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CONTENTS
SEPTEMBER.
www.sprung.com/oilgas
in the news
13
Service companies to up spending, says Conference Board
Engineered Fabric Building Solutions
regional news
19
37
British Columbia
LNG no sure thing, says Rick George
25
Northwestern Alberta
Northwest drives July land sale
31
Central Alberta
Tourmaline Oil says Spirit River/Charlie Lake significant new resource play
43
Southern Alberta
Pine Cliff Energy acquiring shallow gas assets
Northeastern Alberta
Rail in it for the long haul,
51
say railways
BlackPearl advancing Onion Lake
Saskatchewan
EOR program
features Cover Feature
54 63 67 Catching spark New ideas ignite in situ oilsands revolution
Wayfinders In situ oilsands operators navigate the options to get production to market
Short Term Leasing Available
Slow boil Bakken the hot spot but Viking, Shaunavon heating up in southwestern Saskatchewan
every issue
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10 Stats at a Glance 70 Political Cartoon
Direct Dial:
Cover design: Peter Markiw; Image: ©iStockphoto.com/upiir
info@sprung.com CALGARY • ALBERTA
OIL & GAS INQUIRER • SEPTEMBER 2013
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denali 3500Hd Crew Cab shown with available equipment. 2014 Sierra 3500Hd drW regular Cab with available duramax diesel and allison® transmission, when properly equipped. *maximum payload capacity for 3500Hd 4x2 regular Cab includes weight of driver, passengers, optional equipment and cargo. **maximum trailer weight rating of 23,100 lbs. for 3500Hd 4x4 regular Cab is calculated assuming a base vehicle, except for any option(s) necessary to achieve the rating, plus driver. the weight of other optional equipment, passengers and cargo will reduce the maximum trailer weight your vehicle can tow. see your gmC dealer for additional details. ©2013 general motors of Canada limited. all rights reserved. denali® duramax® gmC® sierra® we are professional grade®
Editor’s Note Vol. 25 No. 7 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Lynda Harrison, Carter Haydu, Richard Macedo, James Mahony, Pat Roche, Elsie Ross EDITORIAL ASSISTANCE MANAGER
Marisa Sawchuk | msawchuk@junewarren-nickles.com EDITORIAL ASSISTANCE
Kate Austin, Laura Blackwood, Matthew Stepanic
The changing geography of natural gas
CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER
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Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD
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Peter Markiw
CREATIVE SERVICES
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It used to be that natural gas flowed in predictable patterns across North America. Supply lay in the west and the south. Demand came mainly from the heavily populated northeastern United States and also central Canada and California. But then came the great upheaval. The advent of horizontal drilling and multistage fracturing is redrawing the natural gas map. The northeastern United States is in the midst of changing from buyers to sellers. A new report by energy analysts Wood Mackenzie predicts gas supply from the area will account for 60 per cent of North American natural gas production growth to 2020, topping out at about 14 billion cubic feet per day. By comparison, this is more than Canada produced last year. It is also more than is being produced in the U.S. Gulf Region, long the leading gas supply region on the continent. The increased supply is coming from the Marcellus and Utica shale plays. The impact from these plays is already being felt in Canada. The TransCanada Corporation Mainline heading east has seen the volume of gas flowing through it decline dramatically, from six billion cubic feet per day in 2007 to 2.4 billion cubic feet in 2012. And with TransCanada’s proposal to convert part of the mainline to an oil pipeline, it appears the decline in the mainline is permanent. Canadian natural gas exports have collapsed from almost 10 billion cubic feet per day in 2005 to around five billion cubic feet per day in 2012.
The good news is Wood Mackenzie says this drop in demand for Canadian natural gas should level off in the next few years, and prices should begin to recover in the second half of the decade. But the recovery is going to be slow and spotty, with the geography of gas production in western Canada also changing. Low-productivity, low-decline shallow gas is dead. Production is moving west into the Deep Basin and foothills front, where liquids content makes drilling economic. The analysts say drilling will continue to grow in the Montney, “which has very low and attractive gas break-even rates,” supported by the liquids-rich nature of portions of the play. Montney output will double from current levels to 5.1 billion cubic feet per day. The Duvernay, also supported by liquids, will see production rise to 2.1 billion per day by 2020. The Horn River? Wood Mackenzie says a recovery in development in the northeastern B.C. dry shale gas play won’t happen until after 2020. The wild card in all this is the construction of liquefied natural gas terminals on the West Coast. In the new natural gas geography, western Canadian gas will flow from east to west before leaving the continent for Asia. Or it won’t flow at all. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
Subscription Inquiries Telephone: 1.866.543.7888 Email: circulation@junewarren-nickles.com Online: junewarren-nickles.com GST Registration Number 826256554RT. Printed in Canada by PrintWest. ISSN 1204-4741 | © 2013 JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to:
N E XT I S S U E October 2013
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A look at tight oil plays in the United
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.
States and where Canadian producers are active. Plus a review of oilfield hauling in the age of pad drilling and huge multistage fracturing programs.
Want to sound off on any content in Oil & Gas Inquirer? Send your emails to dstonehouse@junewarren-nickles.com. Please mark them as ”Letter to the Editor” if you want them published.
OIL & GAS INQUIRER • SEPTEMBER 2013
9
FAST NUMBERS
billion
. billion
cubic feet per day
cubic feet per day
Throughput on the TransCanada Mainline in 2007.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
Jul 2012
Aug 2012
T O TA L
MONTH
Jul 2012
Aug 2012
OTHER
OIL
GAS
D RY
SERVICE
T O TA L
873
986
Sep 2012
Sep 2012
908
Oct 2012
Oct 2012
,
1,269
Nov 2012
Nov 2012
1,250
1,054
Dec 2012
Dec 2012
Jan 2013
Jan 2013
645
1,161
Feb 2013
Feb 2013
Mar 2013
Mar 2013
1,295
Apr 2013
Apr 2013
868
Jun 2013
Jun 2013
405
Jul 2013
Jul 2013
840
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B C Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Jul 2012
57
401
Jul 2012
Aug 2012
53
454
Aug 2012
Sep 2012
11
465
Sep 2012
Oct 2012
28
493
Oct 2012
Nov 2012
78
571
Dec 2012
65
636
Jan 2013
31
31
Feb 2013
42
73
Mar 2013
66
139
Apr 2013
69
208
Jun 2013
45
330
Jul 2013
49
379
*From year-to-date
10
Throughput on the TransCanada Mainline in December 2012.
SEPTEMBER 2013 • OIL & GAS INQUIRER
Nov 2012
Dec 2012
Jan 2013
Feb 2013
Mar 2013
Apr 2013
Jun 2013
Jul 2013
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, August 8, 2013 Source: Rig Locator
Alberta, August 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada Alberta
AC T I V E
OIL WELLS
Alberta
GAS WELLS
Jul
Jul
Jul
Jul
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
50%
Southern Alberta
31
%
TOTAL
WC TOTALS
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, August 8, 2013 Source: Rig Locator
Alberta, August 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada
Alberta
AC T I V E
C OA L B E D M E T H A N E
Alberta
BITUMEN WELLS
Jul
Jul
Jul
Jul
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
184
60%
Southern Alberta
WC TOTALS
%
TOTAL
OIL & GAS INQUIRER • SEPTEMBER 2013
11
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IN THE
NEWS Issues affecting Canada’s E&P industry
up spending
Service companies to up spending, says Conference Board
Photo: Joey Podlubny
By James Mahony
Canadian oilfield service companies will boost spending 14.2 per cent this year, to an estimated $7.19 billion, up from last year’s roughly $6.29 billion.
While it might not keep pace with recent figures, capital spending by western Canada’s oilf ield ser v ice companies should be healthy over the next four years, the Conference Board of Canada said in a report in August. Service companies’ capital budgets grew by a healthy 36 and 24 per cent in 2011 and 2012, respectively, but growth will moderate this year and in the years leading up to 2017, the Conference Board said in an industry profile on Canada’s oilfield services sector. According to its projections, Canadian oilfield service companies will boost spending 14.2 per cent this year, to an estimated $7.19 billion, up from last year’s roughly $6.29 billion, thanks partly to healthy growth in western Canada’s oilsands sector. Looking ahead, while still positive, the rate of growth in oilfield services spending is expected to taper off, initially to 13.8 per cent or an estimated $8.18 billion in 2014, slipping further as 2017 approaches. In 2015, the rate of growth will slip to 13.4 per cent, as projected spending rises to $9.28 billion, while the following year will see the pace of growth decline to 11.8 per cent, still producing an overall spending increase, at $10.38 billion. In 2017, growth in spending should slip to 11.4 per cent, generating capital spending of $11.56 billion. On the revenue side of the ledger, the Conference Board was also optimistic, forecasting that, starting next year, growth in revenue in the service sector should average more than eight per cent annually, leading up to 2017. This year, however, it is forecasting revenue growth
of just 3.5 per cent, to approximately $33.58 billion. Next year, oilfield services revenue should grow 8.5 per cent to roughly $36.44 billion, rising 8.8 per cent to $39.63 billion in 2015. The following year, revenue should advance eight per cent to $42.82 billion and then 8.3 per cent to an estimated $46.39 billion in 2017. To augment revenue and earnings, some ser v ice companies have taken steps to expand t heir ser v ice of ferings to include such roles as project management and waste treatment, the Conference Board said. Mea nwh i le, it predic ted ser v ice sector earnings would grow every year bet ween now and 2017, while profit margins should widen slightly each year between 2014 and 2017. This year, the Conference Board estimated the sector’s earnings will double to $250 million from an estimated $124 million in 2012. In 2014, earnings are projected to rise 21.7 per cent to $305 million, climbing 36 per cent to $414 million in 2015. In 2016, profits are expected to increase 27.6 per cent to $529 million before advancing 21 per cent to $641 million in 2017. While the service industry includes such heavy hitters as Trican Well Service Ltd., Precision Drilling Cor poration and Ensign Energy Services Inc., by far the majority—roughly 82 per cent—of Canada’s service companies are smaller players w it h 10 employees or less. Companies of more than 100 employees make up a relatively small part of Canadian service companies.
OIL & GAS INQUIRER • SEPTEMBER 2013
13
In The News
increases temporary
Price increases temporary, says Deloitte By Darrell Stonehouse
Edmonton Par Crude Oil (Real $)
AECO Natural Gas (Real $) $14
$160
$12
$140 $120 $100
$8
C$/bbl
C$/Mcf
$10
$6 $4
$60 $40
$2 $0
$80
$20 2006
2007
Historical
2008
2009
2010
2011
Deloitt e March 31, 2013
2012
2013
2014
Deloitt e June 30, 2013
$0
2006
2007
2008
Historical
2009
2010
2011
Deloitt e March 31, 2013
2012
2013
2014
2015
2016
Deloitt e June 30, 2013
Source: Deloitte’s Resource Evaluation & Advisory practice
The spring upswing in oil and gas prices is temporary, with the fundamentals of supply and demand pointing to long, slowbut-steady growth in prices in the longer term, according to Deloitte’s Resource Evaluation & Advisory practice, which released its quarterly Canadian domestic oil and gas forecast in late June. In his forecast commentary, Andrew Botterill, senior manager of resource evaluation and advisory, cautioned against placing too much emphasis on short-term price increases. “Certainly there have been short-term price increases during the second quarter of 2013,” Botterill acknowledged. “But the laws of supply and demand prevent these from being anything other than temporary. The reality is that North American production has been increasing over the last five years, while demand for Canadian oil and gas has been essentially stagnant. As long as Canada is dependent on the U.S. as its primary export customer, and lacks
the export capabilities to serve other markets, we are unlikely to see significant long-term price increases on which to base increased drilling initiatives.” While NYMEX Henry Hub gas traded as high as US$4.37 per thousand cubic feet (C$3.85/AECO) in April, Botterill says the steady downward trend since then proves that the caution he has exhibited in recent forecasts is well-founded. Deloitte’s latest forecast continues to show natural gas at an AECO real price of C$3.35 per thousand cubic feet in 2013, rising to C$3.70 for 2014 and up to C$5.20 by 2021. Deloitte’s NYMEX real price is forecast at US$3.80 per thousand cubic feet throughout 2013, rising to US$4 for 2014 and up to US$5.50 by 2021. “We have seen differentials of 30 cents per thousand cubic feet in early 2013 widening to more than 50 cents. This shows that any uptick in gas prices is quickly swallowed up by U.S. gas markets and
not felt to the same extent in Canada,” said Botterill. “The bright side is that, even t hough t he 2020 f ut ures pr ice today is about 30 per cent lower than it was in 2008, we are still forecasting the same degree of growth over time. We’re just starting from a lower shortterm price brought on by the oversupply we’ve created with increased production since 2008.” With respect to oil, Deloitte’s longterm outlook for West Texas Intermediate oil increases slightly to US$94 per barrel for 2013, decreasing to $91 for 2014 and eventually levelling out at $85 per barrel by 2017, consistent with long-term futures markets. Deloit te cont i nues to forec a st a $5-per-barrel differential between West Texas Intermediate and Edmonton Par that will decrease to $2 per barrel over the long term to match pipeline tariffs between the two markets.
natural gas reserves
U.S. oil reserves and natural gas reserves additions jump By Darrell Stonehouse
U.S. proved crude oil reserve additions in 2011 set a record volumetric increase for the second year in a row, according to U.S. Crude Oil and Natural Gas Proved Reserves, 2011, released in early August by the U.S. Energy Information Administration (EIA). Natural gas proved reserves rose also, but by less than 2010’s record increase. Nevertheless, natural 14
SEPTEMBER 2013 • OIL & GAS INQUIRER
gas reserve additions in 2011 rank as the second largest annual increase since 1977. “Horizontal drilling and hydraulic fracturing in shale and other tight rock formations continued to increase oil and natural gas reserves,” said EIA administrator Adam Sieminski. “Higher oil prices helped drive record increases in crude oil reserves, while
natural gas reserves grew strongly despite slightly lower natural gas prices in 2011.” Proved oil reserves, including both crude oil and lease condensate, increased by 15 per cent in 2011 to 29 billion barrels, marking the third consecutive annual increase and the highest volume of proved reserves since 1985. Proved reserves in tight oil plays
In The News
accounted for 3.6 billion barrels (13 per cent) of total proved reserves of crude oil and lease condensate in 2011. Texas recorded the largest volumetric increase in proved oil reserves among individual states, largely because of continuing development in the Permian and Western Gulf basins, while North Dakota had the second-largest increase, driven by development activity in the Bakken Formation in the Williston Basin. Natural gas proved reserves, estimated as wet gas that includes natural gas liquids, increased by almost 10 per cent in 2010 to 348.8 trillion cubic feet, the 13th consecutive annual increase.
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“ Higher oil prices helped drive record increases in crude oil reserves, while natural gas
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reserves grew strongly despite slightly lower natural gas prices in 2011.” — Adam Sieminski, administrator, U.S. Energy Information Administration
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Pennsylvania’s proved natural gas reserves, which more than doubled in 2010, rose an additional 90 per cent in 2011, contributing 41 per cent of the overall U.S. increase. Combined, Texas and Pennsylvania added 73 per cent of the net increase in U.S. proved wet natural gas reserves in 2011. Proved reserves in shale gas plays accounted for 131.6 trillion cubic feet (38 per cent) of total proved reserves of wet natural gas in 2011. Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. EIA’s estimates of proved reserves are based on an annual survey of about 1,100 domestic oil and gas well operators.
