Oil & Gas Inquirer April 2015

THIS ISSUE Tracking the carnage in the service industry

Western Canada's Exploration & Production Authority

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CONTENTS

APRIL.

in the news



Natural gas drilling expected to decline this year

regional news

 British Columbia

 Northeastern Alberta

 Southern Alberta

Better methods needed to capture Montney resource

Cenovus to cut 15 per cent of workforce

LGX gains momentum in Big Valley Formation

 Northwestern Alberta

 Central Alberta

 Saskatchewan

Peyto delays some winter drilling awaiting service price drop

Advantage cuts capex, reports strong Glacier results

TORC makes Saskatchewan acquisition, reports service cost decline

features Cover Feature

 

Getting connected (or plugging in) Industrial Internet could drive oilpatch efficiency, says GE

every issue



Stats at a glance



Political cartoon



Beating down costs in the Bakken Low prices and changing technologies drive efficiency in southeastern Saskatchewan



The great reckoning Bloodletting begins in service industry

Cover illustration: Linnea Lapp

OIL & GAS INQUIRER • APRIL 2015

3

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Editor’s Note Vol. 27 No. 4 EDITORIAL EDITOR

Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS

Lynda Harrison, Doug Hanson, Carter Haydu, Richard Macedo, Pat Roche, Maja Veljkovic EDITORIAL ASSISTANCE MANAGER

Tracey Comeau | tcomeau@junewarren-nickles.com

The hangover

EDITORIAL ASSISTANCE

Sarah Maludzinski, Sarah Munn, Jordhana Rempel, Megan Tilley CREATIVE CREATIVE SERVICES MANAGER

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Janelle Johnson | jjohnson@junewarren-nickles.com GRAPHIC DESIGNER

Linnea Lapp SALES SENIOR ACCOUNT EXECUTIVES

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Cheap money, high commodit y prices and the euphoria of an old-time oil rush have resulted in U.S. oil producers going on a five-year drilling and completions binge.

Oil production has climbed from 5.4 million bbls/d in 2009 to exit 2014 at 9.2 million bbls/d. In 2009, an average of 278 rigs were working throughout the year targeting oil formations. By yearend 2014, that number had climbed to around 1,540.

Western Canadian oil producers have followed a similar, if less pronounced, trajectory. Oil production, including condensates, climbed from 2.4 million bbls/d in 2009 to exit 2014 at almost 3.5 million bbls/d.

Total North American oil production has climbed by almost fi ve million bbls/d, or one million bbls/d annually, in the last fi ve years.

But the increase in production has come with increased costs. Since 2000, lifting costs (operations) have quadrupled globally to $21/bbl. Finding and development costs have followed a similar path, reaching $22/boe in 2013, according to IHS Energy.

IHS says the rising costs to find, develop and produce oil have resulted in producers making less money on a $100-barrel of oil in 2014 than they did on a $30-barrel of oil 15 years ago.

And now, with oil prices cut in half in the last six months due to oversupply and weak demand, the party is over and all indications are that the hangover is going to be long and painful.

The rig count targeting oil in the U.S. was down 43 per cent in March, with only 922 rigs actively drilling. In Canada, oilsands projects are being mothballed until prices recover. But work already started means production is expected to continue climbing throughout 2015, with the oilsands alone expected to add around 200,000 bbls/d of production in each of the next three years.

Predictions of U.S. oil growth are all over the map, ranging from 100,000 bbls/d to as high as one million bbls/d.

U.S. oil storage is building rapidly and is now at its highest level since 1982, and this doesn’t include non-traditional storage methods like the thousands of drilled but uncompleted wells that could quickly be brought on stream.

All this hangover production spells a long-term headache for North American oil producers and service companies. Exxon expects the price of oil to remain low over the next two years.

“I see a lot of supply out there,” he said at Exxon’s annual investor day.

There’s going to be a lot of pain as operators and suppliers take their medicine and deflate the cost structure in North America to survive in this low price environment.

But like with real hangovers, the only real cure will be time.

Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com

Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com

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Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

N EXT I S S U E May 2015 Our annual outlook for the oilfield manufacturing industry, along with trends in manufacturing technology. Plus tight oil and heavy oil plays in southern Alberta.

Want to sound off on any content in Oil & Gas Inquirer?

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Please mark them as ”Letter to the Editor” if you want them published.

OIL & GAS INQUIRER • APRIL 2015

5

FAST NUMBERS

308

625

Number of active rigs in Western Canadian Sedimentary Basin in late February 2015.

Number of active rigs in Western Canadian Sedimentary Basin in late February 2014.

Alberta completions

WCSB oil & gas completions

Source: Daily Oil Bulletin

Source: Daily Oil Bulletin OIL

GAS

D RY

SERVICE

Mar 









,

Apr 











May 











Jun 













Jul 





















M O NTH

OIL

GAS

OTHER

T O TA L

Mar 









Apr 









May 









Jun 









Jul 







MONTH

T O TA L

Aug 









Aug 

Sep 









Sep 









,









,

Oct 









Oct 

Nov 









Nov 









,

Dec 









Dec 









,

Jan 









Jan 











Feb 2015









Feb 2015









711

Wells drilled in British Columbia

Saskatchewan completions

Source: B.C. Oil and Gas Commission

Source: Daily Oil Bulletin

MONTH

WELLS DRILLED

C U M U L AT I V E *

MONTH

OIL

GAS

Mar 





Mar 









Apr 





Apr 









May 





May 









Jun 





Jun 









Jul 





Aug 





Sep 





Oct 





Nov 





Dec 





Jan 





Feb 2015

18

59

*Year-to-date

OTHER

TOTAL

Jul 









Aug 









Sep 









Oct 









Nov 









Dec 









Jan 









Feb 2015









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APRIL 2015 • OIL & GAS INQUIRER

Preliminary Engineering

PILOT PLANT

COMMERCIAL SCALE

Design, Construction and Operation

Detailed Engineering

from concept to commercialization

STATS

AT A

GLANCE

Drilling rig count by province/territory

Drilling activity: Oil & gas

Canada, March 11, 2015 Source: Rig Locator

Alberta, February 2015 Source: Daily Oil Bulletin

AC T I V E

DOWN

T O TA L

(Per cent of total)

Western Canada Alberta

AC T I V E







%

British Columbia







%

Manitoba







%

Saskatchewan







22%

WC TOTALS







%







%







%

Eastern Canada Quebec CANADA

OIL WELLS

Alberta

Feb 

Feb 

Feb 

Feb 

Northwestern Alberta









Northeastern Alberta









Central Alberta









Southern Alberta



46













TOTAL

Top operators by active rigs

Drilling activity: CBM & bitumen

Western Canada, March 11, 2015 Source: Rig Locator

Alberta, February 2015 Source: Daily Oil Bulletin

O P E R AT O R

ACTIVE RIGS

DEV

Progress Energy Canada



















Royal Dutch Shell

C OA L B E D M E T H A N E

EXP

Crescent Point Energy

Encana







Seven Generations Energy







Peyto Exploration & Development







Apache Canada







Husky Energy







Canadian Natural Resources







Cenovus Energy







GAS WELLS

Alberta

BITUMEN WELLS

Feb 

Feb 

Feb 

Feb 

Northwestern Alberta









Northeastern Alberta









Central Alberta









Southern Alberta









TOTAL









OIL & GAS INQUIRER • APRIL 2015

7

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IN THE

NEWS Issues affecting Canada’s E&P industry

Natural gas drilling expected to decline this year

By Richard Macedo

Weaker gas and liquids pricing is forcing operators to cut drilling plans.

Natural gas isn’t expected to be a saviour for western Canadian drilling activity in 2015 as weaker prices due to a warmer winter have operators lowering their spending forecasts for the year.

Oil prices have roughly halved over the past six months, while natural gas prices have also been weaker year over year, as part of a general swoon in the commodities sector.

AECO prices in January averaged $2.64/GJ compared to $4.09 during the same month of 2014. Last February, AECO averaged $7.85.

Frigid temperatures helped to push natural gas demand within Alberta to record levels early that month as the AECO price spiked to $25/GJ. The situation now is quite different and price forecasters are offering a more subdued outlook to start the year.

FirstEnergy Capital expects gas will average roughly half what it did last year while TD Securities at the end of January revised its AECO price assumption to $3.05/mcf, down five per cent from the previous forecast. Henry Hub was reduced to US$3.25.

