2015CurrentFeaturesFeaturesGlobal and Regional MarketsMarch/April

Canadian market cools as weather warms, prices fall

Contractors, operators off to slow start in 2015, hopeful for recovery in 2016

By Alex Endress, Editorial Coordinator 

Nabors Rigs 16 and 17 drill for shale gas on a multiwell pad in the Horn River Basin of British Columbia in western Canada. The CAODC expects onshore tight gas and heavy oil plays in British Columbia and northwest Alberta to remain flat in 2015.
Nabors Rigs 16 and 17 drill for shale gas on a multiwell pad in the Horn River Basin of British Columbia in western Canada. The CAODC expects onshore tight gas and heavy oil plays in British Columbia and northwest Alberta to remain flat in 2015.

As frost on the ground gives way to spring thaw and oil prices stay low, Canadian drilling contractors are packing up rigs early in preparation for next winter. Indeed, Canada’s unseasonably warm January and February in Q1 this year precluded drillers from achieving the higher rig utilization levels normally associated with winter. These weather troubles were further compounded by oil prices dipping below $50/bbl in January, which led to shrinking budgets that handicapped the Canadian market as it did worldwide. Rig utilization rates in the region diminished accordingly as companies prepared for the worst. Nevertheless, contractors are hoping the tough economic choices they make today will pay off in winter 2016.

To shed light on the challenges faced in Canada, several industry experts shared their perspectives with DC, including representatives from Trinidad Drilling, Nabors, CanElson Drilling, Douglas-Westwood and the Canadian Association of Oilwell Drilling Contractors (CAODC).

Spring comes early, utilization slides

Screen Shot 2015-03-02 at 12.40.50 PMAlthough winter is usually the Canadian drilling industry’s busiest season each year, the amount of frost on the ground produced by freezing temperatures in Q1 and Q4 is actually what determines capacity for onshore productivity.

“In the middle of winter, we’ll probably have a crust of ground that’s 2- to 3-ft thick before you get to earth that’s not frozen,” CAODC Vice President of Operations Steven Berg said.Without that frost buildup, muskeg and other wetlands prevent contractors from mobilizing rig fleets to various oil plays around Canada.“If the rig-moving companies have to move around in the mud, the rig moves get substantially more expensive, so everybody waits until the frost is driven into the ground,” Mr Berg said.

CanElson Rig 1 is an 850-hp ultra-heavy telescopic double with two 1,600-hp mud pumps, 4-in. X95 drill pipe and a 250-ton top drive. The rig is currently working in Alberta.
CanElson Rig 1 is an 850-hp ultra-heavy telescopic double with two 1,600-hp mud pumps, 4-in. X95 drill pipe and a 250-ton top drive. The rig is currently working in Alberta.

He indicated rig transportation after frost melts in spring could be anywhere from double to triple the cost during peak periods of winter.

In Canada, frost accumulation normally begins during November, when temperatures cool significantly. By December, a typical Canadian winter would have already produced a considerable amount of frozen ground, enabling companies to ramp up drilling efforts and, therefore, boost fleet utilization. The highest levels of onshore rig utilization normally occur from the beginning of January through February. When the frost melts as springtime weather takes over in March, contractors begin to cold-stack rigs during spring breakup.

However, winter in Canada felt a lot more like spring this year, Mr Berg said. “Today, I’m sitting in downtown Calgary, and it’s 60°

(Fahrenheit),” he said on 29 January. That’s a big change compared with the record-breaking weather experienced in 2014, when temperatures dipped as low as -30°F. “It’s a significantly different year. The impact of what’s going on in the world oil pricing obviously has a direct impact on us, but the shortness of our season will happen purely because we don’t have that frost on the ground. We expect to warm up sooner than we did last year,” he said.

In addition to the unfavorably high temperatures, operators are less likely to invest in Canada’s onshore projects in the midst of the significant decline in oil prices. The untimely downturn hit Canada when operators would normally devote spending to drilling programs in the region. “The oil producing companies start their budgets in January… If they’ve assigned capital allocations to do drilling programs in Canada, this is when they would be starting them,” Mr Berg said.