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OIL & GAS INQUIRER • SEPTEMBER 2013
15
In The News
revolution
Waiting for the next technological revolution By Carter Haydu
While technologies such as horizontal drilling and multistage fracturing have dramatically altered the oil and gas industry over the past decade, incremental improvements to drilling and completion technology are also playing an important role in helping to improve the bottom line for operators. Still, are there any technological advancements that could further revolutionize the oil and gas industry to the same degree as horizontal, multistage fracturing? For presenters posed this question at the TD Securities Calgary Energy Conference in July, they believed there are still many ways that ingenuity might improve yields. “I guess if someone could figure out how to drill one wellbore down and multistage frac multiple horizontal lengths, that would be the next big thing, but I don’t know how we could do that,” Myron Stadnyk, president and chief executive officer of ARC Resources Ltd., told the conference. Stadnyk said there are many ways to improve drilling, and “save days” on
dr illing and completion operations, and there are still areas of research and development that could further revolutionize the industry. He added his company continues to see improvements in drilling and fracturing technology. “It seems that every six months there are modest breakthroughs in moving to pad drilling, say, 10–20 per cent on the lease. Some of the more interesting things are happening on completions now as you move to pad drilling and you’re drilling four wells this way and four that way off the pad.” Ian Dundas, president and chief executive officer of Enerplus Corp., told the energy conference that recovery factors are where the industry should expect to see continued improvement and innovation within resource plays. He said, “There is lots of work going on there, and it is very early in terms of where we can take these things. If we can get ourselves to a 20–30 per cent recovery
factor on some of these big resources, it’s a technological advancement with the prize and economic implications being pretty significant.” Crescent Point Energy Corp. president, chief executive officer and director Scott Saxberg said simply having more time to figure out what works best with regards to completion operations will itself be a further improvement to the industry in the future. “In our case, we started with eight-stage fracs, then 16-stage, then 25-stage and 30-stage. We’ll have, in five or six years, some history on that. So simply, we’ll know that maybe it is 20 stages versus 25 and you’re going to save a significant amount of dollars, but get the same reserve benefit and production benefit. It is going to tremendously add to the returns. I think that’s just one of the simple things.” Saxberg said his company would continue to test completions to fi nd out what works best. “I think it is a pretty exciting time.”
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BRITISH COLUMBIA WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
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Source: Daily Oil Bulletin
B.C. British Columbia
LNG no sure thing, says Rick George By Pat Roche
Penn West Petroleum chairman Rick George.
With many global liquefied natural gas (LNG) producers chasing a handful of buyers, the prospect of exporting natural gas from Canada’s West Coast is by no means a slam dunk, according to Penn West Petroleum Ltd. chairman Rick George.
“We do need at least two LNG projects on the West Coast,” George told PennWell Corporation’s 2013 Oil Sands and Heavy Oil Technologies Conference in Calgary. But proposed West Coast LNG projects face big challenges, including the estimated $100-billion capital investment needed to find and produce enough natural gas for the multi-decade life of a liquefaction plant. “What [you’ve] really got to think about there is [you’ve] got to have secure contracts and secure buyers for that gas,” George said in a wide-ranging speech. Such deals aren’t easily secured, he warned, given the number of competing gas projects around the world. He said there are only three or four major potential markets for West Coast LNG, the biggest being China, Japan and India, plus a few smaller buyers. On the seller side, however, there are multiple gas producers exporting or thinking of exporting LNG, George pointed out.
Besides Canada, these include the United States, the Middle East, Australia, Russia and the East Coast of Africa. “And so time is of the essence. That’s kind of the message I’m going to leave you on West Coast LNG. Time is important,” George told a standing-room-only audience. “And if we delay too long…we may miss our opportunity,” he warned, citing the spectre of the Mackenzie Valley Pipeline as a cautionary tale. “When you delay decisions too long, the market moves away. And that has a chance of happening here.” He was referring to what may be the most infamous regulatory marathon in Canadian history. A proposed pipeline to bring gas from the Canadian Arctic to southern markets was heavily studied in the 1970s, then iced for a quarter-century. It was revived in this century, but during years of regulatory wrangling, the shale gas revolution flooded U.S. markets with cheap gas, and the Mackenzie pipeline was never built.
B.C. targets workers for LNG projects
Photo: Canadian Petroleum Hall of Fame
By Carter Haydu
A new B.C. Natural Gas Workforce Strategy Committee action plan suggests the province will require as many as 60,000 workers during the construction of projects, followed by more than 75,000 permanent skilled workers for its liquefied natural gas (LNG) plants. The plan assumes that five LNG plants are to be built and operational in northern British Columbia by 2021. Howe v e r, E d w a r d K a l l io, d i r e c tor of gas consulting with Ziff Energ y Group, said building five multi-billion dollar LNG plants in British Columbia
within the next eight years appears to be unrealistic. “I just think things are going to get a little tight. Obviously, you see the numbers they’re throwing out there…. That’s a lot of people, that’s a lot of rigs and that’s a lot of steel pipe plants.” The B.C. Ministr y of Natural Gas Development said the province’s timeline estimates for the construction of fi ve LNG plants is based on analysis done by independent consultants using information collected by the provincial government, as well as the consultants’ own independent assumptions.
A spokesperson said to date the National Energy Board has issued export licences to three LNG proponents, including the Douglas Channel Energy Project, Kitimat LNG and LNG Canada. Another four proposals— Pacific Northwest LNG, Prince Rupert LNG, Woodfibre LNG, and a proposal by Imperial Oil Limited and ExxonMobil Canada—have been submitted for export application review. Further, the spokesperson said, the province has approved the Kitimat LNG Project and a provincial environmental assessment is underway for the LNG Canada and Prince Rupert LNG projects. Additionally, OIL & GAS INQUIRER • SEPTEMBER 2013
19
British Columbia
B.C. natural gas industry labour snapshot In 2012, B.C.’s natural gas industry employed about 13,235 workers across three subsectors: 8,570 in oil and gas services 3,680 in exploration and production 985 in natural gas pipelines With five LNG plants opening by 2021, it will require: 60,000 workers at peak construction
the B.C. Environmental Assessment Office has received a project description for the Pacific Northwest LNG facility, which it is currently reviewing. The spokesperson said the ministry is currently working with project proponents to complete negotiations and accelerate final investment decisions, and the prospect is that five facilities can be operational by 2021. According to the province’s action plan, 21,600 jobs would be directly involved in the building of these LNG export facilities and associated pipelines during peak construction in 2016-17, while 41,900 jobs would be created in industries that supply goods and services at the peak of the construction phase. Tom Sigurdson, executive director of the British Columbia and Yukon Territory Building and Construction Council, said that if all the LNG projects assumed in the action plan report are to proceed at or near the same time, then the impacts on his province could actually be rather negative. “If all of them go ahead, it’s going to be just terribly problematic. We’ve not had the skills training in B.C. to the degree we should have had over the last 10 years, and we will certainly not be able to put that many people onto the LNG projects in the time frame they suggest all of this activity may take place.” Sigurdson said the B.C. government would have to make significant improvements to its apprenticeship program immediately in order to meet the demands associated with the construction of five simultaneous LNG projects. 20
SEPTEMBER 2013 • OIL & GAS INQUIRER
“You cannot just have jack-of-all-trades out on these projects. They need a very specific skills set that [is] going to be required.” The action plan also suggests there would be 2,400 permanent jobs in operating and maintaining the plants and pipelines on an ongoing basis, as well as 61,700 jobs to support LNG operations, including workers required to drill, produce, process and transport the natural gas required to feed the export facilities. Further, there would be another 11,100 jobs in industries benefiting from LNG workers spending their wages in the broader economy. However, Kallio said, creating so many jobs and developing infrastructure at the scale suggested in the action plan report would be similar to trying to create Fort McMurray in northern British Columbia in less than a decade. “I just think the market is not going to take that much LNG that quickly. I think it’s probably going to build out a bit more slowly than they are assuming here.” According to Kallio, it is more feasible to expect a couple of LNG plants could be up and running by 2021, with a third plant complete by about 2025. “There’s only so much market out there, and everyone is chasing the same market,” he said, adding that it is difficult to find LNG investors and there are lots of cost pressures when it comes to such major projects. A Grant Thornton LLP impact review of B.C. LNG employment suggests capital expenditures during construction phase of the LNG plants would total approximately $98.4 billion.
21,600 jobs will be directly involved in the building of LNG export facilities and associated pipelines during peak construction— expected to occur 2016-17 41,900 jobs will be created in the industries that supply goods and services during the construction phase at its peak Over 75,000 jobs once the LNG projects are fully operational: 2,400 permanent jobs to operate and maintain the plants and pipelines on an ongoing basis 61,700 jobs to support LNG operations, including workers required to drill, produce, process and transport the natural gas required to feed the export facilities 11,100 jobs in industries benefiting from LNG workers spending their wages in the broader economy Source: B.C. Natural Gas Workforce Strategy Committee
While skeptical of the timing suggested in the action plan, Kallio said it appears the province is building a policy around the most extreme case of LNG development. He said preparing for LNG growth is important, as the resource is vital to the energy sector. “The consequences of not doing it are dire for the western Canadian oil and gas industry. Our basin is producing about 13 billion cubic feet per day right now, and without LNG and without export pipe for oil and the resultant natural gas demand, our basin could be below 10 billion cubic feet per day by 2020. “But with LNG, we could be producing 16 [billion] to 20 billion cubic feet per day sometime in that 2020-25 time frame. So that is the swing, and it’s a big swing.”
Photo: Apache Corporation
Nearly 75,000 permanent jobs will be created once LNG exports are up and running.
British Columbia
Painted Pony finds Montney success Painted Pony Petroleum Ltd. said it has fi nished drilling and completion operations on two 100 per cent working interest Upper Montney horizontal wells on the 91-F/94B-16 pad at Blair. One of these wells was completed using a conventional perf-and-plug style system and the other well was completed using an open-hole ball-drop style technique. These two wells are providing vital comparative data concerning the viability of ball-drop completions in the Blair area, following on the company’s successful ball-drop completions at Townsend. The wells are currently being production tested. Over 184 hours, the A-91-F ball-drop well flowed at a peak 24-hour wellhead rate of 8.6 million cubic feet per day at an average flowing casing pressure of 1,198 pounds per square inch (psi) and at an average rate of 7.5 million cubic feet per day at an average flowing casing pressure of 1,406 psi. The final 24-hour rate was 8.1 million cubic feet per day at an average flowing casing pressure of
1,243 psi. Gas analysis indicates a total liquid content from this zone of 76 barrels per million cubic feet (including ethane). On a totalbarrel-of-oil-equivalent combined basis, this well tested at a 24-hour peak rate of 1,872 barrels per day. Over 82 hours, the A-91-F perf-andplug well flowed at a peak 24-hour wellhead rate of 6.7 million cubic feet per day at an average flowing casing pressure of 1,299 psi and at an average rate of 6.2 million cubic feet per day at an average flowing casing pressure of 1,302 psi. The fi nal 24-hour rate was 5.9 million cubic feet per day at an average flowing casing pressure of 1,141 psi. Gas analysis indicates a total liquid content from this zone of 75 barrels per million cubic feet (including ethane). On a total-barrel-equivalent-per-day combined basis, this well tested at a 24-hour peak rate of 1,452 barrels per day. Painted Pony also began drilling operations on two new 100 per cent working interest Montney horizontal wells on the 14-F/94-B-16
pad targeting the Middle Montney and the Lower Montney, also at Blair. The company recently placed on production the fi rst of two 100 per cent working interest wells on the 11-J/94-B-09 pad. The wells were completed and tested during the first half of 2013 on lands acquired in December 2012. The second well will be placed on production as facility constraints permit. The Lower Montney operation at A-11J/94-B-09 produced average wellhead condensate volumes of approximately 11 barrels per million cubic feet during the month of July to date, while the Upper Montney well at A-11-J/94-B-09 produced wellhead condensate volumes of approximately 45 barrels per million cubic feet during a limited test period. Wellhead condensate represents the free condensate that is recovered at the wellsite and does not include additional condensate or other gas liquids that may be recovered at a gas processing facility.
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OIL & GAS INQUIRER • SEPTEMBER 2013
21
British Columbia
Painted Pony began completion operations and production testing on two (0.4 net) non-operated Montney horizontal wells on the Gundy 75-J/94-B-09 pad, which were drilled in the fi rst quarter of 2013. Test results from these wells are expected later in this quarter. Painted Pony continues to pursue the development and expansion of its Montney gas assets in northeastern British Columbia. To date during 2013, the company has drilled or is currently drilling a total of eight (5.6 net) Montney horizontal wells. A further five (four net) horizontal wells are expected to be drilled during the balance of 2013. This will include two (two net) new wells on the liquids-rich project at Townsend. Painted Pony’s current field-estimated sales volumes are approximately 8,800 barrels equivalent per day (82 per cent natural gas weighted). Field-estimated average secondquarter volumes were approximately 7,800 barrels per day (82 per cent gas). Spring breakup and adverse weather conditions, along with scheduled and
unscheduled plant turnarounds in both British Columbia and Saskatchewan, affected several of the company’s key producing properties.
Painted Pony Petroleum Ltd.’s current field-estimated sales volumes are approximately 8,800 barrels equivalent per day (82 per cent natural gas weighted).
In British Columbia, the wet spring conditions contributed to delays in the completion of the 91-F wells at Blair. Weather-related damage to roads and a bridge in the Cypress area restricted operational access for well maintenance and reactivation projects, and a thirdpart y gas facilit y that processes the company’s Cypress gas experienced an unplanned outage.
E a rl ier t h i s yea r, Pa i nted Pony announced two 100 per cent working interest wells in the Townsend block. These wells proved to be a challenge to bring on production due to their strong wellhead flow rates and high associated liquids content. Late in the second quarter of 2013, the company resumed modifications to the facilities used to produce these wells. The Upper Montney well on the Townsend 11-J pad was then produced for a period of 5.2 days during the second quarter of 2013, at which time it flowed at approximately 2,230 barrels equivalent per day of field-estimated raw gas, including wellhead condensate. The well is expected to remain shut-in until late in 2013 when a new operated gas processing facility comes on stream. The Lower Montney well on the Townsend 11-J pad was also produced for 7.1 days during the quarter and it flowed at approximately 1,819 barrels equivalent per day of fieldestimated raw gas, including wellhead condensate. The well has continued to produce through a third-party facility since early July. — DAILY OIL BULLETIN
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NORTHWESTERN ALBERTA WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
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▼
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Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Northwest drives July land sale By Richard Macedo
The Alberta government attracted $21.69 million at its July land sale, which was highlighted by a group of licences purchased in northwestern Alberta. The province sold 80,378 hectares at an average price of $269.87. Year-to-date, the industry has spent $461.48 million acquiring 1.43 million hectares at an average of $322.27. At the same point last year, $689.44 million had come into provincial coffers on 1.61 million hectares at an average of $427.59. Scott Land & Lease Ltd. tendered the land sale bonus high of $3.3 million for a 4,096-hectare licence that produced an average price of $804.80. The posting had two tracts. The first included sections five and seven at 61-07W6; sections 13–17, 19, 20, 30 and 31 at 61-08W6; and sections five, six, eight and nine at 62-08W6 for petroleum and natural gas below the base of the BlueskyBullhead. The second tract included section 10 at 62-08W6 for petroleum and natural gas below the base of the Fernie Group. Britt Resources Ltd. picked up an adjacent 3,840-hectare licence for $2.9 million. The broker paid an average of $754.80, also for two tracts. The first included section 19 and sections 31–33 at 62-08W6; sections 22–25, 27, 28, 33 and 36 at 62-09W6; and section nine and the northwestern quarter of section 11 at 63-09W6 for petroleum and natural gas below the base of the BlueskyBullhead. The second tract included section three, and the southern half and northeastern quarter of section 11 at 63-09W6 for petroleum and natural gas below the base of the Fernie Group. Brad Hayes, president of Pet rel Robertson Consulting Ltd. said these two parcels are part of a group of postings concentrated within townships 61 and 62 and ranges 07-09W6.
