May 2015
THIS ISSUE Tracking resource play development in southern Alberta
Western Canada's Exploration & Production Authority
Measuring success THE NUMBERS TELL A STORY OF UPS AND DOWNS FOR CANADIAN OILFIELD MANUFACTURERS
PLUS: A tough summer ahead, says Ensign Energy Services
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Peace Region Petroleum Show Grande Prairie, Alberta – May 13-14
Bonnyville Oil and Gas Show Bonnyville, Alberta – June 17-18
CONTENTS
MAY.15
in the news
11
Devonian shale plays still in next year country
regional news
15 British Columbia
23 Northeastern Alberta
31 Southern Alberta
Canbriam updates Altares Montney development
Suncor wants to test CO2-aided SAGD at Fort MacKay
Low commodity prices hitting LGX
19 Northwestern Alberta
27 Central Alberta
35 Saskatchewan
Montney drives Delphi production, but market worries temper enthusiasm
Bonavista outlines spending plans
Raging River Viking production continues to skyrocket
features Cover Feature
Measuring success The numbers tell the story for Canadian oilfield manufacturers
Still next year country Low oil prices stall out promising oil exploration in southern Alberta
every issue
8
Stats at a glance
48
Political cartoon
Cover design: Linnea Lapp
O I L & G A S I N Q U I R E R • M AY 20 15
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Editor’s Note Vol. 27 No. 5 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Creating value in a down market
Lynda Harrison, Richard Macedo, James Mahony, Pat Roche EDITORIAL ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com EDITORIAL ASSISTANCE
Sarah Maludzinski, Jordhana Rempel, Megan Tilley CREATIVE CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD
Cathlene Ozubko | cozubko@junewarren-nickles.com PRODUCTION COORDINATOR
Janelle Johnson | jjohnson@junewarren-nickles.com GRAPHIC DESIGNER
Linnea Lapp SALES SENIOR ACCOUNT EXECUTIVES
Nick Drinkwater, Diana Signorile SALES
Rhonda Helmeczi, Mike Ivanik, Nicole Kiefuik, James Pearce, Blair Van Camp
market. Drilling contractors are integrating product lines or forming partnerships with
For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES
Lorraine Ostapovich | atc@junewarren-nickles.com
ing packages that save time and money. Engineering, procurement and construction firms are offering whole field development packages, creating a onewindow approach to cutting procurement costs while optimizing field development. It’s all about creating value for customers. At the JuneWarren-Nickle’s Energy Group, we’re also focused on innovating to create value for our customers during this slowdown. At the Daily Oil Bulletin, we recently launched a new Intelligence Essentials package, a set of tools to help oil and gas professionals improve productivity, identify opportunities and make better decisions with trusted analysis and data sets. We also launched morning news briefs to give readers a head start on the day and a daily infographic to help readers visualize the sometimes incomprehensible numbers that drive the industry. Now, it’s the Oil & Gas Inquirer’s turn for an overhaul. Like the old drilling rigs that once served the industry so well, the Oil & Gas Inquirer is
DIRECTORS PRESIDENT & CEO
Bill Whitelaw | bwhitelaw@junewarren-nickles.com Bemal Mehta | bmehta@junewarren-nickles.com Donovan Volk | dvolk@junewarren-nickles.com Ian MacGillivray | imacgillivray@junewarren-nickles.com Gord Lindenberg | glindenberg@junewarren-nickles.com DIRECTOR, THE DAILY OIL BULLETIN
Stephen Marsters | smarsters@junewarren-nickles.com DIRECTOR, CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR, PRODUCTION
Audrey Sprinkle | asprinkle@junewarren-nickles.com OFFICES Calgary N.E. | Calgary, Alberta Tel: Toll-Free: Edmonton
| Fax:
220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8
Tel: Toll-Free:
Eight months into the second oil and gas price crash of the 21st century the wheels of innovation are spinning hard as oilfield service enterprises hunt for ways to cut costs and increase productivity to survive and grow in the downturn. In the drilling industry, older rigs are being rapidly retired and being replaced with new fit-for-purpose units designed to work
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being retired after 26 years of service to be replaced by a fit-for-purpose model that creates value in today’s resource play–driven market. Starting in June, Oil & Gas Inquirer readers and selected Daily Oil Bulletin subscribers will begin receiving our new publication, The Basin: Insights from the Daily Oil Bulletin. Our goal with The Basin is to give readers the information and context they need to stay on top of the constantly evolving Canadian petroleum landscape. Among The Basin’s new value-adding components being introduced in the next few months will be broader, more comprehensive coverage of operator activity in western Canada, a greatly enhanced regional data package stretching from well and facility licensing through to completions and production, more in-depth coverage of resource play activity and the technologies and processes making exploration and development profitable, and quarterly field activity reports marking regional trends in the Western Canadian Sedimentary Basin. All this information will be packaged in a new design allowing readers quick and easy navigation to the information they need. After spending many of the last 15 years editing the Oil & Gas Inquirer, it is bittersweet seeing the old girl sent to the scrapyard. But the industry is changing and we are changing with it, innovating and ensuring we are creating value for our clients along the way. See you next month in The Basin. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
. Printed in Canada by | PrintWest Energy Group. All rights reserved. Reproduction in whole or in part is . Postage Paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department,
Alberta
N.E., Calgary,
NEXT I S S UE
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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.
June 2015 How Canadian operators and service companies are weathering the market storm in overseas markets
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as if you want them published.
OIL & GAS INQUIRER •
7
FAST NUMBERS
16%
39%
Number of rigs active in the last week of March 2015
Number of rigs active in the last week of March 2014
Alberta completions
WCSB oil & gas completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OTHER
MONTH
OIL
GAS
D RY
SERVICE
Apr
May
Jun
Jul
OIL
GAS
T O TA L
Apr
May
Jun
Jul
T O TA L
Aug
Aug
Sep
Sep
,
Oct
Oct
,
,
Nov
Nov
Dec
Dec
,
Jan
Jan
Feb
Feb
Mar
Mar
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 *
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
*Year-to-date
MONTH
OIL
GAS
OTHER
TOTAL
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
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M AY 20 15 • O I L & G A S I N Q U I R E R
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STATS
AT A
GLANCE
Drilling rig count by province/territory
Drilling activity: Oil & gas
Canada, April 9, 2015 Source: Rig Locator
Alberta, March 2015 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada Alberta
%
British Columbia
%
Manitoba
%
Saskatchewan
%
%
%
%
WC TOTALS
Eastern Canada Quebec CANADA
OIL WELLS
Alberta
Mar
Mar
Mar
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
53
TOTAL
Top operators by active rigs
Drilling activity: CBM & bitumen
Western Canada, April 9, 2015 Source: Rig Locator
Alberta, March 2015 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
EXP
Progress Energy Canada
Seven Generations Energy
Royal Dutch Shell
Peyto Exploration & Development
Encana
Cenovus Energy
Husky Energy
Apache Canada
Bellatrix Exploration
ConocoPhillips Canada
GAS WELLS
C OA L B E D M E T H A N E
Alberta
Mar
BITUMEN WELLS
Mar
Mar
Mar
Mar
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
O I L & G A S I N Q U I R E R • M AY 20 15
9
IN THE
NEWS Issues affecting Canada’s E&P industry
Devonian shale plays still in next year country By Richard Macedo
Some of the promising Devonian-aged shale plays in western Canada—the Duver nay a nd Musk wa i n nor t her n Alberta, the Horn River in B.C. and Canol shale in the Northwest Territories—hold great resource potential, and could one day turn into very large and steady contributors to North American gas, liquids and oil supply. But for various reasons, such as their distance from key markets in North America and a dearth of infrastructure, they are not yet huge commercial producers. During a presentation at the Canadian Energy Research Institute 2015 Natural Gas Conference, Brad Hayes, president of Petrel Robertson Consulting, discussed these four Devonian-aged plays. “All had great big land rushes, all garnered a great deal of interest in the exploration community in Canada and, indeed, they are objects of very active evaluation, and in some cases development,” he told the conference. “But they aren’t yet a big commercial producer. So where are they going and when are they going to get there?” Hayes said the Horn River Basin has been a victim of being a dry gas play, along with its distance from market during a time in which key gas-consuming regions are well-supplied. “The Canol has huge issues with distance from infrastructure, and much of that area I pointed to that is geologically prospective between the Horn River Basin and Central Mackenzie Valley is not currently accessible because of aboriginal/landrights issues,” he said. “Further south, much of the Muskwa is still in pretty remote territory, and I think that many operators have concerns about recovery factors and reservoir risks. Generally
noted. “Even for the Duvernay, distance from primary markets and pipeline tolls have hurt the economics.” The resource across these plays is huge. “The recoverable gas and liquids are also huge, but distance from infrastructure and markets has rendered much of the fairway uneconomic at this time,” Hayes said. “And finally, we are only now seeing sufficient refinement in Duvernay drilling and completions techniques to make it a significant contributor to the supply picture.”
there is much less data than the Duvernay, and some relatively shallow areas where reservoir energy may be a question.” Hayes said the Duvernay is the best of the bunch with respect to having a good resource in place, lots of liquids, lots of well data and good access to infrastructure and pipelines. “Even with this, only now have some companies refined their drilling and completions techniques sufficiently to establish commercial production,” he
Estimate of Alberta shale and siltstone hydrocarbon resource Natural gas (tcf)
Natural-gas liquids (billion barrels)
Oil (billion barrels)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
Wilrich P (preliminary data)
Wilrich P–P
–
–
–
2
5.
2.
Unit Duvernay P50 Duvernay P–P Muskwa P Muskwa P–P Montney P Montney P–P Basal Banff/Exshaw P (preliminary data) Basal Banff/Exshaw P-P North Nordegg P (preliminary data) North Nordegg P–P
Total P (medium estimate) resource endowment
* The percentage of adsorbed gas represents the portion of natural gas that is stored as adsorbed gas.
