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CONTENTS
DECEMBER.
in the news
9
BC’s #1 Destination
Big four U.S. unconventional plays on growth curve
regional news
13
British Columbia
LNG project uncertainty remains despite B.C. tax announcement
15
Northwestern Alberta
Delphi unravelling East Bigstone Montney
17
Northeastern Alberta
Husky perseveres at Tucker
21
Central Alberta
Upgrader/refinery would be profitable, says AFL
25
t for Salmon, Halibu and Albacore Tuna
Southern Alberta
Zargon to spend $46 million in 2015
29
Saskatchewan
Crescent Point busiest driller in first nine months of 2014
features Cover Feature
30 33 36
Up in the air Lower oil prices and flat gas markets stall industry momentum, but optimism remains
every issue
6 38
Stats at a Glance Political Cartoon
Cover design: Peter Markiw
The next big thing Emerging plays promise future growth across the WCSB
Cost busters Technology making SAGD more price proof
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3
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Editor’s Note Vol. 26 No. 12 editorial Editor
Darrell Stonehouse | dstonehouse@junewarren-nickles.com Contributing writers
Lynda Harrison, Carter Haydu, Pat Roche, Elsie Ross, Paul Wells
Cost cutting coming to forefront
Editorial ASSISTANCE MANAGER
Tracey Comeau | tcomeau@junewarren-nickles.com Editorial Assistance
Sarah Miller, Sarah Munn Creative CREATIVE SERVICES manager
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com
Oil and gas producers are making less money
around the return on their capital investments,”
CREATIVE LEAD
now than 14 years ago, and that means an effort
said Lysle Brinker, director of company research
to rein in costs has begun, according to research
at IHS Energy.
Cathlene Ozubko | cozubko@junewarren-nickles.com production coordinator
Janelle Johnson | jjohnson@junewarren-nickles.com Graphic Designer
Peter Markiw
Creative Services
Linnea Lapp Sales
SENIOR ACCOUNT EXECUTIVES
by information and insight provider IHS Energy. And with oil prices down by 25 per cent from June, that pressure is likely to intensify, according to producers. Despite stronger oil prices, corporate
Operators in western Canada expect service prices to decline in 2015 just as oil prices have declined. “We are determined to bring down service costs heading into the New Year’s program,”
Nick Drinkwater, Tony Poblete, Diana Signorile
returns on average capital employed (ROACE)
Tony Marino, president and chief operating offi-
SALES
are lower than in 2001, when oil prices were
cer of Vermilion Energy, said in his third-quarter
less than $30 per bbl, according to Nicholas D.
report to analysts. “I think it’s something we
Cacchione, director at IHS Energy and a lead
can achieve either with or without a big drop in
researcher on cost and energy company per-
industry activity. And eventually, there probably
Lorraine Ostapovich | atc@junewarren-nickles.com
formance. Cacchione looked at results from 80
will be a drop in activity. We’ll have to see how
Directors
producers in making his assessment.
all the capital announcements are that will come
Rhonda Helmeczi, Mike Ivanik, Nicole Kiefuik, Gerry Mayer, James Pearce, Blair Van Camp For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—Magazines
CEO
Bill Whitelaw | bwhitelaw@junewarren-nickles.com
“Collectively, these companies averaged an
out over the next couple of months. But probably
11 per cent ROACE in 2012 and 8.6 per cent in
activity will drop. And if it isn’t significant in Q1,
Rob Pentney | rpentney@junewarren-nickles.com
2013, both of which are weaker than the ROACE
I bet it will be significant later in the year.”
director of sales & Marketing
achieved in 2001, when the WTI crude oil price
president
Maurya Sokolon | msokolon@junewarren-nickles.com director of events & conferences
Ian MacGillivray | imacgillivray@junewarren-nickles.com director of the daily oil bulletin
Stephen Marsters | smarsters@junewarren-nickles.com director of digital strategies
Gord Lindenberg | glindenberg@junewarren-nickles.com
Crescent Point Energy, one of the top
hovered at just under $27 per bbl. The WTI
three busiest drillers in the Western Canadian
crude oil price averaged $94 per bbl in 2012 and
Sedimentary Basin, is also expecting prices to
$98 per bbl in 2013,” he said.
come down.
“The culprit is cost escalation,” he added.
“In these environments—and we’ve been
“While returns have increased in recent
through several of these over the last 13, 14
Chaz Osburn | cosburn@junewarren-nickles.com
years, costs have accelerated at a rate that has
years—we’ll see costs come down because of
director of production
squeezed margins. The more than $60-per-bbl
lower day rates,” Crescent Point president and
increase in global oil prices since 2002 has been
chief executive officer Scott Saxberg told share-
offset by significantly higher costs, and to a
holders. “We’re already talking to our service
lesser degree, weaker U.S. natural gas prices.
providers on that, so there’s an expectation I
Margins have basically been frozen.”
think into next year that we’ll see lower costs.”
director of content
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Lifting costs have more than quadrupled since 2000 to greater than $21 per bbl. Finding
Service providers, put on your poker faces. It’s going to be that kind of year.
and developing costs have followed a similar trajectory, reaching nearly $22 per boe in 2013. “As a result of this ongoing cost pressure, companies are increasingly laser-focused on cost containment and exercising greater discipline
Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
N EXT I S S U E January 2015 Who drilled the most wells in 2014, and what are their drilling plans for 2015? Plus a look at growth in the Deep Basin.
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 • DECEMBER 2014
5
FAST NUMBERS
10,830
10,100
PSAC’s estimated 2014 well count.
PSAC’s estimated 2015 well count.
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
T O TA L
MONTH
OIL
GAS
D RY
SERVICE
T O TA L
Nov
Nov
,
Dec
Dec
Jan
Jan
Feb
Feb
,
Mar
Mar
,
Apr
May
Apr
May
Jun
Jun
Jul
Jul
Aug
Aug
Sep
Sep
,
Oct
Oct
,
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
Nov
Nov
Dec
Dec
Jan
Jan
Feb
Feb
Mar
Apr
Mar
May
Apr
Jun
May
Jul
Jun
Aug
Jul
Sep
Aug
Oct
Sep
Oct
*Year-to-date
6
OTHER
DECEMBER 2014 • OIL & GAS INQUIRER
OTHER
TOTAL
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, November 12, 2014 Source: Rig Locator
Alberta, October 2014 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
AC T I V E (Per cent of total)
Western Canada Alberta
OIL WELLS
Alberta
GAS WELLS
Oct
Oct
Oct
Oct
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
%
Southern Alberta
%
TOTAL
WC TOTAL
Top Active Drillers in Canada
Drilling Activity: CBM & Bitumen
Western Canada, November 12, 2014 Source: Rig Locator
Alberta, October 2014 Source: Daily Oil Bulletin
O P E R AT O R
ACTIVE RIGS
DEV
C OA L B E D M E T H A N E
EXP
Canadian Natural Resources Limited
Crescent Point Energy Corp.
Tourmaline Oil Corp.
Progress Energy Canada Ltd.
Husky Energy Inc.
Encana Corporation
Apache Canada Ltd.
ConocoPhillips Canada
Seven Generations Energy Ltd.
Peyto Exploration & Development Corp.
Alberta
BITUMEN WELLS
Oct
Oct
Northwestern Alberta
Northeastern Alberta
Central Alberta
Southern Alberta
TOTAL
Oct
Oct
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IN THE
NEWS Issues affecting Canada’s E&P industry
Big four U.S. unconventional plays on growth curve By Pat Roche
The big four by the numbers Play
Average well EUR
Average well cost
Average break-even price
Eagle Ford
, boe
$. million
$./boe
Bakken
, boe
$. million
$./boe
. Bcf equivalent
$. million
$./mcf
, boe
$. million
$./boe
Marcellus Permian
Source: Hart Energy
Total production from unconventional plays in the U.S. will continue to grow until at least the early 2020s, a Calgary conference was told in October. The highest growth rate is forecast for the Permian Basin, which is in the very early stages of development as an unconventional play, said Peggy Williams, editorial director at Hart Energy, the U.S. oil and gas publisher. Hart Energy expects Permian Basin output will rise by 145 per cent from current levels before flattening out in the late 2020s. Williams said that more than twice as many rigs are working in the Permian as in either of the other big U.S. plays. Overall, the company expects U.S. production of crude oil and condensate from all unconventional plays to reach about five million bbls/d by 2023, up from more than three million bbls/d last year. Also, natural gas liquids production from the same plays is expected to average around 2.2 million bbls/d through the 2020s. “One thing we found in the 10 short years when unconventionals really began to be developed in the U.S. is that the big plays keep getting bigger,” Williams told the 2014 Unconventional Resources Conference in Calgary, which was planned and operated by the Society of Petroleum
Engineers and the Canadian Society for Unconventional Resources. “The well performance continues to improve in the Eagle Ford, the Bakken, in the Permian Basin and the Marcellus. We think a key reason is that the laterals are getting longer and the completions are becoming more effective,” Williams said. The Hart Energy executive reviewed the current status and remaining potential of the four big U.S. unconventional plays— the Eagle Ford, the Permian, the Bakken and the Marcellus—none of which is expected to reach peak output before 2020. She said activity is declining in older unconventional plays such as the Haynesville and the Barnett. But while rig counts are flat in the Eagle Ford, the Marcellus and the Bakken, well counts are still rising, she said, citing improved rig efficiency and the increasing number of horizontal wells being drilled from pads. The Eagle Ford has about 10,200 wells that are producing or are capable of production. Of the four plays, the Eagle Ford has the largest sweet spot. “The good productive area of the Eagle Ford appears to encompass seven million acres,” said Williams.
Because the Eagle Ford extends from the dry gas window into the black oil window, oil gravity varies widely across the play, ranging between 37 and 57 degrees API. The average gravity is 47 degrees. Williams listed the three top horizontal drillers in the Eagle Ford as EOG Resources Inc. (1,433 wells drilled), Chesapeake Energy Corporation (968 wells) and Anadarko Petroleum Corporation (890 wells). In the Eagle Ford the average cost per frac stage is about US$97,000. Slickwater is the main completion technique. Operators are pumping about 400,000 pounds of sand per frac stage, or about 11 million pounds per well. “This play by itself produces more than some OPEC countries,” said Williams. “It’s just astonishing how much oil and gas and condensate is coming from the Eagle Ford.” Hart Energy expects Eagle Ford production to average somewhere below two million boe/d this year and to grow by 31 per cent by 2020. “So the play, although it is already densely drilled and already has a lot of wells, still has fairly significant growth potential,” she noted. Williams said the Bakken can also grow. “It’s not quite as attractive as the Eagle Ford in break-even price, but the Bakken crude is very high quality and very uniform,” Williams said. “It is the most homogeneous product of any of the plays.” The average grade of the oil is 44 degrees API and the range is between 39 and 45 degrees. More than 8,700 wells have been completed in the U.S. Bakken since 2000. The average cost per frac stage is US$87,500. Williams said market intelligence surveys have found operators are shifting to cross-link gel. Plug-and-perf is the most common completion technique. Sand remains the most common proppant in the Bakken, but the play has the highest use of ceramics, accounting for about 25 per cent of the completions, Williams said. OIL & GAS INQUIRER • DECEMBER 2014
9
In The News
According to the Hart Energy presentation, the top three Bakken operators, based on producing wells completed, are Continental Resources, Inc. (1,152 wells), Hess Corporation (770 wells) and Whiting Petroleum Corporation (768 wells). And while the Bakken well count is flattening out, production is not. “The activity is levelling off in the Bakken, and operators are focusing on downspacing right now and improving completions,” Williams said. Bakken output is forecast to grow by 25 per cent by 2020 from current levels. “Overall, it’s not going to be as big as the Eagle Ford, but it’s still an extremely substantial amount of production,” she said. The Marcellus gas play in the northeastern U.S. also has lots of growth potential, said Williams.
