OIL&GAS May 2013 ~ $6.00
INQUIRER Western Canada's Exploration & Production Authority
A R F
U T C
D E R
PM40069240 40069240
ling l i r d tal n o iz hor n g esi d m sto u c s tor a r e Op
and
ing k c fra
s lay p l a idu v i d r in o f s am r g pro
bia m : u l n s Plu ish Co y for a t Bri s read get boom G LN
BUSINESS PARK • GRANDE PRAIRIE
The Business Core for Grande Prairie
• 150,000 Sq Ft of office & light industrial • 3,000 - 10,000 Sq Ft drive-in and dock loading bays • Professional appearance • Precast concrete construction • Conveniently located at a key intersection
• Built to suit offices • Ample parking • Air conditioning • Strategic highway visibility • Immediate occupancy
FOR LEASE Greg Dobko RE/MAX Grande Prairie 780-538-0288 or toll free 1-866-538-0288 gdobko@gregdobko.com
Open house every Tuesday! 11am-2pm. Unit 101- Building 3, 7001 98th Street Clairmont, Alberta T0H 0W0
www.CrossroadsCentron.com T r u s T e d • r e l i a b l e • K n o w l e d g e a b l e | P h o n e 4 0 3 - 2 5 2 - 1 1 2 0 | c e n T r o n g r o u P. c o m
Frac water storage? We’ve got Canada covered.
828925 Dragon Products full page · fp forward, RH Every type, every size, every situation. There are many challenges that you may face in frac water storage, but one thing is always constant – Dragon has the right solution. From 400-barrel uprights to insulated and non-insulated frac tanks to Water Corrals, we are the only company in Canada that offers the full range of water storage systems. Every product is severeduty engineered to perform in the harshest production environments, and Dragon knows frac water storage and handling like no other company. We offer on-site needs assessment so our engineers can design solutions specific to each job site, including custom packages. Plus, we are fully committed to serving Canada, with a location in Red Deer and a Canadian sales force dedicated to providing exactly what you need. All solutions, all from one source. Make it happen. www.dragonproductsltd.com — 1-403-340-3600 © Copyright 2013 Modern Group Inc. All rights reserved.
Make it happen. U.S. owned and operated for over 50 years.
Increase the reliability of your pipeline project with Flexpipe Systems’ proven solutions Flexpipe Systems’ corrosion resistant spoolable pipe products are available in 2", 3" and 4" internal diameter sizes, maximum rating pressures of up to 2,000 psi, and continuous operating temperatures up to 180°F (82°C). With over 16,000 kilometers of linepipe and 75,000 fittings installed worldwide, Flexpipe Systems is the answer to your next pipeline project.
ShawCor – when you need to be sure
flexpipesystems.com
Learn more about our products by scanning the above QR code
shawcor.com
CONTENTS
MAY.
www.sprung.com/oilgas
in the news
13 Western Canadian crude production to double by 2025
Engineered Fabric Building Solutions
regional news
19 British Columbia
39 Central Alberta
Ottawa pushing world-class tanker safety system
Williams to build $900-million propane dehydrogenation facility at Redwater
25 Northwestern Alberta
45 Southern Alberta
Northwest drives final land sale of
DeeThree ramps up in 2012
the year
29 Northeastern Alberta Trains could carry 800,000 barrels of bitumen per day by 2014
49 Saskatchewan Crescent Point advancing unitization in the Bakken
53 Northern Frontier Canol shale shows potential, says MGM Energy
tech news
54 Field Upgrading receives funding for upgrading technology features Cover Feature
56 Unlocking tight oil and gas Operators custom design horizontal drilling and fracking programs for individual plays
63
Short Term Leasing Available
The waiting game B.C.’s natural gas industry holds on in anticipation of LNG export boom
business intelligence
68 Facility and infrastructure ownership benefit some producers every issue
10 Stats at a Glance 70 Political Cartoon Cover composite: Peter Markiw; Illustration: Serhiy Zavalnyuk/Photos.com
1 800 528.9899 403 601.2292
Direct Dial:
info@sprung.com CALGARY • ALBERTA
O I L & G A S I N Q U I R E R • M AY 20 13
7
When the top energy companies on the planet are looking for an integrated solution to keep the energy sector moving forward, they look no further than ClearStream. We’re driven by the power of over 3000 employees and we are proud to be owned and operated right here in Canada. For industrial services, ClearStream is the clear choice. We bring the strength of our team, our wide service area, and our resources to the energy industry, and we employ from the communities where we work. Serving Alberta and Northeast BC from 23 locations, from construction to maintenance to shutdowns, we see the job through, bringing you innovative solutions and quality work from start to finish. Committed to excellence. Committed to safety.
Editor’s Note Vol. 25 No. 4 EDITORIAL EDITOR
Darrell Stonehouse | dstonehouse@junewarren-nickles.com CONTRIBUTING WRITERS
Godfrey Budd, Lynda Harrison, Carter Haydu, Richard Macedo, Pat Roche, Elsie Ross, Paul Wells
Real wealth
EDITORIAL ASSISTANCE MANAGER
Marisa Sawchuk | msawchuk@junewarren-nickles.com EDITORIAL ASSISTANCE
Shawna Blumenschein, Tracey Comeau, Matthew Stepanic CREATIVE PRINT, PREPRESS & PRODUCTION MANAGER
Michael Gaffney | mgaffney@junewarren-nickles.com CREATIVE SERVICES MANAGER
Tamara Polloway-Webb | tpwebb@junewarren-nickles.com CREATIVE LEAD
Cathlene Ozubko GRAPHIC DESIGNER
Peter Markiw
CREATIVE SERVICES
Janelle Johnson production@junewarren-nickles.com SALES SALES MANAGER—ADVERTISING
Monte Sumner | msumner@junewarren-nickles.com SENIOR ACCOUNT EXECUTIVES
Nick Drinkwater, Diana Signorile SALES
Brian Friesen, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Tony Poblete, Sheri Starko For advertising inquiries please contact adrequests@junewarren-nickles.com AD TRAFFIC COORDINATOR—MAGAZINES
Denise MacKay | atc@junewarren-nickles.com DIRECTORS CEO
Bill Whitelaw | bwhitelaw@junewarren-nickles.com PRESIDENT
Rob Pentney | rpentney@junewarren-nickles.com DIRECTOR OF SALES & MARKETING
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 DIRECTOR OF CONTENT
Chaz Osburn | cosburn@junewarren-nickles.com DIRECTOR OF PRODUCTION
Audrey Sprinkle | asprinkle@junewarren-nickles.com DIRECTOR OF FINANCE
Ken Zacharias, CMA | kzacharias@junewarren-nickles.com OFFICES Calgary
nd Flr- Avenue N.E. | Calgary, Alberta TE Y Tel: .. | Fax: .. Toll-Free: ...
Edmonton 220-9303 34 Avenue N.W. | Edmonton, Alberta T6E 5W8 Tel: .. | Fax: .. Toll-Free: ... SUBSCRIPTIONS Subscription Rate In Canada, year $ plus GST, years $ plus GST Outside Canada, year $
When the public thinks of the wealth of the petroleum industry, it is usually talking about the pay packages of the executives. Investors generally focus on cash flow and profits, and see the wealth of the industry in resources and reserves. But reading this month’s feature story on the technologists and engineers involved in creating and building the knowledge base allowing explorers and developers to access tight oil and gas reserves, it’s easy to recognize that the real wealth in the industry isn’t found on spread sheets or in the mansions surrounding Red Deer Lake or Springbank, Alta. Instead it lies in the heads of people like Tim Leshchyshyn, president of Fracturing Horizontal Well Completions Inc. Leshchyshyn’s company, in partnership with Geo Webworks Inc., has introduced a software tool based on its fast-growing completion, fracturing, drilling and well files database. The FracKnowledge database module is used for optimizing multistage horizontal fracking and improving productivity and well profitability. Leah Hrab, manager for drilling and completions at Sure Energy Inc., is another example of where the real wealth lies. Hrab has experience with multistage fracking in plays across the basin, and that experience is now saving her employer significant money. Both Leshchyshyn and Hrab are examples of how the skill set required to be successful in the industry has changed over the last decade. Last year, almost 7,000 horizontal wells with multistage
Subscription Inquiries Telephone: ... Email: circulation@junewarren-nickles.com Online: junewarren–nickles.com GST Registration Number RT. Printed in Canada by PrintWest. ISSN - | © JuneWarren-Nickle's Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications Mail Agreement Number . Postage paid in Edmonton, Alberta, Canada. If undeliverable, return to: Circulation Department, 80 Valleybrook Dr, North York, ON M3B 2S9 Made in Canada The opinions expressed by contributors to Oil & Gas Inquirer may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.
fracture stimulations were completed in western Canada. And the tight oil and gas boom is in its very early stages, with at least a generation of drilling ahead. Workers with the knowledge and experience to assess which technologies will work best in any given circumstance are in high demand, and their worth will only accelerate once export markets are opened up for the new supplies. On another, sadder note, former Alberta premier Ralph Klein passed away on March 29. Klein’s greatest achievement was praying for another oil boom, getting it, and not pissing it away. Two ideas made Ralph Klein the best premier the province has ever seen in my book. First, he understood that governments, like individuals, could not spend more than they earn. During Klein’s reign, the province earned over $45 billion more than it spent. Second, he believed that individuals could make better decisions on how to spend their own money than governments. This resulted in the lowest taxes in the country. It also resulted in “Ralph Bucks”, excess revenues the government returned to taxpayers when oil and gas prices peaked in 2004-05. In the six years since Klein stepped down, the province has returned to its bad old ways of spending money it doesn’t have, sinking back into deficits and accumulating debt. I have a feeling in the not-too-distant future we’re all going to be praying for the second coming of Ralph Klein. Darrell Stonehouse Editor dstonehouse@junewarren-nickles.com
N E XT I S S U E June 2013 Export opportunities for Canadian service and supply companies, plus a review of Canadian companies exploring globally.
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.
MINI B&W FSC LOGO O I L & G A S I N Q U I R E R • M AY 20 13
9
FAST NUMBERS
,
,
Current Cardium horizontal oil production, says Peters & Co.
Cardium horizontal oil production in 2009, says Peters & Co.
barrels per day
barrels per day
Alberta Completions
WCSB Oil & Gas Completions
Source: Daily Oil Bulletin
Source: Daily Oil Bulletin
M O NTH
OIL
GAS
OTHER
T O TA L
MONTH
OIL
GAS
D RY
SERVICE
T O TA L 1,275
Mar 2012
Mar 2012
Apr 2012
Apr 2012
988
Jun 2012
Jun 2012
449
Jul 2012
Jul 2012
873
Aug 2012
Aug 2012
986
Sep 2012
Sep 2012
908
Oct 2012
,
1,269
Oct 2012
Nov 2012
Nov 2012
1,250
Dec 2012
Dec 2012
1,054
Jan 2013
Jan 2013
645
Feb 2013
Feb 2013
1,161
Mar 2013
Mar 2013
1,295
Wells Drilled in British Columbia
Saskatchewan Completions
Source: B.C. Oil and Gas Commission
Source: Daily Oil Bulletin
MONTH
WELLS DRILLED
C U M U L AT I V E *
MONTH
OIL
GAS
OTHER
TOTAL
Mar 2012
39
158
Mar 2012
Apr 2012
86
244
Apr 2012
Jun 2012
13
334
Jun 2012
Jul 2012
57
401
Aug 2012
53
454
Sep 2012
11
465
Oct 2012
28
493
Nov 2012
78
571
Dec 2012
65
636
Jan 2013
31
31
Feb 2013
42
73
Mar 2013
66
139
*From year-to-date
Jul 2012
Aug 2012
Sep 2012
Oct 2012
Nov 2012
Dec 2012
Jan 2013
Feb 2013
Mar 2013
Gas Migration Testing…
Effective technology at half the cost
• Environmental Drilling • Pipeline Inspections • Steamers • Invasive Plant Inventories
• Hydro-Seeding • Weed Control • GasTrak Leak Detection • No Flame Heaters
Cold Lake • Drayton Valley • Drumheller • Edson • Edmonton Rocky Mountain House • Stettler • Swift Current
1-888-542-9156 | WWW.WESTCOUNTRY.CA 10
M AY 20 13 • O I L & G A S I N Q U I R E R
STATS
AT A
GLANCE
Drilling Rig Count by Province/Territory
Drilling Activity: Oil & Gas
Western Canada, April 10, 2013 Source: Rig Locator
Alberta, April 2013 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
OIL WELLS
Alberta
GAS WELLS
Mar
Mar
Mar
Mar
Alberta
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
4%
Southern Alberta
79
%
TOTAL
WC TOTALS
Service Rig Count by Province/Territory
Drilling Activity: CBM & Bitumen
Western Canada, April 10, 2013 Source: Rig Locator
Alberta, April 2013 Source: Daily Oil Bulletin
AC T I V E
DOWN
T O TA L
(Per cent of total)
Western Canada
Alberta
AC T I V E
Alberta
C OA L B E D M E T H A N E
BITUMEN WELLS
Mar
Mar
Mar
Mar
%
Northwestern Alberta
British Columbia
%
Northeastern Alberta
Manitoba
%
Central Alberta
Saskatchewan
213
46%
Southern Alberta
WC TOTALS
%
TOTAL
O I L & G A S I N Q U I R E R • M AY 20 13
11
THE MOST POWER WITH TOP TOWING AND HAULING.† IT’S THE TOUGH, DEPENDABLE TRUCK THAT KEEPS TOUGH, DEPENDABLE GUYS COMING BACK YEAR AFTER YEAR.
F-Series is the best-selling pickup truck in Canada for 47 years in a row based on Canadian Vehicle Manufacturers’ Association statistical sales report, December 2012. Vehicle may be shown with optional equipment. †Class is non-hybrid Full-Size Pickups under 8,500 lbs GVWR vs. 2012/2013 comparable competitor engines. Max. horsepower of 411 and max. torque of 434 on F-150 6.2L V8 engine. When properly equipped. Max. towing of 11,300 lbs with 3.5L EcoBoost® and 6.2L 2 valve V8 engines. Max. payload of 3,120 lbs with 3.5L EcoBoost® and 5.0L Ti-VCT V8 engines.
IN THE
NEWS Issues affecting Canada’s E&P industry
Western Canadian crude production to double by 2025
Photo: Joey Podlubny
Led by the oilsands, which will account for 64 per cent of incremental production, western Canadian crude oil output is forecast to double to 5.7 million barrels per day by 2025 from the current three million barrels per day, said a new report. In its 51-page forecast, No More Guessing: Canada, New York–based ITG Investment Research estimated average monthly oil production additions of approximately 78,000 barrels per day by 2017, compared to 63,000 barrels per day in 2012, making Canada the world’s fourth-largest producer based on current production, up from sixth place. Industry brought on about 27,000 barrels per day of new production per month from 2007-09, keeping western Canadian oil production relatively flat. From 201012, the pace of additions increased to 49,000 barrels per day, boosting production to nearly three million barrels per day. ITG studied public data from more than 300,000 wells and used play-by-play
analysis to develop rig and project-based models to forecast Canadian oil, natural gas and natural gas liquids (NGLs) production to 2025. The model assumed an average annual total of 375 rigs, up from the 2012 average of 285, driven by an increase in the number of rigs drilling in the Montney, Duvernay and Horn River plays. The study forecasted that rig-based oil production, which includes the Alberta Cardium and Saskatchewan Bakken, will slow to a compound annual growth rate of 3.3 per cent by 2020, down from 8.8 per cent in 2011-12. Assuming no increase in the number of oil-directed rigs, production is projected to grow by approximately 370,000 barrels per day by 2020. Although bitumen, conventional heavy oil and synthetic crude accounted for approximately 53 per cent of production additions since 2007, ITG said it expects their share of additions to decline in the future with the growth in light oil. In 2012, the Cardium play comprised 12 per cent of
Oilsands growth will drive crude production over the next decade.
all production additions while the Bakken provided seven per cent of additional production in western Canada. However, the near-zero decline of heavy oil, bitumen and synthetic crude implies they will make up an increasing share of total production, the report said. Driven by non-declining bitumen production growth, the base decline of western Canadian oil production is expected to fall to approximately seven per cent in 2025, down from approximately 12 per cent in 2012. Supply growth over the next four years also is expected to outpace pipeline capacity in western Canada, the U.S. Rockies and the U.S. Bakken, according to the report. Even if all planned pipeline projects such as Keystone XL and Northern Gateway were to proceed, incremental rail shipment volumes of approximately 600,000 barrels per day, up from existing/planned crude transportation by rail of approximately one million barrels per day, would still be required, it said. Rail capacity would need to increase to approximately 2.5 million barrels per day to keep up with production growth in what ITG described as the “improbable case” that major new pipeline construction is halted. In 2012, the top 10 oil producers in western Canada accounted for approximately 60 per cent of all oil production additions, but all except four had significant oilsands operations and they represented only 13 per cent of additions. On the natural gas side, ITG’s rigbased scenario estimated that marketable gas production will increase to approximately 16 billion cubic feet per day (approximately 19 billion cubic feet per day of raw gas) by 2025. The ITG O I L & G A S I N Q U I R E R • M AY 20 13
13
In The News
forecast is based on a ramp-up in the Montney and the Horn River Basin in response to liquefied natural gas facility feedstock requirements. In addition, the study assumed success in the Duvernay with 42 rigs running there by 2016. If the number of rigs remains flat at 2012 levels, forecast gas production would decline by approximately 3.2 billion cubic feet per day by 2025, resulting in a slight decline in western Canadian gas production. Of the incremental production, gas from liquids-rich plays such as the Deep Basin, Duvernay and associated gas accounted for 56 per cent of gas additions at the end of last year and are expected to account for 55 per cent of new production by 2020. About 36 per cent of gas additions in 2012 came from the top 10 gas producers in western Canada, implying a more diverse set of operators than oil producers, noted ITG. Assuming success in the Duvernay, NGL production is expected to rise to approximately 420,000 barrels per day, up from approximately 300,000 barrels per day last year. — DAILY OIL BULLETIN
14
M AY 20 13 • O I L & G A S I N Q U I R E R
Economy has little to fear, much to gain by Canada pursuing role as an energy “superproducer” Canada would gain significant economic benefits, including job growth and additional tax revenue, by working to become an energy “superproducer,” suggested a new study from the Fraser Institute, an independent, nonpartisan Canadian public-policy think tank. And the growth in energy production and exports would, if managed properly, not damage other facets of the economy, concluded the study, Canada as an emerging energy superproducer. “Further growth in energy production would be of net benefit for Canadians as long as the risks associated with becoming an energy superproducer and net energy exporter are managed to avoid or minimize any negative impacts that energy sector growth could have on other areas of the economy,” said Gerry Angevine, Fraser Institute senior fellow and co-author of the study. Canada as an emerging energy superproducer explores the meaning of the term “energy
superpower” and whether Canada could become an energy superpower or a superproducer of energy. It also examines how Canada’s energy resources, production, and net exports rank from a global perspective and provides an overview of the economic benefits flowing from energy resource production, including the royalty payments that flow to governments, and interprovincial energy trade. “Prime Minister Stephen Harper refers to Canada becoming an energy superpower, but for a country to become an energy superpower, it has to be able to use its energy resources to set market prices and exercise political power,” Angevine said. “With its adherence to free trade and extensive private sector investment in the energy sector, Canada will not become an energy superpower in the traditional sense.” The study found that Canada currently ranks sixth in the world for oil production
In The News
Producers plan to spend over $55 billion (behind Russia, Saudiheader Arabia, the United This is the for this header States, China and Iran). But with planned in 2013 new investment in the oilsands and shale By XX
formations, Canada could become the fourthor even third-largest global oil Tor aut eum corecte mporpor ecepudaecproducer. The story is similar quaeperum for natural tur moluptumquis ipsaererem gas, nonewhere omnimust Canada desequi is currently voloriam thefaccatis fourthlargest etur, quas global qui voluptat producer, videstibus as well quam as elecla ipsant auta estrum, cusa volupti onsediptricity exports and uranium production. Overall, sae. Nequo Canada enda net was ut por the solo fifthblabo. largest Ut exporter exerate estium of oil, est, natural veribusciat gas, oiletur products, seque and nemelectricity verovite od combined que ea dolenesti in 2009, behind num is Russia, sapieni Saudi squunti Arabia, oribus Norway iditature andvenis Iran. ent Kenneth P. Green, study co-author preius sitatquatur, culliquiatis nobit and pre nobit, director simus, in sitas que mincturit hit senior the Fraser Institute’seat Centre arunt pa qui reptas sit, Resource santi dolorer chifor Energy and Natural Studies, tatiis recus exceribus. pointed outdoluptam that Canada’s energy sector already Eprehenim makes enormous que verrocontributions iusdae cum accae to the nonsendit economy inoditis addition idigenimus, to creating optatibustio jobs and govmaxim ament ernment revenues quethrough nest ut royalty endit volor payments. simusapic Oiltoand ereperrum natural gas nonsent extraction quecontributed non comnihilbillion $94 ipitatent to thefugitem. GDP in 2011; Volecestis electric utilities as quo odit alignatem contributed $33 idelian billion; tiumqui the uranium ut voluptamining tur aut rerro industry purchased bearum goods idebit and services volori videbit valued atemquid at $1.1 billion. maximod Additionally, essi the conet study in estimated num que the energy sector as a whole is responsible for at least 663,000 jobs, comparable to almost 4.5 per cent of total payroll employment in 2012.