The Petroleum Services Association of Canada (PSAC) is forecasting 1,270 gas wells

will be drilled in western Canada this year, down 987 from the 2,257 in 2014. In 2015, PSAC expects 395 gas wells in B.C., off by 259 from last year; 875 in Alberta, down 725; and none in Saskatchewan, compared to three in 2014.

Geoff Ready, senior oil and gas analyst with Dundee Capital Markets, said that there’s no question gas drilling will drop off in 2015.

“Weaker gas prices come into play, but so do weaker liquids pricing as some of the most economic plays were focused on liquids-rich gas,” he noted. “Corporate cash flows are also down significantly, reducing the availability of capital to drill any type of wells.

With weaker prices, drilling will be focused on defining plays for future exploitation rather than development itself, Ready said, noting that the Montney gas play is still being defined in many areas of northwestern Alberta and northeastern B.C. “Service costs are being reduced for everybody across the board,” he added.

“Low-cost producers who are continuing with existing drilling programs, such as Peyto Exploration & Development, will accrue the benefits of reduced service costs.”

In his monthly update, the president and chief executive officer of Peyto, Darren Gee, said that despite the fact lower oil prices will mean less revenue from condensate and pentanes, the overall effect is more positive than negative for the company.

“Remember, we’re 90 per cent natural gas, and natural gas prices have been low for awhile,” he stated. “So, we’ve already retooled our business to be profitable at these levels—most oil producers can’t say that.

“At the same time, however, we’ve been fighting underlying inflation in our capital costs, driven by rising oil prices,” Gee added.

“So, if our capital costs are driven more by oil and oil-related activity than they are gas, a lower oil price should translate into lower FD&A costs and a lower cost to add new production. We expect cost reductions in the order of 20 per cent from last year.”

Shut-in production could become a trend if prices stay low

By Carter Haydu

While some companies have announced production shut-ins in response to the current oil market, they are still relatively uncommon as they are something most producers would prefer to avoid, says an industry official.

But the longer crude prices remain low, the more likely producers will be to shut in wells, albeit on a case-by-case basis, says Gary Leach, president of The Explorers and Producers Association of Canada (EPAC).

“It is not a decision anyone will take lightly, but if this pricing environment persists through 2015 and people get the sense

OIL & GAS INQUIRER • APRIL 2015

9

In The News

it will be of longer duration than the optimists among us are hoping, then you will certainly see more of it.

“Shutting in current production is certainly not the first choice of most producers,” he said. “The most likely response would be curtailment of drilling activity.”

The most likely candidates for shutting in wells would be wells that have been drilled but not yet tied in and equipped to produce, he said. In those cases, companies might decide to not incur the additional costs of tying those wells in and producing them at the current, “dismal” oil prices.

Leach said, “For many of the wells today, which are completed horizontally and have big frac jobs performed on them, a lot of the production comes out in the first year, and a company must ask itself whether it wants to produce most of its well’s production over the entire life of that well at today’s prices.”

The EPAC president also foresees many companies deferring well workovers until it makes more economic sense to do so, provided they can operate safely and with no mechanical or safety issues.

10

APRIL 2015 • OIL & GAS INQUIRER

“If the well goes down and develops some issues with production, with the rods in the well or a pump downhole, if there are actual mechanical issues down the well requiring a workover, then that might be the time to close it,” he said. “I think companies will be looking very, very closely at saving costs and only doing work where they have to do it for operational and safety issues and regulatory compliance.”

He added, “Everyone is looking at their budgets rather carefully, and if things can be deferred for a bit, then they probably will choose to defer them.”

There are costs to shutting in a well, according to Leach, including regulatory compliance when the well is suspended. The less risky wells, including those with no sour gas and no flowing production, are relatively easy for the regulator to accommodate.

“However, there are costs associated with this and there are ongoing costs, too— just because you shut in production does not mean maybe there are not some obligations to mineral rights holders, and certainly there are continued obligations to municipalities for property taxes,” he said.

U.S. behind pipe to flood market late this year

By Pat Roche

Despite the drop in drilling due to the oil price collapse, U.S. natural gas output associated with oil and natural gas liquids (NGLs) production will continue to rise this year as wells awaiting pipeline construction are tied in, predicts Bentek Energy.

Those wells have combined production potential of between seven bcf/d and 10 bcf/d waiting to come on stream once pipeline projects are completed, estimates the Denver-based consultancy.

G over n ment st at ist ic s f rom la st summer showed there were 670 wells awa it i ng con nec t ion i n nor t hea stern Pennsylvania and 156 in central Pennsylvania, for a total of 826 in the two dry-gas areas, according to a Bentek presentation. Both are areas where drilling

In The News

currently has the worst economics due to lack of oil and NGL. In areas where liquids improve the economics—but generally not enough to produce an acceptable rate of return—some 1,166 wells are shut in due to pipeline constraints. According to Bentek, these shutins in liquids-rich areas consist of 476 wells in southwestern Pennsylvania, 235 in southern Pennsylvania and 455 in Ohio.

That brings the total wells awaiting pipeline construction to 1,992, and these wells have an estimated gas production capacity of between seven bcf/d and 10 bcf/d, Bentek analyst Thad Walker said.

As various pipeline projects already in the works are completed, five bcf/d of new pipeline capacity is scheduled to come on stream later this year, worsening an already-glutted North American gas market, Walker said.

Bentek estimates this will lead to roughly 1,500 wells being tied in by year’s end, leading to a tsunami of new production hammering gas prices, similar to what happened last fall when a wave of new pipeline expansions were completed.

With supply expected to overwhelm demand, Bentek forecasts an average 2015 gas price of US$2.56/mmBtu—lower than the recent NYMEX forward curve of US$2.89/mmBtu. Walker expects the weakest gas prices to occur in December 2015 as backlogged wells come on stream. “The situation begins to improve once you get out into 2016 and you start to get more power burn.”

There are also a number of other industrial users with expansions coming on stream in 2016. But for this year, the big problem is the massive volumes of gas behind pipe. U.S. gas production in the past four to five years has largely been driven by the associated gas gains from oil and NGLrich plays, according to Bentek.

Oil-driven drilling has been hammered by the collapse in U.S. oil prices to about $50/bbl from $100. NGL economics have also taken a dive.

In the liquids-rich areas of the Marcellus shale play in the U.S. Northeast, Bentek estimates the half-cycle internal rate of return was about 44 per cent last October. It has since fallen to about 14 per cent—below

what Bentek describes as the minimum 20 per cent threshold needed for an acceptable return. While the backlog of wells already drilled is the biggest price damper, Bentek said producer hedges and increased drilling efficiency will keep gas prices low this year.

Bentek expects U.S. gas output to grow by 4.2 bcf/d in 2015 with the Northeast contributing the lion’s share through 2015 and into 2016 due to the backlog of wells awaiting tie-in.

Over the course of 2015, U.S. gas output is expected to stay relatively flat until late 2015 when another wave of pipeline expansions come on stream in the Northeast.

Bentek ran a gas forecast scenario for six major U.S. oil plays—the DJ, the Powder River, the Bakken, the Eagle Ford, the Permian and the Anadarko.

Under its base case, Bentek currently has 19 bcf/d in associated gas coming from these six major oil plays. Bentek estimates it would take an oil price below $50 for a sustained period to get a 50 per cent reduction in drilling in the six oil plays in 2015 and this would reduce their gas output to 17 bcf/d.

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BRITISH COLUMBIA WELL ACTIVITY FEB/14

FEB/15

Wells licensed





FEB/14

FEB/15

Wells spudded





Rigs released

▼

▼

FEB/14

FEB/15



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British Columbia

▼

Source: Daily Oil Bulletin

Better methods needed to capture Montney resource

By Pat Roche

Too much of the Montney’s enormous prize will be left behind unless the industry gets better at extracting the hydrocarbons—both in the technical and non-technical senses.

That’s the message Jim Reimer, vicepresident of geoscience and technology at Painted Pony Petroleum, delivered during a Canadian Society for Unconventional Resources (CSUR) technical lunch presentation in February.

Painted Pony, which had average thirdquarter production of more than 14,000 boe/d, operates exclusively in the Montney Formation of northeastern B.C. Initial gas in place across the entire Montney may exceed 3,500 tcf. This supply is to anchor proposed LNG exports from the West Coast.

“The problem is we’re going to leave a lot of this gas behind if we don’t get better at extracting it,” Reimer said.

Putting the Montney into perspective, the Painted Pony executive said the tight over-pressured fairway is about 350 miles long and 75 miles wide. That works out to more than 25,000 sections of gas-charged

Montney. He noted there are a number of different well-spacing and hydrocarbonextraction ideas for the Montney.