Within this group of parcels, Scott Land generated the per-hectare high of $1,056.33. The broker paid a bonus of $270,420 for section 15 at 61-07W6. The 256-hectare licence included petroleum and natural gas below the base of the Chinook Member, to the base of the Bluesky-Bullhead. “This is an area in the deeper, westerly part of the Deep Basin just east of the Foothills structural front,” he said. In several cases, Cretaceous rights (to the base of the Bluesky-Bullhead) have been posted in separate parcels from rights below the Cretaceous over the same lands. This indicates prospectivity in both Cretaceous (Cadotte, Falher, Wilrich, Gething, Cadomin) and pre-Cretaceous— primarily Montney—targets, and producers wanted to ensure their bids were accurately targeted. “The highest price per-hectare went to a Cretaceous posting, but the largest total bids went to pre-Cretaceous rights,” said Hayes.“I think we will see exploratory activity stepping westward into this area at both Cretaceous and Montney levels.” Steve Hager, senior exploration analyst with Canadian Discovery Ltd., said the high bonus parcels in the area, the two large Deep Basin licences, are in the Route and Lynx fields and include P&NG rights below the Cretaceous. They were posted and purchased for their potential in the Triassic Montney liquids-rich gas resource play, which is being extensively developed using horizontal drilling and multistage fracturing in the Kakwa field two townships to the northeast by Paramount Resources Ltd., Seven Generations Energy Ltd., Contact Exploration Inc. and others. Other highlights at the sale included a successful $2.27-million bid by Britt
Resources for a two-section, 512-hectare licence parcel, which produced an average price of $4,426.20. The broker picked up the rights to sections 25 and 36 at 46-17W5 for all rights except natural gas in the Cardium, Winterburn and Beaverhill Lake zones, Hager added. It’s located in the Foothills at the junction of the Hanlan and Columbia fields. “Operators are using horizontal drilling in the area to uncover liquids-rich gas potential in Cretaceous Mannville equiva lent and Jurassic Roc k Creek zones,” he said. Hayes added that large gas reserves have been produced in the area from the deep Devonian, but these rights are excluded from the sale. “While several Deep Basin reservoirs may be prospective, such as Cardium, Ostracod, Cadomin, Rock Creek, most of these would have dry gas potential,” he noted. “The Montney is not present here and the Duvernay would be very deep, with only dry gas potential. My best guess is that someone sees oil potential in the Belly River, which produces at Peco about a township to the east.” For the rest of the year, Hayes believes there will continue to be relatively small sales in Alberta. “As we have noted previously, most of the big resource play fairways are tied up and action around the fringes, as in this sale, will be at lower prices because of the cost and higher level of risk assumed,” he said. “We are waiting for the next big play to occur, and/or for operators to prove up productive potential in some of the major fairways that will give them the confidence to step out beyond the currently defi ned margins.” “It looks like most of the land has been picked up in t he Montney and Duvernay resource plays, and pickings will be a little thin for the rest of the year,” Hager added. OIL & GAS INQUIRER • SEPTEMBER 2013
25
Northwestern Alberta
Full ownership drives Birchcliff success By James Mahony
Birchcliff Energy Ltd. plans on growing by the drillbit.
In the past 18 months, some Canadian producers signed joint ventures that gave foreign companies stakes in Canadian natural gas reserves that are well placed for future West Coast liquefied natural gas (LNG) development, a move welcomed by Canadian investors at the time. Yet, not every Canadian producer is anxious to strike a joint venture with a foreign company, and according to one Calgary executive, such deals sometimes
arise because the Canadian partner is cash-strapped. “The reason some companies did these joint ventures is because they didn’t have the capital,” said Jeffery Tonken, president and chief executive at Birchcliff Energy Ltd., citing a deal in which the Canadian partner’s stock was low, making the prospect of raising money through issuing shares unlikely. In the end, the deal turned out to be a “home run, but it could have backfired just as easily,” he said. Birchcliff has no plans for a joint venture with a foreign producer, and it’s not for lack of dance partners, so to speak. The company has been approached by Asian producers wanting to build reserves for future LNG exports from the West Coast, he added. “They’re looking for joint ventures, because they want to grab the management teams and invest a bunch of money in a going concern, versus walking in and doing a takeover and being afraid management will run away,” he said in an interview after updating investors and analysts on Birchcliff at the TD Securities Calgary Energy Conference. Rather than sell a stake of his company to a foreign producer, Tonken’s plan is to build Birchcliff up to the point that it’s attractive as a takeover target. “Ultimately, we believe those LNG players are going to need a large resource in place, and that’s what we’re building out to.”
Giving a foreign producer a piece of Birchcliff would not serve that purpose, he said. Instead, he believes the state-owned firms that are trolling Canadian waters will not be content with 20 or 25 per cent, but want full ownership of the companies they’re taking a stake in. “The second you start doing those farmouts, you’re embedding a partner who wants 100 per cent,” he said. On the other hand, Birchcliff plans to continue its high-ownership, high–working interest approach to its oil and gas properties, ensuring that, if the right buyer for the company comes along, it will have a free hand after taking control, since Birchcliff ’s properties will not be encumbered by partnerships or joint ventures that might otherwise tie the new owner’s hands. Currently, Birchcliff produces about 26,000 barrels equivalent per day, about 82 per cent natural gas, the rest light oil. By expanding capacity at the Pouce Coupe South Gas Plant, the company expects this year’s exit production to reach an average 30,000 barrels per day. Also with a view to West Coast LNG exports, Birchcliff is a member of the BC LNG Export Co-Operative LLC, which allows the Calgary-based producer and five others to share 10 per cent of the capacity of an AltaGas Ltd. pipeline to Kitimat, B.C. The other 90 per cent of the line’s capacity is contracted by Chevron Corporation and Apache Corporation.
The Kakwa 14-02-063-06W6 Upp e r Montney horizontal well, previously reported as drilled in early 2013, has been successfully completed and flow tested, Donnycreek Energy Inc. has reported. Donnycreek had not previously tested the Upper Montney although other operators have demonstrated repeated success in the Upper Montney within the Kakwa/ Resthaven trend, said the company. The operator has flow-tested the well for a total of 191 hours with tubing in the hole during the final 98 hours. During the fi rst 24 hours with the tubing in the 26
SEPTEMBER 2013 • OIL & GAS INQUIRER
hole, the well averaged gross production rates consisting of 444 barrels per day of condensate and 3.71 million cubic feet per day natural gas (105 barrels per day condensate and 882 thousand cubic feet per day natural gas net to Donnycreek) against a flowing pressure above 4,500 kilopascals (kPa). During the final 74 hours with tubing in the hole, the operator varied flowing pressures between 800 kPa and up to 6,800 kPa to test the well under various flowing conditions. It averaged gross production rates consisting of 327 barrels per day of condensate
and 2.8 million cubic feet per day of natural gas (77 barrels per day of condensate and 670 thousand cubic feet per day of natural gas net to Donnycreek) during the final 98 hours of testing. In the final hour of testing, the water cut from the 14-02 well was 75 per cent with an average of 80 per cent water cut over the 98-hour testing interval. Approximately 2,300 cubic metres of frac water were pumped during the completion operation, with a total recovery of 1,900 cubic metres of water to date, including both frac water flowback and natural formation water.
Photo: Joey Podlubny
Donnycreek updates Montney well
Northwestern Alberta
Upon completion of the flow test on Jul. 23, 2013, the well was shut in with bottomhole pressure recorders installed. Donnycreek has a 23.75 per cent nonoperated working interest in the 14-02 well, which was drilled to complete its commitment to earn 2.25 gross sections of Montney petroleum and natural gas rights adjacent to its Kakwa land base. It is the fourth successful Montney well the company has participated in for a success rate of 100 per cent. The operator of the 14-02 well is planning to install production equipment and tie in the well and is expecting to have the well on production before year-end, said Donnycreek. The company is currently participating in the drilling of its fi fth Kakwa Montney well (50 per cent working interest) from a surface location at 12-24-063-06W6. It expected to be fi nished drilling by the end of August. — DAILY OIL BULLETIN
Athabasca looking for Duvernay partner By Lynda Harrison
Athabasca Oil Corporation will likely seek a partner on its Duvernay position, where it says initial results are very encouraging. The Duvernay will have a big development program with large capital needs and is ideal for taking on a partner, Sveinung Svarte, chief executive officer, told the TD Securities Calgary Energy Conference. Svarte estimated that, worldwide, the jointventure market has about four or five potential players for oilsands projects compared to five times that (20–30) for the Duvernay. Athabasca has 350,000 acres of prospective lands in the Duvernay, with 200,000 of those acres, or 300 sections, located in what the company calls the sweet spot of Kaybob, Svarte told the conference. The company has recently created its Duvernay development plan, which it plans to announce in the next few months. OIL & GAS INQUIRER • SEPTEMBER 2013
27
Northwestern Alberta
Athabasca Oil Corporation Duvernay snapshot Total acreage: 350,000 Acres at Kaybob: 200,000 Preliminary drilling results: Well: 06-10-062-23W5 30-day IP: 600 boe/d; 175 bbls of liquids per mmcf Well: 08-18-064-17W5 30-day IP: 775 bbls/d light oil Well: 02/02-34-062-20W5 30-day IP: 1,350 boe/d; 245 bbls of liquids per mmcf Source: Athabasca Oil Corporation
Athabasca likes to be in the “condensate window” of the play, and the deeper part of the oil “window,” he said. He said the company has drilled three wells to date and is gaining confidence. The first well at 6-10-062-23W5, closer to the gas window, had 30-day initial production
(IP30) of 600 barrels equivalent per day at a restricted rate, and 175 barrels of liquids per million cubic feet of gas. The second was an oil well, at 8-18064-17W5, with an IP30 of 775 barrels per day of very light oil at 45 degrees API. On its third well, at 02/02-34-06220W5, the company changed its fracturing technique, built a bigger lease, increased horsepower and got more sand into the formation: 14 stages with 160 tonnes of sand per stage and a pump rate of 16–18 cubic metres per minute. “That well is just outstanding with about 1,350 barrels equivalent per day IP30 and very high liquid yields [245 barrels per million cubic feet],” said Svarte. After about five months, the well has produced 81,000 barrels of oil and 400,000 thousand cubic feet of gas, is currently producing 800 barrels equivalent per day and is “extremely” choked back at about 3,000 pounds per square inch of wellhead pressure, he said. The wells cost between $10 million and $15 million to drill and complete.
Advancing the interests of energy partners www.bcenergyconference.ca 28
SEPTEMBER 2013 • OIL & GAS INQUIRER
Seven Generations ramping up Kakwa River production By Richard Macedo
Private producer Seven Generations Energy Ltd. is ramping up activity at its Kakwa River project, which the company said includes multiple zone potential and liquids-rich gas with high production rates. Company representatives gave an overview of the producer and its planned activity for the next while at the TD Securities Calgary Energy Conference. Pat Carlson is the president and chief executive officer of Seven Generations. He previously led North American Oil Sands Corporation. In 2007, Norwegian oil giant Statoil ASA agreed to acquire closely held North American—a new in situ oilsands player at the time—for $2.2 billion in cash. His current company is an active one in nor thwestern A lber ta. Seven
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Generations spent $23.82 million acquiring 13,312 hectares at an average price of $1,789.03 during the fi rst half of the year. The private producer was the top company acquiring acreage under its own name during the period. All of its land was purchased in Alberta. The company holds 369 gross sections at Kakwa River—358 net—with 332 net Montney sections. Seven Generations is currently at production of between 6,000 and 8,000 barrels equivalent per day. It has rig released five wells so far in 2013, with the Montney Formation listed as the total depth zone for all the wells. In 2012, the company rig released eight wells, with nearly all listing the Montney as the total depth zone, except for one that listed the Wilrich Member. “In terms of guidance for this year, we’re looking to be about 10,000 barrels equivalent a day for the fi rm to average, about 50/50 gas and liquids,” said Chris Law, vice-president of corporate planning. “We’re projecting to be north of 20,000 barrels per day by 2014. We’re in quite a
steep growth ramp here, especially with the capital we’ve just raised.” T he company announced in May that it had closed a private placement of US$400 million in aggregate principal amount of 8.25 per cent senior unsecured notes due 2020. “With the Montney…we’ve hit just an incredible asset to use as a growth engine, and we’re putting away a half a billion capital budget this year, so I think it’s one of the more exciting stories you’ll see in the market in terms of growth opportunities,” he added. Drilling is focused on the Montney using pad drilling in the delineated “nest.” Five rigs are expected by the third quarter, seven by the fourth quarter. Going forward, the company will seek liquidity for private shareholders via a sale or public listing, softly targeted in the first or second quarter of 2015. The company was formed in 2008. It will do “nest” drilling of roughly 30 wells per year, which feature the highestreturn, lowest-risk pad drilling; delineation drilling of three to five wells per year
“ With the Montney…we’ve hit just an incredible asset to use as a growth engine.” — Chris Law, vice-president of corporate planning, Seven Generations Energy Ltd.
to establish contingent resources in the Upper and Middle Montney; and drilling to test and demonstrate other resource plays, extend infrastructure and consolidate land where economics are attractive. The company is also increasing its realized liquids content through an Aux Sable marketing arrangement and an increased pace of drilling high-rate, condensate-rich Montney wells, which drives cash flow and reduces sensitivity to gas prices.
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NORTHEASTERN ALBERTA WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
▼
▲
Northeastern Alberta
▲
Source: Daily Oil Bulletin
Rail in it for the long haul, say railways By Carter Haydu and Elsie Ross
Regardless of new pipeline projects that come online in the years ahead, James Cairns, vice-president of petroleum and chemicals for Canadian National Railway Company (CN), believes rail will prevail in the heavy crude transportation market for a long, long time. “Rail is never going to replace pipeline, but it’s a big pie and rail is going to have a bite—a slice of that pie,” he told the TD Securities Energy Conference in Calgary. “Rail is now not just an afterthought as in, ‘well it’s kind of a neat idea, so let me think about it more.’ Rail is now an ingrained part of the supply chain for crude oil. I believe it’s going to be around for a long time, especially when you talk about a heavy barrel.” According to Cairns, the “first wave” of the modern crude-by-rail movement came with the increased Bakken activity in North Dakota, which required immediate takeaway capacity and rail infrastructure was able to accommodate when pipelines were lacking.
He said rail offers an advantage with its deep reach into heavy oil–producing regions, and because of its ability to get product to market. He added the fact that diluent is not needed with rail transportation is a cost savings for oilsands producers. “I’ll tell you, it’s quite simple. If you want to ship 100,000 barrels a day of bitumen by rail, you know what you do? You ship 100,000 barrels of bitumen by rail. If you want to ship 100,000 barrels a day of bitumen by pipe, well you ship 100,000 barrels or so of diluted bitumen…and then you cause another 40,000 barrels of diluent to be shipped on the Alberta market. Whether you’re shipping it yourself or someone else is, there’s another 40,000 barrels that has to get shipped.” For a large company with pipeline infrastructure already carrying product to a major hub, Cairns said it might not make sense to use rail, but rail is exceptionally useful for new, smaller producers needing to haul bitumen.