Near the Nequo enda end net of the ut por firstsolo quarter, blabo. producers Ut exerhave announced plans to spend billion ate estium est, veribusciat etur$55.8 seque nem verovite2013, during od que upeaabout dolenesti $214num million is sapieni from squunti initial plans oribus of $55.58 iditature billion. venis ent preius sitatquatur, Since their culliquiatis initial guidance nobitinpre latenobit, 2012 simus, or earlier sitas this que year, mincturit severaleat of hit thearunt 75 propa qui reptas ducers tracked sit, santi by the dolorer Daily chitatiis Oil Bulletin recus doluptam exceribus. have reported increases to their capital spending Eprehenim plans que for 2013. verro iusdae cum accae nonsendit oditis Oil idigenimus, optatibustio Tourmaline Corp. announced in maxim ament queboosting nest ut endit volorcapital simuFebruary it was its 2013 sapic to ereperrum nonsent que$650 non million comniprogram to $740 million from hil ipitatent and now expects fugitem. to produce Volecestis 80,000 as quo barrels odit alignatem idelian equivalent per daytiumqui versus the ut voluptatur original target aut rerro bearum idebit volori atemquid of 75,000 barrels per day, videbit as a result of the maximod essi conet in num que tur sucaut company’s exploration and production rerroinbearum cess its core idebit areas: volori the Alberta videbit Deep atemquid Basin, maximod Spirit Riveressi andconet the Montney in num que. in northeastern Nequo Columbia. British enda net ut por solo blabo. Ut exerate Tourmaline estium est, veribusciat etur seque10–11 nem is currently operating verovite od queand ea dolenesti num is capital sapieni drilling rigs, the increased program will allow it to continue to employ those rigs after spring breakup and for the balance of 2013.
squunti In January, oribus iditature Bellatrix Exploration venis ent preius Ltd. sitatquatur, and an unnamed culliquiatis South Korean nobit pre company nobit, simus, announced sitas aque joint mincturit ventureeat to hit develop aruntthe pa qui reptasproducer’s Canadian sit, santi dolorer undeveloped chitatiis Cardium recus doluptam lands in west-central exceribus. Alberta. Eprehenim As a result, queBellatrix’s verro iusdae net cum capital accae nonsendit idigenimus, optatibustio spending oditis plan for 2013 is expected to maxim ament que nest ut endit volor simuincrease to between $230 million and sapic ereperrum nonsent que non com$240 to million, not including joint-venture nihil partner ipitatent capital, fugitem. from $180 Volecestis million, as quo the odit alignatem company said. idelian tiumqui ut voluptatur Painted aut rerroPony bearum idebit Ltd. volori videbit Petroleum said in its atemquid maximod essi conet in num fourth-quarter financial release that que the Nequo endacapital net ut budget por solofor blabo. company’s 2013Ut is exerforeate estium veribusciat seque nem cast at $145est, million, of whichetur approximately verovite od que eamillion) dolenestiwill num sapieni 81 per cent ($117 beisdirected squunti gas oribus iditature ent preius toward projects. Lastvenis November, the sitatquatur, culliquiatis nobit budget pre nobit, company announced a capital for simus, 2013 ofsitas $120que million. mincturit eat hit arunt pa qui After reptassetting sit, santia dolorer preliminary chitatiis budget recus doluptam of approximately exceribus.$70 million for 2013, Connacher Oil and Gas Limited set its capital budget at $95 million for this year, consisting of $27 million in sustaining
Meridian manufactures several different models of Horizontal Double Wall Invert Drilling Fluid Tanks, along with a wide range of 400/750/1000BBL Oilfield Tanks & Double Wall ULC Approved Fuel Tanks, taking environmental protection to a whole new level. Meridian is the only tank manufacturer in Western Canada that has ovens large enough to offer our customers a fully Baked on Powder Coat Finish. Our many years of experience and dedication to quality shows in every product we build – give us a call today and let our sales team explain how Meridian can help with all your tank needs. Contact us today at 1-800-661-1436.
© 2013 Meridian Manufacturing Inc. Registered Trademarks Used Under License.
www.MeridianMFG.com
O I L & G A S I N Q U I R E R • M AY 20 13
15
In The News
capital and $68 million for new development projects to boost production. Drilling and development expenditures of $148.7 million will account for the lion’s share of Birchcliff Energy Ltd.’s $184.6-million capital budget for 2013, up from an earlier preliminary estimate of $160 million. The natural gas–weighted producer pla n s to d r i l l a tot a l of 31 (30 net) wells this year. That number includes 15 horizontal gas wells in the Middle/ Lower Montney formation for a total of $89.8 million and 10 Charlie Lake horizontal oil wells at Worsley, Alta., at a cost of $34.7 million. Other companies announcing plans to increase their 2013 budgets from initial plans include Whitecap Resources Inc. (up $8 million to a total of $160 million), Pinecrest Energy Inc. (up $6 million to a total of $136 million) and Delphi Energy Corp. (up from $49 million originally to $50 million to $55 million). Meanwhile, Twin Butte Energy Ltd. said a number of operational and reservoir performance issues at its Primate property in western Saskatchewan and
continued wide heavy-light oil diff erentials have forced it to downgrade expectations and capital expenditures for 2013. The company now anticipates a 2013 capital program of $85 million. This cut from the original $110-million capital plan will reduce 2013 forecast production by 900 barrels per day. Corporate
total of $132.5 million), Zargon Oil & Gas Ltd. (down $9 million to a total of $78 million), Arsenal Energy Inc. (down $7 million to a total of $42 million) and Bonavista Energy Corporation (down $2 million to a total of $423 million). This year’s capital spending plans do not include amounts for Nexen Inc. or Progress
Near the end of the first quarter, producers have announced plans to spend $55.8 billion during 2013, up about $214 million from initial plans of $55.58 billion.
average production for 2013, because of the reduced capital plan and the Primate property’s performance, is now anticipated to average approximately 17,400 barrels per day. Other companies reducing 2013 budgets from original plans include BlackPearl Resources Inc. (down $17.50 million to a
Energy Resources Corp. Both were taken over by state- ow ned oi l compa n ies and have not released spending plans for 2013. In 2012, Nexen set its capital budget at $2.95 billion, while Progress reduced its expected budget during the year to $270 million from an initial $465 million. — DAILY OIL BULLETIN
We’re expanding east.
Visit our newest branch location in Saskatoon. 514-45 Street East, Saskatoon, SK 306.715.2805 Unified Valve Group of Companies unifiedvalve.com | wgiltd.com | mercervalvecanada.com 16
M AY 20 13 • O I L & G A S I N Q U I R E R
YOU CAN TELL A LOT ABOUT SOMEONE BY THE COMPANY THEY KEEP. Tundra Process Solutions is proud to have aligned with these quality manufacturers to exceed your application requirements.
INSTRUMENTATION & CONTROLS
PIPES, VALVES & ACTUATION
MOTORS & DRIVES
Boilers & Water Treatment
Motors & Drives
Instrumentation & Controls
Pipe, Valves & Actuation
Calgary Office 7523 Flint Road S.E. Calgary, AB T2H 1G3 | 403.255.5222
Panels & Buildings
Artificial Lift
Service & Support
www.TundraSolutions.ca
Regional Offices Edmonton, Saskatoon, Fort McMurray, Red Deer, Grande Prairie, Swift Current
BRITISH COLUMBIA WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▲
▲
Ottawa pushing world-class tanker safety system
Photo: Joey Poblubny
A federal government announcement that it will spend $120 million over the next fi ve years on a number of measures to strengthen Canada’s tanker safety system, including more inspections and expanded aerial surveillance, has drawn a mixed reaction. While Enbridge Inc. welcomed the proposed changes, some aboriginal groups remain unconvinced that the new tanker safety plans would adequately protect their region from what they see as an inevitable oil spill. “We support initiatives focused on improving marine transportation safety. It is why Northern Gateway has gone to such great lengths to incorporate marine enhancements into its own safety plans,” Al Monaco, president and chief executive officer of Enbridge, says. “The announcement reinforces Enbridge’s view that a balance can be achieved in facilitating international trade that will support economic growth while protecting the environment.”
B.C. British Columbia
▲
Source: Daily Oil Bulletin
However, the Tsleil-Waututh Nation, a Coast Salish community on Burrard Inlet, says it is adamantly opposed to Kinder Morgan Canada’s expanded Trans Mountain project that terminates in its territory and would result in increased tanker traffic through Burrard Inlet. “The Harper government has stripped the environmental assessment process through Bill C-38, they’ve severely cut back…Fisheries and Oceans [Canada] a nd E nv i ron ment Ca nada, t hey ’ve closed the emergency oil spill office in Vancouver, they’ve closed the Vancouver [Canadian] Coast Guard station and they ’ve been called out by Canada’s environment commissioner,” Carleen Thomas, a Tsleil-Waututh elected councillor, says. “They’ve even gone to China to say that a pipeline is one of their top priorities. And now the Harper government expects us to believe that they are acting in the best interests of protecting B.C.’s coast?”
With more tanker traffic possible on the West Coast, the federal government is pushing new standards to improve safety.
The government announced a number of measures toward what it described as the creation of a “world-class tanker safety system” off both the west and east coasts of Canada—one of the five demands of the B.C. government if it were to support a crude oil pipeline to the West Coast. Denis Lebel, minister of transport, infrastructure and communities, and Joe Oliver, minister of natural resources, announced the implementation of eight tanker safety measures along with the introduction of the Safeguarding Canada’s Seas and Skies Act, and the creation of a
1,500 Number of tanker movements along the West Coast in 2009-10
three-member tanker safety expert panel to review Canada’s current tanker safety system and propose further measures to strengthen it. “As a trading nation, Canada depends on marine shipping for economic growth, jobs and long-term prosperity,” Oliver adds. “There will be no pipeline development without rigorous environmental protection measures and the tanker safety initiatives we are announcing today are an important aspect of our plan for responsible resource development.” As part of the process, the government says it plans to work and engage with aboriginal communities that have expressed concern about the devastating effect that a tanker mishap could have on the environment and on their livelihoods. Among the eight measures designed to strengthen Canada’s tanker safety system are increased tanker inspections to ensure that all foreign tankers are inspected on O I L & G A S I N Q U I R E R • M AY 20 13
19
British Columbia
LINKING PEOPLE & ENTERPRISE, SIMPLY ANYWHERE. As a leader in satellite communication technology, Infosat designs & integrates reliable wireless global communication systems where satellite facilities are a key component in remote & demanding locations.
Benefits To Working With Infosat Communications: ► Enterprise Class, Secure, Engineered Solutions For Data & Voice Communications ► 24 Hour Customer Support For All Solutions ► Reliable Global Coverage & Connectivity
Call us today and ask about how Infosat Communications can help you with your satellite communication needs.
1-888-524-3038 info@infosat.com www.infosat.com
20
M AY 20 13 • O I L & G A S I N Q U I R E R
their fi rst visit to Canada and annually thereafter to ensure they comply with rules and regulations, especially with respect to the required double hulls. With the expansion of the National Aerial Surveillance Program, aircraft will monitor shipping activities using remote sensing equipment, including an Environment Canada satellite tracking program that can identify potential spills from satellite images. More Canadian public ports will be designated for traffic control measures, starting with Kitimat, B.C., the proposed site of both crude oil and liquefied natural gas (LNG) export terminals, the federal government says. The tanker safety expert panel will be chaired by Captain Gordon Houston, a master mariner and the former president and chief executive officer of the Vancouver Fraser Port Authority. The panel will review Canada’s current system and propose further measures to strengthen it. “Our panel will work on recommendations to make a strong tanker safety system world-class,” says Houston. “Together, our panel members have 120 years of maritime experience and a deep commitment to the environment.” In the coming months, the panel will consult with key stakeholders to enhance the government’s knowledge and understanding of how well the current system is working, review current preparedness and response capacity, and propose new ways to bring Canada’s tanker safety system to a world-class status. The review will have two components: the first component will focus on the system currently in place south of 60 degrees north latitude; the second component will focus on the requirements needed for the Arctic as well as a national review of the requirements for hazardous and noxious substances, including LNG. In addition to the public port designations and increased tanker inspections, measures to strengthen Canada’s tanker safety system include: • Incident command system: The government will establish a Canadian Coast Guard (CCG) incident command system, which will allow it to respond more effectively to an incident and integrate its operations with key partners. • Pilotage programs: A review of existing pilotage and tug escort requirements to see what more will be needed in the future. • Public port designations: Beginning with Kitimat, the proposed site of both crude oil and LNG export projects, more ports will be designated for traffic control measures. • Scientific research: The government will conduct scientific research on non-conventional petroleum products, such as diluted bitumen, to enhance understanding of these substances and how they behave when spilled in the marine environment. • New and modified aids to navigation: The CCG will ensure that a system of navigational aids comprised of buoys, lights and other devices to warn of obstructions and to mark the location of preferred shipping routes is installed and maintained. • Modern navigation system: The CCG will develop options for enhancing Canada’s current navigation system (e.g. aids to navigation, hydrographic charts, etc.) by the fall of 2013 for government consideration. The federal government also has tabled legislation to amend the Canada Shipping Act, 2001 to strengthen ship-source oil spill preparedness and response, introduce new requirements for
British Columbia
“Our panel will work on recommendations to make a strong tanker safety system world-class.” — Captain Gordon Houston, chair of tanker safety expert panel
oil-handling facilities, and establish new offences for the contravention of pollution prevention provisions in Canada’s waters, including administrative monetary penalties (civil fi nes designed to ensure compliance with legislation as well as regulations). The proposed amendments will strengthen the current requirements for pollution prevention and response at oil-handling facilities, requiring operators to be proactive in the prevention of spills and also to have the capacity to effectively respond to a spill, if required. Oil-handling facilities currently are required to have emergency response plans in place. However, they are not obliged to submit these plans to Transport Canada. These amendments will make it mandatory for operators to provide these plans to Transport Canada to ensure they meet the regulations. The proposed amendments also will increase Transport Canada’s oversight and enforcement capacity by equipping marine safety inspectors with tools to effectively ensure compliance, introducing new offences for contraventions of the act and extending the administrative monetary penalty provisions to the pollution prevention and response portion of the act. Doing so will give marine safety inspectors the ability to impose administrative monetary penalties to oil-handling facilities not in compliance with regulations. In addition, the legislative changes would enhance response to oil spill incidents by removing legal barriers that could otherwise block agents of Canadian response organizations from participating in clean-up operations. At present, Canadian oil spill response organizations have civil and criminal immunity in the act when they respond to spills from ships. This immunity would be expanded to responses to spills from oil-handling facilities and immunity would be provided to foreign response organizations. In announcing its plans, the federal government notes that oil tankers have been moving safely along the West Coast since the 1930s. In 2009-10, there were about 1,500 tanker movements along the West Coast among 475,000 vessel movements in the area. The only significant oil spill on the West Coast, in 2006, was not tanker related but involved a ferry that sank with 240 tonnes of oil on board. Prior to that, in 1988, Vancouver Island was affected by a spill from an oil barge that lost approximately 1,000 tonnes of oil. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AY 20 13
21
British Columbia
Kitimat refinery has economic merit, says review
Manufacturer of: • Water storage tanks up to 12,000 imp. gal. • Water hauling tanks 12015 - 152 STREET • Chemical tanks
• Secondary containment basins • 100, 300, 500 & 1,000 gallon double wall tanks
ALSO IN GRANDE PRAIRIE ®
12015 - 152 Street, Edmonton, Alberta, T5V 1G4 Ph: (780) 474-7440 Fax: (780) 474-3454 Toll Free: 1-888-474-7441
ALSO IN GRANDE PRAIRIE www.norwescocanada.com Email: info@norwescocanada.com
22
M AY 20 13 • O I L & G A S I N Q U I R E R
A review done by Navigant Consulting Inc. for the B.C. government found that the proposed Kitimat refinery touted by newspaper publisher David Black has economic merit. In the report, Navigant concluded that, based on the information available at the present time, building a refi nery on the coast of British Columbia “has economic merit and should be considered seriously by the government of the province.” Such a refinery would provide incremental long-term economic benefits to the region, compared to export of unfinished feedstock. In addition and equally important, the report said that if configured carefully and managed properly, the refinery would create sustainable margins that otherwise would be lost to Asian purchasers of Canada’s oilsands production. “Furthermore, it is our recommendation that the province approve a design for Kitimat that would make it capable of manufacturing fuel products for...myriad...countries around the Pacific Rim,” Navigant stated. “This would preclude being tied into only a few destination markets—or perhaps just one.” It is Navigant’s opinion that the refi nery configuration recommended by Kitimat Clean Fuels (KC) is technically sound. “They have suggested using a combination of hydrocracking and delayed coking to process oilsands from Alberta into various clean fuels,” the report stated. “This particular configuration is well proven and widely employed in many locations around the world.” KC originally estimated the cost of a new refinery at Kitimat to be about $13 billion. “Although we were provided with very little detail supporting this estimate, Navigant was able to compare to another proposal of similar size and configuration—albeit from 2006,” the report stated. Black, who announced the project last year, told a business audience in Vancouver recently that he expects to sign a memorandum of understanding with Swiss-based Oppenheimer Investments Group for the proposed refinery.
Photo: Joey Poblubny
Suncor Energy Inc. refinery near Edmonton. A similar refinery based on bitumen should be considered for the West Coast, said a new report.