Data from the CAODC’s 2015 onshore drilling forecast, released on 22 January, projected a 20% drop in fleet utilization from 2014 levels, as well as a 41%

Trinidad Rig 58, a 3,000-hp AC triple rig, is working in northern Canada. According to Trinidad, the Montney and Duvernay are the most economic formations for drillers in the midst of a low-priced commodity environment.
Trinidad Rig 58, a 3,000-hp AC triple rig, is working in northern Canada.

drop in operating days due to adverse changes in commodity prices. An earlier forecast for 2015, issued on 20 November, had projected an average of 338 active rigs and 119,578 operating days, based on an oil price of $85/bbl WTI. CAODC updated the forecast in January, however, to reflect a price of $55/bbl WTI. In this updated forecast, projected average for active rigs in

2015 was revised to 203 and annual operating days to 76,696.

With the drastic decrease in onshore utilization, CAODC predicts a potential loss of 3,400 direct jobs and up to 19,500 indirect jobs, with total net job loss reaching 23,000 compared with 2014. “Every one of the contractors here is preparing to buckle down and go into survival mode to weather through this calendar year with relatively low utilization,” Mr Berg said.

Overall, CAODC predicts a disappointing 26% average rig utilization rate for 2015, after rates of 46% in 2014, 41% in 2013 and 44% in 2012. The original CAODC forecast in November projected 42% utilization in 2015.

“I think the highest concern for contractors is going to be their utilization numbers… They see the utilization as a catalyst to have all of their workers walk into another industry. Retention of key personnel is very difficult when you have low utilization,” Mr Berg said.

Strategies to stay competitive

Rigs with newer technologies are being kept on contract for longer in this downturn, according to Trinidad Drilling. “Over the past few years, the industry has really changed their view toward high-spec rigs,” Lisa Ottman, Trinidad VP of Investor Relations, said.
Rigs with newer technologies are being kept on contract for longer in this downturn, according to Trinidad Drilling.

Due to the low utilization rates in Canada, drilling contractors are finding it even more important to remain competitive. For January and February, the CAODC reported industry average utilization rates between 40-50%, although all contractors that spoke with DC – Trinidad, Nabors and CanElson – reported higher rig utilization between 60-65%. Contractors listed technologically advanced rigs, economic value for performance and competent personnel as reasons for their positive fleet utilization rates.

Part of staying competitive is adjusting to what the operator wants, Jay McNeil, Trinidad Vice President of Sales and Marketing for Canada, said.

“Certainly, they need to drill these wells more economically,” he said. “They don’t want to accept anything less for performance and safety, but they still expect that lower cost. We have to work with them and find a balance.”

Nabors AC Rig 127 uses a stomper moving system on a multiwell pad in Alberta. Of the 57 drilling rigs actively marketed by Nabors throughout Canada, 20 have walking systems.
Nabors AC Rig 127 uses a stomper moving system on a multiwell pad in Alberta.

Holding onto competent drillers – who might have picked up the basic skills of a mechanic, electrician, heavy equipment operator and safety leader – can be tough when operators are looking for cheaper ways to drill and there aren’t many rigs working. “All of these qualifications that go into a driller are very sought-after qualifications in any business,” Randy Hawkings, President and CEO of CanElson, said. “If you lose guys to another industry in a downturn, it’s very difficult to entice them back.”

One strategy for keeping employees through downturns is ensuring that they have versatile skill sets to move into different jobs on the rig. Trinidad accomplishes this through an essential skills training program. “It picks out the skill levels at each level on the rig, and then the crew member needs to prove to the rig manager that they can actually do all these skills competently,” Lisa Ottman, Vice President of Investor Relations for Trinidad, said. “The rig manager will sign them off and move them up to the next level. It means, from our point of view, that we have consistent skill sets across the company. We can move guys from one rig to another more easily. Plus, it gives the guys a clear career path.”

Advanced-technology rigs are another factor that’s helping some contractors keep their rigs

Trinidad Rigs 48 and 50 operate on a multiwell pad in the Horn River play of British Columbia.
Trinidad Rigs 48 and 50 operate on a multiwell pad in the Horn River play of British Columbia.

working. In the current market, when operators are looking for more cost-effective drilling operations, it’s becoming more common for older, less advanced rigs to be cut first, Ms Ottman said. She explained that rigs with newer technology are seeing higher demand, even through downturns, because they drill more efficiently.