Crude oil shipped by truck, rail 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
Deliveries to U.S. refi neries in thousands of barrels Source: U.S. Energy Information Administration
An example of one company taking advantage of rail transportation for its bitumen products is Grizzly Oil Sands ULC. “We’ve got a 10-year rail rate with CN now, with a fi xed escalator,” John Pearce, chief executive officer for the company, said. “And it’s a variable volume of crude, so we can ship 5,000 barrels a day or 500,000 barrels a day, and we know what our rates are.” According to Pearce, his company is building a car-loading site near its operations in Conklin, Alta., which will be an open terminal other companies in the area can use as well. His company is also working on an offloading facility in southern Louisiana. “Our belief is that old rail, in terms of price, will beat the freight rates for new pipe, particularly when you take into account the rate for the round trip of the diluent,” he said, adding that rail gives the company the flexibility to take product to whatever market is most promising at any given time. At CN, Cairns said the company is investing about $2 billion in capital projects, about half of that dedicated to track infrastructure. For its network between Winnipeg and Edmonton, CN targeted about $100 million of investment to “increase our resiliency in this ver y, ver y high-demand corridor.” He said the company is adding sections of double track to accommodate longer trains, as well as investing in its Prairie North Line. Along with tank cars, the biggest determinant of growth in the crude by rail market is access to terminals and facilities to get onto and off of rail, said Tracy Robinson, vice-president of marketing and sales, energy and merchandise for Canadian Pacific Railway Limited (CP). The company currently has 18 facilities across Alberta, Saskatchewan and North Dakota. Most of them are private facilities OIL & GAS INQUIRER • SEPTEMBER 2013
31
Northeastern Alberta
on the company’s network and through that producers, marketers and sometimes refiners access the rail capacity. Right now, CP is moving crude to every market in North America. “This is a model that we believe is permanent, [and] provides some unique and valuable features to this industry,” she said. “Rail has emerged as a viable and long-term partner for all of the energy industry, whether it’s the crude oil that increasingly wants to go east and west on the light side or east and south on the heavy side and increasingly that drive to offshore.” One of the features of crude by rail that most surprised the industry was its
optionality, she said. “You can ship from any point in North America on any given day as you are loading the train and point it to any one of the refinery markets in North America,” she said. As the spreads between West Texas Intermediate (WTI) and North Sea Brent and heavy oil and WTI have narrowed in recent months, CP is seeing volumes moving around as marketers are looking to follow the arbitrage of the spread, and they like the ability to move quickly between markets as either their needs change or those opportunities present themselves, said Robinson. One of the useful features is the speed to market—five to seven days from Alberta
or the Bakken to the U.S. Gulf Coast or Northeastern U.S. Coast or even less to the West Coast, she said. “You will hear everywhere that railcars are expensive, but we turn them very quickly.” Increasingly, CP is moving volumes from the Bakken to the northeast and to the west. Earlier this year, it hit an annualized rate of 70,000 cars per year (about 125,000 barrels per day), a combination of Bakken volumes, mid-weight grades and some heavier crude out of the Lloydminster area. Based on initiatives underway, that is expected to grow to 140,000–210,000 cars by 2015.
Lease cancellations anger oilsands operators The Alberta government is cancelling 32 oilsands leases—owned by 10 companies and covering 55,000 acres that surround fast-growing Fort McMurray—to accommodate new residential, commercial and light industrial growth on land dubbed the Urban Development Sub-Region (UDSR). Owners of the cancelled leases will be notified in letters sent by Alberta Energy and will be compensated for what they paid to acquire the land such as bonus bids, rental amounts and application fees, as well as development, reclamation and interest allowances. The Canadian Association of Petroleum Producers (CAPP) supports the view that the municipality needs the extra land to be able to expand and provide the services
32
SEPTEMBER 2013 • OIL & GAS INQUIRER
The river valley just outside of Fort McMurray. The province is cancelling oilsands leases in an effort to open up space for the city to grow.
Photo: Joey Podlubny
By Lynda Harrison
Northeastern Alberta
needed for a quality lifestyle to employees of the various companies in the area as well as their housing, said Martyn Griggs, CAPP’s manager of oilsands. Cancelled leaseholders are getting compensation based upon the Mines and Minerals Act, which covers the cost of the investment. “I think it’s fair to say that that’s inadequate,” Griggs said, adding that companies also want the value of the resource. The 10 affected companies are Value Creation Inc., A lberta Oilsands Inc., Cenovus Energy Inc., Cavalier Land Ltd., E-T Energy Ltd., Grizzly Oil Sands ULC, Koch Oil Sands Operating ULC, Laricina Energy Ltd., Scott Land & Lease Ltd. and Suncor Energy Inc. Some of them would have conducted drilling programs to prove out and delineate their leases; however, there has been no production, said Griggs. The government has cancelled eight of Laricina’s leases, containing two sections it had nearly fully delineated, Glen Schmidt, Laricina’s president and chief executive officer said. They are part of what the company planned to develop as a steam assisted gravity drainage project called Poplar, estimated to be worth 25,000 barrels per day, directly south of Ivanhoe Energy Inc.’s proposed Tamarack project. “I think the provincial government has discussed strong consultation with the community to address the needs of Fort McMurray,” said Schmidt. “I would suggest they probably were less effective in their consultation with the companies, but their focus was clearly on meeting the needs of Fort McMurray.” Schmidt intends to discuss with the province how Laricina will be compensated for Poplar, not just those sections, he said. The government said the specific lands to be sold and the timing have not been determined. The Crown lands will be available for sale to the Regional Municipality of Wood Buffalo to create an area for development twice the current size of Fort McMurray. The additional land will enable Fort McMurray to expand to the east, south and west, and is expected to meet the growth needs of the municipality for more than 25 years. “This is about creating an even better quality of life for the residents of Fort McMurray, a thriving community that is expected to more than double in population by 2030,” said
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Northeastern Alberta
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Ken Hughes, minister of energy, in a release. “We think it’s important that people call Fort McMurray home, and not just their place of work.” An information letter has been sent to surface and subsurface lease holders. Because compensation is for a specific Crown mineral agreement, all applications for compensation will be subject to a concept and financial audit to ensure that claimed costs have been fairly and reasonably expended by a lessee during the qualifying period (for development costs) or eligibility period (for reclamation allowance) and are directly associated with the agreement, or portion of an agreement, to be cancelled, said an Alberta government release. According to the province, the land made available was determined based on resource analysis, municipal growth plans and consultation with First Nations and stakeholders such as industry and the public. In addition to meetings with the Regional Municipality of Wood Buffalo, consultation sessions took place from September 2012 to January 2013 in the form of public engagement sessions and direct meetings. “The Urban Development Sub-Region is incredibly important for future growth in our region,” said Melissa Blake, mayor of the Regional Municipality of Wood Buffalo. “It means stability in our housing market and a new world of business, cultural and recreational opportunities.” The Alberta government says the UDSR boundary will not change; however, it is open to future discussions on the scheduling of land sales within the boundary. The sale of Crown land in stages over time will be based on the urban growth needs of the municipality. U DSR implementation is to star t immediately. Only oilsands development and exploration is currently considered not compatible with urban development, therefore all oilsands agreements within the UDSR will be cancelled, as well as their associated surface dispositions. No restriction is placed on existing or future disposition of metallic and industrial mineral leases, petroleum and natural gas leases or coal leases within the UDSR. All other surface dispositions will require a review from Alberta Environment and Sustainable Resource Development at the time of land sale to determine their compatibility with urban development.
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CENTRAL ALBERTA WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Tourmaline Oil says Spirit River/Charlie Lake significant new resource play By Darrell Stonehouse
Photo: Joey Podlubny
Deep Basin producer Tourmaline Oil Corp. has added a third resource play to its Deep Basin development plans, reporting in early July that its Spirit River/Charlie Lake oil and gas pool has evolved into a major new hybrid play with significant reserve and production upside. This major expansion of the Triassic Charlie Lake Play combined with the successful consolidation of the associated prospective land opportunity have created a third major core operating area for the company, complementing the northeastern B.C. Montney complex and the Alberta Deep Basin. Through ongoing Charlie Lake pool expansion efforts at Spirit River over the past 18 months and 2013 regional Charlie Lake exploration successes, the company has delineated a regional oil and gas accumulation with both structural and stratigraphic trapping elements. Tourmaline estimates
Tourmaline estimates that over 500 million barrels equivalent of light oil and natural gas along the Peace River High defined fairway are potentially recoverable.
that over 500 million barrels equivalent of light oil and natural gas along the defined fairway are potentially recoverable. The company has drilled 43 successful Charlie Lake horizontal oil wells and no dry holes since horizontal exploitation commenced in late 2011. The most recent exploration well, approximately 40 miles from the main Spirit River pool, tested oil and gas at a stabilized rate of 700 barrels equivalent per day at the end of a three-day production test. The most recent pool expansion well, 10 miles south of the main pool, tested at a stabilized rate of 650 barrels per day. The 14-08-077-07W6 well, one of the first-quarter 2013 pool expansion wells, has produced 105,000 barrels equivalent since March 17 (55,000 barrels of oil, 297 million cubic feet of gas) and is currently producing at 316 barrels per day of oil and 2.5 million cubic feet per day of gas. Tourmaline has several additional regional Charlie Lake exploration wells planned over the next 12 months to both assess and expand the 75-mile-long exploration fairway. A major land acquisition program has been underway for over 18 months in the greater Peace River High area with approximately 410 sections of new land, prospective for the Triassic Charlie Lake, acquired. This region of the Peace River High is characterized by stacked, multiple objectives throughout the Mesozoic section. As the company proceeds with the systematic regional Charlie Lake drilling program, numerous, less-expansive up-hole pool discoveries are anticipated. Tourmaline has steadily improved its horizontal drilling and completion techniques for these complex Charlie Lake reservoirs. The improving per-well deliverabilities and steadily decreasing capital costs
Tourmaline Oil Corp. by the numbers 2012 average production: 50,800 boe/d 2013 estimated average production: 80,000 boe/d Undeveloped acres: 1,076,747 Reserves (P&P): 438 million boe (as of year-end 2012) Key plays: Alberta Deep Basin: 6,800 drilling locations Northeastern B.C. Montney: 550 drilling locations Peace River High/Charlie Lake: 750–1,000 drilling locations Source: Tourmaline Oil Corp.
have been an essential component of the overall play evolution. Drilling, completion and stimulation costs have been reduced to approximately $3.6 million per horizontal, with average per-well proved-plus-probable reserve recoveries of 300,000–350,000 barrels equivalent in the main pool. Tourmaline plans to run three rigs over the next 12–18 months pursuing these Charlie Lake horizontal targets, resulting in 70–75 new horizontals drilled by late 2014. The company expects to attain the 10,000-barrel-equivalent-per-day production level at Spirit River by the fourth quarter of this year and believes that continued regional play success could allow it to more than double these production levels over the next two years. Tourmaline is proceeding with plans to build a new gas plant, capable of processing 60 million cubic feet OIL & GAS INQUIRER • SEPTEMBER 2013
37
Central Alberta
per day, in the greater Spirit River area, adding to existing Tourmaline-owned oil and gas infrastructure. The company is also developing plans to capture the
significant, regional, natural gas liquids target, as the average liquid content in the associated gas stream is approximately 102 barrels per million cubic feet. Including the
main Spirit River complex and the associated regional exploration lands, the company now has a potential future drilling inventory of 750–1,000 locations.
Artisan Energy reports Ferrybank drilling success Artisan Energy Corporation said that it successfully drilled two additional 1,000-metre horizontal Belly River oil wells at Ferrybank in west-central Alberta. The wells each are producing in more than 100 barrels per day of oil and are expected to exceed the company’s 60-day initial production expectation of approximately 75 barrels of oil per day per well. The two wells were initially brought on production in the middle of June, but required cleanout workovers to drill out the balls that did not properly dissolve in the brine frac fluid after the fracture stimulation process. The workover operations were successfully completed in July. Artisan currently has three horizontal oil wells producing from the Ferrybank
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pool and has plans to construct an 800metre pipeline to capture the associated gas production, which represents an additional 50 barrels of oil equivalent per day. The company has up to an additional eight horizontal oil drilling locations for future consideration on its existing Ferrybank lands. The company’s current total production is more than 400 barrels equivalent per day (70 per cent oil and natural gas liquids). At Chip Lake, Artisan has completed a solution gas pipeline and brought its initial horizontal Rock Creek well on production. The well is currently flowing 30 barrels per day of oil and 750 thousand cubic feet per day of raw gas at a restricted rate due to short-term compression limitations at the
third party–operated gas plant. Additional natural gas liquids recovery of approximately 20 barrels per day is anticipated from the gas, resulting in approximately 50 barrels per day of total oil and natural gas liquids and approximately 100 barrels equivalent per day of gas after shrinkage. Subject to available funds, Artisan can drill an additional horizontal Rock Creek well from its existing Chip Lake pad and five additional horizontal Rock Creek wells from a nearby approved multi-well pad. Future wells will target areas of the Chip Lake pool that are expected to produce at a higher oil ratio. Artisan has up to an additional 26 horizontal Rock Creek drilling locations for future consideration on its existing Chip Lake Lands. — DAILY OIL BULLETIN
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Plans for Canada’s first gas-to-liquids plant advancing By Pat Roche
Image: Sasol Limited
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Tentative plans for a multi-billion dollar gas-to-liquids (GTL) plant in the Fort Saskatchewan, Alta., area are quietly moving through the regulatory process despite taking a back seat to a Louisiana project. In December 2010, South A frica’s Sasol Limited, the global leader in GTL technology, said it was evaluating western Canada as a potential location for a plant that would convert natural gas to liquid fuels. But earlier this year, Sasol decided it would build its fi rst North American GTL plant at Lake Charles, La., next to its existing chemical complex. The company cited its existing asset base, Louisiana state incentives and competitive capital costs at the Lake Charles chemical hub as factors in its decision. Although the Lake Charles GTL plant is to be built first, Sasol is continuing to work toward the potential construction of a plant in Alberta in the longer term.
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OIL & GAS INQUIRER • SEPTEMBER 2013
39
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SEPTEMBER 2013 • OIL & GAS INQUIRER
The company recently filed environmental impact assessment documentation with Alberta Environment and Sustainable Resource Development. “By working through Alberta’s comprehensive regulatory process in the coming months, we will be well positioned to move into…[the] front-end engineering and design [FEED] stage when we seek the approval to do so of our board,” Sasol Canada president Martin Waterhouse said. A decision on whether to proceed to FEED for a potential Alberta project won’t be made until after construction of the Lake Charles plant, the company said. According to Sasol’s regulatory filings, the plant would convert natural gas to diesel, naphtha and a liquefied petroleum gas (LPG) such as propane. Sasol said the naphtha could be used as diluent for pipelining bitumen. Oilsands producers currently import substantial amounts of diluent. The project would be built in two phases with a combined design capacity of 103,900 barrels of liquid fuels per operating day. On an annual basis, Sasol expects this would work out to a combined output of 96,000 barrels per day of diesel, naphtha and LPG, or 48,000 barrels per day per phase. To produce 96,000 barrels per day of liquid fuels, the GTL plant would consume up to one billion cubic feet per day of natural gas, Sasol said in its project description. This would be good news for western Canada’s gas producers who have been hurting because the U.S. shale gas glut has severely depressed North American prices. Sasol also noted its proposed GTL project is consistent with the Alberta government’s stated goal of deriving greater local value from the province’s resources. After a lengthy process that evaluated potential locations in Alberta and British Columbia, Sasol settled on Strathcona county land owned by Total E&P Canada Ltd., a unit of Paris-based Total S.A. Sasol has an option to buy the site from Total, which had initially planned to build a bitumen upgrader there. The South African company hopes to have the land purchase concluded in September when its option expires, Debbie Pietrusik, a Sasol Canada spokeswoman, said. Sasol chose the location—about four kilometres northeast of Fort Saskatchewan and 40 kilometres northeast of Edmonton— because of its proximity to large natural gas pipeline networks as well as pipeline, rail and road transportation networks and
Central Alberta
of the gas-to-liquids plant would cost between The total capital cost of both phases is estimated 2012 dollars).
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utilities. Also, water is available from the North Saskatchewan River, and the area has a skilled workforce and fabrication facilities. The site is in a large area called Alberta’s Industrial Heartland, which area municipalities are promoting as Canada’s biggest hydrocarbon processing region. It is already zoned for heavy industrial development. Sasol completed pre-feasibility assessments for the proposed GTL project in 2010 and a comprehensive feasibility study was completed in late spring 2012. Formal consultation with communities and stakeholders began last September. In December, Sasol said it would proceed with preFEED activities in 2013. The pre-FEED phase is expected to last between 18 and 42 months. Pending completion of construction of Sasol’s Louisiana plant, the comprehensive FEED phase for the Alberta project will begin after the conclusion of pre-FEED activities—if the company’s board of directors decides to proceed to FEED. Under the timeline set out in its regulatory filings, Sasol would begin FEED preparatory activities in 2015, based on a pre-FEED duration of 30 months. Subject to regulatory approvals and the fi nal investment decision, or corporate sanction for the project, Sasol estimates Phase 1 site construction would begin in the first half of 2018. An estimated 5,000 construction workers would be required at peak construction, including both at the site and in module yards. Sasol said a construction camp isn’t needed. The capacity to use only local construction workers will be further evaluated during FEED. If necessary, additional labour will be sourced from elsewhere in Alberta, Canada, North America and overseas. Housing availability will also be further evaluated. The tentative timeline for the start-up of Phase 1 is 2021. In its regulatory fi lings, Sasol estimates Phase 1 construction would cost between US$6 billion and US$9 billion (in 2012 dollars). The total capital cost of both phases is estimated at between US$11 billion and US$16 billion (in 2012 dollars). The company notes cost estimate are subject to a variety of factors, including world steel prices, the cost of equipment and raw materials, global currency exchange rate fluctuations, labour demand, module yard availability, competition from other construction projects and weather during construction. A more detailed cost estimate will be worked out during FEED.