“But if you were to develop three layers in the Montney and to develop them on four wells per section, that’s 12 wells per section. And if you say we’re just going to develop 50 per cent of that available area, we would drill, as an industry, 150,000 wells,” Reimer said. “If you look at current data sets, people are doing anywhere from 15 to 20 fracs per well. So hypothetically we’re going to do two to three million fracs to get that done. And if your costs are $300,000–$500,000 per frac stage, which is not an unrealistic number, we’re going to spend—as an industry to develop this— somewhere north of $1 trillion to $1.5 trillion.”

To put that in context, Reimer said, “Canada’s entire GDP last year was $1.8 trillion.

So we’re going to spend the equivalent of Canada’s GDP to develop this Montney.

That’s just to frac it.”

On the technical side, Montney producers are still working to optimize recoveries.

Challenges include wellbore parameters

Mapping out the Montney Play area

IP 30 (mmcf/d)

C5+ (bbls/mmcf)

EUR (bcfe)

Liquids (per cent)

Well cost ($Millions)

Drill credit ($Millions)

Septimus

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Blueberry/Inga

Source: BMO Capital Markets

such as total length, azimuth, the number of frac stages, length per stage, proppant tonnage and f luid volumes per stage, pumping rates, interwell spacing, and frac heights and half-widths.

At this point, Reimer said, it’s too soon to predict ultimate recovery rates from the Montney.

“I hear numbers that vary between 20 per cent recovery efficiency and 50 or 60 per cent recovery effi ciency. Can we get better than 50 or 60? I hope so. But a lot of it just has to do with putting enough drainage pathways, enough wellbores, in to properly drain the formation. That’s part of the technical challenge —the recovery challenge.”

Reimer said the ultimate goal is to develop a high-probability model of the stimulated reservoir volume geometry to ensure minimum “spoilage” in gas recovery. The optimal models are expected to vary regionally across the play fairway and also locally within the upper, middle and lower Montney.

One technique some companies, including Painted Pony, are trying is drilling wells in parallel pairs. “I think we were probably one of the fi rst in the northern Montney, but I think many other operators are trying it,” Reimer said.

Two gas wells are drilled at the same landing depth, reasonably close together (about 300–350 metres apart). The wells are completed sequentially and flowed back together.

“The idea is that some of the pressure that we induce into the formation from the completion stimulation is a constructive pressure interference and helps us get a better frac off, a better stimulation network, and therefore higher gas rates,” Reimer explained.

OIL & GAS INQUIRER • APRIL 2015

13

N.W.

NORTHWESTERN ALBERTA WELL ACTIVITY FEB/14

FEB/15

Wells licensed





FEB/14

FEB/15

Wells spudded





FEB/14

FEB/15





Rigs released

▼

▼

Northwestern Alberta

▼

Source: Daily Oil Bulletin

Peyto delays some winter drilling awaiting service price drop As a result of the commodity price downturn, Peyto said the costs of drilling and completing a typical Peyto Deep Basin horizontal well have now fallen by seven per cent and 13 per cent, respectively.

But while these cost savings are significant, the company said even greater savings are required to preserve the economic returns if current commodity prices persist. Peyto believes savings of up to 20 per cent can be achieved and once they have, the company will be pursuing development of its Deep Basin inventory even more aggressively.

“This is exactly the environment in which Peyto thrives—by being countercyclical to the industry and actively developing its asset base when both industry activity and costs are lower, resulting in improved returns,” the company said.

It said the rapidly falling service costs drove its strategic decision to deliberately postpone certain drilling plans in the fi rst six weeks of 2015.

In addition, gas transportation restrictions on TCPL’s Peace River Mainline system temporarily limited take-away capability, which meant Peyto was unable to bring on incremental volumes in any case.

Peyto said both of these factors contributed to lower production at the start of 2015 than was originally forecast. Transportation restrictions have since been removed, and with service cost reductions “mostly in hand,” drilling plans and production additions have resumed, the company said.

The company’s 2015 capital plans are to drill up to 130 net horizontal wells. This plan is contingent on the ability to drill through the traditional breakup period, similar to 2014, but that could change with unfavourable spring weather.

If the full cost savings are achieved as anticipated, then production from the new wells should be added for as little as $13,500/boe/d, the company said.

With this level of cost savings, Peyto said it would spend less than its $700-million to $750-million capital budget. The company said its high level of ownership and control ensures the pace of its drilling program can be adjusted quickly as market and weather conditions dictate.

For the first six weeks of 2015, production has averaged 82,000 boe/d, with 3,000 boe/d shut in, mainly due to service interruptions on the TCPL system. Since Feb. 13,

2015, service has been restored and production has returned to 85,000 boe/d.

For 2015, InSite is forecasting the total base production—all wells on production at Dec. 31, 2014—will decline to about 54,200 boe/d by December 2015. This implies a base decline rate of 36 per cent from December 2014.

This forecast decline rate is lower than the 2014 base decline of 38 per cent because the 2014 production additions represent a smaller proportion of total production than in the prior year. It is expected that the base decline rate will continue to shrink as the company’s total production grows.

In 2014, Peyto was successful in replacing 183 per cent of annual production with new proved producing reserves, resulting in a 13 per cent increase in total proved producing reserves.

Fourth-quarter production, however, increased by 24 per cent to 83,251 boe/d from 67,296 boe/d a year earlier, which had the effect of reducing the proved producing reserve life index to 6.6 years from 7.2 years.

Peyto said its reserve life index in all categories has continued to decline since the adoption of horizontal multistage fracture well designs due to the large initial production rates combined with steep initial declines.

Peyto Exploration Deep Basin well performance by producing zone Cardium

Notikewin

Upper Falher

Middle Falher

Wilrich

Bluesky

Brazeau Falher

Brazeau Wilrich

Well costs (D and C, $Millions)

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Source: Peyto Exploration November presentation

OIL & GAS INQUIRER • APRIL 2015

15

Northwestern Alberta

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APRIL 2015 • OIL & GAS INQUIRER

Tourmaline cuts spending by another $200 million

By Richard Macedo

Tourmaline Oil is lowering its capital-spending outlook again, by $200 million, on a deferral of facility expansions.

This is the second $200-million reduction after announcing its initial budget for 2015 in November.

The original 2015 exploration and production capital program of $1.6 billion was reduced to $1.4 billion in December as the operated drilling program for 2015 was reduced from 20 to 16 rigs. This reduction did not affect 2015 production estimates as guidance for production growth was built on the basis of a 15-rig program.

The company has elected to further reduce the 2015 capital program by $200 million to $1.2 billion through a reduction in 2015 facility expenditures. This reduction does not affect 2015 production guidance as 2014 exit facility processing capacity matches anticipated 2015 production. The deferred projects include facility expansions at Sundown B.C., Wild River, Alta.— 100 mmcf/d now redesigned for 50 mmcf/d expansions in 2015 and 2016, respectively— and Columbia, Alta.

The infrastructure expenditures that remain in the 2015 program will yield a 2015 exit company-operated processing capacity of 200,000 boe/d, sufficient to accommodate preliminary 2016 production estimates.

“There is no further reduction in drilling plans or activities as part of the latest capex plan, and the reduction we announced was entirely focused on deferring facilities projects,” Brian Robinson, the chief financial officer, said.

The company currently has 170,000 boe/d of facilities capacity that it owns and operates, which he said is sufficient to process the volume growth that the company plans for 2015.

“By the end of 2015, the company will have total processing capacity of 200,000 boe/d which will provide adequate capacity to handle growth in 2016,” Robinson said.

Tourmaline is now expecting 2015 cash flow of approximately $1.1 billion including existing commodity hedges.

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Tourmaline drilled the five highest-deliverability gas wells in Alberta in 2014.

Capital spending in 2014, net of proceeds on dispositions, was $1.8 billion, including the operation of a 20-rig program from May through to year-end and a $789.4-million facility and infrastructure construction program. The drilling program included the drilling of 176.7 net wells in calendar 2014, 35 wells ahead of estimates due to steadily improving drilling efficiencies. These additional wells added approximately $190 million to the second-half 2014 capital budget estimates and are expected to provide significant additional production volumes from first half 2015 tie-ins.

The large 2014 facility-and-infrastructure construction program yielded an exit 2014 company-operated total processing capacity of 170,000 boe/d, sufficient for 2015 production growth estimates (164,500 boe/d).

The Alberta Deep Basin drilling-rig fleet will be reduced to 10 rigs from 14 for the balance of 2015. Drilling targets will focus on multi-well pads in defined Wilrich and Notikewin sweet spots.