Source: Alberta Geological Survey
O I L & G A S I N Q U I R E R • M AY 20 15
11
In The News
90 million
PROVIDING INDUSTRIAL ENERGY SERVICES SINCE 1953
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High end of Husky’s resource estimate for the Canol Shale Play
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Various agencies, in particular the Alberta Geological Survey, have done resource assessments of Devonian shales in western Canada. It’s estimated that the Duvernay holds 444 tcf of gas in place, with liquids of 11.8 billion barrels and oil in place of 62.8 billion barrels. In the Muskwa of northwestern Alberta, there’s an estimated 413 tcf of gas resource, 15.5 billion barrels of liquids and 116 billion barrels of oil in place. In the Horn River Basin, there’s 448 tcf of gas in place. As for the Canol shale, he said there’s not yet sufficient data to come up with in-place resource values. “In fact, the National Energy Board, in doing a regional assessment of resources in 2014, just didn’t have enough data to come up with those sorts of in-place resource values that we can get in Alberta and B.C.,” Hayes said. “However, some of the proponents developing the Canol shale, like Husky Energy, which was very busy in 2012 and 2013 in that area, estimated on the order of 20 [million] to 90 million boe per section in the Central Mackenzie Valley,” he added. Husky holds two exploration licences that were acquired in 2011 in the Northwest Territories at the Slater River Canol shale play. Two vertical pilot wells were drilled, completed and flow tested in 2012. These wells satisfied the requirements to extend the term of both the exploration licences to the full nine-year term. The company acquired a 220-square-kilometre multi-component 3-D seismic survey in 2012, and construction of an all-season access road was completed in 2014. Husky withdrew an application to drill four horizontal wells originally planned in 2015.
Ensign expects a tough summer By James Mahony
Despite cuts to service pricing currently running beyond 10 per cent, the oilfield service business will likely weather steeper cuts this summer as contractors compete in a weak market, according to one of western Canada’s largest contractors. “The service pricing conversation started in January, with everyone wanting a 10 per cent reduction,” said Bob Geddes, chief executive officer for Ensign Energy Services, during the fi rm’s fourth-quarter conference call. “That was right across the world. Internationally, the number may be more muted, down to about five per cent.”
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Speaking to analysts, Geddes said Ensign’s price cuts have not yet penetrated a certain threshold. “On a congregated basis, we’re certainly not at 20 per cent,” he said. “I would suggest though, that in Canada you’re going to see very tough competition this summer, because there’s just very little work and very few bids out at all for the summer.” Another Ensign executive predicted the industry would see “competitors’ bids at or below cost as they try and preserve market share.” In a fourth-quarter news release, Ensign said it took steps to trim its equipment fleet, decommissioning 32 drilling rigs, 21 wellservicing and three workover rigs, and booking associated charges that, along with write-downs, quashed quarterly earnings. Those steps follow the contractor’s decision five months ago to halt construction on 34 new-build automated drilling rigs (ADRs), except for nine being built to meet customer contracts. “We’re seeing this market, not as a short-term bump in the road, but as a new normal that will take years, not months, to normalize,” Geddes said.
“ We’re seeing this market, not as a short-term bump in the road, but as a new normal that will take years, not months, to normalize.” — Ensign president Bob Geddes
Ensign reported modest drilling rig utilization in western Canada in the fourth quarter. “We basically ran in the 25–30 per cent utilization fairway all winter,” said Glenn Dagenais, executive vice-president and chief financial officer. “Things just never got off the ground.” At the same time, the quarter was not all bad news, as the company took steps toward transitioning its drilling rigs to a much deeper fleet. “The 18 rigs we decommissioned had an average depth capacity of 2,500 metres, and the six ADRs we’re adding in the first and second quarter have a depth capacity of over 6,000 metres,” Dagenais said. Geddes estimated about 30 per cent of the company’s worldwide drilling fleet is on term contracts, some of which extend forward as far as 2019. “We have about 25 per cent contracted in Canada, 30 per cent in the U.S.,
40 per cent international east and 50 per cent in Latin America tied into term contracts,” he said. “Only on the coring side have we seen a few clients suggest that they would look for some sort of upfront, net present value discount on payout of a term contract. “All of our other contracts are the kind where we send a bill every month. No one seems to want to get out of the contracts we have. More often, there’s some negotiation occasionally, even on the long-term contracts, where this year we will drop the rate by a certain percentage in exchange for an additional year into the future, with some price escalation.” Ensign’s 2015 capital budget has been reduced since December 2014 and now sits at about $220 million, including the costs to complete eight drilling rigs under the reduced new-build program, management said.
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M AY 20 15 • O I L & G A S I N Q U I R E R
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BRITISH COLUMBIA WELL ACTIVITY MAR/14
MAR/15
Wells licensed
133
MAR/14
MAR/15
Wells spudded
49
MAR/14
MAR/15
63
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
B.C. British Columbia
Canbriam updates Altares Montney development Canbriam Energy is targeting a capital b ud g e t b e t we e n $ 3 4 0 m i l l ion a nd $360 million in 2015, about two-thirds of which will be focused on drilling and completion activity within the Main Fault Block of its Altares Montney asset, located west of Fort St. John, B.C. The remainder will support ongoing infrastructure development. In February, Canbriam commissioned the 80-mmcf/d Phase 1 of its 100 per cent owned and operated b-72-A natural gas processing facility, increasing total production capacity to approximately 25,000 boe/d including current natural gas liquids (NGLs) yields. “Completion of Phase 1 of our b-72-A facility is a major milestone for our company,” said Paul Myers, Canbriam president and chief executive officer. “It provides us with the processing capacity to continue to
Canbriam plans on drilling around 20 wells this year.
demonstrate the high deliverability of our Montney wells.” Installation of Phase 2 of the b-72-A facility, an incremental 80 mmcf/d or approximately 15,000 boe/d including NGLs yields, is under construction and expected to be commissioned by year-end 2015. Canbriam plans to commission its new water recycling facility this quarter, which is expected to reduce water-handling costs by between $20 million and $30 million per year. Current production is approximately 16,000 boe/d, an increase of over 60 per cent from fourth-quarter 2014 production of 9,815 boe/d. Full-year production averaged 9,628 boe/d in 2014, 81 per cent of which was natural gas, 11 per cent was condensate and eight per cent was butane and propane. Recent well results have consistently met or exceeded the company’s nine-bcf raw gas type curve for Upper Montney wells and eight-bcf raw gas type curve for its Lower Montney wells within the Main Fault Block of the Altares region. Canbriam’s wells are economically robust in low commodity prices, with forecasted internal rates of return of approximately 55 per cent for Upper Montney locations and 20 per cent for Lower Montney locations in the Main Fault Block using US$50 WTI and US$3.00 NYMEX pricing, excluding infrastructure and land costs. The company plans to drill and complete approximately 20 wells in 2015 based on its current program and expects production to reach current facility capacity of approximately 25,000 boe/d by year-end. At year-end 2014, Canbriam had proved reserves of 169 million boe, a 264 per cent increase over 2013 levels. Proved-plusprobable reserves have increased 156 per cent to 281 million boe, comprised of 1.36
tcf of natural gas and 55 million barrels of NGLs, according to an evaluation done by McDaniel & Associates Consultants. The company said proved-plus-probable finding and development costs, including changes in future development costs, were $8.58/boe. In addition, Canbriam’s provedplus-probable recycle ratio was 3.2 in 2014, based on an operating netback of $27.16/boe. The company said operating costs were $3.40/boe for 2014. Canbriam has 2015 AECO hedges in place for approximately 45,000 GJ/day at an average $3.13/GJ, which represents approximately 50 per cent of expected natural gas production net of royalties. The company has 2015 WTI hedges for approximately 2,200 bbls/d at average WTI price of $96.82/bbl, which represents approximately 90 per cent of expected condensate and butane production net of royalties.
Painted Pony cuts budget Painted Pony Petroleum has lowered its 2015 budget to $104 million, subject to review on a quarterly basis. This was lowered from the $295-million program announced in December, with the intention of preserving a strong balance sheet during this period of weak commodity prices, taking advantage of continued improvements in well productivity and positioning the company for significant growth upon completion of the AltaGas Townsend facility in 2016. Painted Pony and AltaGas have agreed that Painted Pony’s firm capacity of 150 mmcf/d (with a 135-mmcf/d “take or O I L & G A S I N Q U I R E R • M AY 20 15
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pay” commitment beginning three months after facility start-up) at the AltaGas Townsend facility will increase to 198 mmcf/d (180 mmcf/d of which will be “take or pay”), 12 months after facility start-up. This increased commitment will allow Painted Pony to use 100 per cent of the facility’s processing capacity. Expected completion of the AltaGas Townsend facility has been revised to mid-2016, in time to accommodate Painted Pony’s production volumes in the third quarter of 2016. This revised schedule is expected to result in cost savings on both facility construction costs and the processing fees to be paid by Painted Pony when the facility begins processing gas, while also providing flexibility to Painted Pony’s drilling and completion plans. During 2015, Painted Pony intends to drill 14 and complete 11 Montney horizontal natural gas wells in the Blair and Townsend areas. Included in this are eight wells that are pre-drills for the Townsend area and will not be brought on production until 2016. Due to improved well productivity, only six wells are required to be drilled in order to keep the company’s recently expanded processing capacity full and deliver 21 per cent production growth to 16,000 boe/d for 2015, including 1,100 bbls/d of NGL. Current production is over 16,000 boe/d, including volumes being processed at the recently completed Painted Pony–owned facility at West Blair and expanded 50 per cent owned facility at Daiber. Painted Pony is taking steps to reduce costs during this period of low commodity prices. Each of the company’s executive officers has voluntarily taken a 12 per cent reduction in their salary and the board has determined to reduce their annual retainer by the same percentage. As well, Painted Pony has asked each of its suppliers and ser vice providers to reduce their rates, working with the company to reduce capital and operating costs. Together with the revised drilling schedule, deferring some drilling and completion of wells to later in 2015 and into 2016, Painted Pony plans to meet its operational objectives while realizing average savings of over 10 per cent on operating and capital costs. The company has a risk-management program that aims to reduce the impact of commodity price volatility with hedges in place through the first quarter of 2017.
