press release, Sanjel said it anticipates operating on an uninterrupted basis throughout the CCAA process until closing of the transactions. The company has arranged interim financing for this purpose with its existing twelve member banking syndicate. Closing of the sale transactions

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PIPELINE NEWS May 2016

Industry’s research demand shifting: SRC n By Brian Zinchuk

Regina – While there are commercial labs of all sorts, sometimes you need a specialty lab to really delve into a new area.

That’s a primary role of the Saskatchewan Research Council (SRC).

Among its facilities are their labs at the Innovation Place research park at the University of Regina.

Kelly Knorr is the operations manager of the energy division with SRC. On April 13 he took Pipeline News through a tour of the facilities.

“In the Regina facility, we have three business units that operate.

Two are enhanced oil recovery (EOR) units, and the third one is called process development. They deal mostly from the wellhead to the refinery,” Knorr said.

“They deal with surface facilities, and a little bit of pipelining.”

One of the EOR units looks at field

development, the other looks at processes. “They’re kind of separated by the type of oil being produced,” he said. “EOR process looks primarily at light and tight, through to the medium oil, and EOR field development looks at the medium oil through heavy oil, extraheavy oil and oilsands.”

The laboratory for process engineering might look at samples off the wellhead, looking at densities, viscosities, gas:oil ratios, chromatographs, etc.

“They also look at emulsions and how to treat emulsions,” he said.

“Whenever you get into a downturn like this in industry, the first thing that goes away,

really, is enhanced oil recovery, which has long windows of time – five to 10 years – before you get a lot of your money paid back. You start to focus on production optimization and cost reduction,” Knorr said.

When oil companies start talking optimization, the first stage is often things that can be done in the field, like modifying pumping. Near-wellbore cleanup techniques is next, clearing out wax or asphtaltenes, for instance. Next is nearwellbore stimulations, out more than a metre or two. When it comes to radial flow converging around the well, small changes in the flow properties of the

porous media, or the fluid itself, make a big difference in the overall pressure drop it takes to pull that fluid.

A solvent stimulation or hot oil stimulation are possibilities.

But these things have been done and, in the case of hot oil, are standard practice.

“When we talk about optimization, we say, rather than look at a long-term EOR-type of project, which most companies don’t want to look at right now, maybe we can move further out into this reservoir around the wellbore. So we’re out maybe five or 10 metres now? So we’re looking at that.”

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tion, different chemistry, different injection and production scenarios are all possible research areas.

When it comes to tight formations, like the Bakken, he said, “Multi-stage, massive fracs is a wellbore stimulation technique.

You’ve already got most of the stimulation you’re ever going to do in these wells. In those cases, there’s probably not a whole lot of production optimization we can help them with.

Their biggest problem is they’ve got fractures that will transmit the fluid, but the fluid isn’t in the fractures, it’s in

the matrix. It needs to come out of a matrix that’s only got 0.01 milliDarcy permeability.

“What they can do, though, is maybe pressure support, like inject water or gas.”

The SRC hasn’t done any research on refracs, or doing a second hydraulic fracturing operation on a well several years after the initial frac.

Most research, he noted, is incremental.

The industry, and the service companies in particular, come up with sea-change systems like the packers that allowed for multi-stage fracs.

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PIPELINE NEWS May 2016 “That was a technology sea-change that allowed us to produce the Bakken in southeast Saskatchewan,” Knorr said.

“If we have a particularly difficult emulsion that’s hard to break … we’ll work on some chemicals. Usually it’s a combination of chemicals and heat in your treater that will break that emulsion,” he said.

On production optimization, Knorr said, “We don’t have any magic bullets. We don’t have any magic processes (where) that we look at a field facility and say you’ve got

to do A. B and C and you’re going to get this much more oil. These things are areas we’re more interested in now, because of the downturn, because the operators are more interested. The fact remains: the best way to reduce costs is to increase production, because your per unit costs goes down.

A lot of the oilfield is fixed costs, where you’re amortized against whatever oil production you have. If you increase production, you’ll reduce the per-barrel cost.”

Knorr said, “We are essentially an EOR shop, and we have been for 30

years. Now we have to adjust our focus a little bit to meet the needs of industry. The industry needs now have shifted to production optimization and cost reduction.

So we’re starting to look at that. You can apply a lot of the same engineering, physics, and subject matter expertise and skill sets of the researchers to

apply to these problems, to a limited extent. So we have a number of different projects we’ve started with a number of operators looking at specific things they want us to evaluate for them.”

Thus, the two EOR groups are being pulled in the optimization area, because that’s where the demand is now.

This black cylinder is the Small SAGD Test Apparatus at the Saskatchewan Research Council in Regina.

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PIPELINE NEWS May 2016

How does 70 billion original oil in place sound? n

By Brian Zinchuk

Regina – Just how much unconventional oil is in the Saskatchewan Bakken? That’s a question many people would like to know. This spring saw the release of two studies that looked into just that.

The first was prepared for the National Energy Board (NEB), titled The Ultimate Potential for Unconventional Petroleum in the Bakken Formation of Saskatchewan. The second was done by the Geological Survey of Canada (GSC), called An Assessment of Oil and Gas Resources in the Devonian-Mississippian

Lower Middle Bakken Member, Southeastern Saskatchewan. Both were released in 2015 Williston Basin Petroleum Conference. The NEB final report was released last April and the GSC final report was released in this April.

The NEB report looked at the entire Middle Bakken formation, which includes Units A and C. Most Bakken oil production is done from the lowest unit, Unit A. The GSC study focused on just Unit A, and excluded the Unit C. Both studies looked just at southeast Saskatchewan.

Chao Yang, a senior

research geologist with the Saskatchewan Ministry of Economy and the Saskatchewan Geological Survey, was one of the authors on both studies. Pipeline News spoke to her on April 14.

So how much oil is there in the Saskatchewan Bakken? The NEB study, using a recover factor of 6.9 per cent for Unit A and 6 per cent for Unit C, estimated 1.4 billion barrels of marketable oil, and an additional 2.9 trillion cubic feet (Tcf ) of marketable associated gas.

This was based on a recovery factor of 6 to 9 per cent for Unit A and 6per cent for

Unit C. While some companies are reporting recovery factors into the 20+ per cent range, the most likely recovery factors were used for basin-wide estimation.

Only the GSC report used production declined curve to estimate recovery factor.

Yang said their 1.4 billion barrel estimate is risk-adjusted from a staggering number of 70 billion barrels of the initial oil in place. The NEB study used risk factors of 1, 0.8, 0.2 for Viewfield, border and transition areas of Unit A, but 0.2, 0.8, 0.1 for theses area in Unit C. Two years ago the United States Geo-

logical Survey released its estimate of oil of Bakken in Montana, North Dakota, and South Dakota. While Yang said they did not release estimated on their original oil in place, they did estimate 7.4 billion barrel of undiscovered technically recoverable oil in the Bakken and Three Forks. The World Shale Oil and Gas Assessment by EIA estimated Canada’s portion of the Middle Bakken member would be around 1.6 billion barrels of technically recoverable oil.

The GSC study number were relatively close to those in the NEB report. The as-

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sessment indicated the mean recoverable oil is 1.45 billion barrels, while the associated natural gas would be 1.33 Tcf. The mean of the estimated initial oil in-place is 16.6 billion barrels.

Bakken production in southeast Saskatchewan had risen from approximately 629 barrels per day in 2004 (mostly conventional) to approximately 62,900 barrels per day in 2014 (mostly unconventional).

This is the first assessment for Saskatchewan of the Bakken.

“I think this number is very close to what we think,” she said.