Tourmaline has drilled the five highest deliverability–reserve recovery gas wells in Alberta in 2014. The top well, Basing 02-01, recovered over one bcf in the first month of production and is the first well in an extensive new Wilrich sweet spot in the greater Banshee-Minehead plant fetch area.

The Montney program in SunriseDawson-Sundown will be reduced from three drilling rigs to two by spring breakup, with one rig scheduled to drill through

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Northwestern Alberta

breakup. Condensate production rates from the lower Montney turbidite wells drilled late in 2013 continue to average 75–100 bbls/mmcf. The company has several new wells to complete in this developing new regional opportunity.

Current production in northeastern B.C. is ranging between 35,000 and 40,000 boe/d. The company plans to reach the 43,000–45,000 boe/d production level in April 2015 and maintain this level for the balance of the year.

Tourmaline continues to operate three drilling rigs on the Peace River High Charlie Lake oil and gas play and will continue at this pace for the remainder of the year.

A recent pool extension well on the southwestern side of the regional pool came on production in late January at 850 bbl/d of oil with 1.2 mmcf/d of associated natural gas. This delineation well has provided a significant pool expansion and will be followed up with two multi-well pads post-breakup. Despite selling 25 per cent of the entire Peace River High complex late in 2014, Tourmaline grew Peace River High 2P reserves by approximately 48 per cent in 2014 after giving effect to the disposition.

The Spirit River 03-10 sour gas injection plant began operation during the fourth quarter of 2014 and has already led to significant operating cost reductions. Further cost reductions will occur in the first half of 2015 with the completion of the Mulligan battery and expansion of the 03-10 gas plant. These projects in aggregate are expected to reduce overall operating costs in the complex to $10–$11/bbl, making the Charlie Lake play one of the lowest-cost oil developments in North America.

Birchcliff cuts spending to $266.7 million

Birchcliff plans on spending $50 million on gas processing infrastructure in 2015.

Responding to lower commodity prices, Birchcliff Energy has become the latest exploration and production company to reduce its preliminary capital budget for 2015.

The company has announced a budget of $266.7 million, which it expects to fund primarily using internally generated funds flow and available credit facilities.

A total of $164.7 million, including $13 million carried forward from 2014, is allocated for drilling and development.

I n add it ion, t he budget i nc lude s $59 million for infrastructure, of which about $50 million in 2015 is for the PCS gas plant Phase V expansion. It also provides $18.1 million for production optimization and $11 million for land and seismic.

Birchcliff expects to drill 25 (24.5 net) wells in 2015 and anticipates 2015 annual production to average between 38,000 and

40,000 boe/d, an increase of 16 per cent year over year.

These expectations are based on a forecast average WTI price of US$60/bbl of oil and AECO price of C$3/GJ of natural gas during 2015. Birchcliff said it will adjust its capital budget to respond to changes in commodity prices and other material changes in the assumptions underlying its 2015 capital budget.

The company’s preliminary capital budget released in November had called for approximately $450 million to $500 million in capital spending this year, including about $110 million in infrastructure, and targeting exit production of approximately 48,000 to 50,000 boe/d. The preliminary guidance was based on a forecast WTI price of US$90/bbl of oil and AECO price of C$4/GJ.

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NORTHEASTERN ALBERTA WELL ACTIVITY FEB/14

FEB/15

Wells licensed





FEB/14

FEB/15

Wells spudded





FEB/14

FEB/15





Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

N.E.

Northeastern Alberta

Cenovus to cut 15 per cent of workforce

By Lynda Harrison

Cenovus Energy is preparing for a rough year ahead by cutting its workforce by 15 per cent, or about 800 positions—mostly contractors—after a fourth quarter that saw higher production but a deeper net loss in earnings.

The company’s net loss for the fourth quarter of 2014 widened to $472 million while cash flow and revenue fell as production climbed to 296,010 bbls/d.

In 2014, profit improved to $744 million as revenue and output rose but cash flow dipped.

Expecting much greater volatility in oil prices for the foreseeable future, the company is preserving its cash by moderating its growth and reducing its workforce, Brian Ferguson, president and chief executive officer, said.

E a rl ie r t h i s yea r, t he compa ny announced it would defer work on Foster

Creek phase H and at Christina Lake phases G and H. “These actions are prudent and will help protect the financial resilience of Cenov us w ithout compromising our future,” said Ferguson.

Noting that crude oil prices fell between 40 and 50 per cent between Sept. 30 and the end of the year, Ivor Ruste, chief fi nancial officer, said that despite these conditions, fourth-quarter upstream operating cash flow was four per cent higher than in 2013 due to higher hedging gains, increasing crude oil production and lower operating costs.

Cenovus said solid production growth in 2014 was driven by strong performance at its oilsands projects and while the average benchmark price for Brent crude and WTI decreased year over year, the company’s upstream operations benefited from

Cenovus is deferring work on Foster Creek Phase H and Christina Lake phases G and H in response to low prices.

higher average prices for its heavy crude oil sold as Western Canadian Select.

These factors, along with a weakening in the Canadian dollar versus the U.S. dollar, contributed to 19 per cent higher upstream operating cash flow compared with 2013.

This increase was more than offset by a sharp decline in operating cash flow from refining, largely due to lower average market crack spreads and higher heavy crude oil feedstock costs.

Refining operating cash flow was a loss of $323 million for the fourth quarter.

In 2014, Cenovus achieved 25 per cent production growth from its Christina Lake and Foster Creek oilsands operations, averaging more than 128,000 bbls/d net (256,000 bbls/d gross).

Christina Lake production increased 40 per cent to average about 69,000 bbls/d net after expansion phase E reached design capacity in early 2014.

The facility also achieved a consistently high utilization rate for the year.

Foster Creek production averaged more than 59,000 bbls/d net in 2014, up 11 per cent from the previous year.

The production increase was the result of improved plant performance, continued optimization efforts and increased production from wells using Cenovus’s Wedge Well technology.

The company achieved first production from the phase F wells in September.

Phase F, which added 30,000 bbls/d of g ross produc t ion c apac it y, a nd wa s producing approximately 4,000 bbls/d net (8,000 bbls/d gross) at the end of the year.

“We’re pleased with the strong performance of our oilsands projects. Both Christina Lake and Foster Creek delivered reliable production with lower non-fuel OIL & GAS INQUIRER • APRIL 2015

19

Northeastern Alberta

operating costs per barrel and improved safety performance compared with 2013,” said John Brannan, executive vice-president and chief operating officer. “During this current period of lower oil prices, we’re focusing on achieving additional cost savings to help keep our projects among the most cost efficient in the industry.”

Christina Lake continued to perform well in January with production averaging almost 77,000 bbls/d.

The steam to oil ratio (SOR) was 1.8 for 2014, similar to 2013.

Total operating costs at Christina Lake were better than the company ’s expectations at $11.20/bbl for the year, a 10 per cent decline from $12.47/bbl in 2013 and below its 2014 guidance of $12/bbl. The decrease was primarily due to increased production and a decline in fluid, waste handling and trucking costs.

Foster Creek production exceeded the company’s guidance for the year, averaging 59,172 bbls/d net in 2014, 11 per cent higher than in 2013. The increase was primarily due to improved performance at the operation’s facilities, optimization efforts and increased production from wells using the company’s wedge well technology.

Fourth-quarter production was 68,377 bbls/d net, up 30 per cent compared with the same period in 2013. The strong operational performance continued in January with production averaging approximately 72,000 bbls/d.

The SOR at Foster Creek was 2.6 in 2014, compared with 2.5 in 2013. The SOR is expected to range between 2.6 and three while expansion phases F and G are ramping up. After ramp-up, the SOR is expected to drop below 2.5.

Existing oilsands projects expected to plow through low price environment

By Lynda Harrison

Although many oilsands developers are cutting their capital budgets, projects well under way will not only survive current and expected low oil prices but will also see their costs fall, while smaller, nascent projects will be delayed and deferred, said industry analysts.

There’s no way oilsands mines will shut down, regardless of near-term oil prices, because their costs are largely fixed and some revenue is better than no revenue, they said.

“It’s a fi xed-cost game,” Michael Dunn, an analyst with FirstEnergy Capital, said.

The projects’ owners would only consider shutting down those assets if they believed that the long-term price of oil would be below their cost thresholds, and also that the cost of permanently laying off staff and funding reclamation and abandonment liabilities was expected to be less than anticipated future operating losses, said Dunn.