British Columbia
In the first quarter of 2015, the company has hedged 37.9 mmcf/d of natural gas at an average AECO price of $3.58/mcf. For the remainder of 2015, the company has hedged 37.9 mmcf/d of natural gas at an average AECO price of $3.14. From Jan. 1, 2016, to March 31, 2017, Painted Pony has hedged 19 mmcf/d at an average AECO price of $3.05. Painted Pony revealed late last year it was a big spender at the November B.C. Crown land sale. The company acquired 14.5 sections of 100 per cent working interest prospective Montney land for $66.8 million. The land acquired consists of 3,710 hectares or 9,275 acres immediately adjacent to their liquids-rich Montney natural gas project in the Townsend area of northeastern B.C. The acquired land is expected to add over 170 liquids-rich drilling locations within three prospective intervals of the Montney. The average reservoir thickness at Townsend is approximately 340 metres (1,100 feet) and the liquids yields are substantially higher than regional averages. Management believes the new acreage exhibits the same over-pressured geological characteristics as the company’s existing Townsend block, which could enhance both well productivity and reserves. Wells are expected to yield similar liquids recovery of 40–80 bbls/mmcf of condensate, propane and butane. Painted Pony also continues to push technology in the Montney. The drilling of 21 (19.5 net) and completion of 19 (17.5 net) Montney natural gas wells in 2014 was accomplished at a cost of $143 million. All of the wells completed in 2014 used an open-hole, multi-stage system. Painted Pony was an industry leader in completing Montney wells using this technology in its area, as well as moving to parallelpair drilling and completions, including the recently completed first parallel-triple. More recently, the company has completed wells with shorter stage lengths and increased tonnage. Although at varying stages of implementation, all of these initiatives have delivered strong improvements in well productivity and recoveries, resulting in the highest-average peak month gas rate of any Montney operator during the past three years. As a result of these improvements in well productivity, fewer wells and less capital will be required to deliver on the significant growth in Painted Pony’s five-year plan.
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M AY 20 15 • O I L & G A S I N Q U I R E R
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Trican pushes completions envelope in northeastern B.C. Trican Well Service reports a major operator working in northeastern B.C. recently completed a well in which several Trican service lines were integrated with tremendous success, and with considerably greater efficiency in coordination and execution. The completion comprised Trican’s i-Frac multistage frac system consisting of 80 frac sleeves with the internal diameters on the ball seats ranging from 55.83 millimetres to 89.15 millimetres. Two Trican Burst Port System collars were also run as toe initiation subs. The 80-sleeve system consisted of 17 fixed ball drop limited-entry frac treatment stages. To date, 80 frac sleeves is the highest number of 114.3-millimetre i-Frac ball-drop sleeves installed in any single wellbore anywhere worldwide, the company said.
80 frac sleeves Highest number installed in a single well bore in the world
Trican also designed the cementing program and successfully pumped cement to provide isolation between i-Frac stages. In addition, Trican’s wiper dart—designed specifically for the i-Frac system—was bumped as per program. Upon the completion of the stimulation treatment, Trican’s coiled tubing group used 60.3-millimetre coiled tubing to mill out 78 ports. The ports were milled with Trican’s proprietary Vulture mill and a positive displacement motor, all in one run. The company said the average milling times were an impressive 5.7 minutes per seat. “When we can bundle our products and involve several of our service lines, it’s a lot less work in coordination for the customer,” said Rob Cox, vice-president of the Canadian Geographic Region. “By using our advanced tools, and services that complement one another, Trican is able to achieve unparalleled levels of efficiency, service and cost savings in completing the customer’s well.”
NORTHWESTERN ALBERTA WELL ACTIVITY MAR/14
MAR/15
Wells licensed
166
MAR/14
MAR/15
Wells spudded
53
Rigs released
MAR/14
MAR/15
91
▼
▼
▼
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Montney drives Delphi production, but market worries temper enthusiasm By James Mahony
Growth at the company’s Montney development at East Bigstone, Alta., drove record production for Delphi Energy in the fourth quarter. Total production rose 34 per cent to 12,035 boe/d from 8,988 boe/d in last year’s quarter, while full-year volumes climbed 28 per cent to 10,549 boe/d from 8,241 boe/d in 2013. Much of the g row t h ca me f rom Bigstone, wh ic h nearly doubled its fourth-quarter production to 7,743 boe/d from 3,884 boe/d in the 2013 period. Delphi drilled eight wells (7.6 net) in its capital program, completing, tying in and bringing on nine (8.5 net) Montney wells in East Bigstone in northwestern Alberta. Field condensate volumes rose 71 per cent in the fourth quarter, more than doubling in 2014, while natural gas liquids volumes increased 57 per cent in the quarter and 37 per cent in the full year. Financial results reflected higher netbacks from Montney Bigstone and higher commodity prices, management said. Revenue in the fourth quarter increased 21 per cent to $35.53 million from $29.46 million in the 2013 period. Delphi posted a net loss of $25.59 million in the fourth quarter, against a loss of $16.10 million in the 2013 period, while the company’s full-year net loss narrowed to $7.26 million from $11.63 million in 2013. Financial results reflected a $56-million writedown, recorded mainly on the company’s Hythe and Wapiti properties. “Low natural gas prices and other factors have reduced the cash flow potential and economics of the Hythe area, resulting in a $35-million writedown,” Delphi executives
said in a conference call. The Hythe property is also in northwestern Alberta. The writedown on the Wapiti property was smaller, at about $18 million, and together, the Hythe and Wapiti properties made up 94 per cent of the total $56-million writedown Delphi took in 2014. In the weeks ahead, Delphi’s lenders will conduct a review of the company’s borrowing facility. “We are in discussion with our subordinateddebt lenders around our debt-to-cash flow covenant, and fully expect to come to a resolution which ensures the execution of our current capital program,” said Brian Kohlhammer, senior vice-president and chief financial officer. “In light of the current commodity price cycle, we believe industry lenders will be working with their clients, as we have already seen, in the form of covenant relaxations and borrowing base levels to ensure funding stability for higher-quality assets,” he added. Delphi said it would in future sell its gas through Chicago, rather than through the AECO market, as had been its practice. “The new commitment relates to the take-or-pay delivery fee we have agreed to incur to take our production into the Chicago market,” said Kohlhammer. The new commitment takes effect Dec. 1, 2015 at 35.5 mmcf/d, rising to 62.8 mmcf/d by the fourth quarter of 2017 and lasting until Oct. 31, 2020. Delphi’s fourth-quarter 2014 gas volumes reached 49.9 mmcf/d, the company said. For 2016, the company has hedged about 62 mmcf/d of production at $4.16/mcf. The higher sales price will be off set by a
Delphi plans on selling its gas in Chicago rather than in the AECO market.
delivery fee paid to move the gas to the Chicago market. On average, as part of its risk management program, Delphi has hedged about 79 per cent of this year’s gas production at a price of C$3.67/mmcf, management said. In 2014, capital spending reached $118.5 million, including acquisitions, compared to $85.6 million in 2013. The program was directed mainly to Montney development at Bigstone, including drilling, building infrastructure and expanding facility capacity for the Montney Bigstone project. Non-core asset sales in 2014 generated $16.6 million, up from $3.3 million in 2013, and were mainly used to fund $17.7 million in acquisitions in the Bigstone area, management said. Also in 2014, Delphi expanded the capacity of its wholly-owned compression and dehydration facility in East Bigstone to 45 mmcf/d from 30 mmcf/d, and doubled field condensate storage capacity to 6,000 barrels. As well, the company completed pipeline connections to deliver its Montney production at Bigstone to the SemCams K3 processing facility, which it will now be using. O I L & G A S I N Q U I R E R • M AY 20 15
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Northwestern Alberta
Birchcliff pushes ahead in difficult gas market Birchcliff Energy expects its production in 2015 to average between 38,000 and 40,000 boe/d, with production in the first quarter to reach approximately 37,000–38,000 boe/d, the company announced in March. “Our strategy of growth by the drill bit with repeatable, lowcost drilling opportunities provides for low-cost production and reserve additions, on a consistent year-over-year basis, giving Birchcliff the confidence that it can grow in these difficult times,” Jeff Tonken, president and chief executive officer, said. “Birchcliff expects its average annual production in 2015 will grow approximately 16 per cent from 2014, all from the drill bit.” The company’s 2015 capital budget of $226.7 million incorporates $164.7 million towards the drilling and development of 25 (24.5 net) wells, including 14 Montney D1 and four Montney D4 horizontal gas wells, three Basal Doig and Upper Montney horizontal gas wells, one Montney C horizontal gas well, one Charlie Lake horizontal light-oil well, one (0.5 net) Halfway horizontal light-oil well, as well as one other well and $13 million in carry forward. “We remain focused on our strategy, growth by the drill bit, in our core area of the Peace River Arch of Alberta,” Tonken said. “We continue to use the same services, in the same area, directed by the same experienced Birchcliff personnel, which provides consistency, repeatability and reliability in our operations.” According to the operational update, so far in 2015 Birchcliff has successfully explored the Elmworth area in its Montney D4
interval on the Montney and Doig natural gas play, where the company drilled a 100 per cent working-interest horizontal gas well at Elmworth that should come on production by the end of March. Year-to-date, the company has drilled 12 (11.5 net) wells, which include nine Montney/Doig horizontal gas wells in the Pouce Coupe area, one Montney/Doig horizontal gas well in the Elmworth area, one (0.5 net) Halfway horizontal light-oil well at Progress, as well as a 100 per cent working-interest Belloy vertical well drilled as a potential acid gas-injection well at Elmworth. Birchcliff currently has two rigs working, both drilling Montney/Doig gas at Pouce Coupe. Birchcliff recently reduced its 2015 capital budget from an initial range of $450 million to $500 million announced in November 2014, due to lower commodity prices. Management expects to fund its 2015 capital program using cash flow and available credit facilities, with the capital program maintaining a strong balance sheet and significant financial flexibility. 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 for the year. Birchcliff will adjust its 2015 capital budget to respond to changes in commodity prices and other material changes in the assumptions underlying its 2015 budget. Deloitte’s independent reser ves evaluation found that Birchcliff ’s proved-plus-probable (2P) reserves at year-end 2014 were 465 million boe, which is 26 per cent more than at year-end
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Northwestern Alberta
2013, while proved reserves were 282.2 million boe at Dec. 31, 2014, which is up 28 per cent from the same point one year prior. At the end of 2014, the company’s reserve-life index was 19.8 years on a proved basis and 32.7 years on a 2P basis, assuming an average production rate of 39,000 boe/d. The company’s Pouce Coupe South (PCS) gas plant currently processes about 155 mmcf/d of sales gas, with Phase IV expansion of the plant, which expanded processing capacity to 180 mmcf/d, completed on schedule and on budget in September 2014. Birchcliff is currently undertaking engineering, procurement and fabrication work for Phase V expansion, increasing processing capacity to 260 mmcf/d and with start-up in late in the fourth quarter. As a result of weak commodity prices and a reduced capital budget, though, management is delaying field assembly and construction work of the Phase V expansion. The company currently expects to rebid field assembly and construction work for Phase V expansion later this year, which management anticipates will result in cost savings due to the continued reduction in demand for labour, services and materials. As a result, the company is currently uncertain of field assembly, construction and start-up timing for Phase V, which management should determine later this year. Management has initiated preliminary planning and permitting work for Phase VI expansion of the PCS plant, which should increase processing capacity to 320 mmcf/d. While Birchcliff previously indicated Phase VI startup would occur in late 2016, due to the above-mentioned delays the timing of construction and startup is currently uncertain and will be determined later.