British Columbia
According to a recent update from Black, the projected capital cost for a proposed refinery near Kitimat is now $16 billion, up from the previous $13 billion. “It will likely be accompanied by an oil pipeline costing an additional $6 billion, which wouldn’t get built otherwise, and a gas pipeline costing $2 billion. It may even be accompanied by new ocean-going tankers, which could cost an additional $1 billion. The total of all this is $25 billion,” Black said during a presentation earlier this month. Speaking to the original $13-billion figure, Navigant concluded that KC’s cost projection might be on the high side. The consultancy said it’s also fair to say, however, that the 2006 case study is not fully representative of current costs, despite being similar in size and configuration to Kitimat, because: • Expenditures for capital equipment and labour have risen since 2006; • The remoteness of the Kitimat site will, without doubt, increase construction costs considerably. Navigant has not examined the magnitude of such an increase; • The 2006 U.S. refi nery did not need a new plant for power generation, but one will be required at Kitimat; and • The U.S. example was not designed to process oilsands, so it is a somewhat imperfect comparator for Kitimat. If these factors are taken into consideration, Navigant would expect the “total installed cost” of Kitimat (including the power plant) to exceed $7 billion. “It is not possible at this stage to provide a more precise estimate. We would therefore recommend that a more detailed projection of capex [capital expenditure] for Kitimat be carried out,” the report stated. Navigant also analyzed the fuel product supply and demand balance for each of the four target countries from 1990 to 2010 (China, India, South Korea and Japan), as well as for the entire Asia/Oceania region. Despite strong economic growth in some Asian countries, the aggregate demand for product imports has been surprisingly stable at roughly two million barrels per day for about the last 15 years. Thus, the output from Kitimat (0.5 million barrels per day) could be accommodated by markets in Asia/Oceania without major disruption to local spot markets, the report stated. KC’s recommendation is to construct a 550,000-barrel-per-day greenfield, deep conversion refinery on the 3,000-hectare Dubose site, which is Crown land and is located roughly midway between Kitimat and Terrace. Feedstock for the Kitimat facility, if it were to be constructed, would consist of natural gas (for power generation and hydrogen production) and diluted bitumen. Finished products would include propane, details on volume not available; gasoline at 100,000 barrels per day; jet fuel/kerosene at 50,000 barrels per day; diesel at 240,000 barrels per day; petroleum coke, details not available; and sulphur, details not available. The report said that one advantage to a refinery versus exports of bitumen is that vessels used to export products would, on average, be considerably smaller. Navigant said the largest would be Long Range II (70,000–100,000-plus tonnes) product tankers. Given the smaller parcel sizes with products, however, the number of vessel movements would, by necessity, have to increase. — DAILY OIL BULLETIN O I L & G A S I N Q U I R E R • M AY 20 13
23
NORTHWESTERN ALBERTA WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▲
▼
▼
Source: Daily Oil Bulletin
N.W. Northwestern Alberta
Northwest drives final land sale of the year By Richard Macedo
Photo: Joey Podlubny
Alberta attracted $1.04 billion in land-sale revenue during its 2012-13 fi scal year, as auction spending cooled off significantly from 2011-12. For the fiscal year, a total of 3.16 million hectares exchanged hands at an average price of $330.02 per hectare. At last year’s budget, the government had forecast $2.04 billion in land sale revenue for 2012-13. In 2011-12, Alberta attracted $3.29 billion in bonus bids, the second-highest fiscal year haul of all time. A total of 4.19 million hectares were sold at an average of $785.42 per hectare. The fiscal year record of $3.45 billion was reached in 2005-06 thanks to heavy spending for oilsands acreage. Third on the list is 2010-11, when industry spent $2.62 billion, while in 2006-07, the province attracted $2.38 billion in bonus bids. At the final March sale of the 201213 fiscal year, which ended on Mar. 31, 2013, the provincial government attracted $37.36 million in bonus bids on 100,963 hectares at an average of $370.01 per hectare.
Interest in the Wapiti area drove the final Alberta land sale of the year.
For the 2013 calendar year, Alberta has brought in $231.46 million for 702,173 hectares at an average of $329.63 per hectare. To the same point of 2012, $310.69 million had come into provincial coff ers on 704,635 hectares at an average price of $440.92 per hectare. Highlights of this sale included three licences around 64-07W6 and 64-08W6 that combined for total bonus bids of $11.38 million. Steve Hager, senior exploration analyst with Canadian Discovery Ltd., said that the parcels, located in the southeastern corner of the Wapiti field, were posted and purchased for liquids-rich gas potential in the Triassic Montney formation, which is being developed by Paramount Resources Ltd., Seven Generations Energy Ltd. and Contact Exploration Inc. at Kakwa to the east. Those three parcels include mostly petroleum and natural gas rights below the Cretaceous. Brad Hayes, president of Pet rel Robertson Consulting Ltd., added that parcels are posted for deeper rights. “I think Montney was the driver, not the shallower Cretaceous zones,” he said. One of these parcels, a 768-hectare licence, was acquired by O & G Resource Group Ltd. for $5.23 million, which produced an average price of $6,806.96 per hectare. The broker picked up two tracts. The first tract is located at section six of 64-07W6 for petroleum and natural gas below the base of the Spirit River formation. The second tract included section seven at 64-07W6 and section 12 at 64-08W6 for petroleum and natural gas below the base of the Bluesky-Bullhead. O & G also picked up an adjacent 512-hectare licence for $3.49 million, which
produced a per-hectare average of $6,806.96. The parcel included sections 17 and 21 at 64-07W6 for petroleum and natural gas below the base of the Bluesky-Bullhead. Scott Land & Lease Ltd. acquired the third of these parcels. The broker paid a bonus of $2.66 million for the 768-hectare parcel at an average price of $3,468.87 per hectare. Scott scooped up sections 10, 14 and 15 at 64-08W6 on behalf of its client for petroleum and natural gas below the base of the Bluesky-Bullhead.
3.16
million hectares
Amount of land leased in Alberta during the 2012-13 fiscal year
Meanwhile, a bid by Sandstone Land & Mineral Company Ltd. produced the land sale per-hectare high of $10,363.86. The parcel, a 512-hectare licence, also attracted the auction bonus high of $5.31 million. The broker acquired sections 23 and 24 at 66-03W6, which included all rights. Hager said the two-section parcel in the Karr field is located two townships east of the Paramount-operated Karr Montney A Pool, which has produced 4.5 billion cubic feet of gas with 123,200 barrels of condensate from 14 wells since 2008. Four miles south of the subject licence, Celtic Exploration Ltd. recently completed a horizontal Montney development well at Karr, 16-28-065-03W6, which is flowing gas at two million cubic feet per day with no liquids reported. Canadian International Oil Operating Corp. is also actively drilling Montney horizontals in the area. Hayes added that it appears that Dunvegan oil is a target here, but there may be Montney prospectivity as well. O I L & G A S I N Q U I R E R • M AY 20 13
25
Northwestern Alberta
Donnycreek continues success at Kakwa Donnycreek Energy Inc. reports that the third horizontal Kakwa Montney well at 03-19-063-05W6 has been successfully completed and tested. The well was flow-tested for 161 hours. During the fi nal 24 hours of flowback, the well averaged gross production rates of 1,798 barrels equivalent per day, consisting of 826 barrels per day of condensate and 5.83 million cubic feet per day of natural gas (899 barrels equivalent per day net to Donnycreek) against anticipated gathering system pressure of approximately 5,000 kilopascals. The company advises that although the initial rates from the
Donnycreek Energy Inc. expects the drilling of the next well on its 50 per cent Kakwa block to start post-breakup.
After 10 years of providing Land and Environmental services throughout BC and Alberta, we have witnessed the evolution of the energy industry. Our company has taken great pride in itself on driving regulatory policy, cooperative project planning with our clients, and the active role we play within our community.
03-19 well are very encouraging, production test results are not necessarily indicative of long-term performance or of ultimate recovery from the 03-19 well. Donnycreek said the successful drilling and completion of the 03-19 well continues to demonstrate that its Kakwa lands are in the heart of the liquids-rich Montney trend, validating the repeatability of this prolific play. Equipping and facilities work will begin immediately to add additional liquids-handling equipment on site that will accommodate both the 03-19 well and the previously announced second horizontal Kakwa Montney well at 14-30-063-05W6, drilled from the same surface location. It was anticipated that production from both wells would begin in mid-April. The company expects the drilling of the next well on the company’s 50 per cent Kakwa block to start post-breakup.
As we move into the next 10 years, we are excited to announce a new face for BV Land and Northern Rockies. As of October 1, 2012, BV Land Consulting Ltd. and Northern Rockies Environmental Services Ltd. will be combined under our new name: BV Land Corp.
26
Corporate Office: 9807-100th Avenue Fort St. John, BC V1J 1Y4 Office: 1-250-785-6340 Fax: 1-250-785-6351 Ft. St. John: 1-250-261-1802
Calgary Office: Suite 203A 708-11th Avenue SW Calgary, AB T2R 0E4 Office: 1-403-718-9587 Calgary Cell: 1-403-860-9634
Email: brianv@bvland.com
Website: www.bvland.com
M AY 20 13 • O I L & G A S I N Q U I R E R
Donnycreek’s third Montney well tested at peak rates of 1,798 barrels equivalent per day.
Photo: Joey Podlubny
With continued service from our Fort St. John and Calgary offices, we look forward to the new opportunities and challenges the next decade will bring and are eager to share in them with our new and existing clients as well as all the folks we have met along the way.
TANKS
TREATERS
PUMPJACKS
THE OILFIELD EQUIPMENT PEOPLE.
PLATINUM Energy Group 1-888-745-4647
www.platinumenergycanada.com
Tundra Now Represents ABB, the World Leader in Measurement & Instrumentation Solutions ABB measurement products provide the best-in-class technology, reliability and service in the business. » Wired & Wireless Transmitters: Pressure, Temperature, Differential Pressure, Level and more » Flow: Magnetic, Vortex, Swirl, Coriolis, Thermal Mass, Variable Area, Totalflow Computers, & Differential Flow Elements » Analytical: Totalflow Natural Gas Chromatographs, pH, ORP, Combustion Gas Analyzers, and more » Valve Actuation: Actuators and Positioners » Recorders & Controllers: Process Recorders, Controllers & Indicators
Boilers & Water Treatment
Calgary Office 7523 Flint Road S.E. Calgary, AB T2H 1G3 | 403.255.5222
Motors & Drives
Instrumentation & Controls
Pipe, Valves & Actuation
Panels & Buildings
Artificial Lift
Service & Support
Regional Offices Edmonton, Saskatoon, Fort McMurray, Red Deer, Grande Prairie, Swift Current
N.E.
NORTHEASTERN ALBERTA WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▲
▲
Northeastern Alberta
▲
Source: Daily Oil Bulletin
Trains could carry 800,000 barrels of bitumen per day by 2014 By Carter Haydu
Photo: Gerald Ford
Rail transport could more than meet the growing demand from oilsands producers for market access even in the absence of the proposed Keystone XL Pipeline, said a U.S. Department of State report. By late 2014 there will be enough insulated railcars to transport about 800,000 barrels per day of bitumen with little or no diluent, equivalent to just over one million barrels per day of dilbit, according to a market analysis included in the draft Supplemental Environmental Impact Statement (SEIS) for Keystone XL. That’s more than the initial 830,000 barrels per day of dilbit that would be transported on the proposed pipeline. However, while North American railway tracks are in place, more tank cars along with loading and unloading infrastructure are needed, and those issues are being addressed. According to the report, U.S. rail tank car production is currently about 5,000
units per quarter (about 18,000 cars per year). However, orders for new cars are around 8,800 units per quarter, with a 2012 backlog of about 46,700 cars expected to be cleared in 2014. This would add about 1.75 million barrels per day of railway freighting capacity for U.S. and Canadian crude over the next 18–24 months. At least 60 per cent of the tank cars in production are insulated and contain steam coils able to reheat bitumen as needed. “This high percentage is a strong indicator that most of the tank cars on order are either able to carry heavy oilsands crude, or give carriers the flexibility to do so,” said the report. In the absence of new pipeline infrastructure crossing the border, the report noted, rail offers a large-scale transport option for crude oil from the Western Canadian Sedimentary Basin (WCSB) to the United States. And despite the fact that there is a reduction in carrying capacity per car when moving undiluted bitumen, the
The U.S. State Department says trains could meet market demand to ship oil in the absence of approval of the Keystone XL Pipeline.
ability of rail to reduce or eliminate diluent could potentially reduce the total heavy crude volumes that must be shipped from western Canada and increase the volumes of diluent returned. Because tank car load limitations are by weight rather than volume, less raw bitumen can be carried compared to dilbit or light crude; a railcar will be able to carry about 550 barrels of undiluted bitumen versus 650–700 barrels (or more) of light crude. The report assumed all crude oil rail movements occur in unit trains of 100
8,800 Number of new rail tank cars being ordered each quarter in the United States
railcars that transport all their cargo from a single starting point to a single end point with no intermediate stops or storage. However, the number of railcars in unit trains transporting crude oil may vary; BNSF Railway Company recently announced it was considering unit trains of 118 cars. Based on information from the Canadian Association of Petroleum Producers (CAPP), the draft SEIS suggested if no new pipeline capacity is added out of western Canada, rail must be able to accommodate an expected annual industry expansion of about 175,000 barrels per day annually through 2035, in order to keep up with crude supply and prevent shut-ins. In order for rail to accommodate that growth, loading and unloading facilities would need to be developed to handle crude. Fortunately, the report suggested, in 2012 the Canadian National Railway Company (CN) had approximately 14 O I L & G A S I N Q U I R E R • M AY 20 13
29
Northeastern Alberta
crude oil loading facilities completed or under construction, and other midstream operators are constructing crude-byrail terminals as well, with at least eight WCSB producers either freighting crude by rail or planning to do so by the end of the year. CN and Canadian Pacific currently are moving approximately 200,000 barrels of crude per day, including 120,000 from the WCSB, the report suggested. In the United States, according to the draft SEIS, rail on- and off-loading facility construction is on the increase, with approximately one million barrels of offloading capacity in place as of the end of 2012. Unit train off-loading on the U.S. Gulf Coast was estimated at more than 600,000 barrels per day early this year. According to the report, estimating comparative costs for rail transportation of oilsands bitumen is not straightforward, as producers can transport bitumen in a variety of ways. While dilbit and synthetic crude can be freighted in regular tank cars, they include the cost to ship a lot more diluent. While railbit and raw bitumen require
The Canadian National Railway Company and Canadian Pacific currently are moving approximately 200,000 barrels of crude per day, including 120,000 from the Western Canadian Sedimentary Basin, the draft Supplemental Environmental Impact Statement suggested.
Are
Decision MAkers
finDing your
little or no diluent, they require special insulated tank cars and modified terminals. Rail transport of dilbit from the WCSB to the Gulf Coast is estimated at $15.50 per barrel, the report suggested, while an estimated pipeline tariff for the same transport would be about $8 to $9.50 per barrel (according to CAPP 2012 figures), suggesting that rail transport for dilbit is about $6 to $7.50 per barrel more expensive than by pipeline. However, those estimates likely overstate the cost difference because they compare a long-term committed pipeline tariff with contracts of 10–20 years to short-term and uncommitted rail prices, the draft SEIS cautioned. It pointed out that an uncommitted pipeline tariff would be approximately $14 per barrel, reducing the estimated difference to $1.50 per barrel. Nor does the estimated cost reflect the higher expense associated with a pipeline of acquiring the diluent, paying tariffs to transport it and returning it to Alberta, the report said. Net rail transport costs for dilbit, in fact, can be reduced by backhauling diluent on cars during their return trips.
LAst yeAr, over 172,000 peopLe useD tHe buyer’s guide to cAnADA’s oiL & gAs inDustry. DiD tHey finD your coMpAny? Oil and gas industry decision makers are actively using the COSSD to search for and buy products and services. Is your company in the database where it can be found?
ASAP CANCELLED 16% FILL REQUEST 42%
coMpAny?
of COSSD.com visits are from exploration and production companies. are from primary and secondary purchasers like pipeline operators, EPCM companies and manufacturers.
19%
growth of COSSD usage in the past six months alone.
Become a part of this fast-growing buyer/seller community— contact Christopher Kuntz at 403.516.3492 or ckuntz@junewarren-nickles.com.
COSSD.COm
30
M AY 20 13 • O I L & G A S I N Q U I R E R
Northeastern Alberta
Market conditions kill Voyageur By Lynda Harrison
Now that the Voyageur upgrader won’t be built, Total E&P Canada Ltd. said it will send about 280,000 barrels per day of raw, diluted bitumen to market if its two proposed mines, Joslyn and Fort Hills, are built. “As you know...today there [are] plenty of light products due to the unconventional oil and gas production, so finding the diluent is not an issue any more; in fact, [it is] part of the rationale not to upgrade anymore,” said André Goff art, president and chief executive officer of Total. Suncor Energy Inc. and Total announced in late March that they have decided not to proceed with the 200,000-barrel-per-day Voyageur upgrader. Total is working on optimization of Joslyn and is working on its regulatory process before it can give a firm date on start-up, said Goffart. Its permits have to be renewed because it is revising its capacity,
he added. Neither Joslyn nor Fort Hills have been sanctioned. Total and Suncor are working together to develop the logistics to transport diluted bitumen by proposed pipelines in which they have taken positions, said Goffart. “We believe that with the right conjunction of logistics, our projects shouldn’t be affected by the decision,” Goffart said. Total was going to build a 295,000barrel-per-day upgrader near Edmonton to process bitumen from its proposed Joslyn mine, but in 2010 made a deal with Suncor to use the Voyageur upgrader instead. In making the decision not to proceed with the upgrader, global market conditions considered included the rise of tight oil production; increased competition for light, sweet oil refining capacity; decreasing margins; market access issues; demand for Suncor’s products; and new applications of technology, said Suncor spokesperson Sneh Seetal.
Suncor also acquired Total’s interest in the Voyageur Upgrader Limited Partnership for $515 million to gain full control over the partnership’s assets. Those assets include a tank farm with a hot bitumen terminal, an interim storage facility that will be connected to a hot bitumen pipeline that brings product from Firebag 4 and a camp facility called Hudson Lodge. As a result of not proceeding with the Voyageur upgrader near Fort McMurray, Suncor expects to incur a charge to first-quarter 2013 net income and cash flow from operations of approximately $140 million and $180 million, respectively. The charge is the result of a number of items including contract-termination costs, said Seetal. Total said it would book a net loss of $1.65 billion in the fi rst quarter of 2013 as a result of selling its 49 per cent stake in the project to Suncor.
www.defopt.com
Oil and Gas Well Optimization 8
• Removal of liquids in “loaded” or “loading” gas wells • Plunger Tracking • Pumping well optimization and analysis
6
4
5
3
1
D
C
C
B
ISO VIEW
OPTION: PHOSPHATE COATING 4140 MAT' PLUNGER GENERAL TOLERANCES
• Pressure data logging
2
D
DRAWING REFERENCES:
MACHINED TOLERANCES UNLESS OTHERWISE SPECIFIED: FRACTIONAL 1/16" ANGULAR: MACH .5 BEND 1.0 TWO PLACE DECIMAL 0.010 THREE PLACE DECIMAL 0.005
A
DIMENSIONS IN INCHES. METRIC SHOWN AS [XX.XX] IN MILLIMETERS AS ALTERNATE MATERIAL:
AISI 4140 HTSR (Rc 28-34) FINISH:
-
SCALE
PROPORTIONAL UNLESS INDICATED
8
7
6
5
4
3
INIT: DRAWN BY:
BPT
CHECKED BY:
LG
ENG APPR:
BPT
DATE
CLIENT:
Internal Engineering
20080805 TITLE:
20100712 18" Solid Spiral Fish Bone
A
20100712 2 3/8" Artificial Lift Plunger
THIS DRAWING AND THE INFORMATION CONTAINED THEREIN IS THE PROPERTY OF DEFINITIVE OPTIMIZATION AND IS SUPPLIED SOLELY FOR THE PURPOSE FOR WHICH IT IS INTENDED. THE DRAWING AND ALL INFORMATION CONTAINED THEREIN SHALL NOT BE COPIED IN WHOLE OR IN PART AND MAY NOT BE PASSED TO A THIRD PARTY WITHOUT THE WRITTEN PERMISSION OF
DEFINITIVE OPTIMIZATION. COPIES OF THIS DRAWING
IS ISSUED SUBJECT TO RETURN UPON REQUEST.