In the 1980s, Syncrude Canada and Suncor Energy experienced a few years when oil prices were below their sustaining cash costs, but they continued to operate, he noted.

According to Dunn, the cost structure in the Athabasca oilsands region has more than doubled in the past 10 years due to factors such as continued salary escalation, labour availability and lower capacit y utilization. He expects that while infl ationary pressures will recede w it h lower oil pr ices, some modest

cost-infl ation pressures will remain and improved production rates, spreading fi xed costs over more barrels, are the only obvious means of off setting those costs.

Dunn estimates that Canadian Natural’s Horizon mine needs a WTI price of around $60/bbl (US$52/bbl) to generate positive, free cash flow—assuming zero current tax expense—before funding dividends and growth projects.

The estimated threshold oil prices for Syncrude and Suncor appear to be about $68/bbl and $70/bbl, respectively (US$59/bbl and US$61/bbl, respectively) assuming an 87-cent U.S./Canadian dollar exchange rate.

Imperial Oil does not disclose its costs for the Kearl mine.

The “free-cash-flow-neutral” WTI price for most producing SAGD projects is likely around $43–$55/bbl, Dunn estimates.

However, while mining projects such as Suncor’s Fort Hills, Kearl Phase 2 and the Horizon expansion will go ahead, their rate of growth may slow in the next three to four years, according to Dunn.

Horizon has lower costs than Suncor and Syncrude projects because it’s a newer development and does not have legacy tailings ponds to reclaim. Also, it has better capacity utilization than the others and lower royalties because it has not reached payout, he said.

Horizon’s cost advantage is expected to grow for the next few years as it completes

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APRIL 2015 • OIL & GAS INQUIRER

Northeastern Alberta

SAGD operations need prices of $43–$55/bbl to break-even.

the Phase 2/3 expansion—estimated to occur in late 2017—and bring with it significant unit-cost reductions, said Dunn.

He expects Syncrude’s sustaining capital costs to decline by about $4/bbl after 2015 and to remain at that level for the following few years because there will be minimal major non-growth project spending outside of regular maintenance capital.

The effect of low oil prices will depend on the type of project and how far along it is in the process, said Todd Hirsch, chief economist at ATB Financial.

For the large mining projects that have either been operating or have already been under construction for years, this will be less worrisome, he agreed.

“Obviously it’s not good news,” said Hirsch. “Everything is going as planned on those operations because those projects

are looking at 30-year time horizons for oil. They’re not going to start and stop with what’s happening now. It’s still bad news for them, obviously, because it means less cash flow for the company, but it won’t be as disruptive to their capital expenditure plans and their operations.”

For example, Imperial’s Kearl Phase 2 and ConocoPhillips Canada’s Surmont 2 SAGD project are scheduled for completion this year, he said.

“But where we will see more immediate hits are on a lot of the smaller projects that are only in development stages or proposal stages,” said Dunn.

Royal Dutch Shell, for example, has announced that it is delaying a final investment decision on the third and fourth phases of its Carmon Creek in situ oilsands project; the first two phases are under construction.

According to Hirsch, 164 oilsands projects are planned or proposed. Their owners, along with those whose projects are in the early stages of development, will have to decide if they can proceed in this environment.

He declined to speculate on which oilsands projects might be cancelled or delayed but said that proposed SAGD operations that are more technical, more expensive and smaller in scope will have difficulty borrowing money and will be the fi rst to be cancelled, postponed or, at the very least, delayed.

“The problem is, they don’t have cash flow right now, and it’s probably really difficult for them to go to their lenders and say, ‘We need more money,’ because I think a lot of their lenders are going to be saying, ‘Yeah. Haha. Not so much.’”

According to Hirsch, generally, already operating projects have costs of less than $47/bbl but start-up oilsands mines need oil prices of about $80/bbl to break even, while in situ operations need about $90/bbl.

Part of the problem is that oilsands’ costs have escalated in the past 10 years to the point where, even when oil prices were $90/bbl, potential operators questioned whether they could make a go of it, he said.

“So what will happen now—obviously $47 is too low for almost every one of them except the ones that are already operating— [is] we’ll see costs kind of ratchet down.

They won’t fall as quickly as oil prices have fallen, but they will gradually start to ratchet their way down as contractors and even labour [will] get hungrier, and the bids will come in lower.”

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OIL & GAS INQUIRER • APRIL 2015

21

SOUTHERN ALBERTA WELL ACTIVITY FEB/14

FEB/15

Wells licensed





FEB/14

FEB/15

Wells spudded





FEB/14

FEB/15





Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

S.A.B. Southern Alberta

LGX gains momentum in Big Valley Formation

LGX believes it has 20-plus sections prospective in the Big Valley Formation.

LGX Oil + Gas is encouraged by recent completion results achieved in the Big Valley Formation (Three Forks) in southern Alberta.

In November 2014, the company drilled two horizontal wells into the Big Valley Formation (12-02-008-24W4 and 06-36008-24W4). The total capital expenditures for the two wells came in on budget at approximately $14 million.

The 12-02 well was drilled with a 1,402metre horizontal lateral and was completed with a 20-stage fracture stimulation. The well was put on production in late November and averaged 315 bbls/d of light oil for the first 30 days of production. LGX has a 100 per cent working interest in the well prior to recovery of 200 per cent of the drilling, completion, equipping and tie-in costs, at which point its interest will revert to 80 per cent.

The 06-36 well was drilled with a 1,134metre horizontal lateral and was completed with a 20-stage fracture stimulation. The well was also put on production in late November and averaged 185 bbls/d of light oil for the first 30 days of production.

Water cuts are higher than the off setting wells, indicating that load fluid is still being recovered from the well and maximum oil productive capability has not been achieved to date. LGX has a 100 per cent

working interest in the well prior to recovery of 200 per cent of the drilling, completion, equipping and tie-in costs, at which point its interest will revert to 80 per cent.

The latest two wells, combined with previous production results, confirm that the Big Valley Formation continues to be prospective in the area. LGX believes that 20-plus sections of its land are prospective for the Big Valley.

Both wells encountered significant hydrocarbon shows in the overlying Banff Formation as indicated by drill cuttings, gas detector readings and strong oil kicks while drilling through the zone. The additional oil shows, as well as further geological and seismic interpretation and analysis, confirm the potential for a second play in the shallower Banff Formation.

An operator with lands immediately offsetting LGX acreage to the north has achieved strong production results in the Banff Formation. Further drilling is required to confirm the extent of both plays and to hold lands under LGX’s agreement with the Blood Tribe First Nation.

Based on field estimates and subject to fi nal, audited results, the company’s average daily production in 2014 was approximately 860 boe/d, and LGX achieved a peak rate of production of more than 1,200 boe/d in December.

The average and exit rates of production were below previous guidance due to delays in completion timing as the 2014 wells were drilled from the same pad and completion operations could not begin until both wells were drilled.

The company said it is currently formulating a capital budget for 2015 in the context of the current challenging oil price environment and expects to announce the capital budget and associated 2015 production guidance in the near future.

Traverse cuts spending to $15 million Traverse Energy has joined the long list of producers who have reduced capital spending plans for 2015, announcing yesterday it would cut its exploration and development budget to $15 million from $34 million.

The company had announced its initial plans late last year.

The company’s drilling program for this year has been reduced from 14 wells, including seven horizontals, to an estimated seven wells, including two horizontals. The 2015 drilling program will continue to focus on light oil projects at Coyote and Michichi in southern Alberta.

The budget is to be financed by cash flow and new equity issues or debt where appropriate.

In 2014, Traverse drilled 14 wells resulting in nine oil wells and five natural gas wells. At the end of 2014, seven oil wells and three gas wells had commenced production with the remaining wells completed and awaiting tie-in.

The Coyote battery expansion was completed in the third quarter with clean oil shipments beginning in late August. The facility is licensed to treat up to 2,000 bbls/d of oil and water and four mmcf/d of gas. At Turin, Traverse completed the installation of a booster compressor at the central battery. Total capital expenditures for 2014 are estimated at $31 million.

The fi rst two horizontal wells drilled in the Coyote Ellerslie pool were completed in October and started production in mid-November. The first well completed averaged 173 boe/d (83 per cent oil) from the beginning of testing to the end of January.

OIL & GAS INQUIRER • APRIL 2015

27

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SASKATCHEWAN WELL ACTIVITY FEB/14

FEB/15

Wells licensed





FEB/14

FEB/15

Wells spudded





FEB/14

FEB/15





Rigs released

▼

▼

▼

Source: Daily Oil Bulletin

TORC makes Saskatchewan acquisition, reports service cost decline TORC Oil & Gas has agreed to acquire light oil assets, which are complementary to the company’s existing conventional assets in southeastern Saskatchewan.