“Now that the older-style rigs are not as competitive, they are the first ones that get laid down. Over the past few years, the industry has really changed their view toward high-spec rigs,” she said.

In terms of technology, rigs equipped with walking systems remain competitive due to their suitability for multiwell pads. “Some of those rigs will operate right through spring breakup,” Joe Bruce, President of Nabors Canada, said. Currently marketing 57 drilling rigs – including a range of singles, doubles and triples – around Canada, Nabors’ active rig count has fluctuated between 27 to 39 during January and February. Of its Canadian fleet, 20 have walking systems.

Newbuilds on hold, production steady

Trinidad Rig 37, a 1,500-hp AC triple rig built in 2012, is drilling in the Duvernay in British Columbia. The company said it’s seeing higher demand for higher-spec rigs because operators are seeking cost-efficient operations in this soft market.
Trinidad Rig 37, a 1,500-hp AC triple rig built in 2012, is drilling in the Duvernay in British Columbia. The company said it’s seeing higher demand for higher-spec rigs because operators are seeking cost-efficient operations in this soft market.

Looking further into 2015, CAODC is forecasting far less newbuild activity than in 2014 – which brought 20 brand-new rigs to Canada. Mr Berg said he predicts fewer than 10 new rigs in Canada this year. “The rigs being built in the first half of 2015 are simply rigs that could not be completed at the end of 2014, so we’re going to have some additions that were actually budgeted for last year, not this year,” he said.

Andrew Meyers of Douglas-Westwood echoed that sentiment: “I would say newbuild activity is probably coming to a complete halt.” Many contractors in the region have postponed plans for new rigs, he added.

In January, for example, CanElson had only one newbuild go to work in Canada. “The other ones that we have are on ice until economic conditions improve,” Mr Hawkings said. The rig that began operations in January is an AC-powered electric telescoping double that can drill up to 15,000 ft and is currently located in British Columbia with a long-term contract, he said.

Nabors had planned to add two additional rigs for Canada this year, but they have been postponed, as well. “Given the circumstances right now, we’ve put a hold on those rigs,” Mr Bruce said. “We’re seeing anywhere between 15-20% reduction in dayrates, and consequently we are making adjustments to our operating cost.”

The heli-portable Nabors AC Rig 103 moves between multiwell pads on a table-top moving system in Alberta.
The heli-portable Nabors AC Rig 103 moves between multiwell pads on a table-top moving system in Alberta.

Despite the lack of newbuilds on top of an already depressed rig utilization, analysis from Douglas-Westwood indicates that production is expected to either remain flat or even increase. “As a whole, (production) will still be up this year from last year,” Mr Meyers said.

On 21 January, the Canadian Association of Petroleum Producers (CAPP) forecast Western Canadian oil production to increase to 3.6 million bbl/day in 2015. This projection is approximately 150,000 bbl/day higher than the 2014 production of 3.5 million bbl/day, according to CAPP. Data from CAPP also forecast conventional oil production to be flat at 1.3 million bbl/day but predicts oil sands production to increase to 2.3 million bbl/day this year. The increase in oil sands production comes because of prior-year investments for projects that are now coming on stream, the group said.

In terms of conventional oil and gas spending in the Western Canada Sedimentary Basin, CAPP expects it to drop down to $21 billion in 2015 from $36 billion in 2014 due to volatility in oil prices.

This graph charts both historical data (2010-2014) and Douglas-Westwood’s forecast (2015-2020) for number of wells drilled and production levels in Canada. The firm is projecting that, although the number of wells drilled will fall significantly this year and next compared with prior years, production will remain steady or even increase.
This graph charts both historical data (2010-2014) and Douglas-Westwood’s forecast (2015-2020) for number of wells drilled and production levels in Canada. The firm is projecting that, although the number of wells drilled will fall significantly this year and next compared with prior years, production will remain steady or even increase.