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OIL & GAS INQUIRER • SEPTEMBER 2013
41
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†
SOUTHERN ALBERTA WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
Pine Cliff Energy acquiring shallow gas assets Pine Cliff Energy Ltd. has entered into an arm’s length purchase and sale agreement to purchase additional interests in the southern Alberta and southern Saskatchewan properties that Pine Cliff had originally acquired an interest in through the acquisition of Skope Energy Inc. in February 2013. As part of the acquisition, the current asset management agreement governing Pine Cliff ’s current and additional interests in the assets will be terminated and Pine Cliff will become the operator of the assets. The total cash consideration for the acquisition will be $13.25 million, prior to any adjustments. The acquisition includes a further 7.4 per cent working interest in the Monogram Unit and related infrastructure; a further approximate 20 per cent working interest in the Pendor, Black Butte and Eagle Butte areas; and a further approximate 18 per cent
working interest in the Vidora, Cadillac and Wymark areas in Saskatchewan. Upon closing, and assuming the waiver of all rights of first refusals and the closing of the previously announced acquisition of a 53.1 per cent interest in the Monogram Unit, Pine Cliff will own a 90.8 per cent working interest in the Monogram Unit and an approximate 96 per cent working interest in the other assets. Pine Cliff said it has always been a goal of the company to operate and control the development in its core areas, and the acquisition achieves that goal. The termination of the current asset management agreement will result in Pine Cliff ’s operating expenses being reduced by approximately $5.6 million over the next 31 months. The decrease in operating expenses will be offset by an incremental increase to general and administrative expenses of approximately $2.5 million
during the same time period as a direct result of increased staffi ng, set-up and conversion costs. The interests in the assets being purchased produce approximately 850 barrels of oil equivalent per day, weighted 100 per cent towards natural gas, and are characterized by an annual production decline of approximately 14 per cent. Subsequent to the closing of the acquisition, Pine Cliff anticipates it will have production of approximately 6,850 barrels equivalent per day, weighted approximately 97 per cent towards natural gas, of which approximately 5,800 barrels equivalent per day is from the shallow gas assets. An independent reserve evaluation assigned 1,924,600 barrels equivalent of remaining total proved reserves and 2,357,400 barrels of remaining total provedplus-probable reserves in the assets.
Pricing, wet weather squeeze Calfrac’s bottom line
Photo: Aaron Parker
By James Mahony
Calfrac Well Services Ltd. is attributing lower revenue in the second quarter and fi rst half of 2013 to lower pricing and wet weather that slowed operations for most oilfield service firms in western Canada. Results were impacted by lower pricing in both Canada and the United States, compounded by western Canada’s unseasonably wet weather, management said. Calfrac’s net loss widened to $14.94 million from $11.97 million in last year’s second quarter, while revenue slipped 14 per cent to $288.70 million from $335.78 million in the earlier period. The weather “severely hampered” Calfrac’s ability to carry out planned
Calfrac said the drop in Canadian revenue was due mainly to a lack of fracturing and coiled tubing activity in the Horn River Basin.
OIL & GAS INQUIRER • SEPTEMBER 2013
43
Southern Alberta
projects for the quarter and work was deferred to the third quarter as a result. Despite this, the company said it was active in the Montney unconventional resource play and completed several large multi-well pad projects there. The drop in Canadian revenue was due mainly to a lack of fracturing and coiled tubing activity in the Horn River Basin area of northeastern British Columbia, combined with more competitive pricing, somewhat offset by the completion of larger fracturing jobs. Calfrac completed 69 per cent fewer coiled tubing jobs in Canada during the quarter than in last year’s period. In last year’s second quarter, Calfrac completed a significant Horn River project, but the company saw no activity there in 2013. As well, wet weather in June in western Canada, especially in southern and central Alberta, delayed planned completion projects until the third quarter, contributing to the drop in fracturing activity, management said. At the same time, lower revenue in both 2013 reporting periods was partly offset by
higher fracturing activity in two unconventional natural gas shale plays in the United States, stronger multistage fracturing activity in Russia and the start of fracturing operations in Argentina, the company said. But for a $4-million income tax recovery in the second quarter, Calfrac’s loss would have been higher. As well, corporate expenses in both periods rose due to stockbased compensation, which was $1 million higher in the second quarter and $2.6 million higher in the year-to-date period. In the six months ended Jun. 30, 2013, net income declined to $9.25 million from $58.73 million in last year’s first half. In the United States, Calfrac’s secondquarter revenue declined to $146.3 million from $175.1 million in last year’s period, due mainly to competitive pricing and the completion of smaller fracturing jobs in the Bakken play of North Dakota, partly offset by higher fracturing and cementing, management said. At the same time, in the Marcellus and Fayetteville shale plays, fracturing was significantly higher in this year’s second quarter than last year’s period, an increase
that was partly off set by lower activity in North Dakota’s Bakken play, thanks to a longer-than-expected spring breakup and unusually wet weather. Management said capital spending for the year would remain at $74 million, with $25 million allocated to Latin American operations for investments in coiled tubing and fracturing equipment. The remaining capital is focused on maintenance, support capital and investment in logistics equipment. In addition, Calfrac expects the carryover of about $107 million from last year’s capital program will be completed in 2013. In a conference call, Calfrac chief executive office and director Douglas Ramsay said the company had signed a multi-year minimum-commitment contract to supply Progress Energy Canada Ltd. with three fracturing spreads for the company’s Montney project in northeastern British Columbia, with a right of first call for another spread for the same play. Earlier this year, “in anticipation of securing the Progress contract,” and expecting growth in the Canadian marketplace,
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SEPTEMBER 2013 • OIL & GAS INQUIRER
Southern Alberta
Trican ups capital spending
Fracture job by play type Natural gas plays
Crew size (HP)
# fracs per well
Stage size (tonnes)
Horn River
40,000–50,000
20–25
150–300
Deep Basin
12,000–25,000
10–15
80–200
Montney
15,000–30,000
10–15
100–200
Duvernay
30,000–40,000
10–20
100–200
Cardium
8,000–25,000
15–25
20–30
Alberta Bakken
4,000–15,000
12–20
20–30
Viking
6,000–9,000
12–16
20–40
20,000–30,000
10–20
4,000–6,000
15–20
By Carter Haydu
Oil plays
Beaverhill Lake Bakken
*Beaverhill Lake acid frac
Ramsay said Calfrac has boosted its Canadian horsepower by roughly 34 per cent over the past 12 months and has been actively hiring employees. Despite optimism about the U.S. market, he acknowledged the “near-term uncertainty” created by stiff competition
75–150 cubic metres* 6–12
Source: Calfrac Well Services Ltd.
in U.S plays and an oversupply of pressurepumping capacity, a point echoed by Tom Medvedic, Calfrac’s senior vice-president of corporate development and interim chief financial officer, who said pricing remains the primary challenge in the U.S. market.
Trican Well Service Ltd. is adding to its 2013 capital budget, the company told a conference call in early August. Michael Baldwin, senior vice-president of fi nance and chief fi nancial officer, said Trican recently increased its 2013 capital budget by $27 million, to be directed to conversion of frac pumpers to bi-fuel capability, as well as maintenance and infrastructure initiatives for Canadian and U.S. operations. “Capital expenditures for the remainder of 2013 are expected to be approximately $100 million to $120 million, based on current 2013 budgets and remaining capital expenditures on the prior year’s budget,” he said. “We anticipate our total 2013 capital spend to be between $160 million and $180 million.” Late last year, Trican announced its 2013 capital budget at $32.3 million.
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45
Southern Alberta
According to Baldwin, the company is “in a mode of keeping a minimal CAPEX effort out there.” He said the company would monitor and adjust its budget as needed from quarter to quarter. In January, Trican closed the acquisition of i-TEC Well Solutions, a privately owned company based in Norway that has developed a field-proven portfolio of completion systems and intervention tools, which can be used in cemented as well as open-hole installations. During t he conference call, Dale Dusterhoft, chief executive officer, said the company is currently integrating i-TEC tools into all of its regions. “As a result, our completions-tools business did not have a meaningful impact on our second-quarter financial results. However, we are pleased with the progress made by our completions-tools division during the second quarter of this year. We are seeing good customer and technical acceptance of our i-TEC tools in the U.S., Canada and Russia, and we will continue to focus on building a market
presence of our completions-tools business in all our key regions.” During the second quarter of 2013, Trican reported revenue at $396.61 million, a five per cent decrease from the same time frame in 2012. The company’s quarterly net loss increased 11 per cent yearover-year to $56.39 million for the three months ended Jun. 30, 2013. For the fi rst six months of 2013, Trican reported revenue at $1.01 billion, an 11 per cent decrease from the same time frame in 2012. For the first half of the year, the company reported a net loss of $31.2 million, compared to a net profit of $38.52 million in 2012. In Canada, the company generated $116.06 million in revenue from 3,098 jobs it received during the second quarter of 2013, compared with $140.18 million in revenue from 3,334 jobs during the second quarter of 2012. The job count decreased because of the year-over-year decrease in overall Canadian activity levels, while second-quarter materials and operating expenses increased to 104.6 per cent of
revenue compared to 97.1 per cent for the same time frame in 2012. “ T he second-quar ter Canadian results were significantly impacted by bad weather in spring breakup conditions—breakup was more prolonged and severe than in previous years. This had a negative impact on all our pressurepumping service lines in Canada during the second quarter,” Dusterhoft said. “But we are expecting a strong rebound in our Canadian drilling and completions activity, and it is anticipated our equ ipme nt ut i l i zat ion w i l l b e h ig h i n Ca nada dur i ng t he t h i rd qua r ter of 2013.” W hile t hird-quar ter pr icing is expected to improve in Canada compared to the second quarter of 2013, Dusterhoft does not expect in 2013 a return to high pricing levels as experienced during the fi rst quarter. “We do not believe Canadian pricing will increase substantially until activity levels and equipment utilization remains strong over a sustained period of time.”
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SEPTEMBER 2013 • OIL & GAS INQUIRER
Photo: Trican Well Service Ltd.
Southern Alberta
Dusterhoft said, “Early indications for 2014 show growth from the Canadian market, driven by further development of the Duvernay play and LNG [liquefied natural gas] activity in plays like the Montney and Horn River.” In the United States, the company generated $201.54 million in revenue from 2,208 jobs it received during the second quarter of 2013, compared with $206.78 million in revenue from 1,915 jobs during the second quarter of 2012. Overall U.S. activity levels were flat for Trican, as the average U.S. rig count for the second quarter of 2013 was relatively consistent with the first quarter. “We will continue to focus on increasing U.S. equipment utilization in the upcoming quarters,” Dusterhoft said, adding despite a challenging and competitive market, management believes there will be opportunities to increase U.S. use of Trican technology products, including water recycling services, fluid systems and completion tools. “We believe we have differentiating technologies and our focus in the U.S. will be to effectively market this technology to
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new and existing U.S. customers in order to increase utilization.” The company experienced strong usage from its fracturing crews operating in the Eagle Ford and Marcellus plays in the second quarter. In response to the strong demand in the Marcellus, the company deployed an additional fracturing crew in this region near the end of the quarter, which resulted in a total of three crews operating in the Marcellus region. Conversely, the company’s second-quarter activity levels were flat in the Permian and down in the Bakken and Oklahoma, as these areas remained very competitive and oversupplied with fracturing equipment throughout the second quarter. Flooding and wet weather in the Bakken and tornadoes in Oklahoma also negatively impacted activity levels. Therefore, Trican equipment usage levels did not increase sequentially in the Permian, Bakken and Oklahoma. Internationally, Trican generated $79.01 million in revenue from 962 jobs it received during the second quarter of 2013, compared with $71.02 million in revenue
Early indications for 2014 show growth from the Canadian market, driven by further development of the Duvernay play and LNG activity in plays like the Montney and Horn River, said Dale Dusterhoft , Trican chief executive officer.
from 1,057 jobs during the second quarter of 2012. The company’s Russian operations comprised the majority of these international results, although activity levels in Russia
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Southern Alberta
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“The second-quarter Canadian results were significantly impacted by bad weather in spring breakup conditions.”
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SEPTEMBER 2013 • OIL & GAS INQUIRER
— Dale Dusterhoft , chief executive officer, Trican Well Service Ltd.
were slightly below management’s expectations for the second quarter, as several Russian customers’ work programs were slightly behind schedule, which contributed to the lower-than-expected revenue. “You still have a few delays as the Russian market learns more and more about unconventional horizontal fracturing, as well as just regular market issues,” Dusterhoft said. Second-quarter fi nancial results were strong in Kazakhstan for Trican’s two fracturing crews operating in that region. Financial results in Algeria weakened yearover-year and were also down slightly, sequentially, due to a decrease in Trican cementing activity. The company experienced continued strong operating margins from its coiled tubing operations in Algeria during the quarter, but gains from the coiled tubing service line were more than off set by losses for the cementing service line during the second quarter. In response to weak cementing activity in Algeria, Trican parked two cement units during the second quarter, and the company is currently focused on growing its coiled tubing business in the region. Trican’s cementing and environmental services activity increased, sequentially, for Australian operations. However, management reports the Australian market has been slow to develop and is behind initial activity-level expectations.
Southern Alberta
Photo: Joey Podlubny
Precision Drilling ups spending on new rigs
Precision is predicting natural gas drilling will improve this fall as producers prove up resources in preparation for LNG exports.