Birchcliff is expanding its Pouce Coupe gas plant in anticipation of increased production.
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N.E.
NORTHEASTERN ALBERTA WELL ACTIVITY MAR/14
MAR/15
Wells licensed
30
MAR/14
MAR/15
Wells spudded
70
MAR/14
MAR/15
75
Rigs released
▼
▼
Northeastern Alberta
▼
Source: Daily Oil Bulletin
Suncor wants to test CO2-aided SAGD at Fort MacKay By Pat Roche
Suncor Energy hopes to test whether adding CO2 to steam injected into a SAGD reservoir would increase bitumen production due to CO2 solubility and a lower steam to oil ratio (SOR). In an application filed last week with the Alberta Energy Regulator, Suncor is seeking approval to add CO2 to steam injected on well pair 008 on Pad 24 at its MacKay River project northwest of Fort McMurray. Under Suncor’s current timeframe, the CO 2 and steam co-injection pilot would begin in the fourth quarter of this year and run for up to 12 months, depending on reservoir response and operation. Suncor hopes co-injecting CO2 with steam will reduce the SOR and increase
bitumen mobility while reducing bitumen viscosity due to the solubility of CO2 in the oil. Since CO2 has been shown to be effective in some enhanced oil recovery processes due to solubility in oil and swelling factor, CO2 co-injection with steam may have the potential to improve the SAGD process. The potential for CO2 retention or storage in the reservoir would also be evaluated. It is expected that after some retention in the reservoir CO2 will be produced mainly in gas phase from the production well. If CO2 co-injection with steam proves beneficial, CO2 produced in the flue gas from onsite fuel combustion could be used. But for the pilot, liquid CO2 will be trucked to the site. “Despite many research and laboratory tests…it is unknown how reservoir production
Suncor hopes CO2 injection will increase bitumen mobility at Fort Mackay.
and SOR will be affected by CO2 co-injection. It is also unknown how much of the injected CO2 would remain underground,” said Suncor, in explaining the need for the field test. There are no environmental concerns because the CO2 injection equipment would be installed at the existing MacKay River project, which has operated since 2002, Suncor said in its application. Less than 7.5 tonnes of CO2 a day would be injected. At the start of co-injection, the CO2 would be about one per cent of the weight of the injected steam, and gradually increase to five per cent. As the CO2 dissolves in the bitumen, it would lower the viscosity of the semi-solid hydrocarbon, which is expected to compensate for the fact that co-injected CO2 would lower the partial pressure of the steam and lower the steam’s saturation temperature, which would actually increase bitumen viscosity, the application says. The injected CO2 is also expected to form a gas blanket around the edge of the steam chamber, reducing heat loss into the overburden. MacKay River was chosen instead of Suncor’s Firebag SAGD project because there is no mobile water beneath the reservoir at MacKay, hence there is no concern about the water being contaminated by CO2 migration. Suncor says the average thickness of the three cap rock units over the 008 well pair is 41.5 metres. The three laterally continuous units are the Wabiskaw D mudstone overlain by the Wabiskaw A shale, which in turn is overlain by the thickest unit, the Clearwater shale. The 008 well pair is producing about 466 barrels of bitumen per day—lower than the average MacKay River well pairs, so the risk of production loss during the pilot is lower. The ultimate recovery for the pattern where the 008 well pair is located is estimated at 52 per cent—10 per cent below the MacKay River average. Up to January 2015, the 008 well pair had recovered 13 per cent of the original bitumen in place. O I L & G A S I N Q U I R E R • M AY 20 15
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Northeastern Alberta
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M AY 20 15 • O I L & G A S I N Q U I R E R
Equipment for the CO2 co-injection pilot would include a liquid CO2 storage bullet, a pump, a vaporizer and a chemical injection line for the injection of corrosion inhibitor. Once trucked to the MacKay River site, liquid CO2 would be kept in a storage bullet with a capacity of 75 cubic metres. CO2 will be pumped to injection pressure and vaporized in an electrical heater before mixing with steam upstream of the injector wellhead. The test separator at Pad 25 will be used for gas and liquid monitoring via metering and additional sampling. After the test separator, the produced fluids would return to the main production header for transport to the central processing facility. No extension of the lease is required for the new equipment. In planning the pilot, one of the main concerns is the potential for corrosion from CO2 reacting with water droplets in steam. Suncor says this will be closely watched through a corrosion monitoring system. Corrosion inhibitor is to be used to reduce the possibility. Metals don’t corrode in dry CO2 gas, but when CO2 gas is dissolved in water, a weak carbonic acid is formed and becomes corrosive. The main impact to the surface and wellbore facilities comes from the increased corrosion risk. Last year, Frank Cheng of the University of Calgary’s Schulich School of Engineering did a study for Suncor to model and predict the corrosion of steel tubulars in SAGD CO2 co-injection and production systems.
Total withdraws Joslyn North Mine applications By Lynda Harrison
Total E&P Canada has withdrawn its regulatory applications to amend the approvals it was granted in 2011 for the Joslyn North Mine, citing “significant changes to global energy market conditions,” but says it is open to restarting the oilsands project when its economics improve. “Oilsands remain an integral part of Total’s global, long-term strategy but developing the Joslyn lease is no longer considered a near-term priority,” said a February 25 letter from Hugh Campbell, Total’s vicepresident of health, safety and environment and operations support, to the Alberta Energy Regulator. The proposed $11-billion Joslyn North Mine project was delayed last year—the company announced at the time that development activities would be paced—to give its owners time to fi nd ways to reduce costs, putting 150 people out of work. Total will, however, continue to participate in building its other oilsands projects, Fort Hills and Surmont, the letter said. Total and its partners have not progressed to the point of making a final investment decision on Joslyn, noted Andrew Hogg, vice-president of human resources and communications. In the short term, Total will assess what needs to be done to stabilize the areas of the project where work has been done. Hogg said that in addition to engineering work, some drainage and tree clearance had been done on site. He said he could not provide an estimate as to how much capital had been spent to date. Total is operator of the Joslyn North Mine project with a 38.25 per cent interest, while Suncor Energy has 36.75 per cent interest, Occidental Petroleum has 15 per cent and Inpex has 10 per cent.
CENTRAL ALBERTA WELL ACTIVITY MAR/14
MAR/15
Wells licensed
72
MAR/14
MAR/15
Wells spudded
13
MAR/14
MAR/15
18
Rigs released
C.A.B.
▼
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Central Alberta
▼
Source: Daily Oil Bulletin
Bonavista outlines spending plans
Bonavista plans on drilling between 60 and 70 wells in central Alberta in 2015.
Bonavista Energy has lowered its 2015 budget to between $300 million and $320 million from planned spending of $375 million to $425 million, announced in December. It will now drill between 70 (60.4 net) and 80 (69.1 net) wells. Notwithstanding a curtailment of approximately 3,500 boe/d in its annual guidance due to planned facility turnaround activity, annual production is expected to grow approximately five per cent year over year to between 80,000 and 82,000 boe/d. Bonavista’s West Central core area is characterized by liquids-rich natural gas and light oil resources in multiple prospective horizons, with year-round access. It includes extensive infrastructure of over 2,800 kilometres of pipelines and 38 facilities, the majority of which are operated by Bonavista. In this core area, the company has access to approximately 1.3 million acres, containing approximately 800 future drilling locations. Given the current development pace of
drilling 50–60 locations per year, this represents a drilling inventory in excess of 14 years. In 2014, the company spent $380 million on engineering and development (E&D) activities, drilling 98 (82.2 net) horizontal wells. In 2015, the company plans to reduce E&D spending to $167 million, due to current commodity price weakness, drilling 54 (43.8 net) horizontal wells. Production in this area averaged 46,796 boe/d in 2014 representing a 13 per cent increase over 2013, despite significant third party turnaround activity in the second and third quarters. The Hoadley Glauconite Play continues to be the engine of growth representing 71 per cent of the total expenditures forecasted in this core area for 2015. Meanwhile, the emerging growth and profitability of the Falher Play, even in this commodity price environment, has become a focal point of the company’s planning given its recent drilling successes.
