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2011 ca d e • caod c


Thursday, May 12, 2011 TELUS Convention Centre, Calgary, Alberta

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cade ● caodc drilling conference John Garden CADE Co-chair George McHardy CAODC Co-chair Kim Barton Conference Coordinator

2011 cade ● caodc drilling conference

Jessica Coomber Managing Editor Technical Production Management by Aimée Barnabé and Bruce Hennel Smile Productions junewarren-nickle’s energy group Bill Whitelaw President & CEO Agnes Zalewski Publisher Dale Lunan Editor Tracey Comeau, Samantha Kapler, Marisa Kurlovich, Kyle Thompson Editorial Assistance Graham Chandler, Ashok Dutta, Jarret M. Dragani, David Finch, Maurice Smith, Darrell Stonehouse, Gord Wagner Contributors Ken Bessie Art Director Peter Markiw Graphic Designer Susie Wong Designer Nick Drinkwater Account Manager Jeannine Dryden Marketing/Trade Show Coordinator Calgary: 2nd Floor, 816-55 Avenue N.E., Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 Fax: 403.245.8666 Toll-free: 1.800.387.2446 Edmonton: 6111-91 Street N.W., Edmonton, Alberta T6E 6V6 Tel: 780.944.9333 Fax: 780.944.9500 Toll-free: 1.800.563.2946

contents conference information

5 7 9

Welcome Letter &

10 Conference Schedule

Executive Committee

12 Keynote Speakers

CADE ●CAODC Welcome Letters

13 Sponsor Page

Technical Committee

42 Rig Guide


16 A New Wave

Horizontal drilling and multistage fracturing are re-energizing legacy oilfields across western Canada

22 What is a Well?

PPDM’s mammoth effort to streamline well-description lingo is starting to catch on

26 Technology is King

Unleashing the newest technology in older formations like Pembina, Cardium and Viking coaxes new production out of once-uneconomic wells

studies in innovation directional technology helps 35 New with the precise placement of well pairs technology helps 37 VAC-Screen drillers recapture oil-based mud of drilling fluid recovery through 39 Evaluation surface control equipment in modern onshore drilling practices

Neither CADE, CAODC, or CADE CAODC Drilling Conference take any responsibility for the statements, references, or facts printed within this document that may have been written in error and are released from any liability in this regard.


793023 Strad Energy Service full page • fp

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PHOTO: Christina Ryan



n behalf of the CADE•CAODC Drilling Conference Executive Committee, it is my pleasure to welcome you to the 15th CADE•CAODC Drilling and Completions Conference, “Old Fields. New Ideas.” at the Calgary TELUS Convention Centre in Calgary. A significant number of volunteer hours have gone into planning this event, and we hope that you will find the experience informative and enjoyable. With so many available conferences for our industry to participate in, I have been asked numerous times over the past eight years what it is that makes this conference significant. Besides the strong collaborations between operators and service suppliers that you will see in our technical presentations and the networking possibilities to reconnect with industry partners and friends, the most critical contribution this conference makes is toward our future, through supporting career-minded students seeking to enter our industry. This conference is a not-for-profit event with all proceeds paid forward to student bursaries and scholarships. Did you know that over the last three years, this conference has contributed over $50,000 in student funding? This year, we are poised for a record contribution thanks to our sponsors who recognize this very important investment. Look among the delegate members and volunteers today: students from local universities and technical institutions are present and interested in discussing their career path—perhaps even with your organization.