Precision Drilling Corporation has bumped up this year’s capital budget 22.7 per cent, to $654 million from $533 million announced earlier this year, company executives said in a conference call. The figure includes $330 million in expansion capital, $139 million for rig upgrades, and $185 million for sustaining and infrastructure spending, the company said. Expansion capital spending includes the cost to fi nish construction of two drilling rigs from Precision’s 2012 capital program, six new-build rigs for North America and 60 per cent of the cost of two new-build rigs for Kuwait, and other equipment. Upgrade capital of $139 million covers upgrades for about 20 rigs, including two rigs destined for Kurdistan and one for Mexico. Sustaining and infrastructure spending, on the other hand, includes maintenance capital and the cost of upgrading the company’s operating facilities. In Canada, poor weather in June delayed the usual summer ramp-up, as demand continued while 30–40 Precision rigs awaited better weather to move. Even now, while conditions have improved, the company is seeing weather-related delays limit access to some locations, with some 20 rigs currently waiting on weather. Precision executives reviewed the near-term picture for day rates in the United States, where pricing remains fl at despite customer acceptance of the contractor’s Tier 1 drilling rigs, Precision president and chief executive officer Kevin Neveu said. When contracts for those rigs come up for renewal, Precision has had to show flexibility. “We can’t just be hard on price and not back off,” he said. Until demand starts to improve, he said pricing in the United States would stay flat, as Precision treads carefully in renewing contracts. “We might give up $500 or $1,000 a day in renegotiating a contract,” he said. “Until demand goes up, we’re in a relatively flat, slight downward pricing trend in the U.S.” In Canada, the pricing picture is more dependent on local trends, he said. “As we watch Canadian producers roll out drilling plans during the year, we’ll get a better sense of where pricing is going in 2014,” he said, adding there could be pressure from
labour costs in Alberta, where the supply of workers remains tight. “The risk of a really soft spot market for Precision is not hitting us this summer and we feel pretty good about summer pricing,” he told market analysts. As other drilling contractors have done recently, Neveu also talked about expectations for future liquefied natural gas (LNG)–focused drilling in British Columbia and Alberta. “In the second quarter, significant drilling rig specifications and pricing work was discussed with customers, particularly prospective LNG participants. The two contracted, new-build Super Triple 1500 drilling rigs we announced earlier for Canada are a direct result of some of this early producer interest,” he said. He predicted Precision and other drillers would see stronger activity this summer and fall in northeastern British Columbia and northwestern Alberta, thanks to the delineation drilling some LNG participants will do to prove up B.C. resource lands. “We also expect Montney natural gas and Duvernay NGL [natural gas liquids] drilling will see improved activity in this year’s second half,” he said. “While it’s still too early to consider LNG prospects a business certainty, we are encouraged by several factors,” he said, citing a renewed political will on the part of the recently re-elected B.C. government to support B.C. LNG development. He also cited the hefty investments international majors, including Chevron Corporation, Exxon Mobil Corporation, Shell Canada Limited and PETRONAS, have made in British Columbia, with a view to developing and exporting LNG. In t he second quar ter, Precision reported $136 million in capital spending, down $85 million from last year’s comparable figure. Spending in this year’s quarter included $82 million in expansion capital, $34 million in upgrade capital, and $20 million in maintenance capital and infrastructure spending, the company said. Neveu also noted that, in December, Precision largely exited the tier-three drilling market, retiring 52 legacy rigs, including 22 in Canada and 30 in the United States. At the same time, the company will hold on to another 26 of its legacy rigs. OIL & GAS INQUIRER • SEPTEMBER 2013
49
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SASKATCHEWAN WELL ACTIVITY JUL/12
JUL/13
Wells licensed
JUL/12
JUL/13
Wells spudded
JUL/12
JUL/13
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
BlackPearl advancing Onion Lake EOR program
Photo: Joey Podlubny
BlackPearl Resources Inc. said it will accelerate the development of its thermal enhanced oil recovery (EOR) project at its Onion Lake heavy oil property in Saskatchewan. The company has elected to proceed with a 12,000-barrel-per-day EOR project at Onion Lake prior to proceeding with the fi rst phase of its SAGD development at its Blackrod project in northern Alberta. “We are very excited to be moving forward with the next stage of development at Onion Lake,” said John Festival, president, chief executive officer and director of BlackPearl. “Over the next three years, the Onion Lake EOR project is expected to double company production and will
put us in a much stronger fi nancial position to tackle the 80,000-barrel-per-day Blackrod project.” BlackPearl currently produces about 5,000 barrels per day of primary heavy oil at Onion Lake. Similar to other thermal projects in Saskatchewan with mobile oil, the company expects the Onion Lake thermal project will have a rapid ramp-up to peak rates and a relatively low steam to oil ratio (SOR). The expected low SOR should reduce operating costs and generate attractive economics for the company. On Dec. 31, 2012, BlackPearl’s independent reserves evaluator assigned 74 million gross barrels of best-estimate contingent resources to the Onion Lake thermal project.
Initial capital costs of the Onion Lake thermal EOR project are estimated by BlackPearl Resources Inc. to be between $300 million and $350 million.
BlackPearl Resources Inc. Onion Lake fast facts Conventional development Current production: 4,800 bbls/d Drilling locations: 163 Typical IP per well: 40–60 bbls/d CAPEX per well: $300,000 Payout: 12–18 months Thermal EOR development Potential production: 12,000 bbls/d Potential reserves: 30 million to 50 million barrels Steam to oil ratio: 2 5–3 Payout: 3–4 years on a 25-plus-year project
The company noted that capital costs on thermal projects in Saskatchewan are lower than similar projects in the Alberta oilsands due to the reduced scale of thermal projects within the province, resulting in different regulatory requirements. While BlackPearl has not completed detailed third-party engineering cost estimates, the initial capital costs of the Onion Lake thermal EOR project are estimated by the company to be between $300 million and $350 million. Regulatory approval for the thermal EOR project at Onion Lake is expected in the second quarter of 2013. BlackPearl said it plans to pursue a US$350-million second-lien senior secured term-loan facility, which is expected to fully fund the development of the project. In conjunction with the proposed debt offering the company has retained Credit Suisse and RBC Capital Markets as joint bookrunners and joint lead arrangers for the proposed term-loan facility. OIL & GAS INQUIRER • SEPTEMBER 2013
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Initial indications from the lenders in the company’s existing credit facilities is that the $115-million borrowing base will remain the same after completion of the second-lien term-loan offering. In addition, BlackPearl reported that an agreement has been reached between the company and Onion Lake Energy Ltd. (OLE), a company owned by the Onion Lake Cree First Nation, to exchange its working interest in the Onion Lake thermal project for a gross overriding royalty. The existing working interest participation by OLE will continue for all primary production operations. BlackPearl’s original strategy was to proceed with the fi rst 20,000-barrel-perday phase of commercial development of the Blackrod project prior to undertaking the Onion Lake thermal project. Capital costs of the first phase of the Blackrod
project were anticipated to be between $750 million and $800 million. It was the company’s intention to fi nance this phase with a combination of debt, non-core asset sales, joint-venture proceeds and possibly new equity. Given the current soft market for oil and gas assets and the challenging equity markets, BlackPearl believes it would be too dilutive to its shareholders to proceed with fi nancing a project of this size at this time. At Blackrod, regulatory approval for the first 20,000-barrel-per-day phase is expected later in 2013 and the pilot, operating since 2011, has achieved commercial rates of oil production and SOR. The second pilot well pair will start steaming in the third quarter of 2013 while the first well pair has achieved numerous technical milestones in its first two years of operation.
With the latest recompletion in the first pilot well pair, the company said it expects production to return to commercial levels. In April, BlackPearl acquired a 100 per cent interest in 10 sections (6,400 acres) of additional oilsands acreage directly south of its existing Blackrod lands. A third-party reserve and resource evaluation has not been prepared on these recently acquired leases, but the company’s internal review suggests that, as of Dec. 31, 2012, best-estimate contingent resources could range from 50 million to 75 million barrels of bitumen. This acreage will be incorporated into the company’s development plans for the Blackrod project. The first phase of development at Blackrod will likely be deferred until the Onion Lake thermal EOR project is operating or until a joint-venture partner can be found. — DAILY OIL BULLETIN
CNRL advancing heavy oil EOR projects in Saskatchewan By Pat Roche
Canadian Natural Resources Limited (CNRL) extolled the merits of its cold heavy oil operations at its annual investor conference early this summer, emphasizing the success of Canada’s biggest polymer flood and the profitability of primary heavy oil production. While CNRL’s Horizon oilsands mine and steam-assisted oil production are huge and profitable, the best return on capital comes from a business that gets a lot less attention. “Although primary heavy oil is the unheralded part of our portfolio, it is the most profitable part of our portfolio,” CNRL president Steve Laut told analysts. Based on its commodity price assumptions, the company expects “field-operating” free cash flow from its primary heavy oil business will exceed $600 million this year and $800 million in 2014. It defi nes fieldoperating free cash flow as operating cash flow (operational cash flow before corporate costs, interest, foreign exchange and taxes) minus capital. “Primary heavy oil generates the highest free cash flow and returns on capital in our portfolio,” Laut emphasized. CNRL, which bills itself as Canada’s biggest primary heavy oil producer, has budgeted 52
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for 120 horizontal wells targeting that resource this year. But the company is also focused on enhanced oil recovery (EOR), particularly polymer flooding. With seven years’ experience at Pelican Lake—which it describes as one of the world’s biggest polymer floods—CNRL now plans to apply some of its learnings at the northeastern Alberta project to some of its other properties. Polymer is a non-toxic powder that is mixed with water to create fluid that is more viscous than water. Injected into the reservoir, the polymer solution—which has a viscosity similar to corn oil—increases oil recovery by improving the sweep efficiency and reducing the amount of bypassed oil. Along with its success with this relatively new technology, CNRL is also reporting good results with the oldest EOR process—waterflooding. “With a current recovery factor of approximately 10 per cent in primary heavy oil, we continue to work at enhanced recovery methods. We have several of these projects underway with waterf looding progress being made at Lone Rock, South Epping and Salt Lake,” said Scott Stauth,
CNRL’s senior vice-president of North American operations. He was referring to three properties in the greater Lloydminster area of Saskatchewan. At southwestern Epping, the company also recently sanctioned a polymer flood pilot, according to a slide in Stauth’s presentation. The multi-well Lone Rock polymer pilot is under construction at 47-27W3. “And we plan to use our learnings from Pelican, doubling or even tripling the recovery factors,” Stauth said. “Our Lone Rock and Epping waterflood project has proven very successful.” According to a graph on Stauth’s presentation, Sparky Formation oil production at the Lone Rock and South Epping waterflood pilots climbed to nearly 700 barrels per day this year with 28 producers, up from virtually nothing in January 2011. “ We had i m mediate resu lt s f rom init ia l injection in both areas,” Stauth said. Water injection began in February 2011 at the Lone Rock pilot and in May 2012 at South Epping. “When we implement our polymer pilot in this area we will have more insight to
Saskatchewan
compare success rates of polymer versus water for future development in this grade of oil,” he said. CNRL said the oil is 15–17.5 degrees API gravity with dead oil viscosities ranging between 700 and 2,300 centipoise at 20 degrees Celsius. In addition to the pilot under construction at Lone Rock to test polymer flooding in Lloydminster heavy oil, CNRL is planning a chemical-flooding pilot in medium crude and another in light oil, according to a presentation by Lyle Stevens, senior vicepresident of exploitation. The pilot in medium-gravity crude will be an alkaline surfactant polymer flood at Grand Forks (12-13W4) in southern Alberta. Construction is to start in the fourth quarter of this year. The pilot in light crude will test a technology called nanosphere polymer in a mature reservoir at Nipisi (78-09W5) in north-central Alberta. All three are to be operational late 2013 or early 2014, said Stevens. Laut described polymer flooding as driving significant reserves growth for
CNRL and “an important component of our transition to a longer-life, low-decline asset base.” Stevens said CNRL’s incremental capital cost of polymer flooding is in the range of $13–$17 per barrel, depending on the reservoir properties and the existing well density. This includes all the incremental wells, the polymer-mixing facilities, the water-treating facilities, the additional production facilities, maintenance capital and the polymer itself. He said incremental operating costs are about $4 per barrel, mainly associated with handling the polymer and water. “When we started piloting the polymer flood in 2005, it was an untested process in this type of reservoir, and there were no commercial applications with this quality of oil,” Stevens said. CNRL is working on various technology improvements related to polymer flooding. It is evaluating the use of surfactants to help reduce the residual oil that’s left behind as the polymer flood sweeps through the reservoir. It is also continuing to test new polymers
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that have the potential to reduce costs and improve performance. “Water treating plays a complex role in performance of the polymer. In the last few years, we’ve made significant advances in the design of our treating facilities and we continue to work on this front to improve performance and costs,” Stevens said. In the areas where CNRL has polymer flood operations, its independent reserves evaluator now estimates ultimate recoveries will average 25 per cent. “Overall, the polymer flood has resulted in Canadian Natural achieving a very impressive fourfold increase in reserves over primary recovery in the developed regions,” Stevens said. “We’ve proven that taking our time and staging the development has improved both the oil recovery and costs.” He said commercial polymer flooding is “still in its infancy as a recovery process.” Over the next few years, he expects to see more applications of the technology, improved performance, improved economics and increased oil recovery.
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I
t used to be that thermal oilsands projects represented the marginal barrel on global markets. With razor-thin profit margins, thermal projects like steam assisted gravity drainage (SAGD) were the first to be cancelled when prices crashed. Not anymore—Cenovus Energy Inc. executive vice-president and chief operating officer John Brannan told guests at the company’s annual investor day early this summer. “Probably the biggest misconception about oilsands, in particular SAGD development, is that it’s all high cost,” Brannan said before bringing up a chart comparing SAGD break-even costs for 175 global oil projects. “Cenovus SAGD is not the marginal barrel. It is among the lowest cost globally,” he pointed out on the chart developed by Goldman Sachs. “What we have proven over time, once the initial growth capital investment is complete and we move to [a] more sustaining mode, where we are investing capital just to maintain full plant
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production, supply [costs] dramatically decrease,” he explained. “In fact, Foster Creek and Christina Lake have full-cycle supply [costs] now of between $35 and $45 per barrel.” The key to that success has been the implementation of new technologies, said Brannan, and he expects supply costs to continue declining. “Innovations like our wedge-well technology make us more efficient along the way. Any technologies that can incrementally lower steam to oil ratios [SORs], improve cost or increase production capacity will accelerate supply cost improvements,” he explained. “We believe SAGD economics will get better over time.” The company has 100 new technologies at various stages of development, including 22 in the pilot stage. Among the furthest along the path toward commercialization are the patented SkyStrat drilling rig, dewatering, CondenSAP, thin-pay wells and a hot-water pilot. Cenovus is at the commercialization phase for 11 projects including its patented wedge-well
Photo: ©iStockphoto.com/upiir
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spark Catching
New ideas ignite in situ oilsands revolution By Darrell Stonehouse
technology, blowdown boilers, low nitrous oxide burners and the process of accelerated start-up of thermal operations. Currently it has 40 projects in the concept stage, 19 projects in the research stage and 15 projects in the engineering stage. New technologies target hard-to-hit barrels A hot-water pilot is in the evaluation stage at Pelican Lake. Potentially applicable to mobile and immobile portions of the Wabiskaw and to thin reservoirs (less than six metres of pay), the technology involves simultaneous injection of hot water and production in the same wellbore. At present, the pilot consists of one horizontal producer supported by two offsetting horizontal injectors. Wells with output of 30–40 barrels per day are now producing 150–200 barrels per day, said Harbir Chhina, executive vicepresident of oilsands. “This is a huge success story, and you’re going to see more of this stuff coming up and our production increasing at Pelican,” said Chhina.
A big bonus—the technology is also cutting down on wasted heat, he added. Cenovus’s third-party evaluators generally only give the company credit for reserves that are eight metres or thicker, but it has many areas with a thinner resource such as Foster Creek and Christina Lake, and the company intends to prove to evaluators and regulators that even six metres of bitumen thickness can be economic. “That would open up a vast number of additional resources for us,” Brannan said. Chhina said Cenovus will prove up that technology, called thin-pay wells, over the next year or two. Solvent floods cut operating costs Solvent-aided process has been such a success at Narrows Lake—lowering the SOR by 30 per cent, increasing full-field recovery rates by about 15 per cent and reducing non-fuel operating costs by five to 10 per cent all while improving its environmental footprint—that the company plans to apply solvent at all its oilsands operations, Chhina told the meeting.
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Narrows Lake received butane, but Cenovus is also experimenting with “everything from C1 to C7: methane, ethane, propane, pentane and hexane, as well as CO2,” said Chhina. New rig reduces environmental footprint The SkyStrat drilling rig is another success, he said. The new rig was developed to improve stratigraphic drilling programs in the oilsands. It’s approximately two-thirds the size and less than half the weight of a conventional rig and can be transported by helicopter, allowing Cenovus to access remote exploratory drilling locations year-round while reducing its environmental impact. The rig lowers costs by 25 per cent, the meeting heard. Recently, the company was told by Alberta Environment and Sustainable Resources Development that environmental impacts to a recent SkyStrat wellsite were so insignificant that instead of the process taking five to six years, it would issue a reclamation certificate immediately upon the company vacating the site, said Chhina. Manufacturing approach pays dividends Meanwhile, Cenovus attributes some of its success to its manufacturing approach for building oilsands projects.