Bonavista conducted its most active year targeting Glauconite gas in central Alberta, drilling 69 (59.5 net) horizontal wells, representing a 78 per cent increase in net wells from 2013, including 10 wells (9.4 net) in the fourth quarter. This increased activity has resulted in fourth-quarter production of approximately 27,000 boe/d, equating to over 50 per cent growth since the beginning of the year. Well economics remain strong in spite of the decrease in natural gas and natural gas liquids pricing. With the addition of deep-cut processing at the Rimbey facility during the second quarter of 2015, the company expects a 40 per cent improvement in the natural gas liquids recoveries, to approximately 100 bbls/mmcf. Using these improved recoveries, single well economics are slightly improved to a 30 per cent internal rate of return (IRR), using a price of $3/GJ at AECO for natural gas and a WTI price of US$60/bbl for oil O I L & G A S I N Q U I R E R • M AY 20 15
27
Central Alberta
and condensate. This is a testament to the quality of this play and its ability to generate competitive returns in the current commodity price environment, the company stated. The company has drilled 12 extendedreach horizontal wells to date, averaging 1.9 times the length of a typical one-mile well. Using this horizontal length multiplier, these wells have demonstrated cost reductions averaging 19 per cent and production capital efficiency improvements of six per cent. Slickwater completions for these wells have resulted in additional cost savings of 25 per cent versus a standard completion technique. Bonavista plans to drill an additional eight extended-reach wells in 2015. Being the most active operator, with inventory of approximately 400 locations and strong economics, the Glauconite will continue to serve as the foundation of Bonavista’s development program. As such, 44 (33.8 net) wells are planned to be drilled in 2015. In 2014, the Falher E&D program at Morningside yielded exciting results, with the drilling of six horizontal wells, including one during the fourth quarter, said Bonavista. First month production
rates have averaged 1,070 boe/d, inclusive of natural gas liquids yield of approximately 50 bbls/mmcf. Production grew sevenfold to 4,070 boe/d during December 2014 from 500 boe/d in January 2014. The company has 25 Falher drilling locations in its inventory at Morningside and development economics continue to compete with the flagship Glauconite Play. Well costs are $3 million to drill, complete and equip, generating an internal rate of return of 36 per cent using prices of $3 AECO for natural gas and a WTI price of US$60/bbl. The low cost and high deliverability of the Falher enables this play to achieve competitive rates of return at current commodity prices. Consequently, the company plans to drill eight (eight net) Falher wells in 2015, seven of which will be at Morningside. The company drilled four Ellerslie wells in 2014, all of them during the fi rst half of the year. During the second half, the capital allocation shifted away from the Ellerslie and over to the Deep Basin Wilrich Play as a result of the Ansell acquisition. At current commodity prices, the Ellerslie does not
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M AY 20 15 • O I L & G A S I N Q U I R E R
compete with the company’s Glauconite and SpiritRiver plays, and as such there are no wells planned for 2015. The company’s Deep Basin core area contains multiple vertically stacked oil and natural gas reservoirs in a concentrated area, proximate to infrastructure and associated services. Over the past three years, the company has been aggressively building its position in this core area. It has assembled approximately 300,000 net acres, identified 300 horizontal drilling locations and has achieved compounded annual growth in its reserve base of 62 per cent to 111 million boe proved-plus-probable reserves at Dec. 31, 2014, during this period. In 2014, the company spent approximately $175 million on E&D activities, drilling 32 (25.3 net) horizontal wells and built $31 million of infrastructure. This resulted in average annual production growth of approximately 30 per cent to 17,276 boe/d. Bonavista had an active fourth-quarter drilling program in the Deep Basin, drilling 11 (9.8 net) horizontal wells, seven of which were Wilrich wells at Ansell. The Wilrich results continue to exceed expectations; as such, the company plans to install
Central Alberta
additional processing infrastructure in 2015 and have secured incremental egress for its production. Plans for 2015 involve spending $106 million on E&D activities, drilling 19 (18.9 net) horizontal wells. With compelling production performance, the Wilrich Play provides solid economics in the current natural gas pricing environment, resulting in an attractive IRR of 36 per cent, using prices of $3 AECO for natural gas and a WTI price of US$60/bbl. As the company develops the extensive Notikewin and Falher channel systems deposited above the Wilrich reservoir, the company anticipates significant inventory additions to its asset portfolio in this play. Within the Wilrich zone at Ansell, Bonavista drilled 15 (13.9 net) horizontal wells in 2014, including seven (seven net) in the fourth quarter. In 2014, the development plan at Ansell consisted of infrastructure investment with a goal to develop an unrestricted egress for its Ansell Wilrich development. During the first half of the year, the company commissioned two 30-kilometre pipelines with 120 mmcf/d of capacity
and constructed a 30 mmcf/d compressor station. In July, Bonavista acquired its non-operated partner, increasing its ownership from 51 per cent to 100 per cent and, during the fourth quarter, expanded its compression capacity to 60 mmcf/d. With the 2014 Ansell Wilrich drilling program, the company continued to improve its understanding of the play as well as enhance the completion techniques. As a result, Bonavista has improved the initial 30-day production rate from 674 boe/d for first-quarter 2014 wells to 964 boe/d for fourth-quarter 2014 wells. Continuous improvement in the economic performance at Ansell has earned the allocation of 71 per cent ($75 million) of the company’s 2015 Deep Basin capital expenditures, consisting of 16 (16 net) wells. In the Marlboro area, the company drilled five horizontal wells (3.1 net) in 2014, including two (1.6 net) in the fourth quarter. Bonavista said it’s pleased with the Marlboro program as the wells have achieved an average 30-day rate of 975 boe/d. With existing facility utilization near capacity at Marlboro, the company does not plan to drill any wells in 2015.
The successful 2014 Wilrich programs at Ansell and Marlboro has resulted in Wilrich production growing by over 170 per cent in 2014 to approximately 13,000 boe/d in December. In 2014, the company identified numerous Notikewin and Falher opportunities using 3-D seismic. Subsequent to the fourth quarter, Bonavista drilled its first Notikewin well at Ansell, which recorded an initial 30-day rate of 710 boe/d. Bonavista was pleased with this initial result and remain optimistic about future development. The economics of the Notikewin and Falher will benefit from existing infrastructure constructed for the Wilrich and Bluesky programs. In 2014, Bonavista drilled five horizontal Bluesky wells on its Pine Creek acreage. In the fourth quarter, Bonavista drilled two wells with an average 30-day rate of 810 boe/d per well. It also participated in an additional five nonoperated wells with an average 30-day rate of 520 boe/d per well. The operated Bluesky wells have exceeded expectations, however, given facility capacity constraints and the current commodity price environment, the company will only drill one Bluesky well in 2015.
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29
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SOUTHERN ALBERTA WELL ACTIVITY MAR/14
MAR/15
Wells licensed
8
MAR/14
MAR/15
Wells spudded
6
MAR/14
MAR/15
12
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Low commodity prices hitting LGX With cash flows affected by oil prices at five-year lows, LGX Oil + Gas is working to ensure it has the ability to meet its financial obligations under its credit facilities and satisfy the 2015 drilling commitments under its lease of lands on the Blood Reserve. The company is currently evaluating measures, including but not limited to asset sales, accessing third-party capital, joint ventures and drilling commitment extensions. Fourth-quarter 2014 funds flow dipped to $477,855 from $1.16 million in the same quarter of 2013, while full-year funds flow climbed to $6.56 million from $4.41 million the year earlier. At current commodity prices, LGX says it may approach non-compliance with the existing fi nancial covenants under its credit facilities in the near future. Due to the significant decline in commodity prices, the estimated future cash flows of certain assets dropped below the carrying value of those assets. As a result, LGX recorded a $33.8-million aggregate impairment charge on the exploration and evaluation assets and the property, plant and equipment assets of the company in the fourth quarter of 2014. The company reported a net loss of $42.92 million for the year ending Dec. 31, 2014 (2013: $20.33 million). As of Dec. 31, 2014, the company had drawn $20.34 million (2013: $11.05 million) against its credit facilities of $30 million (2013: $25 million) and had other working capital deficiencies of $9.99 million (2013: $8.59 million). As the senior credit facility is a demand loan, it may be called at any time. The junior credit facility is term, but subject to acceleration in the event of breach of covenants. As the lending value of the credit facility is tied closely to reserves, which is directly linked to oil and natural gas forecasted benchmark prices, and current over-supply and
LGX is focused on meeting its 2015 drilling commitments while managing its credit facilities.
depressed pricing is expected to continue for the immediate future, there is no assurance that the credit facility will be renewed on current terms or levels when it is next formally reviewed no later than May 31, 2015. Should the bank not extend the loan, the company would need to seek alternative forms of debt or equity fi nancing, which would be difficult in the current environment, or dispose of certain assets to repay the outstanding indebtedness. Low oil prices, declining production and an emergency order for the protection of the Greater Sage-Grouse may reduce the ability of the company to generate positive cash flows from its operations and in turn may reduce the company’s ability to develop its properties. These circumstances create material uncertainty that lends significant doubt as to the ability of the company to meet its obligations as they come due and, accordingly, the appropriateness of the use of accounting principles applicable to a going concern, said LGX. Its consolidated financial statements include an adjustment to derecognize the
company’s deferred tax asset as there is doubt whether the company may have sufficient future net income to realize the deferred tax asset under current market conditions.