“ We’re seeing pads that have, for instance, 10 Marcellus wells and eight Utica wells.” — Peggy Williams, editorial director at Hart Energy
“Even at today’s very low natural gas prices, people can still make money in the Marcellus,” Williams noted. “While they’re not going as strongly as in some other areas, the Marcellus activity is continuing on at a steady pace.” Slickwater fracs are the most popular completion, and plug-and-perf is the most common technique. The average cost per stage is US$92,000. The Marcellus has more than 5,500 producing horizontal wells, grouped mainly in two major areas. Northeastern Pennsylvania is the dry gas area. The wet gas portion of the Marcellus is in southwestern Pennsylvania and also extends into Ohio and West Virginia. B e c au s e Wi l l i a m s ’ pr e s e nt at ion focused on the four big unconventional U.S. plays, the statistics she presented don’t include the Utica shale, which overlies the Marcellus. “But the Utica, particularly in Ohio, is beginning to yield some massive dry gas wells. We have reports of wells in excess of 40 MMcf/d in the Utica,” she said. “Some operators are just in that area where they have both Utica and 10
DECEMBER 2014 • OIL & GAS INQUIRER
Marcellus. And we’re seeing pads that have, for instance, 10 Marcellus wells and eight Utica wells.” Because of the longer Marcellus laterals and the Utica growth, oilfield service demand is fairly tight in the Appalachian region, she noted. The top three Marcellus operators are Chesapeake, with 850 wells completed, Range Resources Corporation, with 688, and Talisman Energy Inc., with 388. Hart Energy expects Marcellus production to grow to nearly 25 bcf/d by 2027—a whopping 58 per cent increase from 2014. And that doesn’t include the Utica. While the Marcellus forecast includes some natural gas liquids, “it’s not a tremendous amount—it’s really more of a dry gas play,” Williams said. The Permian Basin is still in the early stages of development. “This is by far the most active U.S. basin with 500-plus rigs working in it at present,” Williams said of the Permian. “And it also has the most potential for future growth.” More than 3,100 horizontal producing wells have been completed in the Permian since 2010. “Crude gravities have a bit wider range than the Bakken, but they’re still in that very good area—between 39 degrees and 46 degrees,” she noted. T he Permian has multiple objectives. The primary horizontal target is the Wolfcamp, but there’s also a lot of interest in the Spraberry Trend, Bone Spring and Clear Fork, Williams said. The top three drillers of horizontal wells in the Wolfcamp are EOG, with 205 wells completed, Devon Energ y Corporation, with 183, and EP Energy Corporation, with 148. The average cost per frac stage ranges bet ween US$81,000 and US$91,000. Slickwater is no longer the dominant frac; companies are experimenting with hybrids and cross-linked gels, said Williams. In the Permian, which until recently had a relatively low number of horizontal well pads, multi-well pads are becoming commonplace, she said. Williams displayed a bar chart showing 2014 Permian production at roughly 800,000–900,000 boe/d. Forecasting a 145 per cent increase, Hart Energy expects Permian unconventional output to hit more than two million boe/d by the time it peaks in 2030.
U.S. could be energy independent by 2025, says Wood Mackenzie The U.S. will achieve energy independence by 2025, which will mark the first time since 1952 that the U.S. will export more energy than it imports, according to an integrated outlook by Wood Mackenzie’s Global Trends Service. The outlook identifies higher production and lower demand as the forces driving U.S. energy independence. “A country can achieve energy independence through two channels: it can either produce more or consume less, and the U.S. is doing both,” said James Brick, Wood Mackenzie senior analyst. “Over the last seven years, the U.S. has added three million bbls/d of tight oil and 27.5 bcf/d of shale gas to the global energy mix, a spectacular 42 per cent increase in U.S. oil and gas production.” Meanwhile, oil demand is decreasing, primarily due to efficiency gains in the transport sector. Wood Mackenzie says the uncertainties facing the U.S. energy market fall into two broad categories: those that make it more likely the country will achieve energy independence before 2025, and those that will delay it. The key uncertainties that can speed up U.S. energy independence include a lifting of the U.S. crude oil export ban, higher tight oil production and lower demand in the transport sector. If t he U.S. were to l i f t it s c r ude oil export ban, Wood Mackenzie says U.S. producers would be able to access higher-priced international markets. If an end to the export ban resulted in an additional US$5 per bbl for producers, the consultant estimates that production could increase by 350,000–450,000 bbls/d, requiring an investment of about US$5 billion. “Not all companies would actually benefit from lifting the crude oil export ban,” according to Brick. “It’s likely that upstream producers would generally benefit the most via increased volumes and higher prices. Oilfield service companies and rig manufacturers would also benefit from the additional investment.”
In The News
Even if the crude oil export ban is not lifted, the U.S. could produce more tight oil than is currently anticipated. “Tight oil and shale gas plays are still evolving and there are many opportunities for the application of new production techniques,” said Brick. “Production could be up to three million bbls/d higher than our view of 10.3 million bbls/d by 2030 as a result of the application of technologies such as enhanced oil recovery [EOR] and refracturing. EOR techniques currently being tested are especially promising, and early indicators suggest recovery rates could double.” W hile Wood Mackenzie forecasts that the U.S. vehicle fleet would become over 40 per cent more efficient by 2030, there is still potential for a more rapid improvement in efficiency or for a more pronounced shift to cars away from less efficient light trucks and SUVs. Any improvement in vehicle efficiency or fewer vehicle miles travelled per capita would reduce U.S. oil demand and, consequently, net oil imports. T he t h ree key uncer ta i nt ies t hat would stall U.S. energy independence i nc lude de l ay s i n de v e lopi n g c r itical expor t facilities, env ironmental regulations and energ y policies that would encourage more gas to be used i n t he p owe r s e c tor, ac c or d i n g to Wood Mackenzie. “If local or national regulation that discourages fracturing is passed, oil and gas production will be lower,” said Brick. “A lso, if U.S. energ y policy is enacted to reduce carbon dioxide emissions, it is likely gas used by the power sector will increase.” While the investments driving the U.S. toward energy independence will have substantial direct and indirect benefits for the U.S. economy, any direct benefits from energy independence in itself are more muted, Wood Mackenzie concluded. Furthermore, U.S. energ y i n de p e n de n c e w i l l n o t i s ol at e it s energ y ma rket s f rom i nter nat iona l risk, but it will change how these risks are considered. “Irrespective of the timing of independence, the U.S. has started its transformation from energy consuming giant to prominent exporter,” said Brick. “With this role shift comes obvious economic benefits but also shifting risks and new responsibilities.”
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BRITISH COLUMBIA WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
▼
▲
▼
Source: Daily Oil Bulletin
B.C. British Columbia
LNG project uncertainty remains despite B.C. tax announcement By Carter Haydu, Elsie Ross and Paul Wells
Although the B.C. government’s announcement that it is prepared to reduce the income tax for new LNG projects will provide cost certainty, it is no guarantee that new projects will proceed, say analysts and project proponents. “I think it’s a move in the right direction but I don’t think it’s a needle-mover,” said Dirk Lever, managing director of institutional equity research with AltaCorp Capital Inc. The government can say it recognized company concerns by reducing the rate to 3.5 per cent from seven per cent. However, West Coast LNG project proposals Project Kitimat LNG BC LNG Export Co-op LNG Canada Pacific Northwest LNG Aurora LNG Prince Rupert LNG Triton LNG ExxonMobil/ Imperial Oil
Capacity (Bcf/d) . . . Not released .
Woodfibre LNG
.
Woodside LNG
.
WesPac LNG
.
Steelhead LNG
Discovery LNG
. Source: CAPP
that doesn’t really matter because it’s not writing the cheques for the project and right now it’s a buyer’s—not a seller’s— market, he said. Canadian West Coast LNG projects also face competition from proposed U.S. West Coast projects such as Verasen Inc.’s Jordan Cove, Lever suggested. While LNG project proponents have opposed the proposed LNG tax, he said it was never clear if they had a problem with the rate or with the structure of the tax and “to me that has not yet been finalized.” With the new LNG provincial income tax, a plant operator would pay tax from the beginning, but it most likely would not be paying federal tax because the capital cost allowance (CCA) would shield capital expenditures. An LNG operator would fi le two forms of tax, said Lever. One form is based on net operating income that appears to be net income before tax depreciation, so normal depreciation would be added back in and the project would be taxed at 1.5 per cent of that. “And then you can deduct your capital cost allowance in B.C., which is up to the amount of your operating income, so until you have got cost recovery, it is zero.” With the start-up of a facility, the initial tax rate would be 3.5 per cent, increasing to five per cent, excluding credit for the 1.5 per cent already paid, said Lever. The provincial government’s announcement that it wants to encourage greener LNG projects through reduced emissions could also be a factor, he said. “They want it to be the cleanest running, and that normally means higher capital costs, and if you don’t have the cleanest you pay penalties, so I’m sure the guys are going
to have to go back and recalculate how much it will cost if they meet it and how much it will cost if they don’t meet it, so there will be determinations there,” said Lever. “They will be looking at what is their cost on the federal method and what is their cost under the B.C. method, and we still have not heard from the feds.” Earlier this year, a number of LNG proponents went to Ottawa to push for a higher depreciation rate on some of their incurred capital costs, but so far there has been no response from the federal government. “They pushed B.C. down from seven to 3.5 per cent until 2037, but they do know they are going to have to pay tax up front,” said Lever. “On the federal side they are trying to push for a higher rate, i.e. they are tax-free longer to help offset the impact of British Columbia’s on a combined basis, so there is going to be a lot of number crunching to be done.” Bill Gwozd, senior vice-president of gas services at Ziff Energy Group, a division of HSB Solomon Associates LLC, suggested that B.C. Premier Christy Clark is taking a lesson from the Progressive Conservative Alberta government’s approach to kickstarting oilsands development. While the initial LNG tax is low, the government is counting on higher revenues later on when the projects are paid out, he said. In addition, it should benefit from the increased natural gas activity that will be required to provide gas for the LNG export terminals. Gwozd also noted that while Clark could have provided different tax rates depending upon the size of the facility, she opted not to do so. “Premier Christy Clark is trying to make it simple, easy to number crunch for the economists,” he said. However, the constant rate can be detrimental for a very small facility whereas a large facility has economies of scale, and that needs to be factored in, he said. OIL & GAS INQUIRER • DECEMBER 2014
13
British Columbia
While the industry may resist the imposition of an LNG tax, “overall, B.C. needs to collect money for social programs and the tax system on LNG is a mechanism,” according to Gwozd. “At least there is certainty with the numbers.” Gillian Robinson, spokesperson for Chevron Corporation, which is proposing the Kitimat LNG project, said the company is reviewing the government’s announcement and all the economics of the project will be assessed in their entirety. “That means all elements of the government’s fiscal take, the project cost, the product price and the other global LNG projects that are being developed, because it is a global competition,” she said. Basically, Chevron is looking at all the costs of the project and whether it is competitive globally, she said. “A clear and stable and competitive fiscal framework will be a critical consideration.” Domenico Baruffaldi, national energy tax leader for PwC, said it appears that the B.C. government did listen over the summer to the concerns raised by the LNG
proponents, because it basically decided to reduce the tax that it had introduced on a preliminary basis some months ago. The announcement “is a move forward in the right direction,” he said. However, “before thinking about taxing a new industry you need to make sure the industry is establishing well,” he said. “That is the big issue right now.” Because the LNG industry is so capital intensive, the first step is making sure companies are welcome and subject to a tax framework and a logistical framework that will help them to establish, according to Baruffaldi. The B.C. government, he said, has considered the significant capital that is required to establish the industry. “So there is an acknowledgement of a number of things that the proponents have put forward, and I think that is good from the government perspective.” For Baruff aldi, one of the biggest elements—aside from the reduction in the tax rate—is the fact that the rates are reduced for a 20-year period, which he said is an important step forward.