Standing, Back, left to right: Mike Carter, Mark Scholz, Ed Besuijen, George McHardy (co-chair), Scott Erickson Seated, left to right: Kim Barton (Conference Coordinator), Jessica Coomber, Ron McCosh Missing: John Garden (co-chair)

In addition, the committee is honoured to have two very distinguished keynote speakers with us today to share with you their experiences and best practices. Mr. Rene LaPrade, senior vice-president of operations with PetroBakken Energy Ltd., will open our conference and Dr. Brant Bennion, director of Porous Media Research and technology advisor for Weatherford Canada Partnership, will be our luncheon speaker. Both speakers will present their informed perspectives on our conference theme. Again, the technical abstract submissions this year were plentiful and strong, allowing us to continue to provide concurrent sessions throughout the day, giving our delegates the choice to attend the presentation that is most relevant to them. The sessions include directional drilling, completions, optimization, and environment/planning and designing. Thank you to those authors who took the time to share your case histories and technological advances—you are the backbone of this conference and contribute greatly to our future prosperity. Thank you all for your attendance today, and please provide this committee with your suggestions for our future conferences. In a landscape with so many conferences to support, we appreciate your continued patronage. Sincerely, Kim Barton 2011 CADE•CAODC Conference Coordinator


What the Industry is Saying... 2000 Manning Innovation Award

“...your contribution to worker health and safety in Alberta is truly valued and appreciated.”

“Your commitment and activities will help ensure that the rich environment that we are privileged to have in Alberta is maintained.”

Chair for Alberta Occupational Health and Safety Council Source: Letter regarding Annual Awards for Innovation in Workplace Health and Safety

“If you can start right from the drilling end in keeping your leases clean, it’s going to save you big dollars and help the environment down the road when you want to abandon a well.” Consultant for BP Canada Source: New Technology Magazine

2004 Ernst & Young Entrepreneur of the Year Finalist

2005 Emerald Award

Vice President for Climate Change Central Source: Congratulatory letter regarding receipt of Emerald Award

”The system has proven very effective in controlling spills associated with oil field drilling which subsequently has a positive impact on the environment.”

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“For us being up here in Alaska, which is entirely environmentally sensitive and zero-stain, the Katch Kan™ system is vital. If you have one major spill in Alaska and you can capture it with this product, it’s paid for itself.” Rig Manager for Doyon Drilling Inc. Source: New Technology Magazine Worldwide Installations!

Worldwide Patents / Patents / Patents Pending

Operations Manager for Ensign Drilling Inc. Source: Customer appreciation letter

”We have a good crew onsite and they are pleased with less clean up. Our BOP is kept very clean; therefore, this [Zero Spill System™] saves us on clean up time…” “We are very satisfied!” Rig Manager Contracted for Husky Energy Source: On-Site interview

telephone 780.414.6083 toll free 1.800.840.2877


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elcome delegates, speakers, students and volunteers to the 2011 CADE•CAODC Drilling and Completions Conference, our 15th anniversary for this event. I have had the privilege and pleasure of co-chairing this event with George McHardy, and we are looking forward to an exciting and informative conference. The continued success of the conference is due to the work of the volunteers on the executive committee. The hard work and dedication of everyone on the committee is commendable, and if you enjoy the conference, please thank these people, as they are volunteers and they appreciate the recognition. The conference is always looking for new volunteers, so if you see a place where your talents can add value, talk to one of the executives. This year’s theme of “Old Fields. New Ideas.” is relevant to our industry. The only constant is change and our business is constantly reinventing itself with changes in technology and the lines between drilling and completions engineering being blurred. The Western Canadian Sedimentary Basin has been revitalized with new drilling and completion techniques and these techniques are transferrable to other fields around the world. Canadians are at the forefront, introducing techniques learned here at home to the world, something as an industry we should be exceptionally proud of. Our industry is experiencing activity levels unseen for a number of years, and education and educating rapidly becomes a lower priority. However, it is critical when we are this busy to ensure everyone at every level in the industry understands why we conduct operations the way we do. The end objectives are clear: increased productivity from not only our wells, but also our people. Current equipment is large, powerful and fast, therefore, communication and education ensures the work is done safely so that every family is complete at the end of every working day. I would like to thank the speakers and presenters for sharing their wealth of experience with their peers. In our rapidly changing business, the need has never been greater to inform and educate each other due to the interdisciplinary teamwork that drilling and completion operations require. Wells are becoming increasingly complex, and the exchange of ideas and information is critical to the success of reservoir exploitation and management. Again, thank you for attending the conference, an excellent opportunity to learn about new technology and techniques, reacquaint ourselves with our peers and perhaps make some new friends. I would challenge all participating delegates to think of ideas for next year’s drilling conference and perhaps become one of the presenters.