Marquee closes Michichi acquisition Marquee Energy has closed the previously announced strategic acquisition to further consolidate its core Michichi area. The acquisition includes approximately 330 boe/d and 34 net sections of land containing Banff/Mannville rights that are contiguous with Marquee’s existing land position and infrastructure at Michichi. “The acquisition at Michichi solidifies our control of land and infrastructure over a 25-mile long multi-zone, light oil fairway,” said Richard Thompson, president and chief executive officer. Marquee has identified approximately 40 high-quality, light oil locations on the acquired lands to add to its existing technically driven drilling inventory. O I L & G A S I N Q U I R E R • M AY 20 15
31
Southern Alberta
Anderson cuts costs, ups production Anderson Energy says the cost reductions it implemented could motivate it to resume drilling in the second half of 2015, particularly if commodity prices rise. The company said it has made significant changes to its administrative cost structure that are estimated to reduce costs by 15 per cent from 2014 and to cut field operating costs 17 per cent to $10.30/boe from $12.43/boe. In addition, Anderson is working with its suppliers and service providers to cut capital costs by 30 per cent. Due to weak commodity prices, the drilling of the company ’s remaining three (2.2 net) wells in its winter program was deferred. Production in the fourth quarter of 2014 rose 39 per cent to 3,396 boe/d,
32
M AY 20 15 • O I L & G A S I N Q U I R E R
revenue climbed 38 per cent and cash flow soared twentyfold, but net loss deepened more than twentyfold compared to the fourth quarter of 2013. Cardium output during the fourth quarter of 2015 represented 2,260 boe/d (48 per cent oil, condensate and natural gas liquids [NGLs]) and 2014 annual production was 3,141 boe/d (33 per cent oil, condensate and NGL). The company’s exit rate was 3,400 boe/d (41 per cent oil, condensate and NGL). By using selective positioning of the horizontal well trajectory, Anderson is realizing higher IP 30 production rates than historical Willesden Green area industry averages. The company has now adopted the use of dissolvable frac balls for toe fracs and has moved to less nitrogen usage in heel fracs. Other changes made this year include a redesigned stage tool to reduce the risk of mechanical wellbore failure.
TransCanada Pipelines (TCPL) outages cost Anderson 82 boe/d during the fourth quarter when TCPL was conducting maintenance operations and continued to disrupt production in the fi rst quarter of 2015 with an estimated average of approximately 430 boe/d of production shut-in. Production was restored in January 2015, but the outages resumed on Feb. 9, 2015, on Anderson’s northern blocks and continued throughout the rest of the first quarter of 2015. New outages commenced on March 19 on the company’s central land blocks and on March 23 on its southern land blocks. Outages were forecasted by TCPL to end on April 2 and to resume in June. The company estimates the impact of the TCPL outages averaged approximately 430 boe/d in the fi rst quarter of 2015 and are expected to reduce production in the second quarter of 2015 by approximately 370 boe/d.
Southern Alberta
“There are a lot of challenges in front of us, but we believe that oil prices will correct upward in the future, TCPL will fi nally complete their maintenance and then, when economic and fi nancial conditions dictate, we can be back in the fi eld drilling with a new economic equation,” wrote Brian Dau, president and chief executive officer, in a release. The company estimates production will be 2,200–2,400 boe/d (46 per cent oil, condensate and NGL) in the fi rst half of 2015, net of estimated TCPL outages of 400 boe/d and the impact of approximately 500 boe/d of production sold on January 23. Field capital spending is estimated to be $7 million, most of which occurred in the fi rst quarter of the year. Operating costs averaged $10.03/boe in t h e f o u r t h q u a r t e r o f 2 014 a n d $12.43/boe for the year, a 30 and six per cent reduction respectively, from the previous periods.
“There are a lot of challenges in front of us, but we believe that oil prices will correct upward in the future, TCPL will finally complete their maintenance and then, when economic and financial conditions dictate, we can be back in the field drilling with a new economic equation.” — Anderson chief executive officer Brian Dau
Wit h t he reduc t ion i n com modity prices, Anderson has been focusing on reducing field operating expenses, although a significant portion of its operating expense is fi xed and relates to legacy shallow gas assets. T he c ompa ny s a id it w i l l m a rket it s sh a l low g a s a s set s i n t he se cond qu a r te r of 2 015 to f u r t he r i mpr ove its liquidit y. The company has or is proceeding to shut in or abandon 74 (42.7 net) shallow
gas wells that were producing approximately 172 boe/d and suspend 10 natural gas compressor stations. Anderson has also improved its operating expenses by attracting and collecting third-party processing income. The company’s overall operating expenses in 2014 averaged $12.43/boe. The company estimates that it can reduce operating expenses to $10.30/ boe in 2015, which would be a 17 per cent improvement relative to 2014.
Get the business intelligence you need to help you plan through the downturn and beyond. 2015 Mid-Year Drilling Activity Forecast Thursday, April 30, 2015 11:30 am – 2:00 pm Westin, Calgary
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Join the Petroleum Services Association of Canada as we present its 2015 Mid-Year Drilling Activity Forecast on April 30, 2015 to get important business intelligence to help fuel your ongoing planning to deal with the current downturn. Can’t Join Us? You can get forecast numbers and other key information on top operators, meterage, and well type breakdown in regions across Canada in PSAC’s Canadian Drilling Activity Forecast publication. When used in conjunction with the PSAC Well Cost Study, the Canadian Drilling Activity Forecast can be used to determine potential market sizes for drilling and completion products and services, as well as pricing and activity direction.
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O I L & G A S I N Q U I R E R • M AY 20 15
33
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S.K.
SASKATCHEWAN WELL ACTIVITY MAR/14
MAR/15
Wells licensed
136
MAR/14
MAR/15
Wells spudded
63
MAR/14
MAR/15
95
Rigs released
▼
▼
Saskatchewan
▼
Source: Daily Oil Bulletin
Raging River Viking production continues to skyrocket Raging River Exploration boosted its yearover-year production by 90 per cent in 2014 due to a successful drilling program in 2013 and 2014, combined with about 800 boe/d attributed to a Dodsland-area property acquisition that closed late in 2013. According to the company’s fourth-quarter and year-end financial and operational results, average production increased 61 per cent to 12,548 boe/d in the final quarter of 2014, compared to 7,777 boe/d in 2013. Capital expenditures totalled $97.12 million and $278.59 million, respectively, for the three and 12 months ended Dec. 31, 2014, which represents a 41 per cent decrease and two per cent increase from the same periods in 2013. Fourth-quarter
spending included $92.9 million on drilling, completion and production facilities, $119,000 on geological and geophysical costs, as well as $4.1 million on land and property acquisitions. In the fourth quarter, Raging River drilled 109 (90.9 net) crude wells, resulting in 106 (88.1 net) oil wells and three (2.8 net) dry holes, primarily in the Dodsland area of southwestern Saskatchewan. For 2014, Raging River drilled a total of 294 (248.8 net) wells, resulting in 288 (244 net) crude wells, one (0.5 net) stratigraphic test well and five (4.3 net) dry holes. Operating costs averaged $11.45/boe in the final quarter of 2014 and $11.89/boe for the full year, which represents an eight and
Raging River Viking Play metrics 85.02 Revenue/$boe
85.80 54.00 28.37
FD&A/$boe
25.13 25.13 25.77
Cash cost/$boe
29.56 21.78 54.14 54.69
Supply cost/$boe 46.91 30.88 Revenue less supply/$boe
2013 2014
31.11 7.09
2015 Estimate Source: Raging River Exploration
five per cent decrease from the same periods one year prior, respectively, due to mild winter conditions in 2014 as compared to 2013, a significant component of operating costs being fi xed and the company achieving operating efficiencies from focused operations in its core area. Transportation costs averaged $1.30/boe in the fi nal quarter of 2014 and $1.78/boe for the full year, which represents a 38 and 16 per cent decrease from the same periods one year prior, respectively, due to expanded pipeline infrastructure resulting in less clean-oil trucking. Post-2014, Raging River closed another previously announced property acquisition in the Dodsland area in southwestern Saskatchewan for $35.6 million (before closing adjustments), with the Viking property adding 600 boe/d production at an average decline rate of 30 per cent per year. Crews completed all first-quarter 2015 capital activities in late February, with a total of 60 (53.3 net) wells drilled. To take advantage of anticipated reduced service costs, crews drilled but did not complete a total of 19.4 net wells in the first quarter. Management anticipates no further capital activities until completion of these wells in late May. Of the 60 wells drilled, a total of 30 were on stream for at least 30 days with average oil rates of about 55 bbls/d, which is equivalent to the average results of the 560 wells drilled from March 2012 to December 2014. Raging River currently intends to spend $120 million on its 2015 capital budget, which is a decrease from the $175 million the company initially forecasted it would spend over the year. According to management, anticipated cash flow combined with the existing credit facility of $300 million should fund the capital program. Subsequent to year-end, Raging River completed a bought-deal O I L & G A S I N Q U I R E R • M AY 20 15
35
Saskatchewan
Surge volumes up in Saskatchewan
Raging River drilled 60 wells before spring breakup, but will wait to complete 20 wells in anticipation of lower costs later this year.
fi nancing using $84.1 million in net proceeds to repay outstanding indebtedness under the company’s credit facilities, which management will redraw to fund this year’s capital expenditure program and for general corporate purposes.
Alta.; and three wells in southeastern Saskatchewan. One unsuccessful well in the fourth quarter was a partner-drilled farmout, done at no cost to Surge. In the full year, the company reported a 99 per cent success rate, as it drilled 73 (43 net) wells. Surge boosted its crude oil and natural gas liquids weighting eight per cent in 2014, to 85 per cent from 79 per cent in 2013, management said. Surge’s fourth-quarter capital spending reached $39.8 million, excluding acquisitions and dispositions, versus $40.32 million in the 2013 period. Also in the fourth quarter, roughly $27.7 million was spent drilling 23 (14.1 net) wells. The company put $9.8 million into facilities, equipment and pipelines, spending $2.2 million on land and seismic acquisitions and other capital items. In 2014, capital spending came in at $149.6 million, excluding acquisitions and dispositions, compared to $125.55 million in 2013. Surge spent $98.2 million drilling 73 (43 net) wells during the year, and invested $40.3 million in facilities, equipment and pipel i nes, put t i ng some $11 m i l l ion
Surge Energy reported record production in the fi nal quarter of 2014, driven largely by production increases in Saskatchewan. Total volumes in the quarter jumped 70 per cent to 20,448 boe/d from 12,014 boe/d in the 2013 period, while full-year production rose 67.8 per cent to 18,069 boe/d from 10,769 boe/d in 2013. Management attributed stronger volumes to better than expected drilling results at the company’s Valhalla, Shaunavon and Midale properties, all in Saskatchewan, and to its southeastern Alberta core areas, as well as volumes added through two smaller core area acquisitions. In the fourth quarter, 11 (2.8 net) wells of Surge’s 23 gross wells drilled were Viking farmouts, requiring no capital spending by the company. The other 12 gross wells drilled in the quarter included one at Wainwright, Alta.; one at Eyehill, Alta.; five at Shaunavon, Sask.; one at Valhalla, Sask.; one at Nipisi,
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into land, seismic acquisitions and other capital items. In the fi rst half of 2015, Surge plans to put just $22 million into its capital spending program. The figure will cover spending until July 1, 2015, at which time management said it would reassess capital spending for the second half of 2015.