The sudden drop in commodity prices has thwarted several large operators’ goals for Canada. For example, Apache Corp operated 91 rigs onshore North America during Q3 2014 based on an assumption of $80/bbl WTI in 2015. Now adjusting plans to account for a $50/bbl WTI price, Apache Corp CEO and President John Christmann said his company would reduce its onshore North American rig count to 27 by the end of February. Mr Christmann also indicated Apache would stop all drilling operations in Canada by March 2015.

“In Canada, we are finishing up a three-rig drilling program in the Duvernay and Montney plays this spring and will release the rigs for the remainder of the year. We plan to complete a seven-well pad in the Duvernay in Q3,” Mr Christmann said during Apache’s Q4 2014 earnings call on 12 February. “It’s simply a function of cash flow in Canada limiting how much we’re spending in Canada… Obviously, if prices change going in Q3 or Q4, you could see us decide to step back up, but for right now, the plan would be not to do anything.”

CAODC forecasts 6,612 wells will be drilled in 2015, down from 10,920 in 2014. Nabors’ Mr Bruce noted that he continues to see operators cut capital budgets and delay or cancel projects. “Because we are vulnerable to the capital investment that the companies make, that has an impact on us,” Mr Bruce said.

Crews work on CanElson’s Rig 1 in Alberta. CanElson canceled plans for several newbuilds in 2015 due to drops in global commodity prices. The contractor has had only one newbuild go to work in Canada this year, and several of its rigs have been coldstacked until the market improves.
Crews work on CanElson’s Rig 1 in Alberta. CanElson canceled plans for several newbuilds in 2015 due to drops in global commodity prices. The contractor has had only one newbuild go to work in Canada this year, and several of its rigs have been coldstacked until the market improves.

Mr Berg indicated the estimated average time on well for onshore Canadian drilling to be 11.6 days, with a cost range per well that varies according to geography, depth and complexity. For cost effectiveness, he continued, operators are likely to prefer drilling shallow wells in 2015. Wells in northeastern Alberta, for example, tend to require smaller rigs as they are easily accessible and have known well conditions.

“Oil exploration is not going to be on the forefront,” Mr Berg said. Still, some plays will fare better than others, and he listed heavy oil, as well as onshore tight gas in northwest Alberta and northeastern British Columbia, as plays that will likely remain flat in 2015. The Bakken, on the other hand, has become less attractive due to the slip in oil price. “We’re seeing a bigger decline in activity in North Dakota and Saskatchewan,” Mr Hawkings said, noting that he believes it is due to the higher transportation costs of crude oil. “They’ve seen a bigger drop-off in the immediate term than natural gas liquids in Alberta and British Columbia.”

Long-term outlook in Canada

Nabors AC Rig 102 is drilling SAGD wells in the oil sands of Canada.
Nabors AC Rig 102 is drilling SAGD wells in the oil sands of Canada.

What happens with the Canadian drilling market in the next couple of years will depend on whether global oil prices and winter temperatures can correlate favorably. Mr Meyers said he expects a “modest recovery” in Q3 2015, though not enough for utilization to recover to 2014 levels. CAODC predicts a 25% rig utilization level in Q3 2015 and 30% in Q4.

“We don’t see well count numbers recovering to 2014 levels until at least 2017… but we’re in the ballpark,” he continued.

For offshore drilling, however, Mr Meyers said it looks like operations will continue “full speed ahead” on the East Coast of Canada. “Whether it be BP or Statoil, most of those projects continue going, and the drilling plans are in place for 2015 and 2016.” BP has four exploration licenses (ELs) for offshore Nova Scotia, with blocks adding up to almost 14,000 sq km. The blocks are located about 300 km southeast of Halifax off

Statoil is using the Seadrill West Hercules for its drilling program in the Flemish Pass Basin. The harsh-environment sixth-generation DP3 semisubmersible can operate in up to 3,000-m water depths.
Statoil is using the Seadrill West Hercules for its drilling program in the Flemish Pass Basin. The harsh-environment sixth-generation DP3 semisubmersible can operate in up to 3,000-m water depths.

the coast of Nova Scotia in water depths ranging from 100 m to more than 3,000 m, according to the company’s website.