“It really gives the proponents the ability to have a low tax environment for 20 years. Typically, these large investors want to have at least a 20-year time frame to really amortize their initial investment.” While he is pleased about the government’s decision, “I’m pretty sure that the proponents will probably not all be happy because ultimately there is still a tax.” Bar uf faldi also agreed that while t he r e c lea rly i s mor e ce r t a i nt y, he thinks the decisions by the proponents depend on a number of factors, not only the tax regime. “So my personal view is I believe there is going to be clearly a decision taken in the short term—that means within six to 12 months. There’s going to be someone who is going to come up and make a call about their project.” There’s also likely to still be some negotiation between the proponents and the government because of certain elements of legislation that require a bit more clarity, he suggested.
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14
DECEMBER 2014 • OIL & GAS INQUIRER
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NORTHWESTERN ALBERTA WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
▼
▲
▲
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Delphi unravelling East Bigstone Montney Delphi Energy Corp. continues to be active on its East Bigstone Montney acreage and is encouraged by the results of its 2014 drilling program to date. The company has successfully completed its sixth Montney horizontal well of 2014 at 03-26-059-23W5 in East Bigstone. The 03-26 well (100 per cent working interest) was drilled to a total depth of 5,593 metres with a horizontal lateral length of 2,601 metres, and it was stimulated with a 30-stage slickwater hybrid completion. The well is currently being equipped to produce through the company’s 100 per cent–owned compression and dehydration facility and is expected to be on stream in the next two weeks. Delphi has also finished drilling its seventh Montney well of 2014 at 13-23060-23W5. In 25 days, the 13-23 well (100 per cent working interest) was drilled to a total
Delphi’s Montney wells are achieving average firstyear production rates of 843 boe/d.
depth of 4,995 metres with a horizontal lateral length of 2,161 metres. The 13-23 well will be the 12th well in East Bigstone completed using a 30-stage slickwater hybrid fracture stimulation technique. The company has now started drilling operations at its eighth Montney well of 2014 at 16-27-060-23W5 (87.5 per cent working interest). Since February 2013, the company has brought on stream 10 Montney horizontal wells completed with the 30-stage slickwater hybrid fracture stimulation technique at East Bigstone. Three of the wells have achieved payout with another three expected to reach payout by Dec. 31, 2014. At payout, the average production rate of the three wells was approximately 730 boe/d, generating cash operating income (revenues less royalties, operating costs and transportation) of approximately $2 million per month from the three wells. During September 2014, corporate production averaged approximately 11,000 boe/d with production from the Montney Formation at East Bigstone averaging approximately 7,700 boe/d, an elevenfold increase from 700 boe/d in February 2013. Over that same time period, the company spent approximately $143 million on drilling, completions and infrastructure at East Bigstone. The cash operating income generated from the Montney production for September was approximately $6.2 million, equivalent to an annual run rate of approximately $75 million. Production data gathered over the past 20 months continues to validate the robust economics of Delphi’s East Bigstone Montney
project, with variability in individual well performance being observed as follows. Five of the 10 wells with initial natural gas production rates at or above the type curve of seven MMcf/d are observed to have both field condensate yields (40 bbls per MMcf of raw natural gas) and decline rates consistent with the type curve model. The wells at 10-27-060-23W5, which achieved payout in 14 months, 15-300 6 0 -22W5, wh ic h ac h ieved payout in six months, and 13-30-060-22W5, which is expected to have a payout of eight months, are three examples of this observed performance. The remaining five wells with initial natural gas production rates lower than the type curve generally have higher field condensate yields, ranging from 50 to 90 bbls per MMcf of raw natural gas and initial declines less than that of the type curve. The wells at 15-24-060-23W5, which achieved payout in nine months, and 15-21-060-23W5, which is expected to have a payout of 12 months, are two examples of this observed performance. The average production rate of the 10 wells continues to match the type curve’s profi le of a 180-day average production rate of 1,083 boe/d and the 365-day average production rate of 843 boe/d. The company has realized significant gains in spud-to-spud cycle times of its horizontal Montney drilling program at Bigstone. The accelerated drilling times have allowed Delphi to increase its drilling activity in 2014 from six to eight horizontal Montney wells. On-stream dates for these two additional wells will be at the end of 2014 or early in 2015 and will not materially impact the company’s production guidance for 2014. Given the strong Montney production performance, the company remains on track to meet its 2014 annual production guidance of 10,000–10,500 boe/d and exit production forecast of 11,500–12,000 boe/d. OIL & GAS INQUIRER • DECEMBER 2014
15
Northwestern Alberta
Strategic Oil & Gas Ltd. continues Muskeg success Strategic Oil & Gas Ltd. reported record production levels in October, driven by the company’s summer Muskeg horizontal drilling program. Based on field estimates, Strategic’s corporate production rate averaged 4,510 boe/d (71 per cent oil) for the fourth week of September. New production volumes in the third quarter have been added from five Muskeg wells since the summer drilling program began in June 2014, and a sixth well which was recently fracture stimulated is currently being tied in. Further advancements in the completion program yielded higher oil rates in the latest three Muskeg wells, 15-24, 01-25 and 14-23. Production rates for the 02-26 well have increased in recent days as the well continues to clean up. In the second half of September, a third party sales oil pipeline was impacted by a temporary shutdown affecting all producers shipping through the pipeline. Strategic has not curtailed any production as a result of this event. Strategic immediately implemented measures to mitigate the effect of
the pipeline shutdown on crude oil production and sales volumes, including the use of railcars for transportation and shipping volumes to a company-owned storage facility. As a result of implementing these measures, the company put approximately 30,000 bbls of oil in storage. Strategic has resumed shipping crude oil through the pipeline and both the stored volumes and current production are now being delivered to sales. Strategic expects to continue its active capital program through the fourth quarter, drilling up to six new wells. Production for the second half of 2014 is still estimated at 3,800 boe/d and 2014 exit production guidance is maintained at 4,600 boe/d. “Though the temporary shutdown of the third party oil pipeline forced us to defer some of our oil sales volumes to the fourth quarter, we did not have to curtail any production operations as a result of this event,” said Gurpreet Sawhney, Strategic’s president and chief executive officer. “We continue to increase well performance and gain efficiencies, and our September exit production of 4,510 boe/d was a company record.”
Strategic Muskeg drilling performance Muskeg area
Initial rates days on production
% Oil
Current rate
– well
West
boe/d - days
%
boe/d
– well
West
boe/d - days
%
boe/d
– well
North
boe/d - days
%
boe/d
– well
North
boe/d - days
%
boe/d
Location
Source: Strategic Oil & Gas
Arcan commences winter drilling program Arcan Resources has commenced its winter drilling program with plans for drilling and completing up to nine wells this season, the first two being joint interest wells with a partner in Morse River and Deer Mountain West. Arcan then expects to move the rig to Ethel and will be targeting prospects in proximity to the four successful wells from last year’s drilling program that demonstrated high deliverability performance. The corporation’s target is to have all wells from the winter program on-stream before spring breakup. “We estimate that third-quarter production will be above 3,900 boe/d, which exceeds our projections of 3,650–3,850 boe/d,” said Terry McCoy, Arcan’s chief executive officer. “This is due to a stabilization of base decline rates from waterflood operations and the contributions of the four wells from the fi rst quarter. We’re looking to replicate these successful results again this winter by targeting similar highpotential prospects. We also continue our focus on cost reductions and on executing operationally, which should lead to a strong quarter for Arcan.” Arcan estimates it has delivered thirdquarter production of over 3,900 boe/d, with no new wells brought on stream since the fi rst quarter of 2014. This compares to second-quarter 2014 production of 4,105 boe/d and fi rst quarter 2014 production of 3,740 boe/d.
Gibson Energy is a growth-oriented, solutions-based, North American midstream energy service company with an integrated portfolio of businesses.
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16
DECEMBER 2014 • OIL & GAS INQUIRER
NORTHEASTERN ALBERTA WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
N.E.