s the 2011 CADE•CAODC Drilling Conference commences, I would like to welcome the participants, guests and magazine readers to this important event. The CAODC takes great pride and pleasure in partnering with CADE to undertake the drilling conference. It is a highlight in our calendar and a notable event for the proponent community in the Western Canadian Sedimentary Basin. As we move through 2011, the industry is optimistic that we will continue to see improvements in investment and drilling activity. A very important part of that outlook is founded upon past and current improvements to our drilling and completions technology. The future of a vibrant industry in western Canada is contingent on that continuing focus. We are very hopeful that you will find the conference to be interesting and rewarding. Thank you for attending.

Don M. Herring President, Canadian Association of Oilwell Drilling Contractors

Respectfully, John Garden, P.Eng. President, Canadian Association of Drilling Engineers


HigH PerFormance

HigH Value 521258 Precision Drilling full page • fp




Precision markets a fleet of over 350 technically advanced land drilling rigs and 200 service rigs, along with strategic support services including directional drilling services, snubbing, oilfield equipment rentals, worksite accommodation and wastewater treatment. For more than 50 years, Precision has been building strong relationships with customers by focusing on doing the job safely, on time and on budget. W W W . P R E C I S I O N D R I L L I N G . C O M 1 . 4 0 3 . 7 1 6 . 4 5 0 0

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PHOTO: Christina Ryan


Back, left to right: Brent Warren (Matrix Drilling Fluids), Marty Muir (Husky Energy), Murray Krausert (Beaver Drilling), Ron McCosh, co-chair, (Volant Products), Ron Isinger (Precision Drilling), Jim Rau (ConocoPhillips Canada). Front: Mark Scholz, co-chair (CAODC).

Missing: Jeff Arvidson (Devon Canada), Derrick Westlund (Benchmark Solutions), Dalis Deliu (Halliburton), Karen Roett (Suncor Energy), Peter Diaconescu (Canadian Forest Oil).

The CADE•CAODC technical committee, headed by Mark Scholz and Ron McCosh, was responsible for reviewing all abstracts submitted for consideration as technical presentations at the conference. The work of the committee members was instrumental in the success of the 2011 CADE•CAODC Drilling Conference and the conference executive committee would like to thank the committee for its hard work this year.

conference COMMITTEEs This event would not be possible without the help of the dedicated individuals who volunteered their time and efforts to ensure the success of the 2011 CADE•CAODC Drilling Conference.


Advertising / Sponsorship Committee

George McHardy, Co-Chair (CAODC), Nabors Drilling

Mike Carter, Sponsorship Chair, Ryan Energy Technologies

John Garden, Co-Chair (CADE), Deadeye Engineering & Consulting Inc.

Jessica Coomber, Advertising Chair, BOS Solutions

Kim Barton, Conference Coordinator, Weatherford Canada Partnership

Kym McIntosh, Subcommittee Chair, Ryan Energy Technologies

Ed Besuijen, Keynote Speakers’ Chair, CBW Resource Consultants

Todd Geddie, Moduspec Risk Management Services Canada

Mike Carter, Sponsorship Chair, Ryan Energy Technologies

Kyle Klam, Octane Engineering

Jessica Coomber, Advertising Chair, BOS Solutions Ltd. Scott Erickson, Registration Chair, Apex Oilfield Services (2000) Inc. Mark Scholz, Technical Co-Chair, CAODC Ron McCosh, Technical Co-Chair (CADE), Volant Products Inc.


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Our Business Is Service. Our Expertise Is Engineering. Remember that engineer who never left the office? - ate his lunch at his desk - came in early, stayed late - worked on weekends - got the job done

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We are him. drilling completing, Are you looking at drilling, working over or abandoning? Need well licence applications, drilling and completion programs, or wellsite supervisors?