2
SIZE DWG NO:
B KEI-PLUN-2375-201-006-01
WEIGHT: 8.75 Lb
SHEET 1 OF 1 REV: 02 1
• DIR 17 Flow Measurement • AAWS (Automatic Acoustic Well Sounder) • Surface facility optimization • Field surveys focused on facility optimization • Sales, installation and maintenance • In house enineering • Custom built equipment to suit your needs • Superior products/professional service
ERCB and OGC Regulatory and Compliancy Testing
Canadian Manufactured for Canadian Environments
General Manager Clint Mason 403-318-9762 Asst. Manager/International Acct Sean Gruner 403-820-4675 Calgary Sales Terry Levinsky 403-200-7635 Drumheller Distribution Centre 403-823-2218
O I L & G A S I N Q U I R E R • M AY 20 13
31
Northeastern Alberta
Construction of Voyageur was suspended in 2008. It was intended to process bitumen production at the proposed Fort Hills and Joslyn mines. By late 2010, $4 billion had been spent on the project, whose total costs were pegged at $11.6 billion. Last year, Suncor said its Montreal refi nery was a candidate to process its oilsands production. Analysts had recently predicted that Suncor would nix the project and Suncor itself had hinted as much. The company admitted in February when announcing its third-quarter results
TOUGH JOBS DEMAND TOUGH PRODUCTS.
By late 2010, $4 billion had been spent on the Voyageur Upgrader project, whose total costs were pegged at $11.6 billion.
With all the potential threats to your productivity, don’t let your equipment be another question mark.
Goodyear Engineered Products are built for maximum value, efficiency and longevity. With our vast array of specialized oilfield products, we can help you achieve all your production goals — from site prep to drillings, to fracing, to cementing, water transfer and beyond. Let us help.
To find a Goodyear Engineered Products Distributor near you and download our Oil + Gas Brochure, visit GoodyearEP.com/OilGas or call 800.235.4632. The GOODYEAR (and Winged Foot Design) trademark is used by Veyance Technologies, Inc. under license from The Goodyear Tire & Rubber Company. Goodyear Engineered Products are manufactured and sourced exclusively by Veyance Technologies, Inc. or its affiliates. ©2013 Veyance Technologies, Inc. All Rights Reserved.
32
M AY 2 • O I L & G A S I N Q U I R E R
that the economic outlook for the Voyageur upgrader project was “challenged,” and said it would announce its decision on whether or not to go ahead with it by the end of the first quarter of 2013. Suncor and Total had agreed to minimize expenditures on the project in the meantime. At the end of the fourth quarter of 2012, Suncor recorded an after-tax impairment charge of $1.49 billion related to the upgrader. Suncor and its partners have said they would announce a sanction decision for the Fort Hills mining project—likely delayed until 2017—in the second half of 2013, and Suncor has yet to announce the timing of a sanction decision on the Joslyn mine. As part of its joint venture with Suncor, Total had a 38.25 per cent interest in the Joslyn North mine, a 49 per cent interest in the Voyageur upgrader and a 39.2 per cent interest in the Fort Hills project. In addition to Suncor, which has a 36.75 per cent interest, Total’s partners in Joslyn North are Occidental Petroleum Corporation (15 per cent) and INPEX CORPORATION (10 per cent).
Northeastern Alberta
Forget Alberta upgrading, just increase oilsands output, IHS CERA suggests By Pat Roche
Shipping non-upgraded bitumen out of Alberta has the potential to create more jobs and economic benefits within the province, said a U.S.-based consultancy. “The shift away from new oilsands downstream processing facilities in Alberta has the potential benefit that labour that otherwise would be devoted to constructing those facilities is redirected towards increasing oilsands production,” Cambridge, Mass.–based IHS CERA said. The IHS press release was issued at around the same time Suncor Energy Inc. announced its historic decision to forgo upgrading on its next major oilsands expansion. The decision is significant because Suncor, which achieved Canada’s first commercial oilsands production in 1967, has traditionally included upgrading capacity in its major expansions. “Oilsands production facilities provide more long-term jobs than upgraders or refineries,” the IHS press release said. “Consequently, when construction workers are deployed to build upgraders—resulting in fewer oilsands production facilities being built—this actually reduces the number of long-term jobs in Alberta.” IHS also noted Alberta royalties are based on production of bitumen, not synthetic crude, so provincial royalty revenue isn’t increased by upgrading. While secondary processing is sometimes touted as a way to increase economic value, IHS suggested upgrading could actually have the opposite effect on income taxes. “ Fac i ng c h a l le ng i ng e conom ic s, Alberta upgraders may struggle to generate positive cash flow and consequently pay less income tax,” the press release warned. “Since oilsands projects generate positive returns, higher production and cash f lows results in more income tax revenue.”
I
n 2010 Predator was involved in a flash fire testing at a university for FR rated coveralls. A discussion arose about a garment that could not only give the best FR protection, but based on early lab results, reduce the potential and severity of hot fluid transfer burns to the wearer. Intrigued, Predator embarked on a cooperative field test in 2011 and the results were greater than anticipated. Convinced, we worked closely with Westex to create a one and only, unique to our industry, ‘Hybrid’ Coverall. Once again proving that working with industry, we can design a safer workplace for our future.
The WeSTeX/PredaTor
Hybrid Coveralls
www.predatordrilling.com
(403) 346-0870
O I L & G A S I N Q U I R E R • M AY 20 13
33
Northeastern Alberta
Remote Location WoRk FoRce Housing / oFFices DeaLeR FLeet RequiRements moDuLaR constRuction
oPen camP Locations Ring BoRdeR open camp - North of Ft. St. John Km 92 HigH SieRRa - East of Ft. Nelson Km 178 HigH SieRRa - Northeast of Ft. Nelson BucKingHoRSe Lodge - Mile 175 on the Alaska Hwy JanvieR, aLBeRta Km 227 on Hwy 881 conKLin coRneR, aB Km 175 on Hwy 881
12345 - 121 Street • Edmonton, AB T5L 4Y7 P 780.448.9222 • F 780.454.7900
1.800.207.9818 northgateindustries.com
Pressure Vessels By
Over
12,000
Vessels Built to Date
Separators Dehydrators Treaters FWKOs Scrubbers Swab Vessels
Line Heaters Steam Splitters Coil Rolling Drip Pots External Level Cages Filter Vessels
5715-56 Avenue, Edmonton, Alberta p: 780.434.0222 | f: 780.436.1467 e: info@penfabco.com
www.penfabco.com
34
M AY 2 • O I L & G A S I N Q U I R E R
The conclusions are based on a 25-page IHS CERA paper titled Extracting Economic Value from the Canadian Oil Sands. Though the IHS researchers generally seem to feel that upgrading in Alberta is a bad idea, their paper said returns for upgrading on Canada’s west coast are “a bit stronger” than in Alberta. “The outlook for West Coast oil price is comparatively higher, owing to the oversupply of light crudes in inland North America, which—even considering new pipeline connections—is expected to depress Alberta prices compared with coastal ones— potentially in the range of US$2 to US$3 per barrel,” the paper said in a footnote. But when it comes to refinery construction, China has the biggest advantage over North America because of low capital costs due to cheap labour, the paper said. “The current reality is that, in many cases, new value-added upgrading and refining investments in Alberta have challenging economics and investors do not get a reasonable return on the billions they must commit for a bitumen processing facility,” said Jackie Forrest, IHS director of global oil and oilsands specialist, in the press release. “Producers would be taking additional steps and spending more money to upgrade or refine oilsands, when the strongest demand is for non-upgraded products.” The paper lists several upgrading and refining projects as cancelled or delayed— future phases of the CNOOC Limited upgrader, Syncrude Canada Ltd.’s Mildred Lake debottleneck and expansion, Value Creation Inc.’s upgrader, a Royal Dutch Shell plc Scotford expansion, a Statoil Canada Ltd. upgrader, Total E&P’s Northern Lights upgrader, Peace River Oil Inc.’s Bluesky refinery/upgrader and a potential expansion of Husky Energy Inc.’s Lloydminster upgrader. However, the CNOOC (former Nexen Inc.) upgrader’s future phases were iced because the associated steam assisted gravity drainage project’s abysmal production performance fi lled only about half of the existing upgrader’s capacity, even though many additional wells were drilled. Syncrude is trying to minimize outages, but those outages have more to do with the ore-separation process than the upgrader, suggested Marcel Coutu, president and chief executive officer of Canadian Oil Sands Limited, Syncrude’s lead partner. In a conference call with analysts after releasing Canadian Oil
Northeastern Alberta
Sand’s 2013 budget, Coutu opined that the biggest bottleneck at Syncrude today is in the intermediate operation that separates bitumen from sand and other solids, which then causes problems in the upgrader. Peace R iver ’s Blue sk y ref i ner y/ upgrader was a bit of a long shot because the $2.5-billion project didn’t have a backer such as a Shell or a Husky. Total and Statoil don’t yet have the Canadian production volumes traditionally associated with upgraders, but several upgrader developers now say smaller upgraders can be economic— including Value Creation. Value Creation’s upgrading plans remain very much alive. The company has applied for regulatory approval for a pilot test of its field upgrading process designed to take fluids directly from the wellbore. Privately held Value Creation has also said it is in talks with Asian and Canadian companies in hope of reaching a deal to resume construction of its Heartland upgrader, which was mothballed after the global financial crash. Asked to comment following Suncor’s announcement, Columba Yeung, president of Value Creation and a former Shell downstream executive, said: “People make assessments based on conventional technologies and approach.” In an email, Yeung acknowledged: “Clearly, there is indeed a significant cost disadvantage in Alberta due to cold weather and runaway labour costs.” But he disputed the perception that building more pipelines will be a total panacea for Alberta’s oil glut because a relatively small percentage of refineries can process diluted bitumen. Value Creation’s upgrading process would produce a medium crude that Yeung says a much larger percentage of refineries can process. “There are a whole bunch of factors/ problems to resolve creatively. We are certainly resolving them ourselves,” Yeung wrote, adding his company plans to soon launch an information package detailing for government and industry how he believes many of the problems associated with upgrading in Alberta can be fi xed. Yeung isn’t alone. At least three other companies are pressing ahead with plans for Alberta upgrading projects: • North West Upgrading Inc. and Canadian Natural Resources Limited (CNRL) are building the 50,000-barrelper-day first phase of their jointly owned Redwater upgrader/refinery
Diversified Glycol Services Inc. TEG
TEG
OU T
IN SLUDGE
REDUCE
Secor Isnetworld Complyworks Pics Decades of experience
Glycol Transportation Contractor Disposal
COST$!!
All gylcols... Economics work across the province! diversifiedglycol@yahoo.ca
P.O. Box 888 Red Deer, AB T4N 5H3
403-343-9555
1-888-242-7270
Custom solutions…
From a custom manufacturer. 1-888-227-4923 Phone: (403) 227-7799 Fax: (403) 227 -7796 E -Mail: sales@bilton.ca W ebsite: www.bilton.ca O I L & G A S I N Q U I R E R • M AY 20 13
35
Northeastern Alberta
near Edmonton. CNRL also built its own upgrader for its Horizon oilsands mining project. • Ivanhoe Energy Inc. hopes to strike a partnership this year that will lead to commercialization of its partialupgrading technology designed to upgrade bitumen to a crude that can be pipelined without diluent. • Bitumen producer MEG Energy Corp. is seeking regulatory approval to build a demonstration-scale plant that can process 1,500–3,000 barrels per day of bitumen to produce 1,350–2,700 barrels per day of deasphalted crude that could be pipelined without diluent. MEG believes this product would have a broader market reach than either diluted bitumen or synthetic crude. IHS said the upgrading and refining projects that have been cancelled or delayed “reflect the reality that, in many cases, value-added upgrading and refining in Alberta does not equate with adding profit.” But the paper said that while the returns wouldn’t be as good as in Asia, a
refinery in Alberta or British Columbia could be profitable if it could “consume bitumen, maximize diesel production, control capital costs to a minimum, and maintain a strong price for its products by not oversupplying the market.” But it warned: “A key risk with any new refinery investment in North America is the flat to declining demand for refi ned products in the continent. Consequently, any sizable new refining facility must export its product overseas, likely to Asia, where it would need to compete with refiners there.” IHS also worried about the flood of light oil from newly accessible formations such as the Bakken squeezing out synthetic crude in the North American refining market. “Tight oil is also reducing incentives for investing in heavy oil conversion projects, since refi ners have plenty of light crude to process,” IHS said. For this reason, developers such as Value Creation are targeting the medium-crude refining market, which they say is underserved. “At this juncture, in many cases investors fail to get a reasonable return on the billions
they must commit for a bitumen processing facility,” the IHS paper noted. However, it allowed “this may not be all bad for Alberta. Considering the region’s constrained labour market, less investment in processing facilities will enable faster growth in oil production, which also provides jobs and revenue to the province.” And there’s always the future: “By deploying resources to build bitumen production now, the province is not closing the door to bitumen processing in the future,” IHS argued. “If the future unfolds differently than we assume and the economics for value-added investments strengthen, the option will always remain to upgrade and refine then.” This has been Imperial Oil Limited’s refrain about the possibility of upgrading its Cold Lake bitumen production in Alberta. But in the more than three decades since the thermal oil project came onstream, no Cold Lake upgrader has ever been built. Imperial also decided to forego an upgrader for its new Kearl oilsands mine, which will soon start exporting diluted bitumen.
CONNECTING YOU WITH NORTH AMERICA’S GAS & OIL INDUSTRY
JUNE 11-13, 2013
CALGARY, ALBERTA, CANADA
STAMPEDE PARK gasandoilexpo.com
REGISTER TO ATTEND Enter reference code: OGINQ @petroleumshow #GOE13 Sponsor:
36
M AY 20 13 • O I L & G A S I N Q U I R E R
Partner:
These Leading Organizations Registered Their Personnel. Who Should Attend from Your Company?
For people who oversee Crane, Rigging, and Lifting Activities.
Heavy Rigging June 17-19, 2013 | Edmonton, Alberta www.heavyriggingworkshop.com
Interactive Workshop Sessions for your Company’s Leaders, Including: • The Crosby Keys to Heavy Lifting • A Review of the Shell Lifting & Hoisting Standard • ASME P30 Lift Planning Standard • Competency, Training & Qualification of Personnel • Heavy Lift Shackles & Hooks with Heavy Lift Exercise
World Class Instructors and Speakers Mike Parnell · President/CEO, ITI · Associate Member, CSA Z150 Technical Committee on Mobile Cranes · Vice Chairman, ASME B30 (Cranes & Rigging Standards Main Committee) · Chairman, ASME P30 (Lift Planning Standard Committee) Roger “Skip” Ohman, Jr., P.E. · Technical Advisor, The Crosby Group · BS Mechanical Engineer, MBA, MS Adult Education · Formerly Director of Training, The Crosby Group · Member of Society of Mechanical Engineers (SME)
Kenneth Reynolds · Lifting & Hoisting SME, Shell Geoff Holden, BSc (Hons) · Chief Executive, Lifting Equipment Engineers Association · Former Manager, Bridon International Steve Fryer · Training Manager, NCSG · Member of the Alberta Provincial Apprenticeship Committee
$695
Event hosted at:
Interactive heavy rigging and lifting training workshops addressing the planning, execution, and logistics of lifting activities. World Class Instructors and Speakers
Sept. 4-6, 2013 | Fort McMurray, Alberta www.oilsandslifting.com
Interactive Workshop Sessions for your Company’s Leaders, Including: • Curriculum Development & Delivery for the 21st Century • Advanced Rigging Foundations • Lift Director, Site Supervisor, & ASME B30.5 • Compressor Module Critical Lift Plan
Mike Parnell · President/CEO, ITI · Associate Member, CSA Z150 Technical Committee on Mobile Cranes · Vice Chairman, ASME B30 (Cranes & Rigging Standards Main Committee) · Chairman, ASME P30 (Lift Planning Standard Committee)
Glenn van’t Wout · Dean of Trades & Heavy Industrial Division, Keyano College Trevor Stickel · Product Trainer, The Crosby Group Additional Speakers to be announced soon! Check our website for updates.
$695
Event hosted at:
5% OFF
PO Box 53618 Ellerslie Rd. • Edmonton, AB T6X 0P6 • 780-490-6611 • iti.com
Event Partners
with coupon code: OGI5 MAGNA
Exclusive Event Partnerships available at:
iti.com/workshop-partners
CENTRAL ALBERTA WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▼
▼
▼
Source: Daily Oil Bulletin
C.A.B. Central Alberta
Williams to build $900-million propane dehydrogenation facility at Redwater By Elsie Ross
Photo: Aaron Parker
Tulsa, Okla.–based Williams says it has sanctioned construction of Canada’s fi rst and only propane dehydrogenation (PDH) facility near its existing Redwater fractionation plant northeast of Edmonton. T he new PDH facilit y, estimated to cost up to $900 million, will allow Williams to significantly increase production of polymer-grade propylene from its Canadian operations using propane feedstock primarily from its expanding oilsands upgrader operations. Williams is the only company in Canada currently producing polymer-grade propylene, a valuable petrochemical feedstock used in plastics manufacturing. “It’s really exciting because it’s a whole new value-add for the province,” David Chappell, president of Williams Energy (Canada) Inc. said. “It’s also a whole new value chain—propane to propylene and then hopefully polypropylene.”
A Redwater petrochemical facility. Williams’ new propane plant will make propylene to be shipped to the United States.
The Alberta petrochemical industry is currently based on the ethane chain of ethylene to polyethylene or ethylene glycol. “The project fits strategically within Williams’ operations in Alberta, leverages our expertise in propylene and adds further value to a by-product of oilsands upgraders.” Pending regulatory approvals, the PDH facility is scheduled to go into service in the second quarter of 2016. The company will be undertaking its consultation process shortly and early this summer plans to begin ordering long lead-time items, he said. It also plans to start some fabrication of modules in advance of Alberta Environment and Sustainable Resource Development approvals. “Obviously we are taking some risk, but if we do everything the right way—which we will be doing from an environmental perspective—we believe we will get approval for this,” said Chappell. “This is a huge valueadd for our resources in Alberta.” Williams plans to primarily use propane recovered from its expanding oilsands off-gas processing operations along with local propane purchases as feedstock for the new PDH facility. Last year, it announced an agreement with Canadian Natural Resources Limited to obtain offgases from its Horizon upgrader. The Canadian PDH facility will have the capability to initially produce up to approximately 1.1 billion pounds (500 kilotonnes) annually of polymer-grade propylene, with the opportunity to double capacity with a future expansion. Williams currently produces 180 million pounds annually of polymer-grade propylene, using the propane
extracted from off-gases at the Suncor Energy Inc. upgrader in Fort McMurray for feedstock; that will increase to 280 million pounds with the addition of Horizon. The propane will be converted into higher-value propylene that will be transported by rail to the U.S. Gulf Coast and sold to petrochemical producers because “nobody uses propylene in Canada,” said Chappell. However, Williams is talking to global petrochemical companies about siting a propylene derivative plant in Alberta to produce polypropylene or propylene glycol, a more environmentally friendly type
1.1
billion pounds
Initial capacity of polymer-grade proypylene production at the new Williams facility
of antifreeze, he said. “The annual total production of 1.3 billion barrels would be more than enough for a world-scale polypropylene plant.” Companies are extremely interested in that idea because if propylene is railed to the Gulf Coast, its value in Alberta is lower than on the Gulf Coast, which creates an opportunity for global companies to make plastic pellets here and then either ship them into the United States or into Asian markets through container ports on the West Coast, according to Chappell. Williams expects the new facility to produce one of the lowest-cost, PDHsourced propylene feedstocks in North America. That’s partly due to depressed propane prices in Alberta compared to elsewhere in North America. In addition, there’s existing infrastructure for polymergrade propylene from off-gas feedstock. The PDH facility will also produce byproducts including a “fairly substantial” O I L & G A S I N Q U I R E R • M AY 20 13
39
Central Alberta
“We are extremely excited about this project [a propane dehydrogenation facility] on many levels.” — Alan Armstrong, president and chief executive officer, Williams
amount of hydrogen, butane/butylenes and a small amount of condensate. Plans are to sell the associated hydrogen byproduct in the Alberta market where it is used in upgraders and refineries. Williams also has some unique fractionation facilities at Redwater, which also can turn the butane/butylene-mixed stream into high-value products rather than burning them as fuel, which is usually the case. “This fits very well with our off-gas business because the by-products...can now go back into the facility we have already,” said Chappell. “We are extremely excited about this project on many levels,” added Alan Armstrong, president and chief executive officer of Williams, in a news release.