Statoil has four significant discovery licenses and seven ELs near offshore Newfoundland that comprise 11,000 sq km. Statoil is also partnered with other operators in four other ELs. In November 2014, Statoil started an 18-month drilling program to appraise the Bay du Nord discovery – with potentially 300 million to 600 million bbl of recoverable oil – in the Flemish Pass Basin.

Wells drilled at the site run about 1,200-m deep. Drilling is ongoing using the Seadrill West Hercules, a sixth-generation DP3 semisubmersible. The rig was chosen due to its ability to operate in harsh environments of up to 3,000-m water depths, according to Drilling Manager Jim Beresford of Statoil Canada, Offshore Newfoundland.

Statoil has four significant discovery licenses and seven exploration licenses offshore Newfoundland. In November 2014, Statoil began an 18-month drilling program for the Bay du Nord discovery.
Statoil has four significant discovery licenses and seven exploration licenses offshore Newfoundland. In November 2014, Statoil began an 18-month drilling program for the Bay du Nord discovery.

Additionally, Statoil is exploring two other discoveries in the Flemish Pass Basin offshore Newfoundland – the Mizzen and the Harpoon. The company estimates the Mizzen discovery to hold between 100 million to 200 million bbl of recoverable oil, while the Harpoon discovery is still under evaluation.

While offshore drilling will seemingly continue without disruption in the short term, onshore contractors would need an economic bump in the form of increased WTI prices to recover utilization. Common thought among onshore drilling contractors is to focus on Q1 2016 for a larger recovery. The hope is for global oil prices to rebound in Q3 or Q4 2015, allowing operators to plan for bigger budgets and higher capital expenditure for the Canadian market in January 2016, weather permitting. “If the world oil price starts climbing up in the calendar year of 2015, we probably won’t reap the benefit until sometime in early Q1 of 2016 because the capital budgets for most of the major oil companies in Canada have already been submitted and approved,” Mr Berg said. “They’ve already done their forecasts for budgeting, and they’ve revised them according to what the oil prices dropped to.”

Besides simply the availability of capital, another factor to market recovery is Screen Shot 2015-03-02 at 12.51.25 PMincreasing energy demand and increasing access to markets. If the Keystone XL pipeline isn’t approved in the US, Canadian exploration and production could start to slow down, Mr Berg said. As DC goes to press in late February, the status of Keystone XL remains in question after US President Barack Obama vetoed legislation authorizing the pipeline on 24 February.

However, even without this pipeline, Mr Berg said he believes that Canadian operators will still be able to find other markets for their hydrocarbons in the long term. “If (Keystone XL) is defeated, obviously our drilling programs would be decreased accordingly until we could have our own Canadian pipeline in place to offshore the oil,” Mr Berg said. “Instead of selling to the world market through Texas, we will be flooding the world market through our eastern seaboard and our western seaboard.”

He also believes new pipelines would provide economic incentive for development and deployment of additional technological innovations in the Montney and Duvernay, which have vast shale resources similar to the Eagle Ford in the US, according to Mr Berg. He noted that Canadian companies have already introduced technologies, such as multilaterals, multiwell pads, horizontal drilling and multistage fracturing, into these plays for improved efficiency. “If the pipelines come to fruition within the next 10 years, we have all of this unlocked potential that is just sitting in the ground that we can fill those pipelines with for many years to come.”

Canadian case study: Automated MPD system enables early kick detection, minimizes kick size in Montney well

By Sheldon Sephton and Elvin Mammadov, Weatherford

The Drilling Challenge

This screen shot shows parameters during the first two minutes after an automated MPD control system detected an influx. The outflow increased from 1,000 to 1,244 L (264 to 328 gal), the choke started to close, and the system gradually increased the surface backpressure until the outflow returned to normal level.
This screen shot shows parameters during the first two minutes after an automated MPD control system detected an influx. The outflow increased from 1,000 to 1,244 L (264 to 328 gal), the choke started to close, and the system gradually increased the surface backpressure until the outflow returned to normal level.

When drilling in a tight-gas formation with natural fractures like the Montney, the potential of a gas kick entering the wellbore poses a high risk to the drilling operation. Kicks not detected in a timely manner result in a high potential of exceeding surface or subsurface pressure limitations, which may lead to catastrophic events. Moreover, failure to detect and manage a kick early and allowing it to expand can yield well control events and blowouts. Operators employ well control methods to overbalance the well and circulate out kick fluid. Early detection and proactive responses are fundamental tools for mitigating kicks.