Northeastern Alberta
Husky perseveres at Tucker By Pat Roche
Husky Energy Inc. continues to invest in its Tucker SAGD project, where it hopes production from secondary zones will help keep the project producing far into the future. After pioneering the commercial use of SAGD in the Clearwater, the company is now looking to augment output with production from the Lower Grand Rapids and Colony zones as well. Husky has said little or nothing about Tucker in recent quarters, but public data and September’s presentation on Tucker to the Alberta Energy Regulator (AER) offer a glimpse of what is happening. When steam injection began in August 2006, Husky’s project at Tucker Lake in the Cold Lake oilsands region of northeastern Alberta became the first commercial recovery scheme to use SAGD in the Clearwater Formation. Until then, commercial projects in the Clearwater had used only cyclic steam stimulation (CSS). Imperial Oil Limited, which since the mid-1980s has reigned as king of the Clearwater with its large, successful Cold Lake project, patented SAGD but has never been able to commercially apply the technology in the Clearwater. Husky’s Tucker SAGD project was designed to produce 30,000 bbls/d of bitumen from the Clearwater, but the original output was just a trickle. Husky said the problem was that the initial wells were drilled into the transition zone where bitumen saturation is low. The company says all new Clearwater well pairs—B-North infi ll, A-Pad replacement and infill, C-East, GA-Pad and D-East— have been drilled above the transition zone. With additional spending, Husky achieved commercial SAGD production from Tucker, which was originally
designed to be economic at an oil price of around the $30-$35/bbl range. The company is also sticking with SAGD. Husky did operate a CSS pilot at Tucker that produced a total of 55,295 cubic metres of oil, representing a total recovery factor of 2.9 per cent, according to the company’s 2013 presentation on Tucker to the AER, but the pilot has since been abandoned. Husky originally drilled 32 SAGD well pairs at Tucker. Eight more well pairs were added in 2007 after commercial-scale oil production failed to materialize from the original development. Twenty more well pairs were added during 2009-11, five well pairs were added in 2012-13 and five more were added in the second quarter of 2014. That brought the total to 70 horizontal well pairs. In its 2014 AER presentation, Husky said full project development will include more than 140 well pairs over 35 years. According to public data, Tucker bitumen production averaged 9,551 bbls/d in 2012, 10,318 bbls/d in 2013 and 10,981 bbls/d in the first seven months of this year. According to public data, Tucker’s steam to oil ratio averaged 6.45 in the fi rst seven months of this year. The company’s September 2014 AER presentation said Tucker’s steam utilization is at 80 per cent of design. The presentation said Tucker has five well pads, three of which—Pads A, B and C— produce from the Clearwater. In 2012-13, the company added Pad GA, drilling fi ve SAGD well pairs, to produce from the Lower Grand Rapids Formation. A steam debottleneck project was commissioned in August 2013 to feed steam to the Lower Grand Rapids wells. Last year, Husky sought regulatory approval to also produce bitumen from the Colony sands at Tucker.
Eight years after steaming started at the Tucker project, Husky continues working to make it efficient.
In June of this year, the AER approved an amendment to Husky’s original Tucker development plan to include the Colony development. In its Tucker presentation to the AER in September, Husky said its Colony development plans for 2014-15 include drilling and completing six SAGD well pairs, five infi ll wells and two other wells. It also plans to commission and start up facilities. Husky’s Pad D-East development plans for 2014-15 include drilling and completing 15 SAGD well pairs, commissioning and starting up facilities and drilling three observation wells. Five SAGD well pairs were drilled on Pad D-East by mid-2014, and 10 more are to be drilled by year’s end, Husky told the AER. It also listed a delineation well at 09-26-064-05W4. In its AER presentation, Husky said its 2014-15 plans for Tucker include submitting an application for a sixth once-through steam generator. The steam generator tie-in is scheduled for the third quarter of 2015 when a maintenance turnaround is scheduled for the central processing facility. Plans for 2014-15 also include commissioning and starting up the D-Pad facilities. OIL & GAS INQUIRER • DECEMBER 2014
17
Northeastern Alberta
Operators make progress on technology front By Lynda Harrison
New technologies may ultimately solve some of the problems associated with in situ recovery of bitumen, but these technologies continue to face many challenges in getting off the ground, a recent oilsands forum heard. Presenters at Petroleum Technology Alliance Canada’s (PTAC’s) 2014 oilsands forum, “Building on Technology Momentum,” said the industry is working on advances in the use of steam, oxygen, electricity, non-condensable gas, solvents and surfactants to reduce costs, increase energy efficiency and minimize its environmental footprint. “SAGD is marginally economic in many cases and especially when we have falling oil prices,” said Thomas Harding, corporate technology senior adviser at Nexen, a wholly owned subsidiary of CNOOC Limited.
generation and water treatment facilities by 50 per cent,” he said. There would be an increased cost for producing the oxygen but a much lower capital cost than would be involved in producing twice as much steam as might be required, he added. SAGDOX is currently being tested in a laboratory where Nexen is working on numerical simulation capacity or capability. The decision whether or not to field test it is to be made in late 2015. Enhanced solvent extraction incorporating electromagnetic heating is underway at the Dover former Underground Test Facility site and is scheduled for start-up in January 2015. The project now has five partners, one of which is the Alberta government’s Climate Change and Emissions Management
Simulation capability has been a stumbling block in the development of SAGDOX as well. Fine grids are necessary to run simulations of this process and the computing time is enormous. It’s also difficult to develop a representative reaction kinetics model for SAGDOX and to keep the number of components to a minimum to reduce the computing time, he said. Laboratory testing of hybrid steam and combustion processes is long and expensive, and Nexen faces naysayers among industry insiders regarding the in situ combustion process. “There are at least a hundred people who will say to me that it won’t work for every person who is supportive of the idea.” Nexen is also in the process of patenting a new technology called in situ reflux, which is in the proof-of-concept stage of testing. “The pure novelty of the process,
“There are at least a hundred people who will say to me that it won’t work for every person who is supportive of the idea.” — Thomas Harding, corporate technology senior adviser at Nexen
“The capital and operating costs are both very high in SAGD, and it also has quite an environmental impact,” he said. “It uses a lot of water even though we’re recycling massive amounts of water, and there are carbon emissions, so any technologies that we’re looking for have to not only reduce costs but they also have to reduce environmental impact.” Harding said Nexen is pursuing various new in situ process technologies, including two that it began piloting at Long Lake in October, one involving the injection of solvent and the other the injection of noncondensable gas. The company is also working on a hybrid steam-combustion process called SAGDOX, which combines the benefits of SAGD with in situ combustion to optimize steam and oxygen ratios as the process matures. “We think that by using a mixture of nine per cent oxygen with 91 per cent steam, that 50 per cent of the heat that goes into the reservoir will be generated by the oxygen combustion and the other 50 per cent by the steam. This implies that we could reduce the size of the steam 18
DECEMBER 2014 • OIL & GAS INQUIRER
Corporation, which is paying for 50 per cent of the pilot’s cost, the forum heard. There have been a few well-drilling and completion problems, but power to the radio frequency antenna is now scheduled to be switched on in January 2015, said Harding. He said the greatest challenges with this project have been in understanding the electromagnetic physics in the reservoir and being able to simulate the process. This requires a coupled thermal flow simulation and electromagnetic heating models, and Nexen now has the rudiments of a technology developed to be able to do this, he said. “We’re still lacking a lot of data on the electrical properties of oilsands over a wide range of fluid saturations, especially water saturation, because it turns out that the electromagnetic energy is attracted to the water in the formation, and it’s the water that heats up and heats everything else, but we don’t have a lot of information on the electrical properties of oilsands at very low water saturations and it has been necessary to develop a new well design to house the [radio frequency] antenna that also allows solvent injection,” said Harding.
the fact that we’re starting something completely new, means that it requires a completely new approach, and it’s challenging from that perspective,” said Harding. According to Harding, whose fi rst job was with the Alberta Oil Sands Technology and Research Authority working on steam and combustion recovery at a Cold Lake pilot project that started in 1978, another area that deserves a lot of attention and research is small-scale field upgrading. There are a lot of possibilities in the development of cost effective, small-scale field upgrading that would allow the elimination of large, centralized upgraders and the need for diluent, he said. In current SAGD operations, produced water emerges from the ground at 180–200 degrees Celsius, depending on operating pressure. That water is typically cooled down so that it can go through water treatment systems, which typically cannot handle high temperature water. After treatment, the water is reheated for boiler feed and converted into steam. “It’s a very inefficient process, so if we can develop some high temperature water
Northeastern Alberta
treatment technologies that eliminate the need for cooling, that would be really helpful,” he said. Researchers are fi nding in situ recovery methods that are more energy efficient, he added. These include the application of additives to steam—solvents, noncondensable gas and surfactants—which will improve the steam to oil ratio, and processes that reduce the amount of water and fuel for steam generation, said Harding. Subodh Gupta, chief of technology development at Cenovus Energy Inc., identified what he believes are the oilsands industry’s top three challenges: improving production’s tidewater access, combatting public perception of the industry’s poor environmental performance and the high and rising cost of its projects. Every year, the costs of the industry’s already-expensive projects rise by four to five per cent, he said. High project costs are typically attributed to the resource’s remote locations, isolated from mainstream infrastructure. “That’s what we have to get over, somehow, to reduce our capital costs, our sustaining costs and our operating costs,” said Gupta. “Technology development or innovation can address some of these challenges, not all of them; however, technology development has a few challenges of its own. “That the preponderance or the existence of these challenges is stacking up against us is an indication that maybe our innovation machiner y is slow to react, to tackle some of these challenges, or maybe the pace of development is a little bit isolated or out of tune with the speed of advancements happening elsewhere in the world, in other areas, in other industries.” In addition, even with existing ideas or innovations, there is insufficient fieldtesting capacity, which reduces the speed and capability of converting ideas into robust, commercially applicable solutions or technologies, he said. These challenges of innovation and technology development could be at least partially mitigated through collaboration among operating companies, universities and research institutes, he said. According to Gupta, numerous concepts and combinations need to be tested before they are applied commercially, requiring time, effort and money, and disrupting the production process.
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19
CENTRAL ALBERTA WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Upgrader/refinery would be profitable, says AFL A new upgrading refinery and petrochemical complex in Alberta is likely to be profitable and to generate favourable economic returns—so much so, in fact, that it would meet many of the criteria necessary to attract private sector investment, says a study commissioned by the Alberta Federation of Labour (AFL). The study, Upgrading Our Future: The Economics of In-Province Upgrading, found that the project would be economically viable at WTI prices of between $80 and $120 per bbl. “Based on existing capital cost estimates and arm’s-length purchases of feedstock at market prices, the project appears to be attractive with NPV [net present value] and IRR [internal rate of return] showing good returns under all three crude oil price cases,” says the report. The calculated IRR is 19 per cent at $80 per bbl, 22.6 per cent at $100 per bbl and 25.6 per cent at $120 per bbl. The base case assumes that the diluent return stream would be sold to oilsands producers at a market-related transfer price of WTI plus five per cent. The objective of the study was to examine the potential economics of in-province upgrading of Alberta oilsands and whether it’s something that should be looked at in more detail. The report, authored by Ed Osterwald, a senior partner with United Kingdom–based Competition Economists Group (CEG), was released at a forum in Edmonton. The AFL’s position is that the province should consider the idea of an upgrading and refi nery complex and “give it its due,” Shannon Phillips, a policy analyst with the AFL, said. The federation believes that in-province upgrading is important not only because it is something Albertans want, but also
A new upgrader would be economic at prices between $80 and $120 per barrel, says an AFL report.