“We expect the PDH facility to deliver a very attractive return on investment as well as provide a long-term natural hedge of the propane volumes we control in our Canadian off-gas processing business. Our planned PDH facility will enable Williams to capture the full value between natural gas and polymer-grade propylene rather than just the value between natural gas and propane.” Williams has selected Honeywell as the vendor to provide the proprietary UOP Oleflex process technology for the dehydrogenation process. The technology is environmentally superior because it uses a platinum-based catalyst system, as well as less energy and water than competing PDH technologies, Williams said. T he project will be f unded with ex pected cash f low f rom Williams’ Canadian operation and international cash on hand. The Redwater complex includes fractionation, storage and distribution facilities, and is currently being expanded to produce approximately five million barrels
of propane and 280 million pounds of polymer-grade propylene annually from offgas, in addition to other natural gas liquids (NGLs) and olefins. When producers convert the oilsands into usable oil, the process produces an off-gas by-product that includes a rich mixture of natural gas, NGLs and olefi ns. Williams pioneered the process of extracting the mixture from the off-gas at its Fort McMurray liquids-extraction plant. After it extracts the off-gas mixture, Williams returns the natural gas to the oilsands producer for its operations. Williams then transports the remaining NGL/olefi ns mixture via its Boreal Pipeline to its Redwater fractionation facility for further separation. Williams’ off-gas processing reduces emissions of CO 2 in Alberta by approximately 200,000 tonnes each year and cuts emissions of sulphur dioxide—a contributor to acid rain—by an average of 1,700 tonnes each year. The new off-gas expansions will further reduce both CO2 and sulphur dioxide emissions in Alberta.
GT5M 5 Valve Flanged Manifold Gaugetech five valve soft seat flanged manifolds are supplied in 316L stainless steel and A105 carbon steel and are produced in 1/2” NPT female pipe threaded to flange. Designed with a Delrin® seat to ensure a tight shut off even in abrasive process conditions.
Visit www.gaugetech.ca to see our complete lineup of valves and manifolds or call us at 1.800.661.9039 40
M AY 20 13 • O I L & G A S I N Q U I R E R
Central Alberta
Cardium horizontal wells producing 80,000 barrels per day Oil production from horizontal wells in Alberta’s Cardium formation has skyrocketed to about 80,000 barrels per day in only four years, reported Peters & Co. Limited. Horizontal Cardium wells were producing less than 2,000 barrels of oil per day at the start of 2009, Peters said in a recent seven-page Cardium oil update. The total estimated oil production from the Cardium formation is about 115,000 barrels per day. One of the largest oil reservoirs in western Canada, the Cardium formation has been drilled with vertical wells for decades, but was considered a mature play until the success of multi-frac horizontal wells sparked significant new investment. Thanks to advances in drilling and completion technologies, the Cardium has become the equivalent of Alberta’s Bakken—a tight oil play that has helped reverse a decades-long decline in the province’s light oil production.
Nearly 2,000 wells have been drilled across the vast Cardium fairway spanning about 500 kilometres between Lochend in the south and Wapiti in the northwest, Peters said. “Unconventional horizontal drilling in the Cardium ranks as one of the mosttargeted light oil plays in the Western Canadian Sedimentary Basin, with about 580 wells drilled and about 715 wells brought on stream in 2012,” Peters reported. The current Cardium total of nearly 2,000 horizontal wells is up from fewer than 70 horizontal wells on production at the start of 2009. Over the past 12 months, about 40 operators have drilled a combined total of about 450 horizontal Cardium wells. Peters said the top three horizontal drillers in the Cardium in that period were PetroBakken Energy Ltd. (60), Bonterra Energy Corp. (which acquired Spartan Oil Corp.) (53) and Whitecap Resources Inc. (41). It said the leading operators to license Cardium wells in the past year were
Pressure Vessels
Test Separators Flare Knock Outs
Separator Packages Line Heaters Well Headers
Calgary Sales: 403-539-0850
PetroBakken (93), Bonterra (85) and Vermilion Energy Inc. (70). Of the nearly 2,000 horizontal Cardium wells drilled to date, about 1,700 are outside the main conventional conglomerate play in the Pembina field, Peters said. New areas where horizontal Cardium wells are being drilled include Wapiti, Kakwa and Kaybob in the northwest, and Stolberg, Willesden Green, Ferrier and Harmattan East on the southern portion of the core Pembina fairway, the investment firm said. It emphasized that well productivities vary among operators, and well productivities and costs vary by area. Peters highlighted four emerging areas that have shown increased levels of horizontal drilling activity and good results in 2012—Kaybob, Willesden Green, Ferrier and Stolberg. Ferrier and Willesden Green were productive for Cardium oil in conventional conglomerate reservoirs, while the new horizontal wells have targeted the
Treaters F.W.K.O’s
www.CAPEMFG.ca
Tank Separators Blow Case Packages
Halkirk Plant: 403-884-2442
O I L & G A S I N Q U I R E R • M AY 20 13
41
Central Alberta
Are You SIRIUS? Call us for all your SOLAR NEEDS.
SOLAR/WIND LIGHTING
SOLAR CHEMICAL PUMPS
SOLAR POWER PACKS
BATTERIES, PANELS ETC.
Yes We ARE! Profitable Environmental Solutions
1-866-436-6301
42
M AY 20 13 • O I L & G A S I N Q U I R E R
www.siriuscontrols.com
undeveloped “halo” sandstone reservoirs. Kaybob and Stolberg are newer areas for Cardium oil. When Peters published its fi rst unconventional Cardium play report in early 2010, its type curves in the East Pembina, West Pembina and Garrington areas were based on only about 20 multi-frac horizontal wells with limited production history. Now, with about 1,200 wells in these areas, Peters’ estimated ultimate recovery per well has been reduced by four per cent for East Pembina and Garrington, but increased by 11 per cent for West Pembina. “Our revised type curves result in halfcycle rates of return in the range of 35 per cent (Garrington) to 66 per cent (Harmattan East) with a payout period of between 1.7 to three years,” Peters reported.
Athabasca Oil Corporation updates light oil operations Athabasca Oil Corporation has passed the 10,000-barrels-of-oil-equivalent-per-day mark at its light oil operations in the Fox Creek area of the Alberta Deep Basin. Daily oil and gas production ramped up during the fi nal quarter of 2012, as the company constructed and commissioned its wholly owned infrastructure with a capacity of 36,000 barrels per day and 48 million cubic feet per day of natural gas. In October 2012, Athabasca commissioned a 63-kilometre-long, 12-inch-diameter trunk pipeline with a capacity of up to 180 million cubic feet per day. The Kaybob West Battery was commissioned in October 2012, followed by the Kaybob East and Saxon/ Placid batteries in mid-December 2012. In 2012, the company drilled 46 horizontal wells targeting stacked unconventional reservoirs in the Duvernay, Montney and Nordegg formations—by the start of January, 44 wells had been completed and 33 were on production, including Athabasca’s first three horizontal Duvernay wells. Athabasca is particularly encouraged by the strong initial performance of its three Duvernay wells—in particular, the 02-034-62-20W5 well produced about
Central Alberta
50,000 barrels of 55°-plus API liquids and 0.2 billion cubic feet of gas during its fi rst 80 days of production. Producing at a restricted flow in February, the 02-034 well averaged 840 barrels equivalent per day (63 per cent liquids) at a flowing surface pressure greater than 20 megapascal gauge. Athabasca intends to capture the premium value of the produced condensate as a sales product. “As one of the largest Duvernay land holders in the Deep Basin where the company owns 340,000 acres of high-graded Duvernay rights, Athabasca is excited about the results from its three horizontal wells drilled and completed to date,” said Sveinung Svarte, chief executive officer. “Athabasca is also pleased to see other positive industry test results in the Duvernay. These results, along with recent industry transactions, support Athabasca’s view of the strong value of the Duvernay play.” During the first half of 2013, Athabasca will monitor production and decline rates of the horizontal wells, establishing type curves by formation (Duvernay, Montney and Nordegg) and by area. The type curves will be used to create a development plan to produce these stacked unconventional reservoirs. Athabasca’s Kaybob acreage lies in the heart of the Duvernay Fairway, where the Company holds 200,000 acres (net) with greater than 20 metres of Duvernay pay. Athabasca has high-graded more than 2,000 drilling locations (targeting the stacked Duvernay and Montney formations) to develop the Kaybob and Saxon/Placid areas. On Dec. 31, 2012, Athabasca’s Fox Creek area well inventory included 22 horizontal wells (completed with multistage hydraulic fracturing) awaiting tie-in and seven horizontal wells awaiting multistage completions. Athabasca’s 2013 winter development drilling program involved contracting six rigs to drill 16 horizontal wells targeting the liquids-rich Montney formation. During the second quarter, Athabasca intends to drill four additional horizontal wells targeting the Montney. In late February 2013, Athabasca completed construction, ahead of schedule and below budget, of a 35-kilometre-long, eight-inch-diametre dual pipeline interconnect between the Kaybob East and Kaybob West batteries.
TRANSFORM YOUR CORPORATE TRAINING PROGRAM As a leading polytechnic, NAIT offers hands-on, technology based learning. We are global competitors, essential to serving the needs of business and industry, at home and abroad. NAIT Corporate Training draws on the Institute’s more than 200 programs to customize and deliver training across a range of competencies, including: • Information Technology • Telecommunication • Project Management • Engineering Technologies • Environmental Management • Trades • Business and Leadership • Health and Safety • Aboriginal Initiatives • International Training
Invest in your team. nait.ca/cit | 780.378.1230
EDUCATION FOR THE REAL WORLD
O I L & G A S I N Q U I R E R • M AY 20 13
43
Envision a world that doesn’t just turn. It flies.
Whether you build, produce, manufacture, run or generate, one fact is clear: better lubricants and better lubricant suppliers lead to increased productivity. That’s why Imperial Oil is proud to offer Mobil™-branded industrial lubricants — recognized worldwide by more than 5,000 equipment builders. With the combination of Mobil-branded industrial lubricants and Imperial Oil expertise, we don’t just elevate productivity — we help unleash it. Visit imperialoil.ca for more information.
Imperial Oil is a trademark of Imperial Oil Limited, Imperial Oil, licensee. Mobil and the Pegasus design are trademarks of Exxon Mobil Corporation or one of its subsidiaries, Imperial Oil Licensee.
SOUTHERN ALBERTA WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▲
▲
▲
Source: Daily Oil Bulletin
S.A.B. Southern Alberta
DeeThree ramps up in 2012
Photo: Joey Podlubny
DeeThree Exploration Ltd. achieved a 100 per cent success rate on 30 (28.8 net) wells and saw its revenues increase 160 per cent to $85.11 million in 2012 as the company increased production. “The year was highlighted by our Upper Bakken oil pool discovery at Ferguson in southern Alberta and by the Belly River multi-zone enhancement project in Brazeau—both of which triggered multihorizontal well delineation programs that will provide for future growth and expansion,” DeeThree president, director and chief executive officer Martin Cheyne stated in the company’s 2012 annual report. Whereas the company reported a net loss of $12.57 million for the 12 months ended 2011, in 2012 DeeThree reported a net profit of $7.18 million. For the three months ended December 31, the company reported a net profit of $3.48 million in 2012, compared to a fourth-quarter net loss of $9.33 million in 2011. At $28.38 million, fourth-quarter revenue in 2012 more than
doubled the $11.87 million reported for the same three-month period one year prior. “On the operational front, we grew oil production, increased netbacks, reduced operating and general and administrative costs, and met our year-end production target. This allowed us to enter 2013 with momentum, strategically adding acreage and raising equity early in the year,” Cheyne said. For the year 2012, DeeThree produced an average of 4,223 barrels equivalent per day, which is a 127 per cent increase from 2011 figures. In 2012, the company produced a daily average of 2,472 barrels of oil (at an average $78.40 per barrel) and 267 barrels of natural gas liquids (NGLs) ($58.78 per barrel). The company produced an average of about 8.9 million cubic feet per day of natural gas at $2.51 per thousand cubic feet. In 2011, DeeThree produced a daily average 561 barrels of oil and 137 barrels of NGLs, as well as 6.97 million cubic feet per day of natural gas.
For the fourth quarter of 2012, the company produced an average of 5,333 barrels equivalent per day, which is a 122 per cent increase from the same time frame in 2011. For fourth-quarter 2012, the company produced a daily average of 3,511 barrels of oil, 259 barrels of NGLs and 9.38 million cubic feet of of natural gas. Evaluated by independent petroleum engineering firm Sproule Associates Limited, DeeThree’s total proved reserves were 14.4 million barrels equivalent (78
4,223 barrels equivalent
DeeThree Exploration’s average daily production in 2012
per cent oil and NGLs) at Dec. 31, 2012, representing a 95 per cent increase from 2011 figures. Total proved plus probable reserves were 20.2 million barrels equivalent
Drilling in the Alberta Bakken and Belly River plays upped DeeThree’s production by 122 per cent in 2012.
O I L & G A S I N Q U I R E R • M AY 20 13
45
Southern Alberta
(78 per cent oil and NGLs) at Dec. 31, 2012, representing a 108 per cent increase from the year prior. Based on 2012 fourth-quarter average production, DeeThree’s reserve life index is 10.4 years on a proved plus probable basis and 7.4 years on a proved basis. Proved plus probable reserve additions replaced 679 per cent of 2012 production, and proved reserve additions replaced 450 per cent of 2012 production. The company achieved finding, development and net acquisition (FD&A) costs of $21.51 per barel on proved plus probable reserve additions and $30.21 on total proved reserve additions in 2012. Excluding future development capital, FD&A costs were $12.02 on a proved plus probable basis and $17.02 on a total proved basis. DeeThree’s reserves are located in Alberta’s Ferguson area, featuring Bakken oil plus shallow natural gas, as well as the Brazeau and Peace River Arch areas. In 2012, the company’s capital expenditures totalled $144.75 million, which is a
23 per cent decrease from the company’s $187.56-million capital program in 2011 (before a land-for-shares transaction). The 30 gross wells DeeThree drilled throughout the year included 21 wells at Ferguson, eight wells at Brazeau and one well on the Peace River Arch. Capital expenditures in the three months ended Dec. 31, 2012, totalled $45.13 million, with $10.15 million on tie-ins and facilities, including continued construction of an amine plant and two oilbattery sites at Ferguson. For the first quarter of 2013, the company expects its exit production to be 6,800 barrels per day, as three more wells were expected to be placed on stream by mid-April. The company’s $150-million 2013 capital program aims to drill 20 Alberta Bakken wells and 11 Belly River wells throughout the year, as well as five exploration wells and 26 development wells, with the year’s forecasted production at 6,800– 7,000 barrels per day (76 per cent crude oil and liquids, 24 per cent natural gas) with a 8,500–9,000-barrel-per-day (81 per cent
crude oil and liquids, 19 per cent natural gas) targeted exit rate. So far in 2013, the company has drilled five Belly River horizontal wells in its Brazeau property and is currently completing drilling operations on two (two net) additional Belly River horizontal wells at Brazeau, as well as one (one net) horizontal Bakken well at Ferguson. Two of the Belly River horizontal wells drilled and completed in 2013 tested at significant rates, targeting different intervals within the formation. Horizontal well 05-27-047-14W5 tested at a final stabilizing rate of about 3.5 million cubic feet per day of sales gas, with 215 barrels per day of associated NGLs and 450 barrels per day of light oil at a flowing wellhead pressure of 420 pounds per square inch after an eight-day test. Horizontal well 02-34-047-14W5 tested at a fi nal stabilizing rate of about 1.2 million cubic feet per day of sales gas, with 70 barrels per day of associated NGLs and 500 barrels per day of light oil at a flowing wellhead pressure of 30 pounds per square inch after a five-day test.
COMPLETE LOGISTICS AND TRANSPORTATION SOLUTIONS General Oilfield Hauling Pneumatic Trailers Hopper Bottoms Flat Decks Specialized Loads Construction Equipment Warehouse Storage Yard Transload & Rail Facility Aggregates
1.800.647.7995 Fort Nelson, BC | Lethbridge, AB | Milk River, AB | Cutbank, MT
hughsontrucking.com 46
M AY 20 13 • O I L & G A S I N Q U I R E R
Southern Alberta
LGX plans to spend $7.6 million in 2013 LGX Oil+Gas Inc. expects to spend $7.6 million in 2013 focused on light oil development with the majority of capital—78 per cent—directed to drilling, completions and tie-ins on the Alberta Bakken play. Capital spending will be distributed as follows: drilling, completions and tie-ins, $5.4 million; re-completions, $1.5 million; land and seismic, $500,000; and other, $200,000. The company is planning to drill two (1.6 net) wells in 2013, targeting highquality light oil on the Alberta Bakken play. No capital has been budgeted for acquisitions, although the company continues to evaluate new opportunities, both within and beyond its core areas. LGX anticipates a 2013 averageproduction rate and exit rate of 900 barrels equivalent per day. In 2012, the company closed the purchase from Legacy Oil+Gas Inc. of assets comprised of 68,581 net acres of undeveloped land in southern Alberta for 10 million
LGX Oil+Gas Inc. is planning to spend $5.4 million to drill two (1.6 net) wells in 2013, targeting high-quality light oil on the Alberta Bakken play. post-consolidation common shares. In conjunction with the asset purchase, the company’s management team was replaced with members from Legacy and the board of directors was reconstituted.
LGX closed the acquisition of highly focused, high working interest, operated and producing oil assets in southeastern Alberta, consisting of light oil production, reserves and undeveloped land in the Manyberries area with attractive transaction metrics of $76,667 per barrel per day and $15.78 per barrel proved plus probable. Shareholders approved a proposed name change to LGX from Bowood Energy Inc. and a consolidation of outstanding common shares on a 20-to-one basis. This name change and consolidation of shares were completed and effective as of Aug. 20, 2012. LGX reported average production of 685 barrels per day in the fourth quarter of 2012. The company reported a net loss of $7.02 million during the period. On Dec. 31, 2012, t he company reported 4.42 million barrels of gross proved plus probable reserves and 2.45 million barrels of proved reserves. — DAILY OIL BULLETIN
O I L & G A S I N Q U I R E R • M AY 20 13
47
15th Biennial
SASKATCHEWAN
OIL & GAS SHOW Exhibition Grounds • Weyburn, SK
June 5 & 6, 2013 Show Highlights:
• Awards ceremony • 24-hour security • Keynote speakers • Golf tournament and barbecue • Excellent show facilities with improved outdoor space and storage • First class show management • Social events to broaden exposure • Complimentary loading and unloading • Latest products and services on display • Free passes for attendees
Nominations are now being accepted for the 2013 South East Saskatchewan Oil Person of the Year Please download form off our website: www.oilshow.ca
Weyburn Review Photo Greg Nikkel
Email or send to address below
Sponsored by…
WEYBURN OIL SHOW BOARD
P.O. Box 1450, Weyburn, SK S4H 3J9 Tel: (306) 842.3232 Fax: (306) 842.3265 e-mail sk.oilshow@sasktel.net Web Site: www.oilshow.ca Platinum Sponsors:
Gold Sponsor:
Silver Sponsors:
DEL
Communications Inc.