Calfrac ups its game in Viking Calfrac Well Services reports it has achieved a new level of efficiency in the Viking Play as it successfully completed the fracturing of two wells within a 12-hour period. On a t wo-well pad for W hitecap Resources, Calfrac used two masted coiled tubing units simultaneously with one 12-hour fracturing crew. The annular fracturing was completed with a combined treatment of 36 stages, 470 tons of sand and 1,280 cubic metres of fluid in 12.5 hours of pumping time, Calfrac said.
12 hours Time it took Calfrac to complete a 36-stage Viking well
In addition, Calfrac and Whitecap used the same strategic approach to successfully complete a 24-stage well and a 36-stage well each within a 12-hour period. Since 2013, Calfrac said it has worked extensively on its operational processes to identify areas of improvement that have resulted in the company’s success in the Viking. A thorough evaluation continues to be performed throughout the entire job cycle in the search of maximum efficiency and treatment optimization, it noted. The company has grown its operations in the Viking market through the combination
of product sourcing and logistics, strategically located sand storage terminals, local infrastructure, equipment solutions, en ha nced pro cedu re s, u n ique f lu id systems, best-in-class training and experienced personnel. “Calfrac has played an integral role in the development of our Viking assets and the ability to frac two wells in the same day is a testament to their outstanding execution,” said Brad Jennings, operations engineer at Whitecap. “Capital efficiency is paramount and innovations such as this improve our economics.”
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Cover Feature
Measu
SALES OF OILFIELD EQUIPMENT BEGAN DECLINING IN 2013 AND HAVE CONTINUED INTO 2015.
40
M AY 20 15 • O I L & G A S I N Q U I R E R
Cover Feature
ring success T H E L A S T D E C A D E has been wild ride for Canadian manufacturers of oilfield equipment and machinery, according to Statistics Canada. The trend has been upward, with sales of mining and oil and gas field machinery increasing almost every year from 2003-13 and more than doubling in value. But the bad years have been real bad. Sales for Canadian manufacturers fell 28 per cent in 2009 to $3.3 billion, before rebounding by 29.6 per cent in 2010 and 43.3 per cent in 2011. In 2011, annual sales were 34 per cent above their pre-recession peak. Sales for the industry continued to increase in 2012, up 4.3 per cent to a record high of $6.3 billion. But then the trend reversed. Sales of mining and oil and gas field machinery declined 14.3 per cent in 2013 as the domestic industry experienced a downturn. Sales continued to decrease in the first three quarters of 2014, declining 1.1 per cent on a year-to-date basis. The trend for domestic manufacturers tracks the overall trend for oilfield equipment expenditures in Canada. Including imported machinery and equipment, spending on field machinery and equipment totaled $8.4 billion in 2008, before declining to $5.7 billion during the fi nancial crisis of 2009, according to Canadian Association of Petroleum Producers (CAPP) numbers. In 2010, sales recovered to $8.4 billion and then rapidly climbed to $13.8 billion in 2013. But with the crash in oil and gas prices, oilfield manufacturers are about to face another tough year in 2015. In January, CAPP predicted a 33 per cent decline in capital spending, down to $46 billion from $69 billion last year. This is comparable to spending levels in 2010. But a more recent survey of 77 producers by the Daily Oil Bulletin puts 2015 capital spending closer to $40 billion, with companies continuing to cut capital budgets
THE NUMBERS TELL THE STORY FOR CANADIAN OILFIELD MANUFACTURERS By Darrell Stonehouse as the year progresses. If field equipment and machinery spending tracks past trends, the overall Canadian market could shrink by $5.4 billion in 2015, back to levels of around $8.4 billion. In response to producer capital budget cuts, service companies from rig manufacturers down through the supply chain are slashing spending.
Rig building boom over
The last four years have seen a boom in rig building as drilling contractors retire older rigs and replace them with fit-for-purpose new rigs designed for shale and tight resource plays. That boom is now over. Ensign Energy Services is one example of this new reality. As late as last November, the company had plans to build 34 new high-tech ADR rigs by 2016 to serve the resource play market. Now, only nine of these rigs are being built to satisfy customer contracts. Each rigs costs approximately $25 million, according to the company. “We’re seeing this market, not as a short-term bump in the road, but as a new normal that will take years, not months, to normalize,” Ensign president and chief operating officer Bob Geddes says. Trinidad Drilling is also cutting costs and reducing new rig builds. “Given the weakness in commodity prices, we lowered our original capital expenditures planned for 2015 from $350 million to $175 million,” says Lyle Whitmarsh, Trinidad’s chief executive officer. O I L & G A S I N Q U I R E R • M AY 20 15
41
Cover Feature
“I E XPECT OUR RIG BUILDING ACTIVIT Y WILL BE IDLED UNTIL WE SEE AN IMPROVED COMMODIT Y PRICE ENVIRONMENT AND RISING CUSTOMER NE W-BUILD DEMAND.” — PRECISION PRESIDENT AND CHIEF EXECUTIVE OFFICER KEVIN NEVEU
Rather than building two new rigs to fulfill a commitment in the U.S., the customer has agreed to use two existing rigs. Capital items purchased for new builds and upgrades no longer required will be put into capital inventory for use on Trinidad’s existing fleet. In addition, Whitmarsh said Trinidad has chosen to postpone upgrades previously scheduled for existing rigs. Precision Drilling, Canada’s largest drilling contractor, is spending $467 million on capital projects in 2015, down from $857 million last year. Much of the 2015 capital spend is targeted towards 16 new builds that were announced in 2014 and expected to be completed this year. Two new build rigs scheduled for customer delivery in 2015 have been deferred. “Following the delivery of the 16 rigs, I expect our rig building activity will be idled until we see an improved commodity price environment and rising customer new-build demand,” says Precision president and chief executive officer Kevin Neveu. CanElson Drilling has gutted its 2015 capital program by 80 per cent, including the deferral of construction of three contracted drilling rigs. CanElson has delayed the completion of construction of Rig #47, Rig #48 and Rig #104 indefinitely. In November 2014, CanElson announced that it had signed the three drilling rigs to long-term contracts. However, CanElson is in the process of negotiating revisions to its agreements with a view to mutually beneficial outcomes. As of Dec. 31, 2014, CanElson had spent $13.6 million on long-lead components for these three rigs. CanElson cut its capital program to $12.9 million from $63.9 million, which now only covers critical maintenance items and minimal upgrade capital.
Completions market stalls
The resource play revolution resulted in massive expansion in the completions market over the 42
M AY 20 15 • O I L & G A S I N Q U I R E R
last five years, with extended-reach coiled tubing units coming to the fore and pressure pumping capacity rapidly expanding. With resource plays drilling stalled, the extended-reach coiled tubing expansion is on hiatus. Essential Energy Services has been in the process of updating its coiled tubing fleet in response to the resource play boom. In the fourth quarter of 2014, Essential retired 12 conventional coil tubing rigs, including five shallow, five intermediate and two deep rigs. These older rigs have shallower depth capacity and have historically operated at a much lower utilization than the extended-reach masted coil tubing rigs now in demand. Essential’s 2015 capital budget of $21 million, announced in January, is comprised of $13-million growth capital and $8-million maintenance capital. Essential’s 2015 growth capital consists primarily of four Generation IV masted coil tubing rigs, two of which are expected to be in service in 2015 and two in the first half of 2016. Essential’s long-term capital build program is aimed at increasing the size and depth capacity of the masted coil tubing fleet. To date, the company has added three Generation III and two Generation IV masted coil tubing rigs. Essential reduced its expected spend on this program from $63 million to approximately $48 million by deferring the build of one Generation III and two Generation IV rigs in early 2015. Upon completion of the $48-million spending program in 2016, Essential will have three Generation III and six Generation IV masted coil tubing rigs. By Dec. 31, 2014, Essential had spent approximately $37 million on this capital program. The Generation III and Generation IV rigs have the capability to work on long-reach horizontal wells and are well suited to work in deep, high pressure basins, including the Montney, Bakken, Duvernay and Horn River.
Cover Feature
Unlike other service companies, Canadian pressure pumpers saw a major over-build of equipment across North America in 2010-13, leading to a slowdown in capital spending for the last two years. That slowdown will continue in the current market. Calfrac saw its global pumping capacity expand from around 400,000 horsepower in 2008 to 1,194,000 by 2013. Calfrac’s 2015 capital program is anticipated to be approximately $215 million, which includes approximately $175 million of carryover capital from the 2014 capital program. Calfrac was able to defer or cancel approximately $30 million of the $360-million capital program previously announced for 2014. Calfrac now intends to deliver 140,000 horsepower in mid-to-late 2015. The company’s 2015 capital program of $40 million will be used for sustaining infrastructure and maintenance initiatives. Trican, Calfrac’s main Canadian competitor, also saw a major expansion of its fleet. And like Calfrac, Trican is on hold for 2015. “Given the reduced North American activity expectations for 2015, capital spending will be kept to a minimum throughout the year,” Trican chief executive officer Dale Dusterhoft said. “The primary focus will be on maintaining equipment quality and performance of our existing asset base. Based on existing capital budget commitments, we expect capital spending to be between $50 million and $60 million during 2015.”
Management also cited uncertainty due to the current industry downturn, increasing competition and “operational challenges” in achieving bid margins on oilsands projects. Enerflex, a global supplier of natural gas compression and facilities, also said the downturn has begun to affect customers and will likely “negatively impact demand for products and services” this year. Apart from cutting capital budgets, customers have deferred or cancelled some minor projects, Enerflex said. Goertzen said the company has undertaken cost savings measures in response to the downturn. In January 2015, for example, Enerflex cut staff, imposed a hiring freeze, deferred salary increases, limited business travel expenses and cut marketing spending and capital expenditures for facilities, IT infrastructure and maintenance.