Although effective in some applications, conventional well control methods have relatively conservative pressure limitations. Conventional methods also contribute to NPT due to the need to check the flow, close the BOP and subsequently delay the operation. The total response time to regain balance and rectify the flow into and out of the well could accumulate many hours of NPT while the influx intensifies to a point that could potentially exceed pressure limitations and increase safety risks.

MPD Solution

This graph shows influx and control parameters within 20 minutes of initial kick detection. At the moment the system applied surface backpressure, the flow out started to decrease, and the surface backpressure increased and stabilized at approximately 3,500 to 4,000 kPa (508 to 580 psi).
This graph shows influx and control parameters within 20 minutes of initial kick detection. At the moment the system applied surface backpressure, the flow out started to decrease, and the surface backpressure increased and stabilized at approximately 3,500 to 4,000 kPa (508 to 580 psi).

Managed pressure drilling (MPD) methodologies are based on a closed-loop circulating system. Using a rotating control device (RCD), MPD can overcome some of the limits of conventional technology to drill through tight operating windows, reduce the likelihood of a well control event and manage wellbore stability to mitigate stuck pipe. MPD’s automation capabilities via the Microflux control system provides operators the ability to detect kicks early and to manage the pressure profile by applying surface backpressure as needed.

Project Details

In a Montney horizontal well in the Altares field, the operator utilized an automated MPD control system for fully automatic kick detection and control while drilling. The operator expected abnormal pressure zones at a measured depth of 1,994 m (6, 542 ft) to 4,795 m (15,731 ft) total depth. The system was used with a light-density drilling fluid to optimize ROP, control unexpected gas influxes, avoid reservoir damage and maintain constant bottomhole pressure.

The control system detected a kick at a bit depth of 2,440-m (8,005-ft) MD when using a mud weight of 1,230 kg/cu m (77 lb/cu ft) and a constant bottomhole equivalent circulating density of 1,320 kg/cu m (82 lb/cu ft). For 15 seconds, the system monitored the discrepancy in the flow in and out before it confirmed the influx and automatically activated the dynamic well control procedure.

In its entirety, the well gained only 244 L (64 gal) of drilling fluid, which was safely circulated out in 4 hours.
In its entirety, the well gained only 244 L (64 gal) of drilling fluid, which was safely circulated out in 4 hours.

Within 20 seconds, the choke started to close, and the control system automatically began gradually increasing the surface backpressure from 3,700 to 4,000 kPa (537 to 580 psi) to control the kick. The system applied pressure in stages while monitoring the change in the return flow.

For the first two minutes after detection, the outflow increased from 1,000 to 1,244 L (264 to 328 gal). Meanwhile, the driller stopped rotation, picked off bottom and continued circulation at the drilling rate. The system circulated the influx out using a modified Driller’s Method and monitored the pressure balance in the wellbore until the flow returned to normal level.

In 10 minutes, the system had the kick under control without human intervention. The system automatically controlled the influx by calculating the required surface backpressure and applying it on time.

The well gained only 244 L (64 gal) of drilling fluid, which was safely circulated out in 4 hours. The entire well control operation was conducted at a full circulation rate, which enabled the operator to quickly resume drilling operations. The system maintained balance with pore pressure throughout the project, and drilling reached total depth without any losses or gains into the formation or any other incidents.

Results

Early detection and precise control of unexpected gas influxes using the automated MPD control system enabled the operator to minimize the size of the kick, which eliminated the need to shut in the well and drastically reduced the potential amount of NPT. The system circulated the potentially catastrophic kick out in 4 hours at full circulation rates for a safe and quick return to drilling to reach TD. Using a light-density drilling fluid with the MPD system enabled the operator to increase the ROP, protect against formation damage, enhance control of influxes and reduce costs of required drilling fluids. Tripping accounted for only 8.3% of the time because of the light-density drilling mud used. Drilling accounted for approximately 70% of operational time, which is significantly more than in conventional drilling operations.

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