because they are at the mercy of fluctuating commodity prices that often result in cutbacks to health, education and other essential services, said Phillips. “What we are seeing is an emerging national consensus that these kinds of activities are in Canadians’ interest and are part of building shared prosperity for everyone and finding ways to maximize the value from our natural resources,” said Phillips. “What we are saying is that some of that enormous wealth that is flowing out of the country and the good family-sustaining, middle-class jobs that go with it should be enjoyed not only by Albertans but across the country.” Osterwald told the forum that private companies would begin to be interested in developing a project with an IRR of 14 per cent, “although that’s not to say they would do it,” said Phillips. “This report was an exercise using the Government of Alberta’s report in order to demonstrate that the margins remain attractive,” she said. “Perhaps it might not be something that is attractive to vertically integrated producers who have a physical plant
elsewhere, but that doesn’t mean to say it’s not an attractive proposition for Albertans.” Because refining margins have been extremely profitable, they are attractive to many in the private sector who aren’t part of the small group for whom it is advantageous to refi ne either in Asia or in the U.S. Gulf Coast, said Phillips. “There are other private sector actors, and they are beginning to look at those refi ning margins as something that could form the basis for long-term prosperity for everyone.” The new study updates a 2006 study by David Netzer of Consulting Chemical Engineer and Associates that was commissioned by the Government of Alberta under the Hydrocarbon Upgrading Task Force, a joint industry and government initiative. CEG used information from the earlier study, along with other factors such as CEG’s price forecasts, discount rate and projected fi xed and variable costs, to develop an operating cash flow model of the proposed project. The Netzer project configuration helps to reduce some of the potential market volatility OIL & GAS INQUIRER • DECEMBER 2014
21
Central Alberta
inherent in simple crack spreads since it uses many of the heavy oil residues in the petrochemical process, said Phillips. “In that way, you have a variety of different margins because you have a variety of different products for a variety of different markets.” On the basis that the project is commercially attractive and viable, the onus is likely to be on the Alberta government to move it forward, at the very least in the initial stages, says the report. It points out that the government has the flexibility to adjust the cost of oilsands production to users through the bitumen-royalty-inkind program in order to encourage the private sector to assume a greater role in the development of the project. If necessary, discounts on feedstock prices could be used to improve returns should there be cost increases in other risk areas, such as capital cost, the report says.
“ What we are saying is that some of that enormous wealth that is flowing out of the country and the good familysustaining, middle-class jobs that go with it should be enjoyed not only by Albertans but across the country.” — Shannon Phillips, a policy analyst with the AFL
“Alternatively, the government may have to initiate the process on its own or through a partnership with the private sector,” it says. “Although there may be an initial cost to these incentives, over the medium to long term it is likely to benefit the province, both in fi nancial and non-fi nancial terms, such as job creation and less dependency on the upstream sector.” Last year, only 52 per cent of Alberta’s bitumen production was upgraded in the province, and that share is expected to fall to 36 per cent by 2023, the Alberta Energy Regulator predicted in its 2013 reserves report. In its 2014 Crude Oil Outlook, Markets and Transportation study, the Canadian Association of Petroleum Producers forecast that only one-third of bitumen production will be upgraded in Alberta in 2030, down from 52 per cent in 2013. Economic deterrents to building upgraders in Alberta include high capital costs and the need for a sustained differential of at least $25 per bbl between the price of heavy and light crudes, it said.
Montney oil economic at $60 per barrel Despite technical challenges, the economics of the Alberta Montney oil sub-play are strong enough that drilling is unlikely to be slowed by oil prices of US$80 per bbl, said IHS Energy. The U.S.-based consultancy said it has completed a study on the Montney oil sub-play, which is located almost entirely in Alberta. IHS said the economics remain robust despite technical challenges and highly fragmented ownership. It didn’t say how much oil the play was producing or provide the average or range of API gravities. “The IHS Energy economic analysis puts the break-even price for the average Montney oil well at $60 per bbl. With the current drop in oil prices averaging in the $80 per bbl range, we do not 22
DECEMBER 2014 • OIL & GAS INQUIRER
Central Alberta
think price pressure will lead to a curtailment in activity,” said Hassan Eltorie, author of the study. IHS said that last year the National Energy Board (NEB) estimated the Montney’s oil-in-place resource at 141.5 billion barrels. Commercially recoverable resources were estimated at 1.1 billion barrels, implying a recovery factor of less than one per cent, much lower than in most unconventional plays. In addition, the NEB cautioned that the shallowness of the sub-play casts doubt on well recovery factors, suggesting unusual technical challenges, IHS said. North American “oil shale” plays have an average recovery rate of two to five per cent, but the Montney’s recovery factor is estimated at less than one per cent because of the shallowness of the play, which suggests lower pressures, the consultancy said. “The Montney oil sub-play offers robust economics, which bodes well for the commercial development of the play,” IHS said. “But the play does face some technical challenges and its fragmentation means that we really don’t have the large sweet spot that would attract larger operators to the play. A larger company would have to make many acquisitions to have an impact in the play, which would be difficult due to a lack of [merger and acquisition] activity.” Average peak-month production rates for the Montney oil sub-play wells in Alberta dropped 16 per cent in 2013 to 351 boe/d after jumping 211 per cent in 2011 and 124 per cent in 2012, said IHS. Some operators are reducing activity because 2013 drilling results failed to build on the steadily improving 2010 to 2012 results, IHS said. Operators are targeting numerous areas across the play with each operator focusing on one or two areas, IHS said. Much of the drilling has centred on the Ante Creek and Kaybob areas in the southeastern portion of the play. “We are seeing strong results led by RMP Energy and ARC Resources,” IHS said. “ARC Resources has excelled, in particular, since its well performance has bucked the trend by recording improved rates.” In the Kaybob Duvernay play, operators Trilogy Resources and Athabasca are also drilling the Montney, IHS said. In the northeastern portion of the sub-play, Long Run Exploration’s drilling dominates in the shallower Girouxville and Normandville areas, the consultancy said.
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OIL & GAS INQUIRER • DECEMBER 2014
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SOUTHERN ALBERTA WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
S.A.B.
▲
▲
Southern Alberta
▲
Source: Daily Oil Bulletin
Zargon to spend $46 million in 2015
Zargon expects its ASP project to ultimately yield 4,200 bbls/d.
Zargon Oil & Gas Ltd. said it has increased its 2014 capital budget by $5 million to $57 million (before dispositions of $12 million) and set its 2015 capital budget at $46 million. The budget includes $11 million of chemical costs for its Little Bow Alkaline Surfactant Polymer (ASP) tertiary flood, $8 million of ASP Phase 1 construction and sanctioning costs, $2 million of ASP Phase 1 optimization costs, plus $36 million of conventional (non-ASP) field capital expenditures directed to existing oil exploitation projects. The increase in the 2014 capital program reflects additional costs for Phase 1 ASP optimizations and the acceleration of some conventional projects into the lowercost pre-winter period, said Zargon. Following $34 million of capital expenditures in the first half of the year, the company
anticipates the remaining second-half expenditures of $23 million will be roughly equally divided between the third and fourth quarters. For the upcoming winter months, non-ASP field activities will be kept to a minimum. Zargon’s 2015 budget has been set at $46 million and includes $13 million of Little Bow ASP chemical costs, $2 million of Phase 1 optimization costs, $6 million of Little Bow ASP Phase 2 development costs and $25 million of conventional (non-ASP) field capital expenditures directed to existing oil exploitation projects. Depending on the corporate cash flows realized throughout the 2015 calendar year, the conventional capital program may be increased or decreased in order to maintain stable debt levels after the payment of dividends.
Zargon said it continues to be encouraged by the early injection data for the Little Bow enhanced oil recovery project. In March 2014, it initiated the injection of large volumes of a dilute chemical solution into the partially depleted Little Bow Mannville I Pool in order to recover substantial incremental oil reserves. To date, ASP injections have totalled approximately two million barrels and represent just less than 10 per cent of the total chemical bank (ASP and polymer only) to be injected. Encouragingly, pattern injection rates are balanced and are meeting or exceeding reservoir models, said Zargon. It has also observed numerous indicators that are precursors to ASP production, namely, increased produced gas-to-oil ratios, reduced producer total inflow volumes, changes in the produced water chemistry, minor produced polymer concentrations and increasing injection pressures. At one producer (02/10-32-014-18W4), Zargon has observed 12 bbls/d of first incremental ASP production volumes as evidenced by a tripling of oil production volumes with a corresponding increase in produced oil cuts. While it said it views these production indicators very positively, the company acknowledged that Phase 1 incremental ASP production volumes are small. Phase 1 production capability is averaging approximately 260 bbls/d, which is marginally ahead of the 250-bbl/d baseline rate for the pre-ASP waterflood project. Over the next few months, a material ramp-up in production is anticipated. Zargon’s internal estimates continue to forecast incremental Phase 1 production volumes to begin in the fourth quarter of 2014 and increase to a 2014 year-end rate of 150 bbls/d. Incremental ASP production is expected to average 700 bbls/d in 2015 and then increase to 1,550 bbls/d of oil in 2016 once Phase 2 production begins. OIL & GAS INQUIRER • DECEMBER 2014
25
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Production guidance Zargon has reaffi rmed a third and fourth quarter 2014 oil and liquids production rate guidance of 4,200 bbls/d. The fourth quarter 2014 oil volumes are expected to reflect a minor contribution from the Little Bow ASP production volumes.
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DECEMBER 2014 • OIL & GAS INQUIRER
Marquee boosts spending at Michichi and Lloydminster Marquee Energy Ltd.’s strong drilling results, operational performance and improved balance sheet have allowed the company to expand its capital program for core properties at Michichi and Lloydminster. Having dramatically boosted its balance sheet throughout 2014—mainly due to increased operating cash flow, continued execution of its non-core disposition program and fi nancing that included the recent disposition of gas-weighted Pembina properties in which the company sold about 425 net boe/d for $15.8 million—Marquee is setting its capital budget to $46 million for 2014 (net of dispositions) with exit production at 5,600–5,800 boe/d. Capital budget additions include two horizontal wells at Michichi as well as two vertical wells and 0.5 horizontal wells at Lloydminster, all of which will be drilled in the fourth quarter, with the majority of new production to be fully realized in early 2015. Marquee will also accelerate certain facility improvements at its Drumheller oil battery and terminal in the fourth quarter, subject to obtaining regulatory approvals in a timely manner. At Michichi, the company has increased production by about 4,000 boe/d, achieving 100 per cent drilling success year-to-date with 11 completed oil wells and a 12th underway. According to management, production from this drilling has contributed to positive type curve revisions. Of the first four wells since spring breakup that Marquee has completed and placed on production at its new oil battery at 04-09-032-17W4, currently three produce at a combined rate of 645 boe/d (65 per cent oil), which is an average of 215 boe/d per well after more than a month. The fourth well awaits additional completion operations. Marquee completed its next two wells in September, which are currently tied in to the company’s owned and operated infrastructure. Both wells have been on production for less than a month, recovering most of their completion-load fluid. Additionally, crews are undertaking completion operations for wells 10 and 11, both of which were tied in to the new oil battery by early November. The company’s drilling results continue to validate its assessment that at least 80 low-risk drilling locations exist on focus-area lands out of a total area drilling inventory of 175. Furthermore, Marquee is evaluating the possibility that Michichi will support downspacing from four to six wells per section. A new 67-squaremile 3-D seismic survey is also underway to evaluate further extensions to the company’s focus area. At Lloydminster, Marquee has increased production to about 700 boe/d, drilling one vertical well and one short-leg horizontal well in August. Both wells currently produce with results exceeding
Southern Alberta
type curve expectations for the area. The company’s vertical well positively delineates its exploration discovery made in September 2013 at 09-03-048-01W4. The drilled horizontal well offsets other successful competitor horizontals. In this area, Marquee management has identified at least 30 similar low-risk, high-productivity drilling opportunities out of a total drilling inventory of 50 locations on the property.