Fabricating modules at the company’s owned and operated Nisku yard eliminates field rework and enhances safety, the company contends. Despite having cut its labour force at the Nisku yard by 20–25 per cent in the past 12 months, productivity has improved by 25 per cent, said Chhina. Cenovus has delivered nine phases at Foster Creek and Christina Lake on time and on budget, with the announced amount of production as well as industryleading SORs and low operating costs, Brannan said. It has another six phases under construction and is working on regulatory applications for additional ones. The company brings on projects with production of 40,000–50,000 barrels per day every 12–18 months, and since 2010 it has accelerated its schedules and advanced production faster than it had originally planned at both Foster Creek and Christina Lake, the meeting heard. While building continues at those two sites, this year a third construction team will be working at Narrows Lake. “We’ll be running those three projects simultaneously,” he said. Narrows Lake, the third SAGD oilsands project operated by Cenovus, is expected to have total gross production capacity of 130,000 barrels per day, three
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phases and a project life of up to 40 years. Supply costs are pegged at $45–$55 per barrels. Groundwork for the initial phase of 45,000 gross barrels per day began in the fall of 2012, and it is projected to begin operations in January 2017. Cenovus has 50 per cent ownership of Narrows Lake with partner ConocoPhillips Company. At Christina Lake, the company has delivered ramp ups at phases C and D that have gone faster than anybody in the industry has seen, said Brannan. “We’ve gone from first oil to full production in about six months on projects that used to take more than a year.” The quick start was a result of getting into the better part of the reservoir but also a combination of new start-up technologies, he said. Facility capacity for future phases of Foster Creek and Christina Lake is now expected to be reached in six to nine months—well ahead of industry averages, he added. The next phase of Christina Lake, Phase E, is expected to be on stream this summer. Suite of technologies drive down MEG costs MEG Energy Corp. has also been advancing technology to cut SAGD supply costs. MEG announced in July that its board of directors had conditionally approved its RISER technology suite as part of an
effort to increase production to 80,000 barrels per day by early 2015. “The goal of RISER is to deliver production increases from existing facilities,” says Bill McCaffrey, president and chief executive officer. “For 2012, the implementation of these enhancement initiatives will support full-year production at the high end of our guidance of 26,000–28,000 barrels per day. With broader deployment of the technology, we’ll be working on opportunities for interphase growth between major expansion projects of 10–15 per cent per year over the next several years.” The suite of technologies comprising RISER incor porates infill wells, non-condensable gas (NCG) injection to maintain reservoir pressure and a variety of related proprietary processes. “These are relatively low-capital, high-return initiatives, which not only support increased production with shorter lead times but should also help drive our operating costs even lower,” says McCaffrey. “The RISER concept has been implemented in MEG’s Phase 1 area. NCG was introduced into the three existing well pairs, and two infill wells were added. Production from the pilot pattern increased to 2,900 barrels per day at a steam-oil ratio of 1.3 in the second quarter of this year, compared with production of 2,300 barrels per day at a steam-oil ratio of 2.7 in the second quarter of 2011.
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Harbir Chhina, executive vicepresident of oilsands for Cenovus Energy Inc.
John Brannan, executive vicepresident and chief operating officer for Cenovus Energy Inc.
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Smaller operators target tough reservoirs With technology driving down costs at the best thermal reservoirs, focus is now on lower-quality reservoirs with massive bitumen supplies. “The Grade B reservoirs are going to take not only new technologies but new techniques and ways of doing things,” Byron Lutes, president and chief executive officer of Southern Pacific Resource Corp., said in response to a question at the TD Securities Calgary Energy Conference. “Smaller changes in technology will be important for oper ators to be more effective in their business,” he said. That could include, for example, improvements in temper ature readings so that an operator doesn’t need to worry about the accuracy of downhole temperature measurements, said Lutes. While continued improvements in technology are important to the industry in general, “technical” technology such as solvents are likely to play a more prominent role in the future, said John Zahary, president and chief executive officer of Sunshine Oilsands Ltd. However, he said there also is a need to see improvements in commercial matters—bringing down capital and operating costs, he said. Sunshine, which has a number of Chinese investors, is looking at different ways of building equipment further afield and
Photos (from left to right): Cenovus Energy Inc.; Todd Korol
“Achieving low steam-oil ratios frees up steam for redeployment into new wells, further supporting higher production levels,” McCaffrey adds. MEG plans to implement RISER in phases 1 and 2 prior to the start-up of Phase 3A, currently scheduled for 2016. Over the next two years, MEG plans to drill up to 32 additional infill wells in the Phase 2 area and, subject to regulatory approval, introduce NCG injection on additional SAGD well pairs. Engineering work is underway to assess the extent of facility modifications that may be required, as well as to position future phases to incorporate RISER technology. To support RISER and to advance engineering and procurement for Christina Lake Phase 3A and related infrastructure, MEG plans to increase its 2012 capital budget to a total of $1.75 billion. Of the expanded 2012 capital program, $185 million is related to RISER, including nine new infill wells in the Phase 2 project area, nine additional SAGD well pairs, and engineering and facility modifications to ensure that the central water- and oil-handling facilities can reliably accommodate increased volumes. Work on the central facilities is to be undertaken during MEG’s previously planned maintenance turnaround in September 2012.
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bringing it to the field location. It’s also examining different ways of operating facilities than have been done in the past. “This is a very large business; there is a lot of opportunity,” he said. “We are a price taker on the oil side, so we need to manage our costs in order to get the kind of profitability we need to make this business successful.” Southern Pacific has had to experiment with a number of techniques to get the ramp-up of its STP-McKay SAGD project back on track because it is not getting even conformance as it is warming up the wellbores, said Lutes. “We are having certain areas breaking through first and we are having some hot spots that we are having to manage the production to until we get to a more even conformance.” The process is taking longer than expected, which the company believes is due in part to the fact that it is operating at a slightly lower pressure than most SAGD projects, he said. “We are the second shallowest project out there and because of that we have a lower maximum operating pressure. So we can’t use pressure as one of our tools to really push things through and really get the zone between the injector and producer opened up.” STP-McKay, 45 kilometres northwest of Fort McMurray, is also in a slightly younger-aged McMurray sand, and some of the grains are more angular than those in some larger projects such as Suncor Energy Inc.’s Firebag or Cenovus’ Christina Lake, said Lutes. “We think some of the packing is more like rice kernels rather than marbles, so we have a little bit tighter packing that we need to dislodge or dilate, and we need pressure to do that.” The most effective technique appears to be a high-pressure steam stimulation. In June, Southern Pacific completely shut in the injector well in one well pair and with the regulator’s approval pushed steam into the producer well at higher than its maximum operating pressure. “What we are really trying to do is fluff up the sand…and twist the grains of sand in between the producer and the injector so we can improve and accelerate the rate of conformance in the pair.” As a result of the procedure, one of the company’s poorest wells in terms of conformance is now a producing SAGD well that has been operating steadily since June 4. Based on that, Southern Pacific has applied and received Alberta Energy Regulator approval to test five more wells and has already started its second steam test. It will continue to stimulate the wells over the summer and is hopeful that will accelerate conformance, said Lutes. “It’s not a silver bullet; there are other companies that are doing dilation and various techniques, but it is a way that we think will help us get that conformance so we can start to ramp up some of those well pairs and get them going.” STP-McKay has 12 well pairs capable of SAGD production and two of these periodically return to circulation. The project got off to a fast start in July 2012 with production peaking at 1,400 barrels per day in January 2013, but the company backed off following a liner failure in a well pair and has been gradually increasing volumes, which averaged 1,200 barrels per day in June. “We see now that we can move forward with a slow but steady ramp-up,” said Lutes. Rates are expected to approach permitted capacity of 12,000 barrels per day in the second calendar quarter of 2014. BlackPearl Resources Inc. also has been “experimenting” with its 700-metre single well pair at its Blackrod SAGD pilot project in the Athabasca oilsands, said John Festival, president and chief executive officer. The pilot is in the Lower Grand Rapids formation at a depth of approximately 300 metres, and has 10–28 metres of continuous net pay.
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The Grand Rapids pilot has been underway for two years, and for the first 12 months had “very good results,” with production of 400 barrels per day and a steam to oil ratio of three, said Festival. BlackPearl’s results for the first year, in fact, were better than those of Canadian Natural Resources Limited’s (CNRL’s) Wolf Lake project, which the junior was watching as CNRL was learning with its process, he said. At that point, BlackPearl realized that it didn’t really have an optimized completion process, so it went back in and looked at its steam strategies, the conference heard. Earlier this year, the company tried removing the sand controls as it felt it had some fines migration and some clay. “We went and blew holes in the pipe to allow greater contact with the reservoir,” Festival said later. “It worked very, very well; we know that more surface contact with the reservoir will allow better rates.” BlackPearl got the well up to 600 barrels per day with flush production and believes it will stabilize at between 400 and 500 barrels per day. In the first quarter of this year, the company drilled a second 900-metre well pair using a wire-wrapped screen that allows for more surface area contact with the reservoir, which should alleviate some inflow problems. While it is a better solution, it may not yet be the optimal solution, said Festival. “We have a commercial solution; we are just narrowing it down to what the optimized commercial solution will be.” The company filed an 80,000-barrel-per-day commercial application in the second quarter of 2012 and approval is expected later this year. The project is to be built in phases beginning with a 20,000-barrel-per-day phase, followed by two 30,000-barrel-perday phases. The shoreface sand of the Grand Rapids Formation is “dirtier” with fi nes and clays in it, and the permeability is not as good as in the McMurray fluvial channel systems but it is very predictable, he said. “What we lack in prolific results, we make up in geological extent.” However, “once you figure out the engineering solution to make it work, it works great,” said Festival, citing the examples of CNRL’s Primrose project and Imperial Oil Limited’s Cold Lake cyclic steam stimulation projects. Those projects, though, use high-pressure steam, which is needed to crack the rock, he said.
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WAYFINDERS In situ oilsands operators navigate the options to get production to market By Darrell Stonehouse
Illustration: Jenna O’Flaherty
W
here there’s a will, there’s a way. Nowhere is this old saw more true than when it comes to the efforts of Canadian bitumen and heavy oil producers to find markets for expanding production. Whether by pipe, rail or water, the oil is moving and producers continue finding new takeaway capacity to markets where they can get the best price for their production. During his second-quarter presentation to analysts and shareholders Canadian Natural Resources Limited (CNRL) president Steve Laut said much of the concern about takeaway capacity out of western Canada is overstated. “Canadian oil will not be trapped in Canada,” Laut said. “Canadian Natural is the largest heavy oil producer in Canada. We move and market roughly 500,000 barrels a day of conventional light, synthetic, medium and heavy blends and diluent through a cross-section of pipelines and refineries throughout North America. As you would expect, our marketing department has an excellent understanding of the actual workings of the market.” Laut said in both the short term and long term there will be adequate markets and the means to deliver product to those markets for Canadian production. “We’re bullish on heavy oil pricing in 2013 as well as the medium and long term as there is significant heavy oil conversion capacity coming on stream in PADD II [the U.S. Midwest] and significant current underutilized heavy oil refining capacity on the Gulf Coast. And we see the infrastructure to get to the Gulf Coast being built,” he said.
Laut said if pipelines like the Keystone XL to the Gulf Coast or the Northern Gateway to the Canadian West Coast are delayed, rail will pick up the slack like it has with the 500,000 barrels per day coming out of the Bakken in North Dakota. He added that the company believes pipelines are the best way to move oil, and he believes Keystone will be approved, but the other options are there. CNRL is currently shipping about 14,000 barrels per day of heavy oil by rail to the Gulf Coast. “We have the capacity today to go to 30,000 barrels a day, and we just don’t need it,” Laut said, adding, “It does take time to build railcars, and we believe we have time.” MEG takes a wheel-and-spoke approach Bill McCaff rey, president and chief executive officer of MEG Energy Corp., told his company’s shareholders in his secondquarter report that MEG’s strategy is to use whatever means at its disposal to maximize returns on its bitumen production. “There’s a lot of value to be harnessed between the wellhead and the customer,” McCaff rey explained. “We are positioning ourselves to take advantage of infrastructure to get to markets and most importantly to have direct control of our access to those markets. The goal is to participate in projects that will significantly reduce or eliminate exposure to North American differentials and help move our products towards world-market pricing. Along these lines, we’re getting to benefit from both the structural changes in the larger markets, while at the same time advancing our own marketing strategies. We believe macro changes in the market
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“ Both barge and rail can be independently ramped up or down depending on whether they are accretive to the market price we can achieve using other alternatives.” — Bill McCaffrey, president and chief executive officer, MEG Energy Corp.
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“Transportation spokes that branch out from the hub to gain access to reliable long-term international pricing include not just pipeline connections like the Flanagan/Seaway but also other alternatives we can employ at our option,” said McCaff rey. “The first alternative spoke is barging via the U.S. on the waterways system, and that goes to high-valued markets on the U.S. Gulf Coast. And I am happy to report that MEG has now taken delivery of all of its 18 leased barges and that they are available as needed for use.” Each barge can carry 20,000–30,000 barrels of oil, and there are six barges per tow for a total 120,000–180,000 barrels of oil in one shipment. “The second alternative spoke is rail delivery,” he added. “As with barging, we’ve already tested new refining markets with rail shipments and we will have the option at our discretion to move significant volumes by rail with the completion of the initial phase of loading facilities later this year.” McCaff rey said rail and barge provide some advantages to producers looking to maximize prices. “Both barge and rail can be independently ramped up or down depending on whether they are accretive to the market price we can achieve using other alternatives,” he noted. “So when combined with pipeline options, we expect to have the flexibility to optimize market access throughout North America and that flexibility is really what our hub-and-spoke strategy is all about.” Cenovus focused on increasing margin on every barrel Don Swystun, executive vice-president of refining, marketing, transportation and development for Cenovus, told the company’s recent investor-day crowd his company is also taking a portfolio approach to marketing its growing production.
Photo: Charles Hope
are beginning to shift the overall pricing equation and that we are at the early stages of normalizing light-heavy differentials.” McCaff rey agreed with Laut that new conversion capacity this year at the BP Whiting Refinery will increase demand for heavy oil in the PADD 2 area. “In fact, with around 240,000–250,000 barrels a day of heavy capacity, Whiting will more than absorb expected increases in the near-term heavy supplies, including the ramp-up of Imperial’s Kearl Project,” he said. McCaff rey said the ramp-up of the Permian and Longhorn pipelines, in addition to new takeaway capacity from Cushing via the Seaway Pipeline to the Gulf Coast, are helping release some of the congestion that drove the differential between North American and global prices and between heavy and light prices. “We believe the combined effects of these changes [are] causing some of the current tightening of both WCS [Western Canada Select] to WTI [West Texas Intermediate] and WTI to Brent, and it’s helping strengthen MEG’s netbacks,” he said. Additional structural changes in the market will continue this year, with the completion of the southern leg of Keystone XL between Cushing and the Gulf Coast and into next year with the launching of Flanagan/Seaway Pipeline system in mid-2014, he added. MEG is also making its own moves to secure higher prices for its production, using what McCaff rey describes as “a hub-andspoke marketing strategy.” The first piece of that strategy is its interest in the Access Pipeline, which delivers product from MEG’s Christina Lake operations to the Edmonton area. Access is being connected to MEG’s 900,000-barrel Stonefell storage terminal, which is on schedule for mechanical completion in the third quarter. Stonefell will act as the hub and launch point for MEG’s marketing initiatives.
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“Our goal is to increase the margin on every barrel of oil produced by Cenovus,” he noted. “We are creating a portfolio of opportunities, particularly related to transportation alternatives to provide us with flexibility on where we sell our products and exposure to optimal pricing structures.” Swystun said Cenovus is currently using both pipelines and rail to expand marketing opportunities. “By selling bitumen blend at multiple market hubs, including Alberta, the West Coast, Midwest and U.S. Gulf Coast, we can optimize realized prices,” he explained, adding that Cenovus’ ownership in two U.S.-based refineries allows it to access the full value chain from production of oil to sale of refined products at global pricing. “The value chain exposes us to numerous market locations, the first being [the] local Alberta market hub, where we receive Alberta-based pricing,” he explained. “The second, which is down the value chain by accessing pipeline and rail capacity to get exposure to other markets with pricing tied to WTI or global pricing via tidewater. The third part of the value chain is utilizing our refining capacity to gain exposure to the sale of refined products with pricing typically tied to global benchmarks such as Brent.” Swystun said with pipeline capacity tight for all of 2013, rail has helped to fill the gap. “We expect that rail capacity will continue to play a growing role in transporting oil, particularly in the event that any of the planned new pipelines or pipeline expansions are delayed or cancelled,” he said.