2011 CADE • CAODC conference schedule

T h u r s d a y , M a y 1 2 , 2 0 11 7:00 a.m.

Registration Opens and Continental Breakfast Sponsored by Beaver Drilling Ltd.

7:45 a.m.

Theatre Doors Open

8:00 a.m.

Opening Remarks George McHardy & John Garden, Conference Chairmen


Keynote Presentation Rene LaPrade, PetroBakken Energy Ltd.


Conference Overview - 2011 Kim Barton, Conference Coordinator




A lt e r n at e P r e s e n tat i o n Research Initiatives to Optimize Casing String Running Tools: an R&D Case Study I. Meger, Meyers Norris Penny LLP/Noetic Engineering







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T ELUS c o n v e n t i o n c e n t r e , c a l g a ry


Session I - Horizontal Drilling Sponsored By: Savanna Energy Services Corp.

Session II - Optimization Sponsored By: Akita Drilling Ltd.

Session Chairmen: J. Arvidson, Devon Canada M. Krausert, Beaver Drilling Ltd.

Session Chairmen: R. Isinger, Precision Drilling Corporation D. Deliu, Halliburton

8:45 a.m. Fluid Hammer Drives Down Well Costs B. Francis, Suncor Energy Inc.

Using an Intelligent Well Technology M. Bedry, Halliburton Well Dynamics

9:15 a.m. Rotary Steerable Technology: A Modern Solution to a Dated Challenge D. Drake, Baker Hughes Canada

Super Singles vs. Triples A. Denholm, Precision Drilling

9:45 a.m. Casing Centralization in Horizontal and Extended Reach Wells A. Sanchez, Top-Co LP

Real Time Along String Pressure Measurements Reduce Drilling Risk and Increase Efficiency M. Reeves, XACT Downhole Telemetry Inc.

10:15 a.m.

Networking Break Sponsored By: Beaver Drilling Ltd.

10:45 a.m. Tighter Well Spacing by Use of Multi-Station Analysis (MSA) R . Quigg, Weatherford Canada Partnership

Use of the ACFM Inspection Method to Reduce Downhole Drillstring Failures D. Thurlow, Global Inspections NDT Inc.

11:15 a.m. First Deployments of Integrated Coiled Tubing Drilling Solutions in Canada D. Drake, Baker Hughes Canada

Innovert - Stepping up to the High-Temperature Challenge in Extended Horizontals M. Upshall, Halliburton

11:45 a.m. 12:00 p.m.

Technical Sessions Close

No Host Reception Keynote Luncheon: Dr. Brant Bennion, Weatherford Canada Partnership ‘Drilling and Formation Damage - Is it really always OUR fault? Sponsored By: Ensign Energy Services Inc. Tickets for this event must be purchased in advance

Session III - Completions Sponsored By: Evraz Inc. NA, Energy Resources Conservation Board 1:15 p.m. Session Chairmen: M. Muir, Husky Energy Inc. J. Rau, ConocoPhillips Canada

Session Chairmen: B. Warren, Matrix Drilling Fluids R. McCosh, Volant Productions Inc.

Real Time Gas Composition Measurement: How New Technology Enables Improvements in Oil and Gas Wells R. van Beurden, Pason Systems Corp. 1:45 p.m. New Debris Management System for Managed Pressure Milling Operations K. Demong, Apache Corp 2:15 p.m.

Session IV - Environment/Planning & Designing Sponsored By: Summit Tubulars Corporation, Top-Co LP & Innovative Fluid Systems Inc.

Development and Deployment of a Comprehensive Centrifugal Cuttings Drying System: An Environmental Solution and an Increasingly Economic Problem C. Murray, Fuse Enviro Ltd. Old Fields: Fountains of Youth or Geriatric Care Patients? D. Cuthill, Concord Well Servicing

Networking Break Sponsored By: Pason Systems Corp.

2:45 p.m. Deploying Multi-Stage Completion Technology in HPHT Applications R. Oberhofer, Packers Plus Energy Services Inc.