Urban drilling resolution passed by AUMA delegates By Carter Haydu
During last month’s Alberta Urban Municipalities Association (AUMA) conference in Edmonton, delegates approved a resolution to amend the Municipal Government Act, allowing municipal regulations and bylaws to apply to a well, battery, pipeline or pipeline structure. Karen Diaper, spokeswoman with AUMA, said that while she does not know by what margin the city of Lethbridge resolution passed at the recent convention, she did confi rm that delegates strongly supported it. “Resolutions are sent to the responsible provincial or federal minister for response,” she said in an email. “In the case of this resolution, we will be sending it to the minister of energy for his response.” The resolution calls for the deletion of provisions that allow licences, permits, approvals or other authorizations permitted by the Alberta Energy Regulator (AER) to prevail over the statutory plans, land use bylaws, subdivision or development decisions of a municipality. It also calls for the deletion of provisions that provide that a condition of such a licence, permit, approval or other authorization prevails over any condition of a municipal development permit. Furthermore, the resolution calls for amendments to legislation governing the AER, requiring a statement from the local municipality for each application pertaining to the suitability and compatibility of all new applications for resource extraction within the jurisdiction of a municipality. The resolution also calls for AER legislation amendments that ensure a municipality is granted standing in hearings for all new resource extraction applications within the municipality’s jurisdiction, with the municipality able to participate at its discretion. Finally, the resolution calls for all AER resource extraction applications to address issues of compatibility with local municipal development plans and existing developments. Lethbridge city council recently voted to submit the resolution to the annual convention following a controversial bid by Calgarybased Goldenkey Oil Inc. to drill an oil well within the city limits as part of its Penny project, which was widely opposed by both the community—as evidenced by the citizens’ group No Drilling Lethbridge—and local elected officials such as city council. The Penny project would have drilled three exploration wells in the Big Valley Formation on the city’s west side, but Goldenkey eventually decided it would not make an application to access potential resources from the Lethbridge area, suggesting associated barriers did not justify costs.
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OIL & GAS INQUIRER • DECEMBER 2014
27
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SASKATCHEWAN WELL ACTIVITY OCT/13
OCT/14
Wells licensed
OCT/13
OCT/14
Wells spudded
OCT/13
OCT/14
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
S.K. Saskatchewan
Crescent Point busiest driller in first nine months of 2014 Crescent Point Energy drilled the most metres during the first nine months of 2014, while Canadian Natural Resources Limited rig released the most wells. Bet ween Januar y and September, Crescent Point drilled 1.11 million metres of exploration and development hole, beating out Canadian Natural’s 1.05 million metres. The two producers were the only ones to pass the million-metre mark for total metreage. Ranked by metres drilled, the top fi ve was rounded out by Encana (712,103 metres), Husky Energy (689,489 metres) and Cenovus Energy (646,993 metres). At 828, Canadian Natural drilled the most wells over the first nine months of 2014, followed by Husky (518), Crescent Point (401), Cenovus (339) and Encana (210). Crescent Point was also t he top explorer for the nine-month period, based on metreage. The company drilled 180,655 metres of explorator y hole, followed by Seven Generations Energy Ltd. with
150,261 metres and Royal Dutch Shell plc with 117,395 metres. In Alberta, Canadian Natural was the top operator in the first nine months of the year based on rig releases (686) and metres drilled (802,069), followed by Cenovus (324 rig releases and 610,447 metres drilled). Based on rig releases, Husky drilled 268 wells for third spot, ConocoPhillips Canada rig released 196 and Encana drilled 169. On the metres drilled side, Encana rig released 506,134 metres in Alberta, followed by ConocoPhillips (454,069 metres) and Husky (367,559 metres). Progress Energy Resources led the pack in British Columbia with 131 wells drilled and 486,986 metres of hole. Last year, the company rig released 77 wells and 284,235 metres over the first nine months. Other top operators in B.C. included Royal Dutch Shell (54 rig releases and 220,302 metres) and ARC Resources (53 rig releases and 217,419 metres). Encana
rig released 41 wells (205,969 metres) and Tourmaline Oil Corp. drilled 32 wells (123,086 metres). Based on rig releases, Saskatchewan’s busiest operator was Crescent Point (370 wells drilled), followed by Husky (249), Teine Energy (198), Northern Blizzard Resources (197 ) a nd R ag i ng R iver Exploration (138). On a metres-drilled basis, Crescent Point was the runaway leader: the company drilled 1.03 million metres in Saskatchewan to the end of September compared to 317,959 metres for Husky. Teine drilled 285,191 metres of hole, Legacy Oil + Gas Inc. rig released 227,309 metres and Northern Blizzard drilled 204,090 metres. Tundra Oil & Gas Partnership dominated the rig release count in Manitoba with 105 wells drilled (220,140 metres). EOG Resources Canada rig released 49 wells (83,672 metres), while Corex Resources drilled 30 wells (51,522 metres).
Quattro strikes pay at Wood Mountain Quattro Exploration and Production said its evaluation well at Wood Mountain, Sask., successfully intersected the Bakken, Torquay and Birdbear zones and terminated in the Duperow at an aggregate cost of $1.2 million. The well was drilled, cored, logged and cased to a total depth of 1,950 metres. On October 16, the company released the drilling rig after completing its evaluation plan, which included collecting 33 metres of core from the Bakken and the
Torquay and obtaining high resolution logs. The drilling logs have been used to evaluate a series of geological events totalling 134 metres, including a 34-metre section of the Birdbear zone and the initial 56 metres of the Duperow zone. Quattro will be using this information to complete further analysis over the course of the next 6–12 months, prior to advancing its drilling and development plans within the 110,000 acres (net) it holds in the Williston Basin of Wood Mountain.
“Our initial objectives have confirmed the hydrocarbon potential in the region with the information collected being an important step towards the commercial development of oil and gas in the region,” commented Leonard Van Betuw, Quattro’s president and chief executive officer. “The completion of the evaluation well at 08-22-005-03W3 in correlation with our gravity, seismic and previously identified key wells further supports our interpretation of a continuous section of Bakken ranging from 12 to 16 metres over the breadth of our lands.” OIL & GAS INQUIRER • DECEMBER 2014
29
Cover Feature
In other words, the forward curve is saying producer cash flow should be down by about $6 billion to $7 billion next year, or roughly 10 per cent lower than 2014, he said.
Oilsands capital spending is expected to be roughly $25 billion to $30 billion per year on new projects and maintenance through 2020. Spending on oilsands operating costs, which is estimated to be almost $20 billion this year, is expected to exceed $32 billion per year in 2020. Peters expects total capital spending in Western Canada of $77 billion in 2014 compared with $74 billion in 2013. It predicts expenditures will tumble to $72 billion next year. Fetterly said oil futures contracts give an indication of the likely drop in overall producer cash flow in Western Canada next year. “We entered the year with the forward curve implying that producer cash flow in 2014 would be just under $68 billion, and the forward curve implied 2015 was going to be about $67 billion,” he said. That increased as 2014 progressed, peaking around May or June at projected producer cash flow of about $77 billion to $78 billion for 2014 and $72 billion to $73 billion projected for 2015. “You go forward to what’s happened in the last 60 days, pricing and cash flow expectations for 2014 have remained relatively constant. But for 2015 you can see the effect from both the reduction in forward pricing and also the backwardation in the forward curve,” Fetterly said.
Lower prices mean a slight well count drop PSAC president Mark Salkeld told the conference the drop in oil prices will be felt by the service industry, but it will be more like a bump than a crash. “We are forecasting only a small slump in activity for the year despite the fairly rapid decline in the price per barrel,” said Salkeld. “We are anticipating a cold winter again this year, so expect that we will see a typical ramp-up of Q1 activity, and, of course, slower activities in the spring with breakup. However, we expect the last two quarters of 2015 to see an uptick to finish another year with strong performance.” “There is a lot at play out there, but commodity pricing and market access are two of the biggest drivers behind forecasted activity levels,” he added. “But we are optimistic that 2015 will bring some resolve and positive movement on both those fronts.” PSAC is basing its 2015 forecast on an average AECO natural gas price of C$3.80 per mcf and a WTI crude oil price of US$85 per bbl. On a provincial basis for 2015, PSAC estimates a decline in activity levels across the board in Western Canada. In Alberta, PSAC is forecasting a total of 5,740 wells to be drilled or just over a six per cent decrease over 2014 activity levels. British Columbia is forecasted to have the largest decline of 20 per cent from 690 to 555 wells for next year. PSAC is forecasting 3,365 wells to be drilled in Saskatchewan and 430 in Manitoba, or a five per cent and four per cent decline respectively. “We are forecasting that 2015 will see nearly 90 per cent of well completions in favour of oil, which is being driven by commodity prices still,” Salkeld added. Salkeld said that while there will be a slight decline in the number of wells drilled next year, with longer horizontal wells becoming the norm, this doesn’t necessarily translate into a decline in activity. “If anything, it’s as busy as ever,” Salkeld said. PSAC is forecasting that total metres drilled will rise to 24.39 million next year, up from a forecast 24.22 million metres this year and 22.85 million metres drilled last year. At the same time, PSAC is forecasting well lengths will continue to increase to an average 2,415 metres in 2015, up from the 2,236 metres per well forecast for 2014, 2,065 metres per well drilled in 2013, 2,002 metres per well averaged in 2012 and 1,856 metres per well in 2011. Improved efficiency and deeper, longer wells are resulting in more production per well. “We are, in fact, delivering more wells with fewer holes in the ground,” Salkeld said. He noted PSAC’s 2015 forecast has the average metres per well doubling from 1,232 in 2005. The gain in efficiency is obvious from the lower number of rig operating days. Although PSAC expects the total metres drilled to rise next year, rig operating days—a crucial measure of producer drilling costs—continue to fall. PSAC expects rig operating days to total only 103,590 next year, down from a forecast 112,600 in 2014 and well down from 131,588 rig operating days recorded in 2011. “Again, you see increasing improvement—bigger, safer, faster, more efficient rigs,” Salkeld said, referring to how highly automated and specialized rigs drilling from multi-well pads continue to improve performance. “It’s a very sunny outlook.” OIL & GAS INQUIRER • DECEMBER 2014
31
Cover Feature
PSAC drilling forecast by province 2014 Forecast
2015 Forecast
% Decline 6.3
Alberta
6,124
5,740
Saskatchewan
3,554
3,365
5.3
British Columbia
690
555
19.6
Manitoba
449
430
4.2
Other
13
10
23.1
Total
10,830
10,100
6.7
Source: PSAC
Deep wells will drive drilling contractor market With metres drilled per well on the uptick, Fetterly said demand for big drilling rigs will continue to climb in 2015 and beyond. Of the 810 rigs available for work in Western Canada, Peters estimates fewer than 300 have the capacity that will be required for the expected drilling ramp-up in deep, demanding resource plays such as the Duvernay, the Montney and the Liard Basin. About 45 rigs are currently being built in Canada, and Fetterly expects this extra capacity will be absorbed over the near term. But in the longer term, he expects the Canadian drilling sector will need to build more than 100 rigs to meet the demands of the four or five biggest resource plays. Precision Drilling chief executive officer Kevin Neveu shares this view. Speaking at the Barclays Energy Conference, Neveu said while there have been no final go-aheads for LNG export terminals off the west coast, activity in supply basins is already underway, and he expects that activity to grow. “Currently today there are about 25 rigs that are running in Canada that are doing delineation work and early drilling work for the LNG projects. So it’s happening right now,” Neveu said. Under Precision’s calculations, Neveu estimated that roughly 20–25 rigs would be needed per billion cubic feet of export capability, meaning the opportunity is huge for drilling outfits. “So if my handicapping is right and three projects get approval, that could be between six and eight billion cubic feet a day of opportunity for 100–200 rigs in the industry for Canada and we would certainly be targeting to get our share or more of that business,” he said. “For us it’s interesting in that likely most of these rigs will be new builds. If this is going to be pad-type drilling, these rigs don’t exist in Canada right now.”