TransCanada proceeding with Energy East Pipeline TransCanada Corporation is moving forward with the 1.1-millionbarrel-per-day Energy East Pipeline project based on binding,
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But Cenovus is a big supporter of almost all the planned pipelines out of western Canada, he added. “We have committed volumes of 175,000 barrels per day to the West Coast on the Trans Mountain expansion and the Northern Gateway Pipeline. We have also entered into a long-term deal to move an additional 150,000 barrels a day to the Gulf Coast on the Keystone XL and Enbridge’s U.S. Gulf Coast access,” he said. “In addition, we are also participating in TransCanada [Corporation] pipeline’s open season to move oil to central Canada and the East Coast, to St. John. Our strategy has been to participate in multiple pipeline opportunities and rail to manage the risk of some of the projects being delayed.” But even with the pipelines, Cenovus will continue using rail. “It’s a great option during periods of pipeline congestion and also opens up markets not accessible to western crudes by pipeline,” he said. “As well, rail provides the flexibility to move bitumen with less diluent. And expanding our rail commitment, so far, we have least 800 railcars, 300 general-purpose and 500 coiled and insulated cars for heavy oil that will arrive starting in late 2014. And of course, in addition to these, we contract railcars from others. We’re also looking to participate in rail terminals with the prospect of having up to 30,000 barrels per day of unit train capacity available for market hubs.”
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OIL & GAS INQUIRER • SEPTEMBER 2013
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SEPTEMBER 2013 • OIL & GAS INQUIRER
long-term contracts received from producers and refiners. The conclusion of the successful open season confirmed strong market support for a pipeline with approximately 900,000 barrels per day of firm, long-term contracts to transport crude oil from western Canada to eastern Canadian refineries and export terminals, TransCanada said. Russ Girling, TransCanada’s president and chief executive officer, announced in August plans to proceed with the line after a strong open season. Girling added that interest in Energy East supports refineries’ desire to have access to a stable and reliable supply of western Canadian crude oil—pushing out more expensive crude oil from foreign regimes. Eastern Canada currently imports approximately 700,000 barrels per day. It also confirms the desire producers have to support safe and innovative ways to get their crude oil to market. The project is expected to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. The Energy East Pipeline will have a capacity of approximately 1.1 million barrels per day and is anticipated to be in service by late 2017 for deliveries in Quebec and 2018 for deliveries to New Brunswick. The Energy East Pipeline project involves converting a portion of natural gas pipeline capacity in approximately 3,000 kilometres of TransCanada’s existing Canadian Mainline to crude oil service and constructing approximately 1,400 kilometres of new pipeline. The pipeline will transport crude oil from receipt points in Alberta and Saskatchewan to delivery points in Montreal, the Quebec City region and Saint John, N.B., greatly enhancing producer access to eastern Canadian and international markets. The pipeline will terminate at Canaport in Saint John, where TransCanada and Irving Oil have formed a joint venture to build, own and operate a new deepwater marine terminal. The company intends to proceed with the necessary regulatory applications for approvals to construct and operate the pipeline project and terminal facilities in early 2014. In 2012, 83 per cent of crude oil deliveries to Atlantic Canadian refineries and 92 per cent of crude oil deliveries to refineries in Quebec were imported from countries like Saudi Arabia, Algeria and Angola.
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SLOW BOIL Bakken the hot spot but Viking, Shaunavon heating up in southwestern Saskatchewan By Darrell Stonehouse
Photo: Hemera Technologies/Photos.com
A
After years of decline, the advent of horizontal drilling and multistage fracturing has turned around the Saskatchewan oil industry. In 2012, the province reported record production of almost 180 million barrels, or around 493,000 barrels per day. Over 3,200 oil wells were drilled, with $4.7 billion spent on new exploration and development. The Bakken tight oil play in southeastern Saskatchewan has been the focus of industry watchers since it first began to be developed eight years ago. Production has climbed from less than 1,000 barrels per day in 2004 to over 70,000 barrels per day in 2012. But with the Bakken now maturing and moving into development drilling and secondary recovery, eyes are shifting westward to the Viking and Lower Shaunavon plays in earlier stages of development. The Viking tight oil play, centred around Dodsland, is currently producing around 27,000 barrels per day. The Lower Shaunavon is now over 17,000 barrels per day and growing quickly. Meanwhile, in the area surrounding Lloydminster, Sask., heavy oil producers remain the backbone of the province’s oil industry, leveraging technologies like horizontal drilling and thermal recovery to keep the oil and cash flowing. After bottoming out at 184,000 barrels per day, Saskatchewan heavy oil production has rebounded to 191,000 barrels per day last year. As explorers gain greater understanding of Saskatchewan’s massive oil-in-place resource and leverage new technologies to
access that oil, expect production to climb across the western part of the province.
THE VIKING The Viking Formation is one of Saskatchewan’s legacy oilfields. It was recognized as an oil-bearing formation in 1918. Production began in earnest in the 1950s, with nearly 8,000 vertical wells drilled into the upper zone of the formation over the next 60 years. By 2008, about 6,000 of those vertical oil wells were producing about 9,000 barrels per day. Today’s new wave of exploration is targeting the lower, thicker Viking sands where an estimated four billion barrels are in play. Since 2008, 1,800 horizontal wells have been drilled into the formation, adding almost 20,000 barrels per day of incremental production. Penn West Exploration is one of the pioneers in developing the Viking play on both sides of the Alberta-Saskatchewan border. Mark Fitzgerald, senior vice-president of development for Penn West, says the company will probably drill between 55 and 60 wells in that formation by year-end, as production from the Viking is proving quite profitable. “Avon Hills, which is generally in the central part of the Viking, we’ll see three-month average rates between 60 and 80 barrels a day,” he says. At Dodsland, Sask., three-month initial production rates are 60 –70 barrels per day. OIL & GAS INQUIRER • SEPTEMBER 2013
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Fort McMurray
AB
Fort McMurray
SK
BC
MB
Grande Prairie
AB
SK
Edmonton
Edmonton
Saskatoon
Saskatoon
Calgary
Calgary Medicine Hat
Medicine Hat
Regina
Lethbridge
The Viking play along the Alberta border
U.S. Flares from well testing dot the Saskatchewan skyline.
Penn West is the big player in the Viking in terms of acreage, according to Fitzgerald. He said his company believes new techniques such as hydraulic fracturing are increasing the likability of this formation for his and other companies. “We very consistently characterize the Viking as one of the four core resource plays that we have,” he says. “It has great netbacks, it’s very economic, it’s highly predictable for us and it is an area that we anticipate we will continue to develop and continue to drill.” Fitzgerald says his company has been involved in the Viking for several years, growing that investment with the Petrofund Energy Trust merger in 2006 and the acquisition of Canetic Resources Trust in 2008. “We’ve been long-time holders in the Viking, for sure,” he says, adding that recent changes in completion techniques with longrange horizontal wells and multistage fracturing greatly improve the viability of the formation. “The economics and the deliverability and, I guess ultimately, the estimated ultimate recovery associated per well has changed dramatically, and of course that has changed the attractiveness and the economics across the whole play,” Fitzgerald says, adding that waterfloods are definitely proving to be an important part of the Viking’s continued evolution. “We’ve seen people move from a maximum of eight wells per section to testing 16 wells per section, which again is increasing potential recoveries across the area,” he adds. Along with increasing its number of wells per section, Fitzgerald says, Penn West also sees further development of waterflooding as critical for the company’s long-term growth in the formation. In the Viking, Fitzgerald says, there is always the opportunity for greater production efficiency, which has been happening more and more with such techniques as high use of the immiscible production nitrogen in the company’s completion procedures. He says it might cost a bit more, but it also results in more output from the wells. “I also think there is a real opportunity over time to optimize just the entire producing area of the Viking. It is lower pressure, it’s sensitive to gathering system pressures and back pressures on the wells, and I think for us part of the opportunity continues to be in reducing pressures across the system in order to maximize the ability of these wells to deliver,” he adds. While other formations along the western portion of Saskatchewan tend to produce a bit heavier oil, Fitzgerald says the Viking is a bit lighter, which results in higher netbacks, making it “the play to be in” for that region. SEPTEMBER 2013 • OIL & GAS INQUIRER
Regina
Lethbridge
U.S.
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MB
The Lower Shaunavon play
Fitzgerald says it is interesting to note the recent discovery of higher oil amounts in Penn West’s Alberta Viking assets, as that is historically a gassier part of the play when compared to the company’s Saskatchewan Viking assets. “We’ve seen an emergence on the western side of the Viking in our lands where we can get 50–60 per cent oil cuts…which we think has unlocked another evolution and another opportunity for development across a pretty significant land position. “Granted, that is going to require a little bit of help from gas before it starts to compete with the balance of our light oil portfolio, but it is an interesting development area for us,” he says, adding that Penn West’s Viking operations are about 60 per cent on the Saskatchewan side of the play and 40 per cent on the Alberta side.
LOWER SHAUNAVON Production from Saskatchewan’s Lower Shaunavon Formation has soared to 17,350 barrels per day from 820 wells, up from only about 200 barrels per day from 20 vertical wells in 2007. Crescent Point Energy Corp. is the dominant explorer in the play. Neil Smith, chief operating officer for Crescent Point, says the company identified the opportunity in the Shaunavon after first developing their horizontal drilling and multistage fracturing chops in the Bakken. “We knew it was there with lower permeability, medium gravity and lower recovery…big oil in place,” he explains. “So, we initially got in and bought four or five sections of land, tried our techniques and said, ‘Yep, with a little bit of modification this is going to work.’” Smith says Crescent Point now owns about 90 per cent of an oil play with about 4.2 billion barrels in place. It currently has 10 major oil opportunities, eight of which were discovered since 2005 with techniques developed in the Bakken. “It’s been extremely important, the advances in fracture stimulating horizontal oil wells. We really have built a 90 per cent oil-weighted, unique company based on that technology,” he notes. The company plans to drill up to 95 net wells in the Shaunavon area in 2013, including 19 Lower Shaunavon infill wells spaced at eight wells per section and two at 16 wells per section. Four Upper Shaunavon infill wells are also planned at eight wells per section. In 2013, Crescent Point expects to spend approximately $315 million in the area, including expenditures on land, seismic and facilities. It is also launching an unitized waterflood in the play, receiving approval of the Leitchville North Shaunavon Voluntary Unit #1 early this year. The approval will allow Crescent Point to implement the Lower Shaunavon waterflood across a larger area. This waterflood is
Photo: Pipeline News
BC
Grande Prairie
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expected to assist in reducing declines in the play and add incremental reserves over time. Water is currently being injected into 31 converted wells in both the Lower and Upper Shaunavon unconventional zones and several of the offset producers have begun to show positive response through shallowing declines and increased production. Crescent Point is also testing new completion techniques in the play to capture resources in water-saturated areas. Acid fracture stimulation techniques are planned for seven wells in higher water-saturation areas in 2013. To date, five wells have been completed with encouraging initial results, says the company. Cenovus Energy Inc. was the other pioneer in the Shaunavon. Cenovus, however, sold its acreage in the play to Surge Energy in July for around $250 million. Surge, which is looking to become a dividend-paying producer, says its acreage has more than 250 million barrels of oil in place with a recovery factor of 1.5 per cent. Surge estimates more than 264 net lower-risk development-drilling locations and full unbooked waterflood upside potential.
HEAVY OIL Heavy oil surrounding Lloydminster has long been the bread and butter of the Saskatchewan oil industry. Production peaked in 2007 at 221,000 barrels per day and declined to 184,000 barrels per day by 2010 after prices crashed in 2008 and investment dollars declined. Production is now once again on the upswing, driven by the application of thermal technologies, horizontal drilling and, coming soon, chemical floods.
Husky Energy Inc. has been driving thermal development, increasing steam assisted heavy oil production from 15,000 barrels per day to 37,000 barrels per day in the last seven years. Husky is forecasting 55,000 barrels per day of thermal production by 2017. “Thermal recovery for us is already big and is getting bigger,” company president and chief executive officer Asim Ghosh said at Husky’s investor day late last year. “When you look at the overall heavy oil portfolio we have a very, very large resource in place, and over the last 70 years somewhere of the order of magnitude of 800 million barrels have been extracted from our Lloyd heavy oil complex. And with our new focus, with the technology already in place, we have great confidence we can recover that amount again in the future.” Husky is also using horizontal wells to access more heavy oil in western Saskatchewan. “With horizontal wells we are going after thinner reservoirs that were not previously considered commercial,” said Husky chief operating officer Robert Peabody. “New technologies have allowed us to grow production to over 8,000 barrels per day and we are on target to hit 16,000 barrels per day by 2017.” Polymer flooding is also being tested as a means to get to more heavy oil in Saskatchewan. Canadian Natural Resources Limited (CNRL) has pilots underway at Epping, Lone Rock and Salt Lake. In the areas where CNRL has polymer flood operations, its independent reserves evaluator now estimates ultimate recoveries will average 25 per cent.
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OIL & GAS INQUIRER • SEPTEMBER 2013
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advertisers' index Allmand Bros Inc . . . . . . . . . . . . . . . . . . . . . . . . . 34
Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . 66
Pelican Products ULC . . . . . . . . . . . . . . . . . . . . . 46
Annugas Compression Consulting Ltd . . . . . . . . 36
Edey Consulting Services Ltd . . . . . . . . . . . . . . . 58
Baker Hughes Canada Company . . inside front cover
Edmonton Exchanger & Manufacturing Ltd . . . . 27
Bear Slashing Inc . . . . . . . . . . . . . . inside back cover
Expertec Van Systems Inc . . . . . . . . . . . . . . . . . . 32
Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 59
FlexSteel Pipeline Technologies Inc . . . . . . . . . . .12
Brother’s Specialized Coating Systems Ltd . . . . 38
Ford Motor Co Canada . . . . . . . . . . . . . . . . . . . . . 42
Pembina Controls Inc . . . . . . . . . . . . . . . . . . . . . . 38 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 40 Platinum Energy Services Corp . . . . . . . . . . . . . . 23 Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . 17 PTI Group Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30 Pumps & Pressure Inc . . . . . . . . . . . . . . . . . .41 & 47 Schneider Electric . . . . . . . . . . . . . . . . . . . . . . . . . 4
Canadian Enviro-Tub Inc . . . . . . . . . . . . . . . . . . . .41
General Motors of Canada Ltd . . . . . . . . . . . . . . . 8
Canadian Standards Association . . . . . . . . . . . . .10
Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . . 45
CG Industrial Specialties Ltd. . . . . . . . . . . . . . . . . 6
Manulift EMI Ltee . . . . . . . . . . . . . . . . . . . . . . . . 33
Chemineer, Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
MaXfield Inc . . . . . . . . . . . . . . . outside back cover
Chevron Delo . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Meridian Manufacturing . . . . . . . . . . . . . . . . . . . 29
City of Fort St. John . . . . . . . . . . . . . . . . . . . . . . . 28
MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 59
ClearStream Energy Holdings . . . . . . . . . . . . . . . 62
MRC Global Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Site Energy Services . . . . . . . . . . . . . . . . . . . . . . .21 Skyway Canada Limited . . . . . . . . . . . . . . . . . . . 56 Sprung Structures Ltd . . . . . . . . . . . . . . . . . . . . . . 7 TOG Systems-Telecom Oil + Gas . . . . . . . . . . . . . . 15 TransGas Limited . . . . . . . . . . . . . . . . . . . . . . . . . 53
CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
NC Services Group Ltd . . . . . . . . . . . . . . . . . . . . 40
Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
NETZSCH Canada Inc . . . . . . . . . . . . . . . . . . . . . 48
dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Nexus Exhibits Ltd . . . . . . . . . . . . . . . . . . . . . . . 44
Do All Industries Ltd . . . . . . . . . . . . . . . . . . . . . . 60
Northgate Industries Ltd . . . . . . . . . . . . . . . . . . 48
West Country Oilfield Services & Weed Control . . 46
Dragon Products Ltd . . . . . . . . . . . . . . . . . . . . . . .61
Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 58
Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
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Tundra Process Solutions Ltd . . . . . . . . . . . 24 & 50 U F A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11
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