Effect of Shale Anisotropy on Wellbore Stability in Horn River Basin S. Khan, Schlumberger Canada

3:15 p.m. Developing a Stage Tool for Cemented Mono-Bore Completions on Open Hole Multi-Stage Completions in the Montney, K. Kimitt, Packers Plus Energy Services Inc.

Remedial Casing/Cement Repair with Sodium Silicate C. Hogstead, Cenovus Energy Inc.

3:45 p.m.

Old Fields, New Stimulation Ideas C. Medhurst, Sanjel Corporation

4:15 p.m.

Closing Reception Sponsored By: Nabors Drilling


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K EYNOTE SPEAK ERS Rene LaPrade, P.Eng, senior vice-president of operations for PetroBakken Energy Ltd., has been with the company since its inception, after serving in the same role at Petrobank Energy and Resources Ltd. Previously, he was president and chief executive officer of Mirage Energy Ltd. from October 2006 to February 2008; vice-president of operations for Petrobank Energy and Resources from July 2002 to September 2006; manager of operations for Barrington Petroleum Ltd. from May 2001 to September 2001, and vice-president of operations for Petrorep Energy Resources Ltd. from June 1991 to May 2000. He is a professional engineer with over 30 years of experience in the oil and gas business. Rene LaPrade, P.Eng, PetroBakken Energy Ltd. Opening Keynote

Dr. Brant Bennion, P.Eng, Weatherford Laboratories Keynote luncheon presentation

Dr. Brant Bennion, P.Eng. has over 30 years of experience in the area of multiphase flow in porous media, formation damage, phase behaviour, drilling, completion and enhanced oil recovery operations. Brant has been a distinguished lecturer for both the Society of Petroleum Engineers and the Petroleum Society on the topic of formation damage, lectures as an adjunct professor at the University of Calgary, is the author/co-author of almost 250 technical papers and has lectured extensively in over 40 countries in recent years. He has been employed by Weatherford Laboratories (formerly Hycal Energy Research Laboratories Ltd.) in various capacities since 1979 and currently is the director of Weatherford’s porous media research group. He is a registered professional engineer with APEGGA and holds B.Sc. and PhD degrees in chemical and petroleum engineering from the University of Calgary.



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conference SPonsors GOLD



LUNch Sponsor A.M./P.m. Sponsor

Closing reception sole technical sponsor

S Savanna

partial technical sponsor Lanyard Sponsor

Thank you to all our sponsors who made this conference possible through their generous support and contributions.


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Drilling rig activity A syn o ps i s o f v i ta l d r i l l i n g stat i st i cs f o r wester n C anadA

2008 2009 2010 2011

AVAILABLE DRILLING RIGS Total number in western Canada

925 900 875


850 825 800 775 750 725 700 675 JAN







2008 2009 2010 2011


Per cent active in western Canada



80 60 40 20 0 JAN







2008 2009 2010 2011


Total number drilling in western Canada

800 700 600

SOURCE: G. Wagner and CAODC


500 400 300 200 100 0 JAN








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a new wave Horizontal drilling and multistage fracturing are re-energizing legacy Oilfields across western Canada By Darrell Stonehouse


Legac production in southern

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Legacy Oil + Gas is using new technology to optimize production from the historic Turner Valley field in southern Alberta.

Penn West Exploration is using modern horizontal drilling and multistage fracs to optimize Cardium formation production near Drayton Valley, in west-central Alberta. PHOTOs: (LEFT) Brian harder, (RIGHT) Penn West Petroleum Ltd.