Pressure pumpers cautiously optimistic for 2015 Fetterly said the Canadian pressure pumping market moved from a state of oversupply to showing signs of undersupply late in 2014, which may allow pumpers to increase prices in 2015. Trican Well Services agrees. “We will continue to seek pricing increases in Canada as opportunities arise,” the company said in its third-quarter report to shareholders in early November. Looking ahead to 2015, Calfrac reported it is confident demand for its services will remain strong in the first quarter. From there on it will depend on commodity prices. “With the recent declines in oil and gas prices, we will take a cautious approach when making decisions regarding new equipment deployment, capital spending and cost management during 2015,” the company reported. “Our Canadian customers have not yet finalized capital budgets for 2015, but based on recent discussions and initial work programs, we expect to be fully utilized during the first quarter of 2015. Overall, Canadian pressure pumping supply has not increased significantly, and we do not currently expect significant supply increases during 2015. Controlled supply growth, combined with a continued increase in fracturing intensity, is expected to result in strong demand for our services throughout 2015. However, demand growth in 2015 will depend on commodity prices that drive the cash flows of our customer base.” Calfrac Energy Services echoed Trican’s outlook in its thirdquarter report to shareholders. In the near term, Calfrac expects activity to be relatively stable across its operating divisions, but uncertainty over the longer term has increased. Calfrac expects initial producer capital budgets for 2015 will reflect a cautious approach, but the company believes producers’ spending could increase when there is more certainty regarding oil prices. At the same time, Calfrac says there are a number of positive trends going into 2015. “Spot natural gas prices in the United States have been relatively stable in recent months while storage levels in the United States and Canada remain below their five-year weekly lows. These factors should be constructive for natural gas–related development in North America heading into the period of high demand during the winter,” the company noted. There are also a number of encouraging developments Calfrac is experiencing that are specifically related to well completions, such as greater service intensity through larger multi-well pad designs, more fracturing stages per horizontal well and increased tonnage per stage.
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DECEMBER 2014 • OIL & GAS INQUIRER
BIG
Feature
THE NEXT
Emerging plays promise future growth across the WCSB By Darrell Stonehouse
O
ver a decade into the unconventional resource revolution, oil and gas companies continue to use extended-reach horizontal drilling and multistage fracturing technology to open up new plays and expand existing plays. Tight oil plays like the Bakken, the Cardium and the Viking are now well into development mode, with many moving into secondary recovery. Gas and liquids plays like the Montney, the Wilrich, and the Fahler, all in the Deep Basin, are also proven, and dry gas plays in the Horn River Liard Basin are also well established. But new plays are emerging all the time. The technologies are increasingly being used on more conventional types of formations as well, adding more production from aging fields. Across the Western Canadian Sedimentary Basin (WCSB) a number of new developments emerged in 2014, including the Torquay play in southeastern Saskatchewan and the Charlie Lake oil play in northwestern Alberta. Other plays, like the Duvernay in central Alberta, are moving from exploratory to development mode. And other more conventional plays, including the Glauconite liquids play in central Alberta, are now benefiting from horizontal drilling and multistage fracturing. Torquay discovery adds to southeastern Saskatchewan Bakken development Crescent Point Energy announced in April that it had made a significant Torquay discovery in the Flat Lake area of southeastern Saskatchewan, which it described as an extension of its Three Forks resource play in North Dakota. The company reported that throughout 2013 and early 2014 it had delineated the discovery in the Flat Lake area, where the company has more than 220 net sections of land and 400 low-risk Torquay drilling locations on the Canadian side of the border. Crescent Point reported drilling 36 (35.2 net) horizontal wells
THING
targeting the Torquay Formation at Flat Lake, growing net production from zero to approximately 5,100 boe/d in just 12 months. “We’re very excited about the results we’ve seen in the Torquay so far,” president and chief executive officer Scott Saxberg said. “These are high-rate-of-return wells at low capital costs relative to North Dakota that complement the Bakken production from our core Flat Lake area. To put it in context, this play has the potential to be the equivalent size of our Viewfield Bakken play.” In 2013, the company added proved plus probable reserves of 11.2 million boe at Flat Lake in the Torquay and Bakken formations combined. Finding and development costs were $11.46 per boe, excluding changes in future development capital, which represents a recycle ratio of 6.4 times per proved plus probable boe for this area. “The recycle ratio for Flat Lake is more than double the 2.8 recycle ratio we achieved corporately in 2013 and more than triple a recycle ratio of two times, which is considered very good in our industry,” Saxberg said. At year-end 2013, Crescent Point’s independent reserve engineers booked estimated ultimate recoveries on producing Torquay wells as high as 275,000 bbls per mile-long well. This type of well, which has a $3.35 million capital cost, generates rates of return of approximately 300 per cent and payouts of approximately seven months. In 2014, Crescent Point expected to spend approximately $200 million of its 2014 budget in Flat Lake, including drilling approximately 48 net wells. In addition to its core Flat Lake Torquay land position, over the past 18 months Crescent Point has continued to accumulate a significant exploratory land position of more than 400 net sections in the southern part of southeastern Saskatchewan, targeting the Torquay and Bakken formations. These lands are in addition to the delineated core-area lands discussed above. Later in April, Crescent Point announced it was acquiring privately held CanEra Energy Corp. and its southeastern Saskatchewan assets for a total consideration of $1.1 billion. OIL & GAS INQUIRER • DECEMBER 2014
33
Feature
The CanEra assets include more than 260 net sections of land with Torquay potential, of which more than 200 net sections are exploratory land and 60 net sections are in Crescent Point’s core Flat Lake area. This gives Crescent Point more than 880 net sections of land with Torquay potential, of which more than 280 net sections are in the core Flat Lake area. Crescent Point drilled 25 oil wells into the Torquay during the third quarter of 2014, again reporting positive results. Charlie Lake quickly becomes commercial Tourmaline Oil Corp. spent $53 million in 2013 consolidating land in the Charlie Lake oil play, and in aggregate, 514 sections were acquired on the trend. The company has wasted little time developing the play. Tourmaline has drilled 84 horizontal wells into the Charlie Lake play and expects to exit 2014 producing between 18,000 and 20,000 boe/d. The company believes that the regional pool could ultimately yield over 500 million barrels of oil equivalent. The producer said it controls over 75 per cent of the prospective trend as currently mapped. The company drilled approximately 35 new wells in 2013, and about 50–60 horizontal wells should be completed by the end of 2014. Tourmaline said Charlie Lake is a significant resource-style play, but it is not as large as the
said Jeff Tonken, president and chief executive officer. “We believe the play has significant growth potential on land we currently own.” He added that the play stretches across the Peace River Arch and has become popular because of the economics and the opportunity for growth due to the application of horizontal drilling and fracturing, which is enabling further resources to be unlocked. “New technology, horizontal wells, completion techniques and resulting recoveries together with higher light oil prices have driven this play,” Tonken said. “This formation is only found in the Peace River Arch, so it will be limited to northwestern Alberta.” On average, drilling and completion costs are roughly $2.5 million per well, Birchcliff says. Duvernay advancing to commercial production With an estimated 443 trillion cubic feet of gas, 11.3 billion barrels of natural gas liquids, and 61 billion cubic feet of oil, the Duvernay is the big prize when it comes to Alberta’s shale resource. In 2014, a number of operators reported making progress in moving the play toward development mode. At the end of the winter drilling season, Encana reported it had drilled 24 gross wells (12 net) in the Duvernay year-to-date and was making good progress in commercializing the play, reported chief operating officer Mike McAllister.
“
Encana has released five Simonette horizontal wells in the second quarter with an average spud-to-rig-release of just under 30 days. This represents a reduction of 17 days or 35 per cent off our average in the first quarter of this year.