Security Sponsor:
SASKATCHEWAN WELL ACTIVITY MAR/12
MAR/13
Wells licensed
MAR/12
MAR/13
Wells spudded
MAR/12
MAR/13
Rigs released
▼
▲
S.K. Saskatchewan
▲
Source: Daily Oil Bulletin
Crescent Point advancing unitization in the Bakken By Pat Roche
Photo: Joey Podlubny
Crescent Point Energy Corp. , which has made waterflooding a major plank in its growth strategy, has applied for approval for unitization of a number of fields to accelerate its waterflood program. Enhanced oil recovery (EOR) schemes such as waterflooding are best done on a pool-wide basis rather than well by well. This means a pool with multiple owners must reach a unitization agreement for the EOR scheme before a project can proceed. Unitization refers to the creation of a single operating unit in pools with several owners. Each owner contributes to the capital and operating costs—and shares in the profits—based on its stake in the unit. Unitization agreements were common in western Canada, but for a long time there were few, if any, new ones as conventional light oil activity waned. Like the recent upsurge in light oil drilling, Crescent Point’s push toward unitization is further evidence of western Canada’s reinvigorated light oil sector.
Crescent Point is moving forward with major waterflood projects in the Bakken.
A Petroleum Technology Alliance Canada study estimated water re-distribution and better water management could add a billion barrels to western Canada’s oil reserves. The study, which was made public about five years ago, was called Ramping Up Recovery. This year, Crescent Point expects to continue to develop its expanding waterflood programs in the Bakken, Shaunavon and Viking resource plays, which the company says continue to show positive results. Crescent Point also expects to initiate waterf lood programs in the Beaverhill Lake formation in Alberta and the Uinta Basin in Utah. In southeastern Saskatchewan and Manitoba during the fourth quarter, the company converted five more producing Viewfield Bakken wells to water injection for a total of 46 water-injection wells in the play. Crescent Point said production performance from water injection patterns in the Viewfield Bakken resource play continues to exceed its expectations and has demonstrated the field-wide applicability of waterflooding. In an earnings conference call, Crescent Point president, chief executive officer and director Scott Saxberg estimated at least 40,000 barrels per day of the company’s forecast 100,000 barrels of oil per day of production exiting this year will be affected by waterflooding. “There’s easily 25,000 barrels per day today of long-term waterfloods that we have within our company already from legacy assets. On the Bakken side, it’s probably going to push close to 10,000 barrels a day that will be affected. And on the Shaunavon side it’s probably 5,000 barrels a day,” Saxberg told analysts.
“The push this year is we’re working towards unitization—the fi rst unit of four units right now,” said Neil Smith, chief operating officer. In southeastern Saskatchewan, water is currently being injected into 30 converted wells in both the Lower and Upper Shaunavon unconventional zones. Crescent Point has submitted applications to the Saskatchewan government to establish the first Lower Shaunavon unit for the purpose of implementing a unit-wide water injection scheme.
40,000 barrels per day
Amount of Crescent Point production affected by waterfloods Discussions with the Saskatchewan government to implement the fi rst of four proposed units for waterf looding are advancing, the company said. “So we’re working with the Saskatchewan government, optimistically hoping over the next quarter to two that that will be done— we’ll unitize and then we’ll implement it field-wide on that first unit,” Smith said. Once the first unitization is accomplished, he said, the company will do the next three over the next couple of years. In south-central Alberta and westcentral Saskatchewan, Crescent Point’s plans for its first waterflood pilot in the Beaverhill Lake play are well underway, and the first pilot is expected to be operational in early 2013. This year, the company plans to reduce capital spending in the area to $77 million and to drill 11 net wells to take advantage of expected declines in future capital costs in the play. By the end of last year’s fourth quarter, the company had drilled 18 (18 net) O I L & G A S I N Q U I R E R • M AY 20 13
49
Saskatchewan
“We’re seeing good early results on the waterflood in the Viking. We’re seeing really strong results in the Shaunavon.” — Neil Smith, chief operating officer, Crescent Point Energy Corp.
wells with a 100 per cent success in the Viking on lands acquired with Cutpick Energy Inc. Crescent Point plans to drill 30 net wells on these lands in 2013. The company plans to convert an additional three producing Viking wells to water injection wells on these lands this year. Once the unitization is in place, the company can start booking some incremental waterflood reserves. In the near term, production will be lost as oil-producing wells are converted to water injectors. But in the long term, waterflooding will slow company-wide production declines and boost reserves.
Crescent Point is moving to focus on unitization on a bigger scale. “We made some technical decisions partway through the year to go to two injectors in some areas, and in other areas we have four injectors,” Smith said. “We also made the decision to kind of push the waterfloods across all of our plays versus just focusing on the Bakken. And so we’ve seen a big expansion to all of our plays.” He added, “We’re seeing good early results on the waterflood in the Viking. We’re seeing really strong results in the Shaunavon as we’ve added more injectors there. And we’re pushing to the unitization of the Shaunavon field and we’re a lot further down the path on that.” Also targeted for waterflooding are the Beaverhill Lake and Uinta plays. “We’ve seen how well this application has worked with the multistage fracs in the Bakken and the Shaunavon. We made that call to push it across all of our plays instead of just focusing on one,” Smith said. Getting government approval and moving ahead with unitization will be a significant event for Crescent Point, he said.
Quicker Deliveries
Strong and Expandable
Westeel’s automated manufacturing system ensures quick order turnarounds. Better still, most tanks can be moved on a single truck, reducing both your transportation needs and carbon footprint.
Engineered for strength and durability, this innovative Westeel tank 13,000 also allows for future expansion in three foot increments up to a maximum 132,000 barrels.
Easier Installs Installs and breakdowns are quick and easy with a crew as small as six people plus one picker truck.
Lower Total Cost of Ownership Lower material, installation and transportation costs add up to the best long term value in frac water storage.
132,000
SAVINGS REPORT Price Transportation Installation Reusable
MF22608-0313
Four Reasons This May Be The Best Fluids Tank Ever.
Asked when the company expects the negotiations to be concluded, Smith said, “We’re hoping to be able to conclude something in Q2 on one of the units, and then by the end of the year on the Bakken units.” The company is also re-fracturing existing wells. In the Saskatchewan Bakken, Crescent Point has re-entered existing wells that were originally completed with eightstage and 16-stage cemented liners and increased them to 25-stage and 30-stage cemented liner completions. The company is encouraged by results to date and has identified 90 wells in the play as candidates for this process. Crescent Point drilled a fourth two-mile horizontal well during the fourth quarter in the Flat Lake area. Based on the initial success of these wells, the company plans to drill six more two-mile horizontal wells in 2013. Crescent Point expects these wells will be drilled for roughly half the cost of similar wells drilled across the border in North Dakota, where red-hot demand and crews from warm climates have driven well costs up.
Westeel’s Above Ground Water Storage Tank.
(800) 665-2099 | westeelFLUIDS.com
50
M AY 20 13 • O I L & G A S I N Q U I R E R
Saskatchewan
Saskatchewan expects higher royalties this fiscal year The Saskatchewan government forecast oil royalties of $1.44 billion in 2013-14, which is roughly $119 million higher than the expected fi nal tally for 2012-13, during an economic update in March. The expected increase is largely due to higher prices, with wellhead prices forecast to average $75.29 per barrel in 2013-14, an increase of $6 per barrel from 2012-13. The price increase is a result of a smaller lightheavy differential forecast, a higher West Texas Intermediate (WTI) oil price forecast and a lower exchange rate. Saskatchewan had originally forecast oil royalties of $1.6 billion for 2012-13. T he major it y of oil produced in Saskatchewan is heavier and more sour than WTI and requires further processing to turn into refi ned products, the province said. As a result, Saskatchewan oil generally trades at a discount to WTI oil. In 2012-13, increasing production in western Canada and North Dakota, coupled with pipeline capacity limits, contributed to an increase in the price discount for Saskatchewan oil. This discount is expected to ease somewhat in the coming year. The light-heavy blend differential is forecast to average 17.9 per cent in 2013-14, down from 20.4 per cent in 2012-13. The province is projecting a 2013-14 general revenue fund pre-transfer surplus of $64.8 million. Real gross domestic product is forecast to grow at 2.6 per cent in 2013 and 3.1 per cent in 2014. For 2013-14, Saskatchewan is forecasting a WTI price of US$92.84 per barrel, up slightly from the latest forecast for 201213 of $91.76 per barrel. Oil production is expected to climb slightly to 171.8 million barrels in 2013-14 from 171.2 million barrels in 2012-13. Crown land sale revenue is forecast to climb to $111.4 million in 2013-14 from $88.9 million in 2012-13. Saskatchewan had originally predicted $220 million in sale revenue for 2012-13.
You can misjudge
your strength, your pump jack shouldn’t
The Ecoquip 9000 series Hydraulic Pump Jack is reliable, durable and powerful. • No unreliable and faulty sensor bars or proximity switches mounted on or near wellhead. • The only unit using a true N2 counter-balance which ensures an energy efficient and smooth stroke that reduces wear on equipment, rods, pumps or seals. • 144” stroke length, 35,000lbs lifting capacity and speeds up to 7 strokes per minute all at the same time. No de-rating of performance based on well dynamics.
Pump Jacks
www.ecoquip.ca O I L & G A S I N Q U I R E R • M AY 20 13
51
Since 1921, we’ve been doing one thing and one thing only: providing PVF products and solutions to our customers. We create savings well beyond the price of our products. Trusted Supplier, Proven Results
MRC Offers PVF Products and Services Globally
425+ Locations
MRO Solutions
Carbon Steel
24 Automation Facilities
Project Solutions
Stainless Steel
$1B+ Inventory
Logistics Solutions
Alloys & Duplex
www.mrcglobal.com
N.F.
Northern Frontier
Canol shale shows potential, says MGM Energy Early results from MGM Energy Corp.’s East MacKay I-78 vertical well drilled this winter in the Central Mackenzie Valley have identified the presence of hydrocarbons in the primary target Canol formation, said the company. MGM was the operator and Shell Canada Limited picked up the cost of the well as part of a farm-in deal. The well on EL 466B was spud on Jan. 27, 2013, and reached the target depth of 2,001 metres on February 15. Following logging, casing and the running of the completion string, the drilling rig was released February 25. Drilling operations proceeded without incident and all formations were present as expected, said MGM. In particular, the Canol shale was found between 1,819 metres and 1,919 metres, and the Bluefish formation, the secondary target, was found between 1,936 metres and 1,957 metres. Cores were taken within the Canol and Bluefi sh formations, as well as the upper Hume formation, immediately below the Bluefi sh. A full suite of electric logs was run once drilling was completed. Testing operations on the Bluefi sh formation began on March 2. One zone of the Bluefi sh was fractured using a small 20-tonne frac energized with nitrogen. The frac was successful, with emplacement of the sand. After f lowing back approximately 30 per cent of the frac fluid, the well ceased flowing due to lack of formation pressure. Rather than undertaking operations to resume the flow, and given the seasonal constraints of operating in the Central Mackenzie Valley, the decision was made to discontinue testing of this
secondary zone to ensure suffi cient time to test the primary Canol target. Testing operations on the Canol began on March 4 and the formation was fractured in three stages, with one stage having two perforation zones. Each of these fracs was again small, ranging from 23 tonnes to 35 tonnes, using a total of 2,450 barrels of frac fluid. All fracs were successful and all were energized with nitrogen. Approximately 70 per cent of the frac fluid was recovered in the first five days after fracking. During that time, the well continued to clean up. Over the five-day period of March 10–14, the well returned approximately 140 barrels of fluid consisting of a mixture of frac f luid and formation hydrocarbons, the latter consisting of light, sweet crude oil and natural gas. Throughout this period, nitrogen was used to assist in lifting f luids from the well. Because of seasonal constraints on activity, well testing operations in the Canol formation were concluded on March 15 and equipment has since been demobilized. In order to obtain pressure data, gauges have been left in the hole, and are expected to be retrieved in the summer or fall of 2013. MGM also drilled, sampled and monitored three water wells in the area immediately adjacent to the I-78 well. Samples of water were taken before, during and after the fracs. The results of this monitoring are ongoing and, along with water samples, are being shared with regulators and governments. MGM noted that although well operations were conducted in a remote area
and in harsh weather conditions, there were no material environmental or safety incidents at any stage of the project. “We are very excited with the early results of the well,” Henry Sykes, president and director of MGM, said. “The results are quite consistent with our expectations,” he added. “While it isn’t possible to establish ultimate flow rates with a vertical well and the small fracs undertaken, at this point we’ve identified the presence of hydrocarbons in the Canol shale underlying our lands.”
“ While it isn’t possible to establish ultimate flow rates with a vertical well and the small fracs undertaken, at this point we’ve identified the presence of hydrocarbons in the Canol shale underlying our lands.” — Henry Sykes, president and director, MGM Energy Corp.
One or more horizontal wells will need to be drilled to establish the best method of completing these wells, to discover the flow parameters and, ultimately, to determine a type curve for these wells, he said. In the near term, a great deal of work and analysis remains to be done with respect to information obtained and cores taken during the project, and that work will take some months to complete. Sykes said MGM looks forward to working with regulators and local communities to ensure that the benefits of responsible development of the Canol shale are well understood and quantified. “And fi nally, we wish to gratefully acknowledge the support we received from the local communities throughout our operations.” O I L & G A S I N Q U I R E R • M AY 20 13
53
News Tech
The latest regional technology news
Field Upgrading receives funding for upgrading technology Field Upgrading Ltd. has been selected by A lber ta Innovates – Energ y and Environment Solutions to receive $500,000 in funding toward the commercialization of a new upgrading technology that could see more of Alberta’s bitumen upgraded in the province. “Compared to conventional oilsands upgraders in use today, the Molten Sodium Upgrading technology we’re testing has the potential to cut capital costs significantly,” says Neil Camarta, president and chief executive officer. “Moreover, we’re looking to cut carbon dioxide emissions by more than half and
eliminate sulphur emissions completely. And since we’ll be using fewer ‘pots and pans,’ we can accomplish all of this from a much smaller footprint.” In addition to the environmental benefits, the scalability of the technology is also noteworthy. Since the upgrading process can be sized to the need at hand, it may be cost-effective even for smaller steam assisted gravity drainage oilsands producers. Those operators will no longer have to make a choice between building expensive and complex upgrader facilities, or losing potential profits by blending their raw bitumen with expensive
diluent for shipping to a third-part y upgrader. Molten Sodium Upgrading was developed by Ceramatec, Inc., an advanced ceramics materials technolog y company based in Salt Lake City, Utah. Field Upgrading has partnered with Ceramatec t o c om m e r c i a l i z e M olt e n S o d iu m Upgrading for use in Alberta’s oilsands. Bench-scale testing of the new technology on oilsands bitumen is currently under way at Ceramatec’s facilities in Salt Lake City. Pilot testing is planned to commence this year at the Natural Resources Canada research centre in Devon, Alta.
Acuren to deploy Creaform’s Pipecheck solution for pipeline integrity in North America ACUREN and CREAFORM have entered into a commercial and technical partnership agreement covering the deployment of the Pipecheck inspection solution in North America for external corrosion and mechanical damage on pipelines and in facilities. ACUREN has been an early adopter of laser scanning technology, having worked with the technology since 2009. In response to strong demand, ACUREN has just taken delivery of 20 Pipecheck systems and had their technicians trained by CREAFORM. The systems are being deployed across Canada and the United States to support the needs of their clients. This agreement provides for the deployment of Pipecheck in ACUREN field operations on pipelines and refineries, and for the development of innovative applications 54
M AY 20 13 • O I L & G A S I N Q U I R E R
in the field of optical 3-D measurement for non-destructive testing (NDT), mainly applied to the energy industry. In 2011, CREAFORM launched the Pipecheck inspection solution for pipeline integrity assessments to address the market need for fast decision making based on repeatable and reliable results. The Pipecheck solution is based on the proven Handyscan 3-D laser scanning technology launched in 2005. 3-D laser scanning combined with a dynamic referencing system represents the most efficient way to obtain high accuracy on large areas in field environments. “CREAFORM’s Pipecheck inspection solution is quickly becoming the reference in the industry for inspection of external corrosion and mechanical damage on pipelines
and pressure vessels; it’s about using the right technology for the right application. With this deployment, ACUREN confirms its leadership position in NDT inspection services by acquiring state-of-the-art technology to ensure maximum value to its clients,” explained Pierre-Hugues Allard from CREAFORM. Tal Pizzey, chief operating officer for ACUREN, stated that “We are very excited to be working with CREAFORM to deploy this technology to the NDT industry. ACUREN has made a significant investment and have received an enthusiastic response from our clients for both pipelines and plant applications. Laser scanning significantly raises the bar for non-destructive testing by offering one of the most accurate and repeatable processes available.”
Te c h N e w s
GE Motors to drive pioneering bitumen refinery Sustainable development of Alberta’s vast oilsands is a key priority, and in early 2013 construction began on the world’s first refinery specifically designed to reduce environmental impacts as it turns tarry bitumen crude into clean-burning diesel fuel. GE’s Power Conversion business is playing an enabling role in the refinery, near Edmonton and owned by the North West Redwater Partnership, by supplying GE’s Series 9000-RCM large electric motors to drive the refinery’s reciprocating compressors, under a $14-million contract that includes related services. The partnership is a joint venture between North West Upgrading Inc. and Canadian Natural Resources Limited. The 150,000-barrel-per-day bitumen refi nery will be the first to incorporate an integrated CO2 management system, setting an international precedent for responsible development. In the fi rst of three phases,
by 2015 it is expected to begin producing clean diesel fuel with fewer emissions and up to 30 per cent higher fuel efficiency than gasoline, exceeding Canadian standards and meeting global specifications. There is strong demand for clean diesel in North America, China, Southeast Asia and elsewhere. In Canada, for example, diesel is available nationwide at gasoline fi lling stations and at comparable prices. Transporting and processing crude bitumen, or heavy crude oil, extracted from the oilsands is challenging and expensive because it is a tarry, sludgy solid or semisolid that doesn’t flow easily at normal oil-pipeline temperatures. Reciprocating compressors are used to handle hydrogen, which is used to process the bitumen, because they offer extremely high compression ratios. GE’s powerful and rugged Series 9000-RCM motors are built to drive
reciprocating compressors in the petrochemical industry, with ratings up to 13.8 kilovolts and up to 22,000 horsepower (16,000 kilowatts). Besides raw power and reliable performance, they offer fast installation/start-up and ease of maintenance, helping to minimize delays and maximize capital resources. “Refineries are complex and expensive undertakings, and so a key priority for their owners is to minimize risk and maximize investment return,” said Alberto Peluzzo, sales leader for Power Conversion Rotating Machines. “GE’s Series 9000-RCM motors are seeing increased use throughout Canada’s oilsands region because of their proven, reliable performance. Along with GE’s expert technical services, they will help enable the North West Redwater Partnership to achieve world-class operational performance and efficiencies at this landmark refinery.”