The strategic acquisition includes over 1,550 boe/d (94 per cent light oil and liquids) of high-quality, low-decline, strong netback, light oil producing assets. Total consideration for the acquisition is approximately $128 million, before adjustments.

The acquisition is consistent with TORC’s strategy to capitalize on opportunities to enhance the quality of its asset base throughout the commodity price cycle. The acquired assets improve TORC’s decline profile, operating netback and light oil drilling inventory. The assets are 94 per cent light oil and liquids and have an average decline rate of approximately 20 per cent, providing a dependable free cash flow stream to further strengthen TORC’s disciplined growth plus sustainable dividend business model.

Additionally, TORC has identified approximately 50 (net) high-quality conventional light oil drilling locations on the acquired assets that will provide some of the highest relative economic returns in the Western Canadian Sedimentary Basin in all commodity price environments, according to the company.

The acquisition includes proved developed producing reserves of 2.8 million boe and total proved reserves of 4.4 million boe, with proved-plus-probable reserves of 5.9 million boe. Average crude quality is 36 degrees API, with ownership of over

S.K. Saskatchewan

135 square kilometres of 3-D seismic data and 50 net undrilled locations.

“The acquisition complements our conventional light oil platform and provides a strong and stable cash flow base further strengthening the sustainability of our business model while the high-quality drilling inventory will enhance our capital program for years to come,” said Brett Herman, president and CEO. The acquired assets have been conservatively managed with a long-term focus by a private oil and gas company in southeastern Saskatchewan that has an operating history of over 40 years. The assets have a longestablished decline profile of approximately 20 per cent, further solidifying TORC’s underlying production base. With the addition of the acquired assets, TORC’s decline profile improves to 24 per cent from 25 per cent.

The acquired assets are weighted 94 per cent to light oil and liquids, providing for a strong operating netback and increasing the company’s light oil and liquids weighting to over 86 per cent from 85 per cent.

TORC has identified approximately 50 (net) top-tier conventional light oil development drilling locations on the acquired assets. The assets have a 90 per cent average working interest and are 99 per cent operated, providing control over the development of the acquired assets. The majority of the identified locations are low-risk infi ll locations in established high-quality light oil pools, which are expected to provide attractive economics even in a lower commodity price environment.

With a low decline profile and highquality inventory, TORC estimates that it can maintain the production from the acquired assets by drilling five wells per year. With minimal capital reinvestment required, the acquired assets are expected to provide an ongoing positive free cash flow stream with a 10-year, high-quality drilling inventory.

TORC has elected to maintain the prev iously a n nou nced 2015 budget of $125 million. While the capital budget

spending amount is unchanged, the capital allocation includes the drilling of a number of high-quality locations on the acquired assets that are highly economic even in the current oil price environment. The addition of these locations will reduce TORC’s overall estimated corporate capital efficiency to approximately $38,000/boe/d from $40,000.

Service cost savings experienced early in 2015 range from five to 10 per cent.

TORC’s 2015 budget currently does not take into account any such anticipated reductions in service costs. Should a low oil price environment persist, substantial unbudgeted service cost reductions would be expected. Of TORC’s $125 million capital budget, 25 per cent is expected to be spent in the first quarter with the majority of the remaining capital to be spent in the second half of 2015. In addition, the remaining capital expenditures are fully discretionary, providing significant flexibility to the capital program.

Pro forma the acquisition, TORC has the following key operational and financial attributes: 2014 exit production of over 11,900 boe/d, average production for

TORC has identified 50 top-tier drilling locations in the acquired lands in southeastern Saskatchewan.

OIL & GAS INQUIRER • APRIL 2015

29

Cover Feature

GETTING

CONNECTED (O R P L U G G I N G I N )

I N D U S T R I A L I N T E R N E T CO U L D D R I V E O I L PAT C H E F F I C I E N C Y, SAYS G E

BY DARRELL STONEHOUSE

Illustration: Linnea Lapp

IN THE LAST DECADE, the consumer-driven Internet has grown into a $1-trillion industry with three billion users connected worldwide.

In the next decade Bill Ruh, vicepresident of software for GE Research, expects this revolution to come to the industrial market, resulting in 50 billion machines connecting together and creating $1 trillion in revenues.

“The physical world and the digital world are going to come together like never before,” Ruh told an audience at GE’s Minds + Machines seminar in Calgary in February.

The oil and gas industry stands to be a major beneficiary, as field and plant devices are connected and the huge amount of data they provide is gathered and analyzed, added Ashley Haynes-Gaspar, general manager, software and services, GE Oil & Gas. Haynes-Gaspar said the arrival of connectivity to the industry promises improved equipment reliability, improved equipment availability, better operational efficiency and project optimization opportunities.

“Project optimization is the holy grail,” she said. “You get more oil out of the earth

faster. We believe there is a six to eight per cent potential increase in production available to the oil and gas industry.”

“You can make a lot of money off of zero downtime and zero mistakes,” added Ruh.“On maintenance, the impact is huge.”

But getting there is going to be a step-by-step process said Ruh. The keys to making it happen are connecting equipment to the Internet, developing the software and analytics to manage the reams of data they deliver, and using that data to improve operations.

OIL & GAS INQUIRER • APRIL 2015

31

Cover Feature

Thanks to the cell phone industry, the cost of sensors and other technologies is now low enough to connect billions of machines to the virtual world, explained Ruh. “The technology is here, and the cost of entry is low,” he said. “What our industrial customers want to know is: ‘How do I link up my assets and devices, and how do I monitor, manage and maintain my machines?’

They want more control. There has to be interconnectivity between different manufacturers. And they want greater real-time operational intelligence.”

This real-time operational intelligence will come from gathering reams of data and analyzing that data for trends, said Ruh. “Everything will be about analytics,” he explained.

Analytics is basically the hunt for meaningful patterns in huge amounts of data. It uses mathematics, statistics, computer programming and research about the operations in question to quantify performance. The patterns found in the data, when analyzed, can be used to predict future performance and develop risk management plans for everything from a valve in a gas plant to entire operations of a given oil or gas play.

The people who specialize in analytics are called quants, and they are in short supply, said Ruh. Part of the challenge in connecting oil and gas operations together is the huge volume of data produced by equipment in the field and processing plant, said

Haynes-Gaspar. While consumer I nter net memor y needs a re measured in gigabytes, the oil and gas industry’s data comes in terabytes and petabytes.

“A gigabyte is seven minutes of [high-definition] video. A petabyte is 13.3 years of [high-definition] video,” she explained for comparison.

In the past, information technology suppliers like GE have tried to overlay complete data gathering and analysis solutions on oil and gas operations with limited success.

GE’s current formula is to mimic the applications-based system common in consumer cell phones and tablets to break down the process into manageable parts.

“There will be hundreds of different industrial apps you will apply,” predicted Ruh. GE is also using the model consumer Internet start-ups pioneered when bringing new applications to market.

“We’re creating a minimally viable product and then continually enhancing it and then continually learning and enhancing,” he said.

GE has already seen some success in applying its mix of the industrial Internet, analytics and software to the power industry for optimizing wind turbines. The traditional method of optimization was to use models ahead of time.

“We asked, ‘What if you optimize based on history?’” said Ruh. “The result was a five per cent increase in energy output and 20 per cent more profit with no physical change to the turbine.”

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The intelligence gleaned from unparalleled volumes of data are being leveraged to improve production, increase recovery, predict potential disruptions and reduce environmental impact.

Decision making and operational and business performance that affect the cost of production can be greatly improved by using information technologies to help integrate operations. From the discovery of new reserves to maximizing oil yields, companies can take advantage of recent innovations in analytics to better manage and organize data, extract insight and increase productivity— saving them billions year after year.

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For instance, analytics using real-time data have enabled operators to detect submersible pump failures and pipeline leaks for some time. So what’s different now? Three things: data-driven models that examine hundreds of variables; the ability to insert models into flowing streams of real-time data and the ability to predict— with a high degree of accuracy—an impending failure that will disrupt production.

With more visibility into overall performance, operators can gain insight from shifting unplanned to planned work that enhances forecasting and leads to quicker responses, vastly improving decisions, actions and outcomes.