Montney, for example. The average cost to drill and complete is $3.6 million. The company has identified 1200 drilling locations in the play. In early November, Tourmaline announced it sold a 25 per cent stake in the Charlie Lake play to Canadian Non-Operated Resources LP for $500 million. Under the deal, CNOR is taking a 25 per cent interest in all lands, wells, production, reserves and facilities in the northern Alberta play and shares all future development and acquisition costs. Tourmaline made the move to speed development in the play. “Tourmaline will accelerate the planned exploration and development program commencing in 2015, with both an accelerated drilling program and infrastructure build-out resulting in expenditures of at least $400 million per annum over the duration of the five-year plan,” it said in announcing the deal. Birchcliff Energy Ltd. has been working the Charlie Lake play and expanding its operations at the Worsley field since acquiring it in 2007. The company holds 181,541 net acres that are prospective for the Charlie Lake light oil resource play. “Our main pool, holding over 400 million barrels of oil in place, is in Worsley, Alta. Our land is mostly large blocks of 100 per cent owned, contiguous blocks, which helps with repeatability, pad drilling and the construction of infrastructure,” 34
DECEMBER 2014 • OIL & GAS INQUIRER
“
— Mike McAllister, Encana chief operating officer
“We have seen tremendous progress in drilling cycle times in the play,” he said. Ten high-intensity completion horizontal wells in Simonette are meeting or exceeding expectations, with initial production averaging about 1,300 boe/d per well. Spud-to-rig release times have improved by an average of 17 days since the first quarter, resulting in cost savings of roughly $1.5 million per well. Five rigs are currently running in the play. “Encana has released five Simonette horizontal wells in the second quarter with an average spud-to-rig-release of just under 30 days. This represents a reduction of 17 days or 35 per cent off our average in the first quarter of this year. It also translates into cost savings of about $1.5 million per well,” McAllister said. “These five wells are the longest horizontals in the play, with average lateral lengths of 7,000 feet. “We have also tested five new Simonette horizontal wells in the second quarter. All five wells are meeting or outperforming expectations.” Royal Dutch Shell plc, which describes itself as the leading Duvernay driller, says the jury is still out on the shale play’s commercial viability. “It’s still an emerging play from our perspective. PVT [pressure, volume, temperature] and reservoir physics are not well
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understood yet,” said Holger Mandler, who leads the geoscience team for Shell’s Fox Creek unit. “Profitability will still have to be proven by more tests and prolonged production data across the sweet spot,” Mandler told the 2014 Unconventional Resources Conference, which was planned and operated by the Society of Petroleum Engineers and the Canadian Society for Unconventional Resources and which took place in Calgary. Shell entered the play in 2011, spudding its first Duvernay horizontal at Fox Creek in December 2011 and ramping up the program to five rigs by mid-2013. “It was by far the most aggressive ramp-up of any of the operators in the area,” Mandler said. “And after that we slowed down the pace in 2014, currently with one to two rigs basically running.” Looking at industry activity in the Duvernay as of August, Mandler said Shell had drilled and completed the most wells. “The same thing for production,” he said, referring to January 2014 output. “At that point, Duvernay production had come up to about 20,000 boe/d with Shell basically producing roughly half of that at the time.” In any multi-fracture play in tight rock, initial production declines steeply. Mandler said the company now has about 50 wells in the play with 40 on production producing about 7,000 boe/d from Fox Creek. At Willesden Green, the company has drilled just eight wells to date and has three on production. Much more production history is needed before profitability can be assessed, he emphasized. “Not all the information is coming right away. You have to produce these wells for quite some time...to try to understand the potential.” When it comes to evaluating the Duvernay’s commercial viability, one of the key challenges, in Shell’s view, is understanding the reservoir. “PVT sampling is still a somewhat open question in our minds,” said Mandler. “You have to collect a lot of data there. But because of the nature of the Duvernay, of the variability of PVT behaviour across the sweet spot, and the difficulty or impossibility, so far, to collect downhole samples, this is a very difficult question to address technically.” He said the absence of adequate PVT data “has a huge impact when you run dynamic models. It has a large impact in terms of per-well EURs [estimated ultimate recoveries]. So this is a key parameter for estimating, for predicting or modelling well performance. And it’s very difficult to tackle in this area.” “Same thing with production,” he added. “Similarly, we feel that we need really extended production history to really have a high-confidence estimate of well performance. So long-term production that is half a year or longer.” With more wells on stream, production history will obviously accumulate over time, Mandler acknowledged, but he added, “A lot of the information we have is still based on tests across the area and on short-term production.” Another challenge is reservoir architecture. He said the Duvernay B—“a fairly massive mudstone”—and other calcareous stringers appear to be potential frac barriers. Mandler said “a number of observations” suggest natural fractures are present across the play, and this could pose another technical challenge. “The wells are somewhat active while drilling, which you wouldn’t expect given the really low permeabilities in the play.” One of the things Shell did last year in its initial Duvernay drilling blitz was to drill three “data pads,” four-well pads with
unique configurations to help determine development parameters such as well spacing and frac fluids. “We call them data pads because they’re not only unique configurations to test certain concepts but also have some additional technology deployment that you wouldn’t do in a regular appraisal or a development well,” he explained, citing microseismic monitors as an example. Mandler didn’t talk about Shell’s individual Duvernay well results, but he said the industry as a whole has been reporting perwell results in the range of roughly 350–1,300 bbls/d of oil and one to seven MMcf/d of gas. He cited third-party ultimate recovery estimates of up to 700,000 bbls of liquids per well and 4.7 bcf of gas. He said a few wells that have already produced more than 150,000 bbls of oil. A typical Duvernay well takes between 20 and 40 days from spud to rig release, and most have been cased and cemented with plug-and-perf completions, Mandler said. “There were a number of wells that were attempted with open-hole completions with mixed results...so most operators have gone to plugand-perf.” He said total lateral lengths range between 900 and 2,600 metres, and the number of frac stages ranges between seven and 27. Oil gravities range between 43 and 55 degrees API. Glauconite benefits from horizontal technology New drilling and completion technologies are also having a significant impact on more conventional plays. For example, Bonavista Energy is using horizontal drilling in the Hoadley Glauconite play in south-central Alberta. The Hoadley Glauconite was originally discovered in 1977 and is estimated to contain an ultimate potential recoverable reserve of six trillion to seven trillion cubic feet of gas and 350 million to 400 million barrels of associated natural gas liquids. “Our Hoadley Glauconite play continues to be the engine of growth representing a forecasted 65 per cent of the total expenditures in this core area for 2014 and delivering excellent economics at current prices,” Bonavista president and chief executive officer Jason Skehar said in announcing the company’s second-quarter results. Bonavista drilled 15 net horizontal Glauconite wells in the second quarter, bringing total activity in the first half of 2014 to 27 net horizontal wells. This represents a 25 per cent increase in drilling activity when compared to 20.4 net horizontal wells drilled in the first half of 2013. Current horizontal Glauconite production volumes are approximately 22,500 boe/d, which is modestly ahead of the company’s five-year forecast. Bonavista said that the continued growth in its Glauconite play has warranted additional infrastructure, including a transmission line designed for 120 MMcf/d of natural gas transportation and a 30-MMcf/d compressor station. The average cost reduction of 11 per cent per well realized to date in the company’s extended-reach horizontal program is compelling when compared to the cost to access the equivalent reservoir from two separate horizontal wells. Year-to-date, Bonavista has drilled five extended-reach horizontals with three of these wells drilled in the second quarter. Well performance is meeting expectations. OIL & GAS INQUIRER • DECEMBER 2014
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COST BUSTERS TECHNOLOGY MAKING SAGD MORE PRICE PROOF BY PAT ROCHE
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DECEMBER 2014 • OIL & GAS INQUIRER
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lthough low oil prices pinch SAGD economics, gamechanging technologies will cushion the blow, said Jared Wynveen, a reservoir engineer and associate at McDaniel & Associates Consultants Ltd., in a presentation at the Canadian Heavy Oil Association’s fall conference. “Pricing variability still has the biggest impact. We all know that it’s the number one driver. And unfortunately, it’s something that we have zero control over,” he said. “That being said, some of these new technologies could really moderate the impact of pricing variability,” the reservoir engineer added. Wynveen sees three technologies as “near-term game changers where we’re really going to see a step-change in the performance of a number of projects. And the reality is we’ve already started to see these trends.” He identified the near-term game changers in SAGD as coinjection of methane with steam, the use of solvent with steam and the drilling of infill wells. “And I would go out on a limb and say that the aggregate steam [to] oil ratios [SORs] that we’re going to see from projects across the board will continue to improve over the next five to 10 years,” he said. He also credited improvements in drilling accuracy and greater future use of inflow control devices and outflow control devices in SAGD well pairs. “Even if there isn’t a new silver bullet that takes us away from SAGD technology, what I will say is that SAGD itself is going to become incredibly efficient. And at this point, we’re only starting to see those trends emerge.” As the adoption of these technologies becomes more widespread, there should be greater market recognition of the positive impact on project economics because of improved steam to oil ratios, productivity and ultimate recovery, he said. While some of the technologies are still being piloted, Wynveen said “there are also new technologies that I would argue are commercially demonstrated.... They are real and their use is only going to become more pervasive in the next few years.” Technologies working in the field Several producers have been co-injecting methane with steam in some SAGD well pairs. MEG Energy Corp. has probably used this technology the most with the best results. “They’re absolutely doing amazing things,” Wynveen said of MEG’s use of non-condensable gas co-injection with steam in conjunction with infill wells. “Their SORs, on an instantaneous basis, have gone from about 2.5 down to about 1.4 for certain pads. That is absolutely exceptional. And to be honest, it’s beyond what I would have anticipated when they went into the RISER program. So I think they may have surprised a few in the industry with how robust their new process is.” While struggling Connacher Oil and Gas Limited certainly wasn’t the only company to inject solvent with steam, its success may have gone unnoticed because of the company’s other problems. “You may not have realized, but they’ve had a huge turnaround in their production performance. They are using infill wells. They are using solvent co-injection. And their productivity is arguably higher now than it has ever been in the past,” Wynveen said of Connacher.
“Their SORs are trending in the three range as opposed to 4 1/2. And it has completely changed the dynamics of that project and ultimately what we expect from an economic perspective,” he added. Looking generally at the baseline economics of a typical SAGD project, Wynveen assumes solvent injection with steam would result in a 20 per cent SOR reduction and a 20 per cent increase in bitumen production and recoverable volumes. Similarly, he assumes the use of infill wells—without methane or solvent co-injection—would result in about a 10 per cent reduction in SOR. But while he described infill wells as “a very positive step,” he suggested it’s the combination of technologies that will really lead to a “step-change in performance.” McDaniel’s economic analysis indicates the combination of infill wells and methane co-injection with steam would result in about a 20 per cent drop in the SOR of a typical SAGD project. Though they are not game changers like solvent or methane co-injection with infill wells, Wynveen listed other technologies he expects will boost SAGD economics. Southern Pacific Resource Corp. opted for inflow and outflow control devices to help lift lagging production. “What we’re seeing with a lot of projects that have been developed in the last few years is that early time conformance and early time productivity is really not living up to the expectations that were set corporately,” Wynveen said. (Wellbore conformance refers to the even distribution of steam along the length of each well.) He suggested an explanation: “One is that everybody is used to developing the reservoirs with five, six, seven darcy rock, like the Christina Lakes and Firebags, and when you move to a reservoir that has a third of the permeability and you try and do everything the exact same, well, there’s a learning curve.” Improvement has a cost, though: “With these types of devices, I would suspect your all-in well-pair costs are going from about $8 million or $9 million to about $10 million.” But he added: “If you’re outside of those real top-decile reservoirs, or you’re a shareholder of a company who doesn’t have a top-decile reservoir, this is something you should very seriously consider pushing on the management team.” Wynveen described drilling SAGD wells as “inherently more challenging and less accurate than most people recognize.” A SAGD reservoir, for example, may be 350 metres deep. The horizontal wellbores might be 1,000 metres long. Wells are drilled with what engineers call the ellipse of uncertainty. “When we drill these wells, we only know where we are within a certain radius of inf luence,” Wynveen said. “And by the time you make it to the toe of a well, the delta from where you think you are, relative to where you actually could be, is five metres. That’s huge.” “When we look at projects that don’t have 30, 40 metres of net pay thickness—and most of the future projects will not have that level of thickness—drilling accuracy is incredibly important. Because if you’re missing five or six metres at the base of your reservoir, the amount you might have on top might not be enough to substantiate an economic project.” Fortunately, advances in geosteering and other drilling technologies have resulted in improved drilling accuracy, less stranded pay and better avoidance of problem areas such as bottom-water zones.
OIL & GAS INQUIRER • DECEMBER 2014
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