Logan acquiring drilling jar product line from Smith International Logan International Inc. announced that two of its U.S. wholly owned subsidiaries have entered into an agreement to purchase certain assets and operations of the Sup-R-Jar drilling jar line from Smith International, Inc. Logan, through its wholly owned subsidiaries, will acquire the majority of Smith International’s North American Sup-R-Jar rental and service assets. In addition, Logan will also receive raw materials and parts inventories, manufacturing specifications and use of the Sup-R-Jar trade name. The purchase price
includes the assumption of certain postclosing liabilities and $17.2 million in cash, $15.6 million of which is payable at closing with the remaining $1.6 million payable on delivery of certain inventory items. “We believe this acquisition fits very well with our strategy of becoming a leading provider of downhole tools,” Gerald Hage, Logan chief executive officer, said. “The North American Sup-R-Jar rental tool and our proprietary Xciter tool are both used by drilling contractors and operators, which Logan believes both improve drilling efficiency, especially in horizontal wells.”
The Sup-R-Jar delivers a sharp blow to the drill string to free stuck drill pipes and to assist the drill string as it turns from a vertical orientation to a horizontal orientation. The Xciter tool increases the drilling rate by introducing a vibration into the drill string, thereby reducing wellbore friction, Logan said. “We intend to combine the Xciter and Sup-R-Jar sales, marketing and operations organizations,” Hage noted. “In addition, Logan Oil Tools, Inc. will begin manufacturing and selling the Sup-R-Jar to its international customers.”
“Industry Leading Quality & Service Since 1987” Specialists in internal & external coating applications Epoxies • Metallizing • Plural Spray Pipe • Tanks • Vessels • Bends • Valves 6150 - 76 Avenue, Edmonton, AB T6B 0A6 Phone (780) 440-2855 Fax (780) 440-1050
• 100% Canadian Owned • www.brotherscoating.com O I L & G A S I N Q U I R E R • M AY 20 13
55
Cover Feature
A R F
U T C
D E R
FRACTURED
UNLOCKING TIGHT OIL AND GAS Operators custom design horizontal drilling and fracking programs for individual plays By Godfrey Budd
C
onsider the range of technical factors that today’s drilling and completions managers must weigh in to their decisions and the old days really do look simpler. Until just the last few years, the key determinants of reservoir productivity were almost always porosity and permeability. But with the advent of multi-frac horizontals in the last decade, this is no longer the case. When vertical wells dominated the industry, the number of key input variables, aside from the geology, when deciding on a frac program to implement, could
56
M AY 20 13 • O I L & G A S I N Q U I R E R
usually be boiled down to three: frac fluid, proppant type and amount of sand. “Today, the inputs are cost, frac fluid chemistry, total number of stages, spacing, the type of isolation or diversionary liners—for example, cemented liner versus open-hole are among the variables—[and] tonnes of proppant per stage,” says Tim Leshchyshyn, president of Fracturing Horizontal Wells Completions Inc. The Calgary-based consulting firm, in partnership with Geo Webworks Inc., which has been providing public exploration and production data to the industry since 2000, introduced a software tool a couple of years ago in the form of a fast-growing completion, fracturing, drilling and well files database. The
FracKnowledge database module is used for optimizing multistage horizontal fracking (MSHF) and improving productivity and well profitability. It is no surprise that Leshchyshyn, a chemical engineer with more than a dozen years’ experience in the fracturing sector, and his firm have attracted clients in both North America and overseas recently. The FracKnowledge database is geared to address some of the key well history and data challenges of the horizontal fracking environment and help companies figure out how best to proceed with their specific frac jobs. Whether Deep Basin tight gas or tight oil plays in the Cardium, Viking, Bakken, and elsewhere across the Western Canadian Sedimentary Basin (WCSB),
Cover Feature
the role of MSHF has expanded sharply. A recent report from the Canadian Energy Research Institute points to a four-year period from 2006 to 2010 when the percentage of horizontal oil-directed licences in Alberta grew from 24 to 62 per cent. At a Cl Energy Group oil and gas water management strategies conference in Calgary in January, Leshchyshyn said that 6,000–7,500 horizontal multi-frac wells are completed each year in Canada. If the old rule—good reservoir porosity plus permeability equals productivity—no longer applies in today’s tight oil and gas plays, companies have found that attempts at a new, alternate one-size-fits-all approach are doomed to fail. Acceptance of this challenging, if perhaps unwelcome,
fact was the main theme of the Bakken Tight Oil Congress in Denver, Colo., last year. Based on the importance of recognizing the Bakken as a heterogeneous resource that should be seen not as a single play but as a collection of unique play types, papers and discussion focused on possible solutions. What is clear is that if a company has the time and the budget, the right technique, honed by a series of additional tweaks, can cut drilling and completions costs and boost well productivity. As has been found in the Bakken, a second well a couple of kilometres from the first might require a different technique. On the other hand, horizontal drilling techniques across the WCSB are pretty much the same for oil and gas.
“The only real difference between the two is that in gas formations you usually have more target room vertically. In oil, it is usually tight vertically so it requires closer attention, and this is where some operators opt for gamma-at-bit or inclination-at-bit,” says Dan Robson, director of strategic development at Departure Energy Services Inc. The new era of MSHF has ushered in greater collaboration between drilling and completion specialists. In the old days, drilling tended to be quite separate from completion. The drilling outfit was there to drill the well under budget—not to worry about the endliner. But today, if laterals are involved, “The directional driller should discuss the well objectives for completion and future intervention right at the planning stage,” says Robson. O I L & G A S I N Q U I R E R • M AY 20 13
57
Cover Feature
When drilling tight oil you save, the more money you make, says Leah Hrab, manager for drilling and completions at Sure Energy Inc.
OIL HORIZONTALS: THE BOTTOM LINE AFFECTS TECHNIQUES USED IN BAKKEN, CARDIUM, VIKING PLAYS Keeping a steady focus on the economics of developing and producing horizontal wells can make the difference between profit and loss in oil shale plays, suggests Leah Hrab, manager for drilling and completions at Sure Energy Inc. Netbacks per barrel of oil in the WCSB can range from $25–$60, after various
58
M AY 20 13 • O I L & G A S I N Q U I R E R
fees are paid and costs met, “depending on where you are.” Last summer, when the price of the benchmark West Texas Intermediate fell to around $80 per barrel, drilling dropped off significantly in the Bakken. “A lot of shale plays are called resource plays. They can have very steep declines. A Bakken well can go from initial production of 250 barrels per day to 50 in one year. The way plays like this become more economic
is to be more efficient. Try to drill in 15 days, not 20. The more money you save, the more you profit at the end of the day,” Hrab says. Wells in the Saskatchewan Bakken cost $3 million to $4 million. On the U.S. side, where wells are often deeper, companies are spending around $8 million to drill and complete. Pad drilling, which was first used in the United States after environmentalists and community and public interest groups lobbied regulators to get operators to shrink their footprint, is achieving economies of scale in the Bakken. In the United States, pads sometimes have as many as 20 laterals. On the Bakken’s Canadian side, pads don’t as a rule have more than six or eight laterals, says Mark Woitt, associate senior completions specialist at the Calgary office of international consultancy RPS Group Plc. Part of maximizing the potential of pad drilling is to “optimize how far apart the laterals are. Where is that optimal point between 250 and 100 metres apart? For oil, you tend to have them closer together. In the Cardium and Viking, they’re maybe 85 metres apart sometimes, if there’s low porosity and low permeability,” Hrab says.
Photo: Aaron Parker
plays, the more money
Cover Feature
She says some operators were tempted to make laterals as long as possible because of the amount of money already spent on getting to the depth where the pay zone was located. But they are better advised to seek an optimal length for the lateral. She says, “Ten per cent more length doesn’t mean 10 per cent more production.” Her experience working on a drilling and completions program in a Cardium tight oil play illustrates the benefits of building history data and the application of a trial-and-error approach—provided you have the time. Laterals were typically about 1,000 metres long and the operator initially opted for fi ve frac stages, 150 metres apart. Then, Hrab says, this was switched to 10 stages, with spacing of 70 metres. Sand was reduced from 20 to 15 tonnes per frac stage. “You use less [sand] tonnage for oil because of the better permeability,” Hrab says. At first, it looked as though more stages translated into more production. Initial production from a stage frac came in at about 350 barrels per day, compared to
200–250 barrels following a five-stage frac. At the six-month point, however, the numbers stemming from the two treatments were getting closer together. By eight months, it was a tie, and, after 12 months, production from the well that had received 10 frac stages was less than the one with five. “After three years, both wells recovered about the same amount of oil. It told us that the extra cost of doing more frac stages didn’t translate to more production,” Hrab says. Monobore wells can be an option for either oil or gas plays. They can be a costeffective well-construction methodology and are suited for situations where holding the line on costs, efficiency, and speed of well construction and drilling may be priorities, Hrab says. Where there is a risk of sloughing, as in the Viking, and, on occasion, in the Cardium, “going to monobore can save days.” Another technique that relates to either oil or gas completions with horizontal multi-fracs involves an open-hole completion with a packer system, where no casing or liner is cemented in place along the production zone. One of the big
advantages of this technique is speed. Frac times can be dramatically reduced. On a single lateral, all stages of a frac job could be done in one day—instead of four, says Hrab. On a pad with eight laterals, with 20 stages each, the frac job could still be done within about 24 hours, says Woitt of RPS. But, with cemented casing, the same job would take about eight days, he says. Nonetheless, in the United States, the majority of multistage frac jobs on laterals are done with cemented casing, and only about 20 per cent done with open-hole. “The economics of perf and plug can make sense if you have a number of wellbores on a pad,” Woitt says. Two advantages of fracking with cemented casing, not open-hole, says Hrab, are that, “You know exactly where the frac is and you’re not limited to a certain number of stages. Even with one-eighth inch increments per stage, at the toe there is going to be one very small hole for sand and fluid and gel, etc. Then, it’s got to create a fracture. You won’t reach a high enough pressure to frac the well. You won’t be able to frac at
TM
O I L & G A S I N Q U I R E R • M AY 20 13
59
Pad drilling is being used with horizontal wells and multistage
the required or breakdown pressure on all the stages. But with bridge plugs, you have full-bore access to the well—and it’s easier to clean out.” Another technique for completions of unconventional oil or gas reservoirs involves deploying an activation tool on coiled tubing (CT) to open fracture sleeves on a horizontal well. “The new technology uses fracture sleeves that are activated swiftly using a CT bottomhole assembly. The system, already used in thousands of fracturing stages in Canada, speeds up the completion process, uses less fluid, minimizes risks and reduces overall downtime,” says a June 2012 article in the Journal of Petroleum Technology. NCS Energy Services Inc., on its website, provides a quick comparison between its Multistage Unlimited technology and two other techniques—ball sleeves, often called ball-drop, and plug and perf. The proof of the pudding, they say, is in the eating. A Mar. 4, 2013, press release from NCS announced that the deployment of the company’s completion technology had resulted in the successful placement of 50 stages in a single well completion along a two-mile lateral targeting the Bakken. “By successfully completing three consecutive two-mile laterals, we have demonstrated our ability to execute that style of completion 60
M AY 20 13 • O I L & G A S I N Q U I R E R
without any extra tool trips, while maintaining an unobstructed wellbore,” said Eric Schmelzl, vice-president of strategic business, in the release. The Multistage Unlimited technique can be used on either cemented or openhole completions. One NCS process, called the HalfStraddle, is geared for very small fracs in thin zones, often with water-bearing zones nearby, which are best avoided. “By limiting the size of the frac, you avoid producing unwanted water. You pump the frac down inside the coil, so the rock is fracked with frac fluid only, and much less water is used, saving as much as 50 per cent. It’s a more controlled frac, and more likely to remain in the targeted intervals,” says Schmelzl in an interview. He says the Half-Straddle method has been used in the Manitoba and Saskatchewan Bakken, and in the Viking.
NATURAL GAS: OPEN-HOLE VERSUS CASED About 70 per cent of laterals in the tight gas plays of the Deep Basin are completed on an open-hole basis. A good chunk of the other 30 per cent were likely cemented and cased as a result of a fracture injection test. This would have been done to ascertain the level of difficulty that an operator could expect when fracking a specific zone.
“If it is likely to be difficult, then we recommend that it’s cased,” says Elham Samari, well construction and production engineering manager at RPS. On the other hand, if the inherent stresses within the rock along the wellbore are relatively uniform, then openhole is acceptable. Either way, the multi-stacked pay zones of the Deep Basin make well-planning a critical factor. “Ideally, you have the toe higher than the heel,” Samari says. Formations extending into the Deep Basin include Bluesky, Falher, Granite Wash, Montney and Cadomin. Extraction from the play can take many years, says Schmelzl. The number of stacked pay zones varies across the basin. In some parts they number five or six, but there can be as many nine. The rule is to start with the deepest formation. “Once that’s played out, then you move to the next formation above,” Schmelzl says. Noting that parts of the Montney and the Duvernay gas wells are rich in natural gas liquids, he points to the successful use of the company’s Multistage Unlimited technology to complete a well in what was apparently a test case between competing techniques. With two laterals extending in opposite directions from each other, one used a high-rate frac, with three
Photo: Gerald Ford
fracturing to cut costs.
Cover Feature
clusters, for completion. The other, using Multistage Unlimited, placed each frac individually. After observing that the competition expended a lot of horsepower simply overcoming friction pressure to obtain a high-rate frac, Schmelzl says, “The operator realized not only a doubling of production, [but] also nearly doubled ultimate production. When accessing a reservoir, if you don’t do it right the first time, there is almost no second chance. It’s difficult to access what you missed by going in a second time.” In a series of Montney shale gas wells, trial and error—and tweaking—eventually led to the desired outcome for another outfit. “At first we did the conventional thing. Then, the first change was we switched to oil from water-based mud. With oil, there was much less chance of getting stuck; also, maybe less damage to the reservoir formation. Then we decided on monobore. We optimized the motors with the bits,” says Hrab, who worked for a different company at the time. And so it went. In less than two years, drilling time dropped from around 21 days per well to 12 or 13. Costs per well halved—from over $8 million to an average of just over $4 million. The tweaking had paid off. O I L & G A S I N Q U I R E R • M AY 20 13
61
Feature
thewaitinggame B.C.’s natural gas industry holds on in anticipation of LNG export boom
Map Illustration: Adrian Sawvel/Photos.com; Design: Peter Markiw
By Darrell Stonehouse, with notes from the Daily Oil Bulletin
Every year, almost nine trillion cubic feet of natural gas with a value of $150 billion is super-cooled and shipped in tankers to Asian markets. Getting a piece of that giant liquefied natural gas (LNG) market will ultimately determine whether British Columbia’s natural gas industry continues to expand or stagnates. And right now the odds are around even on whether the five biggest LNG export terminals planned will be built, according to the experts. The size of the prize is huge, according to Ziff Energy Group. LNG exports to Asia could easily build up to 10 billion cubic feet per day within five years of the fi rst export terminal opening, Edward Kallio, the fi rm’s director of gas consulting, said at a recent Ziff-sponsored breakfast in Calgary. “We could get over 20 billion cubic feet a day of total western Canadian gas output pretty quickly if several of the proposed West Coast LNG export projects are realized, which is really good news for our basin. Drill bits will have to start turning to come up with this gas,” said Kallio. Western Canadian gas output has plunged to about 13 billion cubic feet per day and will probably fall closer to 12 billion cubic feet per day next year, Ziff Energy expects.
O I L & G A S I N Q U I R E R • M AY 20 13
63
Feature
“Our gas is being shut out of the U.S. market and even the eastern Canadian market,” Kallio said, referring to the inability of western Canadian gas to compete with cheap output from shale plays such as the Marcellus in the northeastern United States. “Marcellus is going to get up to 15, maybe 20 billion cubic feet a day by 2020,” Kallio said. “They don’t need our gas.” When western Canada was producing 17 billion cubic feet per day, about 10 billion cubic feet per day of that was shipped south of the border. Exports to the United States have now plummeted to roughly five billion cubic feet per day and are headed to three or four billion cubic feet per day, or even lower, Kallio said. Asian exports could make up for that lost market.
Time is of the essence, say analysts But to make that happen, industry needs to act fast in getting West Coast LNG export terminals up and running, according to Gerry Goobie, principal with Gas Processing Management Inc. “We really have to raise our game to participate in this LNG business,” Goobie told the Canadian Energy Research Institute natural gas conference. “If we’re going to be successful, we’ve got to get our product to market cheaper than the next guy. “If we take forever in the regulatory process to get through this, then LNG exports won’t happen and the whole gas development in western Canada won’t happen, and that would be a big calamity. I’m not saying this will occur, but we really have to focus on getting it done,” he said. “There is a window of opportunity
and we’ve got to get after it because that window is not going to remain open forever.” Some have suggested that Canada only has until the end of this decade to build up its LNG industry or face being overtaken by other countries looking to cash in on the booming demand for fuel throughout Asia. Gary Weilinger, vice-president of strategic development and external affairs with Spectra Energy Transmission, echoed the fact that the timing of these projects in British Columbia is critical. Last year, Spectra signed a project development agreement with BG Group plc to jointly develop plans for a new natural gas transportation system from northeastern British Columbia to serve BG Group’s potential LNG export facility in Prince Rupert, B.C., on the province’s northwestern coast. “If we think the world LNG markets are just waiting patiently for western Canadian LNG projects, then we’re mistaken,” he said. “This is a very competitive space with potential projects in Russia, Africa, the Middle East and Australia.” Of these, he pointed out that East Africa is emerging as a very competitive region. “Mozambique has shown recent exploration success,” he added. “In the U.S., our only export market, it could become our biggest competitor. We’re behind Australia and the U.S. There’s no catching Australia, which is in full construction mode. These plants will be coming on stream soon.” The United States, by virtue of the import regasification buildup, has infrastructure Canada doesn’t have and has pipeline access already in place.
CanGas S
Leading the Way.
CanElson Drilling Inc. Suite 700, 808 - 4th Avenue SW Calgary, AB, Canada T2P 3E8 www.CanElsonDrilling.com
64
M AY 20 13 • O I L & G A S I N Q U I R E R
O
L
U
T
I
O
N
S
Specializing in Natural Gas Transport and Flare Gas Collection.
CanGas Solutions Ltd. 2010, 444 - 5th Avenue SW Calgary, AB, Canada T2P 2T8 www.cangassolutions.com
Feature
“These could make U.S. supplies as competitive or more competitive than us,” Weilinger said. “Project approval timelines have not been our strong suit lately.”
Industry in a critical period, says Prentice Jim Prentice, senior executive vice-president and vice-chairman of CIBC, noted at a recent B.C. LNG conference that the challenge with gas is similar to oil in that there is a growing urgency to tap new markets. “Industry revenues are down sharply,” noted the former federal cabinet minister in an evening address to the conference. “Government revenues have been adversely affected. The impact on western Canadian producers has been devastating. And with key plays in the U.S. expected to result in even higher production south of the border, the threat to—and impact on—Canadian gas producers is likely to continue. “We’ve entered a critical period. We face the imperative to match up Canada’s resources with the needs of the Asian marketplace. We must access new and growing markets if we want to reinvigorate this important industry,” he added. “We therefore need to do the hard work of reorienting ourselves to serve the demand of tomorrow—and we need to get on with it, because there are others who are equally determined to get into those markets.” He noted that the critical element in the LNG industry is—and always will be—contractual dependability. “The world has a lot of natural gas,” Prentice said. “What it doesn’t have is an ample supply of reliable, dependable nation states that are capable of fulfilling their contractual obligations over a
50-year period without potential interruption due to political, legal or territorial conflict. “But let’s be clear. Getting into liquefied natural gas represents a big financial bet,” he added. “The stakes are high and the challenges are formidable. This is no slam dunk. We need to be confident and aggressive, but we must also ensure that we resolve and bring across the finish line a number of key outstanding issues.” First, Prentice said, a royalty regime must be defined in such a way that it promotes the establishment of an LNG industry in Canada and helps ensure its long-term survival and success. “In a highly competitive global industry, it doesn’t take much to marginalize returns to the point that other jurisdictions begin to look more attractive,” he said. “This month, the B.C. government indicated that it foresees some $100 billion in tax and royalty revenue coming to it from LNG over the next 30 years. In tough economic times, it’s human nature to celebrate potential good news.” But, he warned that the key driver of any project of this scale should be the overall benefits to the local, provincial and national economies, not simply the potential taxation base. “The imperative in LNG must be to ensure that the taxes we place on this important burgeoning industry don’t have the effect of stymieing or undermining its creation and its growth,” Prentice said. He added that there needs to be sufficient skilled labour to build the proposed LNG facilities and pipelines under tight timelines. “Australia, whose industry is more mature than ours, has already experienced significant delays caused by a shortage of qualified workers,” Prentice noted.