One mining organization uses predictive analytics to improve machine performance while reducing downtime and costs. They found that equipment downtime and maintenance fees were major challenges for operators and manufacturers. By using technologies in big data and analytics, the company expects to improve the efficiency of machinery through datadriven predictive maintenance. In real time, advanced and predictive insight from remote monitoring and machine diagnostics can help identify new and continuous improvement opportunities for equipment, increase machine productivity and lower operating costs.

In shale oil operations in the Eagle Ford area of Texas, operators insert analytical learning models into petabytes of data streaming off well sensors, creating a game changer for oil drilling. Integrating analytics within shale operations has yielded insights resulting in increased productivity, reduced incidents where drill strings are lodged down

drilling holes and greater detection of failures due to pipe buildup, just to name a few.

Groundbreaking cognitive computing systems can provide further insights to improve performance outcomes while lowering costs. These systems assist in differentiating and analyzing large amounts of data. Cognitive computing can determine correlations, create hypotheses resulting from experiences and present confidenceweighted, evidence-based responses.

By making sense of that information and learning from experiences, these cognitive systems naturally interact with people and extend their capabilities far better than any other technologies available today.

In the oil and gas sector, cognitive computing can assist hydrologists, geologists, geophysicists, engineers, planners and developers improve decisions and create higher quality outcomes. Cognitive computing can help accelerate oil and gas research projects by combing through thousands of experiments and findings to suggest possible outcomes. A cognitivecomputing assistant can help researchers establish an affordable development plan, schedule assessments in an early stage and identify risks and rewards.

A Spain-based global energy company is using cognitive computing to explore applications that help optimize strategies for drilling wells. In the future, the company foresees other organizations setting up physical locations dedicated to cognitive technologies that work to improve decision making of all types.

In the oilsands, it is becoming more important for the industry to improve monitoring methods that can assess the

impact of oil production. By applying the power of big data and analytics, researchers can better understand cumulative impacts of operations and make predictions that greatly enhance decisions and ultimately reduce environmental risks.

Canada’s Oil Sands Innovation Alliance is currently collaborating with members and associate member technology companies to dramatically improve environmental performance using new and innovative technologies.

Researchers are using inexpensive remote sensors to feed scientific models and in-stream computer algorithms to determine environmental concerns. By gathering better insight and answering concerns associated with energy production and environmental performance, these individuals are using advanced streaming analytics software in real time to gather information that allows them to detect, visualize and predict changes in the health of the environment.

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OIL & GAS INQUIRER • APRIL 2015

33

Feature

W

ith oil prices halved in the last seven months, it is little surprise that activity expectations are down in southeastern Saskatchewan oil country.

Yet despite oil prices hovering around US$50/bbl, money is still being spent in the Bakken and Torquay tight oil plays and conventional oil plays in the region.

Crescent Point Energy, by far the biggest operator in southeastern Saskatchewan, plans on investing $725 million in the region this year, drilling almost 300 wells.

Crescent Point expects to spend approximately $408 million in the Viewfield Bakken play in southeastern Saskatchewan, including drilling approximately 185 net wells.

In the Flat Lake oil resource play, the company plans to spend $188 million, drilling approximately 44 net wells.

In the Torquay play at Flat Lake, Crescent Point said it is generating

strong rates of return, even at current oil prices.

In the company’s conventional assets in southeastern Saskatchewan, Crescent Point plans to spend approximately $129 million to drill approximately 68 net wells. Approximately 40 per cent of these wells are expected to be drilled on lands acquired by the company in 2014. These conventional assets offer high rates of return even at low oil prices and typically require reduced capital expenditures and no fracture stimulation to achieve high levels of production.

The company’s waterflood plans for 2015 include the conversion of 30 producing wells to water injection wells in the Viewfield Bakken play. The water injection conversions implemented to date have reduced decline rates and increased recovery factors in the play.

The company also plans to initiate its first waterflood pilot in the area targeting the Torquay zone in mid-2015.

Legacy Oil + Gas is also spending in southeastern Saskatchewan, with plans to invest $150 million. The majority of the capital spending will be allocated to the Taylorton/Pinto area at $100 million. Legacy plans on spending $37 million at Steelman and another $18 million at Manor/Wordsworth.

In all, the Petroleum Services Association of Canada is expecting more than 750 wells to be drilled in southeastern Saskatchewan in 2015, compared to 920 last year.

The big differences this year will be operators are expecting to drill and complete wells at bargain rates, and they will be looking for technological advances to further reduce costs while increasing production.

Crescent Point’s 2015 budget assumes an initial 10 per cent reduction to service costs. Based on conversations to date with its service providers, the company anticipates that even greater

beating down COSTS IN THE BAKKEN low prices and changing technologies drive efficiency in southeastern saskatchewan

BY DARRELL STONEHOUSE

34

APRIL 2015 • OIL & GAS INQUIRER

Feature

cost reductions are very likely if a low oil price environment persists.

“When prices fell dramatically in 200809, we were able to realize a 30 per cent reduction in our Bakken drilling and completions costs,” said the company’s president and chief executive officer, Scott Saxberg.

“We’ll be working hard with our service providers and fully expect to see rates come down even more than they already have.”

In addition to improving its capital efficiencies, Crescent Point is also working on drilling and completion technologies that can potentially add to production and reserves in a cost-efficient manner. Crescent Point continues to refine its cemented liner completion techniques in the Viewfield Bakken, which has resulted in increased production and lower corporate declines.

The company has been using cemented liners with 25 fracturing stages exclusively in the play since 2013 with excellent results, said Neil Smith, chief operating officer of Crescent Point, last fall.

“About three years ago, we moved from the packer system to cemented liners,” Smith explained. “Basically what it does is allow you more precision as to where you place the frac, and it allows you to go back into wells and do as many fracs as you want. So we started out with eight stages with a cemented liner, and then we went to 16-stage cemented liner, then to 20, then to 25. We adjusted the amount of sand, the amount of water used, and did the correlation between productivity and reserves and cost. And we’ve seen a tremendous uptick in that.

“Also what has occurred, which we didn’t actually really expect, was that we got higher IPs [initial production rates] and lower declines because we are opening up more rock,” he added. “And opening up more rock opens up more matrix porosity within the rock, which then allows more oil to flow and flow at lower pressure change, which then allows for the flattening of the production curves. We’ve seen that across all of the plays that we’ve implemented this in. And to give you an example, I think the math on the Bakken is something like after 12 months instead of 50 bbls/d, it’s at 100 bbls/d. It’s a pretty tremendous outperformance relative to the older 16-stage completion technique.”

Smith said he believes the cemented liner system works better because it has fewer failed frac stages.

“A lot of it is simply that in the 16-stage packer system technique, you maybe got 10–12 of the fracs that worked. So what we see is that there is a low percentage of fracs that work in that kind of methodology, and you wind up refracking the same frac in that case. And so, you don’t get the good productivity,” he explained.

The cemented liner completions technology has also cut costs, largely due to less water handling, said Crescent Point chief financial officer Greg Tisdale.

“When you complete a well, just to give you a simple example, instead of using 2,000 cubes [cubic metres] of water, we use 1,000 cubes. So there is less tank storage, less power to pump that fluid in. Then when you flow it back, you’re disposing of less water. All of that goes into your capital cost.”

Tisdale says the cemented liner completions save about $100,000/well on water handling costs.

“Our completion guides are really focused in on reducing the amount of fluid,” he adds, pointing out that often in the industry you hear about operators doubling their fluid, doubling their sand—doubling everything—and so their costs are going up. “We’re trying to look at it from the opposite direction and mitigate costs and reduce costs but get better performance.

That’s what we’ve seen. And so we’re pretty excited about that side of it. There are further ways to reduce those costs. So that’s really over the last year to two years what’s happened is any of the inflationary costs that you would have seen in capital programs we’ve mitigated just by changing and optimizing our completion technique.”

Legacy is also a believer in cemented liners, company president and chief executive officer Trent Yanko said last year.

“Over three and a half years ago, we started using cemented liners in the Bakken,” he said. “We recognized the potential of the improvement in being able to control the frac, how those fracs initiate and the profile of them back at that time. We have moved to cemented liners, using them in the Three Forks, Spearfish, Bakken and in a lot of our different areas, and we have been at the forefront of that.”

“Also, we have been at the forefront of using slower pumping rates and less tonnage,” he added. “Three and a half to four years ago, we recognized that as a potential for cost savings but also a performance enhancer in these plays.”

“over three and a half years ago, we started using cemented liners in the bakken. we recognized the potential of the improvement in being able to control the frac, how those fracs initiate and the profile of them back at that time.”