“GIVEN THE REDUCED NORTH AMERICAN ACTIVITY EXPECTATIONS FOR 2015, CAPITAL SPENDING WILL BE KEPT TO A MINIMUM THROUGHOUT THE YEAR.” — TRICAN CHIEF EXECUTIVE OFFICER DALE DUSTERHOF T
Oilsands, facilities construction under pressure
It’s not just the conventional exploration and development equipment and machinery market under pressure in 2015. Manufacturers targeting the oilsands and other facilities construction are also facing significant headwinds. Oilsands fabricators are facing intense competition as operator capital budgets are cut. This is causing at least one fabricator to exit the market. Enerflex will step away from the oilsands modular construction market, closing its Nisku, Alta., fabrication facility later this year, company executives said in February. “The margins were extremely poor,” Blair Goertzen, Enerflex president and chief executive, said in a fourth-quarter conference call. “We just didn’t see a long-term future in that type of fabrication for Enerflex. “There’s a lot we do in the oilsands for gasgathering infrastructure, heating water, steam injection and SAGD, and we’ll continue those initiatives in Calgary, but it was really the carbonsteel, assembly-type operation and these modules just didn’t fit with our long-term strategy.” O I L & G A S I N Q U I R E R • M AY 20 15
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still next
year
country Low oil prices stall out promising oil exploration in southern Alberta BY DARRELL STONEHOUSE
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Feature
ust when it seemed a handful of junior exploration companies were making progress on unlocking a number of oil plays in southern Alberta, low prices are now putting much of that exploration and technical development effort on hold. Five years ago, the Alberta Bakken elevated interest in the south after a series of huge land sales in the region. That momentum, however, stalled after disappointing drilling results by a number of major players. So far, DeeThree Exploration is the only one to make a go of it drilling into the Exshaw Formation at Ferguson. But other junior explorers, like LGX Oil + Gas, are also reporting success. Yet other companies, like Hemisphere Energy, are finding success targeting untapped heavy oil targets in the region. Manitok Energy and Traverse Energy are taking a different approach, targeting traditional light oil formations with new technology. DeeThree Exploration is in full-on development phase at its Alberta Bakken discovery at Ferguson. In 2014, the company drilled 18 wells at Ferguson. With a reduced budget totaling $160 million, it has six wells planned for 2015. In 2015, DeeThree plans on focusing on its gas re-injection enhanced oil recovery (EOR) scheme on its Alberta Bakken property. Based on the success of the pilot that started in July 2013, the company invested an additional $7 million of capital in 2014, installing a built-for-purpose compressor and associated high-pressure injection lines, which have the capacity to re-inject all currently produced gas. Since increasing the injection rate in September 2014, the company has observed reduced declines over a 14-section area in the heart of the pool.
DEETHREE IS USING GAS RE-INJECTION TO DRIVE PRODUCTION AT FERGUSON.
Preliminary results from reservoir modeling by third-party consultants, using Petrel modeling software, predict the potential for a recovery increase of up to 200 per cent associated with gas re-injection beyond primary drilling alone. The first well drilled and completed in 2015 is a horizontal infill well located within the gas re-injection area. “The well has exceeded expectations and provides additional data which further supports the case for gas reinjection,” says DeeThree. “The 01-24-00317W4 well tested at various flowing rates of up to 1,800 bbls/d of crude oil and has continued to flow at a restricted rate of 370 bbls/d of oil and 450 mcf/d of gas at 305 psi after 14 days of production.” The company says it has drilled a second well into the pool using monobore technology and has seen drilling-cost reductions of 25–30 per cent. “Given the improved decline rates in the EOR area, the positive data from the computer modeling of the reservoir and the recent new well data described above, management is increasingly confident that the EOR scheme is effective, and as such, plans to accelerate the transition towards full implementation of EOR for its Alberta Bakken property,” says DeeThree. The second well of 2015 was designed specifically to optimize the company’s ongoing gas re-injection scheme. The 2,000-metre horizontal lateral well was drilled in the base of the Alberta Bakken zone within the core EOR scheme area and near where it has been re-injecting produced Bakken gas with a high CO2 content. At the end of a five-day production test, the well continued to flow at approximately 1,000 bbls/d of 30° API oil and 500 mcf/d of natural gas at a flowing wellhead pressure of 300 psi. The significant rate and, more specifically, the low gas to oil ratio (GOR) of the production further demonstrates the
efficiency and effectiveness of DeeThree’s gas re-injection EOR scheme. To date, the company has not seen any material gas breakthrough or increasing GOR’s in existing wells. The well was drilled with monobore technology and completed with cemented sliding sleeve technology. Having successfully executed both operations DeeThree expects to continue reducing its future drilling and completion costs. The company is focused on the longterm development of the pool with the goal of maximizing oil recovery and capital efficiency with a capital program tailored to match the EOR strategy. With an improving decline rate, increasing pressure support, a large drilling inventory and reduced capital costs, the company is expecting to grow production and free cash flow at a sustainable rate, even under current commodity pricing, it says. LGX has reported success in the Big Valley (Three Forks) Formation in southern Alberta. In November 2014, the company drilled two horizontal wells into the Big Valley Formation (12-02-008-24W4 and 06-36-008-24W4). The total capital expenditures for the two wells came in on budget at approximately $14 million. The 12-02 well was drilled with a 1,402-metre horizontal lateral and was completed with 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 1,134-metre horizontal lateral and was completed with a 20-stage fracture stimulation. The well was also put on production in late November and
O I L & G A S I N Q U I R E R • M AY 20 15
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Feature
averaged 185 bbls/d of light oil for the first 30 days of production. Water cuts are higher than the offsetting wells, indicating that load fluid is still being recovered from the well and maximum oil production 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 Manitok discovered five encountered significant hydrocarbon shows new lower Mannville in the overlying Banff Formation pools (two Glauconite as indicated by and three BQ) capable of drill cuttings, gas detector readings and strong oil commercial production. 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. While LGX is enjoying drilling success, current low prices are forcing it to retrench in 2015. Hemisphere Energy is taking a different approach in southern Alberta, targeting heavy oil pools in the Jenner area. During the fourth quarter, Hemisphere drilled, completed and equipped four horizontal oil wells in Atlee Buffalo. Three of these wells, drilled from the same pad, have been on production for over 30 days and have produced a combined rate of approximately 270 bbls/d of oil during the past two weeks. The fourth well was drilled to evaluate key lands in an area with historically higher associated water production. It produced approximately 30 bbls/d of oil, but due to lower oil prices and higher operating costs associated with trucking water, it will remain shutin until prices recover. In 2014, Hemisphere drilled 10 successful horizontal wells in Atlee Buffalo, with average performance at or above initial expectations. The company says it is encouraged by the results in Atlee Buffalo and is well poised to further develop this growth area in an appropriate pricing environment. Hemisphere’s management and board continue to monitor the current market conditions and will apply a conservative approach to capital spending during this time of low commodity prices.
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Feature
The company has no drilling commitments or material land expiries in 2015, and has deferred drilling activity until the second half of 2015. At current oil prices, Hemisphere’s production remains cash-flow positive due to its low operating costs. Hemisphere is presently optimizing its production base in the Jenner and Atlee Buffalo core areas while minimizing operating costs. At this time, the company will focus on reducing net debt in order to expand its financial flexibility to pursue potential acquisitions and maximize long-term shareholder value. Manitok Energy is taking yet another approach to the oil hunt in southern Alberta, targeting more conventional zones throughout its farm-in lands. During 2014, Manitok successfully drilled 14 wells with a 100 per cent working interest (four vertical and 10 horizontal) in the Entice area, fulfilling its 2014 capital commitment to PrairieSky Royalty. Manitok spent approximately $34.1 million on drilling and completions in Entice in 2014, exceeding the 2014 capital commitment by about $12.1 million. The $12.1 million will be carried forward and applied to the 2015 capital commitment of $33 million, resulting in a net 2015 drilling commitment of approximately $20.9 million. The company targeted horizontal drilling locations with multistage fracturing completions. Manitok successfully drilled, completed and tested four horizontal wells in the Lithic Glauconitic Formation and five horizontal wells in the Basal Quartz (BQ) Formation.
The 2014 Entice drilling program was successful in proving the concept that the large oil in place, tight sand reservoirs of the lower Mannville Formation are capable of commercial production, said Manitok. Of the 10 horizontal wells, seven wells were successful with test rates that support the potential for commercial production, two wells were hampered with mechanical issues or reservoir sloughing but were able to establish potential production from those reservoirs, and one well was unsuccessful. Manitok discovered five new lower Mannville pools (two Glauconite and three BQ) capable of commercial production. Based on the company’s seismic interpretation, geological mapping, historic well control and drilling results to date, Manitok’s potential horizontal drilling inventory has increased to 26 Glauconite locations in two pools and 40 BQ locations in three pools. Manitok has also identified four to five possible new pools (two to three lithic Glauconite and two BQ), using the company’s newly refined seismic information and well control. Manitok, however, has limited its budget to $3 million to $4 million in the first half of 2015 due to low prices and has no plans to drill any wells. Southern Alberta oil explorer Traverse Energy has also reduced capital spending plans for 2015, announcing it would cut its exploration and development budget to $15 million from $34 million. 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. 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 first two horizontal wells drilled in the Coyote Ellerslie pool were completed in October and started production in midNovember. The first well completed averaged 173 boe/d (83 per cent oil) from the beginning of tests to the end of January. The second well completed averaged 353 boe/d (85 per cent oil) from the beginning of tests to the end of January. These averages are calculated utilizing producing hours. The wells were on production 90 per cent of the time during December and January. The wells encountered some initial production issues due to the recovery of fracture sand placed during completion operations. Sand was subsequently cleaned out of both wells using coil-tubing operations. Artificial lift has now been installed on the first well; the second well continues to flow.
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M AY 20 15 • O I L & G A S I N Q U I R E R
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