O I L & G A S I N Q U I R E R • M AY 20 13
65
Feature
g p r c . a b . c a
Careers with
SPA R K
Apprenticeship, Pre-trades Welding, Heavy Duty Mechanic, Steamfitter-Pipefitter, Power Engineer & many more.
1.888.999.7882 GPRC Fairview Campus Fairview, Alberta
Also, he said that the federal government needs to adopt a proactive role on coastal management. “Ottawa has sole jurisdiction over our territorial waters, so it must take the lead in developing a management regime that will take into account the rewards as well as the environmental risks of increased West Coast tanker traffic,” Prentice said. “We need to better understand and move to address the competitive challenge that may be posed by the United States. The Americans represent a different market offering. They are not necessarily committed to a long-term future as a natural gas exporter and they are prepared to sell at floating market prices.”
w w w . m a r m i t p l a s t i c s . c o m 888.868.2658
66
•
Grande Prairie, AB
M AY 20 13 • O I L & G A S I N Q U I R E R
Image: Apache Corporation
E&P companies hold on in low price environment While efforts to build export infrastructure sort themselves out, B.C. gas producers are finding ways to survive while waiting for the boom. Cost cutting is one means being used by Encana Corporation, the largest landholder in British Columbia. “At the end of the day, the oil and gas industry is the commodity business, and while we can’t control the prices for natural gas, oil or natural gas liquids, we can exert discipline on our cost,” interim president and chief executive officer Clayton Woitas told shareholders in late February. “We intend to increase our margins without depending on the natural gas price recovery.” The company is already reporting success in the Montney play in northeastern British Columbia, said Michael McAllister, executive vice-president for Encana and president of its Canadian operations. “Last year in Cutbank Ridge, we drilled 35 Dawson Creek Montney wells, where our resource play hub model continues to deliver cost savings driven by reduced drilling times and more efficient completions,” McAllister said. “The use of limited-entry slick-water completions has resulted in cost structures going down by 22 per cent, while simultaneously improving unconstrained initial production by 50 per cent in this area. Returns on our Montney play currently range between 30–40 per cent, and we
Feature
YEAR ROUND INDUSTRIAL & COMMERCIAL INSTALLATION
The proposed Kitimat LNG terminal.
518870 • Chain Link Fence and Gates Phoenix Fence Inc • Electric Gate Operators & Access Controls 1/4v · qpv • Pre-Manufactured/Portable Site Enclosures • Industry Leading Health, Safety feature & Environmental Program We also offer Safety Fence, T-Posts, Ornamental Fence & Vinyl Fence
expect our supply cost to be $2.70 per thousand cubic [feet] on an unleveraged basis. If we include the carry capital, our supply costs are expected to come in below $2.” Like many others, Encana is using foreign partnerships to help fund development in British Columbia. At Cutbank Ridge, it is partnered with Japanese multinational Mitsubishi in the Cutbank Ridge Partnership (CRP). The CRP plans to invest a total of $540 million in 2013, of which Mitsubishi has agreed to contribute $380 million and Encana has agreed to contribute $160 million. Overall, Encana has agreed to fund approximately 30 per cent of the development drilling program for its 60 per cent partnership interest. The CRP plans to run a four-rig drilling program in 2013. Talisman Energy Inc. has taken a similar tack with its Montney assets, with its partnership with South Africa’s Sasol Limited. Other companies are just holding on, waiting for exports to make natural gas development economical. EOG Resources, Inc. has written off the remaining book value of its entire Horn River acreage in northeastern British Columbia, along with all proved developed and proved undeveloped reserves because they are uneconomic at current gas prices, company chairman and chief executive officer Mark Papa said at EOG’s annual meeting. However, the drilling the company has done to date holds its remaining 127,000 net acres in the Horn River, with an estimated seven trillion cubic feet reserve potential, until 2020, according to Papa. The company previously was involved in the proposed Kitimat LNG project but, in late December, Encana Corporation and EOG sold their positions in the project and Chevron Corporation will take over as operator. Chevron and Apache Corporation now each hold 50 per cent in the project, which has struggled to secure a long-term off-take agreement with an Asian buyer. “We believe Kitimat is a good project, and with Chevron involved, the project will likely get built,” Papa said. “We simply believed that the substantial go-forward capital required by Kitimat would be best re-invested in U.S. oil shale plays.”
EDMONTON
CALGARY
(780)447-1919
(403)259-5155
12816 - 156 St. Fax: (780) 447-2512 edmonton@phoenixfence.ca
6204 - 2nd St. S.E. Fax: (403) 259-2262 calgary@phoenixfence.ca
1-800-661-9847
1-888-220-2525
Exclusive Authorized Distributor
ISO 9001-2000 CERTIFIED
BELZONA WESTERN LTD CALGARY, ALBERTA CANADA PH: 403-225-0474 TOLL FREE: 1-800-268-4553 FAX: 403-278-8898 WEB SITE: www.belzona.ca E-MAIL: belzona1@telus.net Belzona Polymeric Coatings combat erosion, corrosion and abrasion in high temperature immersed conditions. Rebuild and line tanks, process vessels and plant equipment. Contact us for advice on Belzona Know How Solutions and Procedures. -180˚ C Immersion Temperatures -Safe VOC Free Formulations -Brushable or Sprayable -Resists Rapid Decompressions -Belzona 1111 – 1311 -1391 – 1521 – 1591
-Amine Tower – Strippers -Exchangers – Chemical Tanks -Flare Knock Out Drums -Oil – Gas Separators -Outstanding Cavitation Resistance -Pressure Resistant
O I L & G A S I N Q U I R E R • M AY 20 13
67
The latest regional business news
Business
Intelligence Facility and infrastructure ownership benefit some producers By Paul Wells
Some intermediate companies that own and operate their own infrastruc-
James Surbey, vice-president of corporate development, says that the PCS
ture and facilities are finding success in attaining lower cost structures and
plant, which is located in the heart of the company’s Montney/Doig natural gas
increased control of development in an era of volatile commodity prices and
resource play, allows Birchcliff to control and operate all essential infrastruc-
market uncertainty.
ture—from wellhead to sales point.
Geoff Ready, an oil and gas analyst with Haywood Securities Inc., says that
“One of the main benefits is you get to control your own destiny a little bit;
as long as a company has sufficient output and has a sizeable footprint in a core
the pace in which you do things. If you want a midstreamer to provide you with
producing area, the business model of an intermediate exploration and produc-
capacity, they have to get capital approved to build pipe and to build a plant,
tion company owning and operating its own infrastructure network can work.
and that can take awhile. We can generally move quicker than they can move,”
“There are benefits depending on the scale of activity that you’re doing. If you
Surbey says. “It’s also a question of pace, as well. If I want to go harder than a
have a controlling interest in an area then there’s definite advantages to owning
midstreamer can go, that’s one thing. But if I want to slow down activity a little
your own infrastructure, both for controlling your own destiny in terms of when
bit, if I own my own plant, it’s easy for me to do compared to if I have a firm ser-
production will be on, but also from a cost perspective,” Ready says.
vice contract with someone else’s plant—if I want to slow down, I have to pay
“If you can keep the facilities near maximum capacity then there are real efficiencies, especially if it’s in an area you’re going to operate in over a longer period of time and you have lots of running room—then it makes a lot of sense.” There are drawbacks, however. Ready notes that a company has to weigh the
for it. So I’m paying for something I’m not using. That’s prett y crippling when gas prices are really low.” In Alberta, Vermilion Energy Inc. operates four natural gas plants and holds an ownership interest in a fifth with combined processing capacity to handle
benefits of investing a portion of capital into infrastructure versus directing it predominantly toward the drill bit. “The cons, of course, would be that for all the dollars you’re spending on infra-
“By us controlling our own facilities in the Cardium, for
structure, you’re not drilling wells with that money and adding more reserves. So
example, then we have direct control over the indirect
it’s a trade-off of operating costs versus your capital efficiency costs of finding reserves,” he says. “However, the infrastructure costs that you pay can be offset by operating -cost savings that you will achieve over time.” Adds Gary Leach, executive director of the Explorers and Producers Association of Canada: “Ownership of gas processing facilities by producers is more likely to be found among the larger junior- and intermediate-scale
and direct costs that get applied to that facility. We can basically decide what has to be spent and when, and, as a result, we have direct control with that.” — Lorenzo Donadeo, president and chief executive officer, Vermilion Energy Inc.
operators, and, of course, senior producers. Control and ownership of processing capacity has proven attractive for some operators, but there are a large
90 million cubic feet per day. The company also operates five oil batteries with
number of factors to be assessed; the same business model doesn’t work in
combined processing capacity to handle 200,000 barrels per day of fluids,
all situations.”
including 15,000 barrels per day of crude oil.
Birchcliff Energy Ltd., which last October completed the Phase III expansion
In its evolving Cardium play, Vermilion’s per-well production rates
of its 100 per cent owned and operated Pouce Coupe South (PCS) gas plant, is an
have remained consistently above its peers in the West Pembina region,
example of an intermediate that believes in the benefits of owning and operating
reflecting the high quality of the reservoir underlying the company’s land
its own infrastructure and facilities.
base. At the current drilling rate of 40–60 wells per year, production is
The company increased the processing capacity of the PCS plant to 150 million cubic feet per day (raw inlet capacity) from the then-licensed processing capacity
anticipated to reach a peak of 12,000–14,000 barrels per day in the next two to three years.
of 120 million cubic feet per day. To operate the plant at 150 million cubic feet per
President and chief executive officer Lorenzo Donadeo says that in any
day required some modifications to pipelines and sales meters on the NOVA pipe-
resource play cost containment is key. To that end, the company completed a
line system, but the capital required was not material.
15,000- barrel-per-day oil battery in 2011 that has enabled Vermilion to achieve
In 2012, Birchcliff installed over 31,600 metres of line pipe that feeds into
top-quartile operating costs of less than $6 per barrel on operated production
the PCS gas plant. Approximately 30 per cent of these pipelines are main trunk
and provides the necessary infrastructure for full-scale development of the
lines that are between eight inches and 12 inches in diameter.
Cardium light oil play.
68
M AY 20 13 • O I L & G A S I N Q U I R E R
Business Intelligence
“If you look at other producers in the area that are using third parties, it’s
Deep Basin gas player Peyto Exploration and Development Corp.’s third-
probably double that,” Donadeo says. “If your operating netback is around $35 or
quarter 2012 acquisition of Open Range Energy Corp. represented the first
$40, if you knock $4 off, that’s 10 per cent of your operating margin.”
major corporate acquisition in the company’s 14-year history. The properties
Vermilion prefers to own and operate its facilities for a myriad of reasons,
that were acquired were a natural fit with Peyto’s Greater Sundance core
not the least of which is the ability to control the pace of development in its
area and included strategic facility and pipeline infrastructure that can be
core regions.
expanded and integrated into Peyto’s existing system.
“Otherwise you’re relying on third parties for providing capacity when it’s available, and sometimes you can’t control that,” Donadeo says.
Late in 2012, natural gas–weighted Peyto completed an enhanced liquids recovery project at its owned and operated Oldman gas plant. The company
He adds that the company has benefited from taking a staged approach to
expects that the Oldman liquid yield will increase to 40 barrels per million
infrastructure and facility development—as a play develops, so, too, does the
cubic feet from 25 barrels, principally from improved propane and butane
scope of the midstream asset.
recoveries.
“You have to be careful not to overcapitalize your assets and build too large of
Executive vice-president, chief operating officer and director Scott
assets. That’s a mistake some people make—they have early success in a field
Robinson says the Oldman plant and other associated infrastructure are key
and then they build a large processing facility, whether it’s oil or gas, and then find
drivers of the company’s long-term business plan.
out a couple of years later that it’s been way oversized and they’ve overcapitalized the asset,” Donadeo says. “We always try to take it from a staged development [perspective]. We start small and then design the facilities so that they can be easily expanded at a later
“First and foremost, in a developing situation, where we really focus in a core area and we concentrate on the things we can do well, having a facility there is really the foundation to allow us to grow in a cost-effective manner,” he says.
date as you prove up your project,” he adds. “A lot of times these developments
“There are numerous advantages. The nature of the resource we’re tack-
are in early phases, and until you get some real production history you really don’t
ling is a long-life resource asset to the various formations that we’re drilling,
have an accurate estimate as to what the ultimate recovery and production of the
so it really behooves us to own our own facility rather than paying fees for
field will be. That’s why it’s good to stage the development of facilities over time.”
30 or 40 years into the future, which would pay for a facility multiple times.”
According to Donadeo, the ability to control operating and capital costs is another benefit of facility ownership.
Given the continued weakness in natural gas prices, Robinson says the economics of owning infrastructure assets have proven valuable.
“That’s pretty important to us because it allows us to obtain higher operating
“As we experienced last year with very, very low commodity prices, our low
margins by controlling operating costs and also to get better returns by having
operating costs that have come about as a result of us owning our facilities
better capital efficiency,” he says.
and controlling them and keeping them full—I can’t stress that enough—
“By us controlling our own facilities in the Cardium, for example, then we have direct control over the indirect and direct costs that get applied to that facility. We can basically decide what has to be spent and when, and, as a result, we have direct control with that.” While exploration and production companies generally get better rates of return on development projects than on capital projects, Donadeo and Vermilion believe that competitive advantages gained from infrastructure ownership exceed the negatives.
provides us with a real low-cost operating platform that allows us to endure a lot of these ups and downs in prices,” he says. “That became very evident last year. People were not making any cash flow, and even at a $1.50-per–thousand-cubic-feet gas price, we were still generating operating income because of that low cost aspect of owning our own facilities.” Certainty of market access is another compelling benefit of facility and infrastructure ownership, Robinson notes.
“There are competitive advantages in terms of competing for mineral rights
“We can control our sales gas and our liquids with the knowledge that
and for other acquisitions. So once you have got control of infrastructure, you
we’re not going to be shut-in a month or two because of short-term [third-
have a better opportunity in terms of trying to dominate an area,” he says.
party] deals,” he says.
“It also allows you to maximize your online times and to maximize your pro-
“If you do take your production to another party’s facility, quite often
duction. There’s a bunch of ancillary benefits that are hard to build into your
you’re in an uncertain situation and vulnerable...that your volumes get dis-
economics when you look at the headline numbers in terms of rates of return or
placed and you would be shut-in and looking for a new place to take it. That
facility versus development assets.... These things can add to your economics
certainty is worth a lot,” Robinson adds. “As well, our on-stream times I think
quite significantly.”
are some of the best around, if not the best.”
O I L & G A S I N Q U I R E R • M AY 20 13
69
advertisers' index Advantage Valve Maintenance Ltd . . . . . . . . . . . 26 Annugas Compression Consulting Ltd . . . . . . . . 38 Bear Slashing Inc . . . . . . . . . . . . . inside back cover Belzona Western Ltd . . . . . . . . . . . . . . . . . . . . . . 67 Bilton Welding and Manufacturing Ltd . . . . . . . . 35 Bonnyville Chamber of Commerce . . . . . . . . . . . . 3 Brother’s Specialized Coating Systems Ltd . . . . 55 BV Land Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 CanElson Drilling Inc . . . . . . . . . . . . . . . . . . . . . . 64 CAPE Manufacturing Ltd . . . . . . . . . . . . . . . . . . . 41 City of Grande Prairie . . . . . . . . . . . . . . . . . . . . . 24 ClearStream Energy Holdings . . . . . . . . . . . . . . . . 8 CRD Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Daemar Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 Definitive Optimization . . . . . . . . . . . . . . . . . . . . 31 Diversified Glycol Services Inc . . . . . . . . . . . . . . 35 dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Dragon Products . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Ecoquip Rentals & Sales Ltd . . . . . . . . . . . . . . . . .51 Edmonton Exchanger & Manufacturing Ltd . . . . .61
70
M AY 20 13 • O I L & G A S I N Q U I R E R
EV Canada Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 Expertec Van Systems Inc . . . . . . . . . . . . . . . . . 69 Flexpipe Systems . . . . . . . . . . . . . . . . . . . . . . . . . 6 Ford Motor Co Canada . . . . . . . . . . . . . . . . . . . . . 12 GPRC Fairview . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Hughson Trucking Inc . . . . . . . . . . . . . . . . . . . . . 46 Imperial Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Industrial Training International . . . . . . . . . . . . . 37 Infosat Communications LP . . . . . . . . . . . . . . . . 20 MaXfield Inc . . . . . . . . . . . . . . . outside back cover MDI Industrial Sales Inc . . . . . . . . . . . . . . . . . . . 40 Meridian Manufacturing . . . . . . . . . . . . . . . . 14 & 15 MPI-Marmit Plastics Inc . . . . . . . . . . . . . . . . . . . 66 MRC Global Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 NAIT Corporate and International Training . . . . . 43 NC Services Group Ltd . . . . . . . . . . . . . . . . . . . . 22 Nexus Exhibits Ltd . . . . . . . . . . . . . . . . . . . . . . . . 65 Northgate Industries Ltd . . . . . . . . . . . . . . . . . . . 34 Norwesco Canada Ltd . . . . . . . . . . . . . . . . . . . . . 22 Penfabco Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
Phoenix Fence Inc . . . . . . . . . . . . . . . . . . . . . . . . 67 Platinum Grover Int. Inc . . . . . . . . . . . . . . . . . . . . . 17 Platinum Pumpjack Services Corp . . . . . . . . . . . 27 Predator Drilling Inc . . . . . . . . . . . . . . . . . . . . . . . 33 PTI Group Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 Saskatchewan Oil & Gas Show . . . . . . . . . . . . . . 48 Sirius Instrumentation And Controls Inc . . . . . . . 42 Sprung Instant Structures . . . . . . . . . . . . . . . . . . . 7 STEP Energy Services . . . . . . . . . . . . . . . . . 21 & 23 Tundra Process Solutions Ltd . . . . . . . . . . . .18 & 28 Unified Valve Ltd . . . . . . . . . . . . . . . . . . . . . . . . . .16 Veyance Technologies Inc . . . . . . . . . . . . . . . . . . 32 V.J. Pamensky Canada Inc . . . . . . . . . . . . . . . . . . . 11 West Country Oilfield Services & Weed Control . . . 10 Westeel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 Yantai Jereh Petroleum Equipment Technologies Co Ltd . . . . . . . . . . inside front cover ZCL Composites Inc . . . . . . . . . . . . . . . . . . . . . . . 59
TOG ETHE R WE CAN
For over 10 years MaXfield has quietly been gaining the expertise and experience to handle your next project. From custom vessels to structural steel, piping and modular packaged equipment; MaXfield is now your one stop shop for industrial fabrication.
w w w. m a x f i e l d . c a