— Trent Yanko, president and chief executive officer, Legacy Oil + Gas

OIL & GAS INQUIRER • APRIL 2015

35

Feature

The great

reckoning BLOODLETTING BEGINS IN SERVICE INDUSTRY

The 2015 winter drilling season is over, and it’s been a bad one across the board for western Canadian service companies.

In late February, there were 317 fewer active rigs across western Canada than during the same time period a year earlier.

Activity levels in the Western Canadian Sedimentary Basin stood at 40 per cent, Rig Locator records show. There were 308 active rigs at work in western Canada out of a fleet of 773. A year ago, the activity level stood at 77 per cent, with 625 active rigs out of a fleet of 810.

This trend is expected to continue, with only around 10 per cent of rigs active during the traditionally slow second quarter.

The decline in activity is hitting drilling contractors hard, according to Precision Drilling president and chief executive officer Kevin Neveu.

“The winter season disappointed us and the industry,” Neveu said during a conference call. “While overall activity is down to a level similar to the U.S., heavy oil has been hit particularly hard, somewhat offset by improved activity in the Deep Basin gas and liquids plays in the Montney and Duvernay.”

Spot market rates for drilling rigs in western Canada are under pressure, with 10–15 per cent price reductions typical, and some 20 per cent cuts occurring. The company said it has 124 rigs, on average, booked under term contracts in the first quarter.

In Canada, the Montney and Duvernay plays represent bright spots, with momentum expected to continue, Neveu said.

Looking ahead, Precision does not expect a significant increase in early contract terminations on rigs booked in western Canada, “but we may see more rigs shift to idle-but-contracted status as our customers balance their spending,” he said.

Also during the conference call, Neveu was asked if Precision would roll back workers’ wages.

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APRIL 2015 • OIL & GAS INQUIRER

BY DARRELL STONEHOUSE

“I personally feel the field labour force right now is bearing the full brunt of the job risk, and I’m anxious to try to protect the guys who have worked so hard for us in the past few years and let them continue earning at this rate,” he said.

Each active Precision rig employs 20–25 field workers. In a firstquarter press release, management estimated the company currently runs fewer than 200 rigs, versus almost 250 at this time last year. The result is that there is not enough work to keep everyone busy.

Precision’s completion and production services division in western Canada has come under intense, competitive pressure in recent months, Neveu added.

“We’re hearing about a growing inventory of producers’ repair and abandonment backlogs, but it’s clear that they continue to defer this spending, prioritizing the highest-value well repair work in the short-term,” he said.

He said the current mood in the industry is all about cost cutting.

“There’s a drive on to slam down costs. It’s a very orderly but aggressive reduction of activity. ‘Do everything you can to drive down cash costs and spending.’ There’s very little talk about highgrading or performance enhancements,” he explained.

Pressure pumpers like Calfrac Well Services and Trican Well Services are also feeling the pain.

In late February, Trican said it expects to idle 20–25 per cent of its pressure-pumping fleet during the second quarter.

In the current downturn, Trican chief executive Dale Dusterhoft says the drop in industry activity has been steeper and may yet turn out to be deeper than the 2009 industry downturn.

“We think the third quarter will be relatively slow across North America,” he says, adding that Trican’s customers will provide a baseline of crude-oil-related work over the quarter, ensuring profitability. “Our plan to park equipment in Canada is more

Feature

related to the second quarter, and we think it will be a slower third quarter, as our customers really don’t have any urgency to drill programs right now.”

In Canada, with about 400,000 horsepower currently active, the company will park about 100,000 horsepower, in addition to 30,000 horsepower that was parked earlier this year.

Trican is also looking to its suppliers to help it cut costs, says Dusterhoft.

“The most significant cost-cutting initiatives relate to product, product transportation and personnel costs,” he says. “We are currently in negotiations with all Canadian and U.S. suppliers to reduce product and product transportation costs to the greatest extent possible. We are pleased with the progress made to date, but will continue to focus on this initiative as it will have the most significant impact on our cost structure.”

It is also looking to its employees to help weather the storm.

In North America, 600 workers have been laid off, and remaining employees are facing an average 10 per cent pay cut.

Calfrac chief executive officer Fernando Aguilar said the pressure-pumping sector is seeing demands for major price concessions from operators.

“We’ve seen pricing pressure from those who are trying to do more work with less capital, asking service companies to discount service rates 25–30 per cent,” he told investors and analysts at the company’s 2014 fourth-quarter conference call. “Our response is that there’s no room for 25–30 per cent price discounts in the industry.”

Acknowledging the gravity of the situation, he noted some pressure-pumping contractors are parking their fleets rather than work at such deeply discounted rates. “We’ve seen customers asking for more discounts, but there has to be a limit. We would like to see how many people can operate at a loss and for how long.”

Oilfield hauler and service provider Mullen Group is shutting in some of its oilfield services equipment as lower crude prices create a scenario that is “close to ugly” for the services sector, Murray Mullen, president and chief executive officer, said in February.

“As the oil and gas industry adjusted to the new pricing realities, cash flows started to decline, bank lines began to get stretched and the result is that capital investment in drilling activity budgets have come under pressure,” Mullen said in the company’s fourth-quarter 2014 conference call. “The near-term impacts were minimal as the fourth quarter began. However, as of December the demands for services really started to slow and competition intensified. At Mullen, we felt the slowdown.”

As for what lays ahead in regard to oil prices and the impact on the industry and those companies that service it, Mullen said it would be difficult for anyone to guess. “Absolutely nothing is simple these days, and predicting the future…well, let’s just say ‘good luck.’”

He added: “The fallout will be steep, it will be rough and it will spare no one, Mullen Group included. In 2014, 60 per cent of our revenue was generated directly from the oil and gas segment of the economy, and so it is pretty obvious we will be impacted in 2015.”

At Mullen Group, management is implementing a review of all its businesses in the oilfield segment, and the action plan will include layoffs and salary freezes as well as several temporary layoffs in order to try to maintain experienced staff for when energy prices improve, Mullen told the conference call.

“We have also implemented job sharing where it is appropriate, obviously a wage and salary review, as well as the temporary decommissioning of equipment.”

“ IN THE OILFIELD SERVICES SEGMENT, THE OLD ADAGE IS THAT THE TOUGHER IT GETS, THE QUICKER MANY OF OUR COMPETITORS WILL FAIL.” — Murray Mullen, president and chief executive officer, Mullen Group

Mullen said his company would shut in some equipment until energy prices improve and there are improved industry activity levels. He said Mullen Group will not run equipment for reduced rates that do not pay for the upkeep of that equipment, even if some of the competition is willing to do so, and his company would “not be running on all cylinders” throughout the challenging oil and gas environment.

“In the oilfield services segment, the old adage is that the tougher it gets, the quicker many of our competitors will fail.

That is my opinion. I believe they added capacity, they added cost structure and they added too much debt at precisely the wrong time. Let us compare that to what we did at Mullen Group: We sold assets, we downsized and we strengthened the balance sheet. Only one of us can be right, and we will see. But I just can’t believe they will all make it.”

Strad Energy Services expects pricing pressure to continue across all of its operating regions in 2015 as producers seek to reduce drilling costs per well.

“We’ve experienced pricing pressures, as you would expect, in all regions. It’s more pronounced in oily areas, for sure,” Andy Pernal, president and chief executive officer, told the company’s fourth-quarter 2014 conference call.

“We’ve been proactive with all our customers, [and] we’ve worked with all of our customers in trying to meet their needs in terms of reducing costs. We’ve laid off people, we’ve had wage rollbacks and we’ve cut hours significantly in terms of our field staff. So we’re working with our customers to definitely reduce their cost structures and help them achieve their goals,” he added.

“Part of that is pricing concessions. And also as a part of those discussions we’re asking for more work from our customers. The more work we have, the more assertive we can be on the pricing side.”

In response to expected declines in drilling activity, Strad has undertaken cost-reduction initiatives in the first quarter of 2015 to reduce the impact of lower activity and revenue levels on profitability.

Staff layoffs, reduction of labour hours, company-wide wage rollbacks and reductions in discretionary expenditures have been implemented.

In an effort to maintain a strong balance sheet and preserve flexibility, Pernal said that capital-spending plans were reduced significantly and in the near term will be limited to maintenance capital spending.

“We are expecting our capital program to be modest and primarily focused on maintenance capital this year,” he said.

“Our capital program is currently estimated at $10 million, with a planning number of $5 million in maintenance capex and $5 million in growth capex. However, if activity levels are weak, we would look to reduce this budgeted spend.”

OIL & GAS INQUIRER • APRIL 2015

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