he Bakken/Three Forks play in southeastern Saskatchewan is the epicentre of the resurgence in western Canada’s conventional oil industry. In the past five years, over 2,000 horizontal wells with multistage fracture completions have been drilled into the play, with production reaching over 65,000 barrels per day in 2011. “The Bakken pool is now the largest producing oilfield in western Canada,” Greg Tisdale, chief financial officer of Crescent Point Energy Corp., told a BMO Capital Markets conference late last year. “With an estimated four or five billion barrels in place, the Bakken light oil resource play is the largest pool discovery in western Canada in the last 50 years.” And now, the horizontal drilling and multistage fracturing technologies used to crack open the Bakken are being used to free trapped oil in mature fields and new plays across the Western Canadian Sedimentary Basin, setting off a boom that could ultimately turn around the three to four per cent production decline plaguing the sector since 1999. The Cardium formation underlying much of western Alberta is the immediate target, but other areas of interest include the Viking formation in west-central Saskatchewan, the Lower Shaunavon in southwestern Saskatchewan and the Devonian in north-central Alberta. The technology is also causing a renaissance in the Pekisko play running from southern Alberta northwest to the Peace region. And a number of new plays, including the Alberta Bakken, Nordegg and Duvernay, are also taking shape. Crescent Point is the most significant producer in the Bakken, with 32,000 barrels of oil equivalent per day of production and 930 net sections of land. The company has 3,800 drilling locations in inventory.


PHOTO: Penn West Petroleum Ltd.

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the same number of fracs that we used on the long wells, the short wells performed initially at exactly the same or slightly higher rates—again taking us to the conclusion that more fracs make more oil.” From there, Smith said, as the multistage fracturing technology evolved, the company could increase fracturing density over longer horizontal legs, resulting in increased recoverable reserves. The company was the first to execute a 20-stage fracture in the play, which is now the standard. “We saw some operators starting to drill two long horizontal wells on each quarter section,” he noted. “We thought, if that’s the way the play is going to go, we need a more capital-efficient way to do that.” PetroBakken came up with a scheme to drill bilateral wells off of a single vertical well to cut costs. “In the subsurface, it’s exactly the same impact. That’s the conclusion of the reserve auditor,” explained Smith. “If you add a second horizontal leg, the reserve auditor says it results in an increase of 50 per cent of the reserves the original well would have recovered. But with the bilaterals, there are tremendous capital efficiencies. A bilateral costs $2.58 million to drill, while it costs $4 million to drill two wells.” PetroBakken has drilled 121 bilateral wells into the Bakken since 2009. In 2011, it plans on drilling another 75 bilaterals into the play. It has 900 potential targets in its Bakken inventory. While the Bakken is still in its development drilling phase, producers are already looking to enhanced recovery technologies to further capture more trapped oil. Crescent Point is already piloting four waterflood tests in the hopes of capturing more resource. The first pilot began in 2001, and the results have been encouraging. Crescent Point A horizontal well being drilled by Penn West Exploration in the Cardium play near Drayton Valley, in west-central Alberta. estimates it will increase the recovery factor from the three-well pattern from 19 per cent Crescent Point is the most significant producer in the Bakken, with to 30 per cent. The company drilled 13 injection wells in 2010 and plans 32,000 barrels of oil equivalent per day of production and 930 net sections for up to 40 injection wells by the end of this year. of land. The company has 3,800 drilling locations in inventory. Tisdale says Crescent Point expects the waterflood scheme will PetroBakken Energy Ltd. is the second-largest producer. In reporting allow the company to increase recovery by around 307,000 barrels the company’s 2010 results in March, president and chief operating officer per well, and that this will transfer into increased economic value for Gregg Smith said the company has been on a steep learning curve in the company. developing the play over the last decade. “Three wells under primary production would be worth around “Since entering the Bakken play, we’ve been continually evolving the $18 million,” he explained. “Under waterflood, the value of those technology we’ve used,” Smith explained. “The first wells were long wells would be $24.6 million. horizontals with no multistage fracturing. About five years ago, we PetroBakken is also advancing enhanced recovery plans, injecting gas introduced multistage fracturing. A typical well would have received about rather than water to force more oil out of the rock. eight fractures along a mile-long horizontal [leg]. We discovered by playing “We did a carbon dioxide injection on a well early in 2010,” with the technology that more fracs equalled more oil. But the only way explained Smith. “We started a well in February and injected carbon to increase the fracture density at the time was to drill shorter wells. The dioxide over two days. We wanted to use natural gas, but it is more interesting thing that came out of drilling the shorter wells was that with difficult to do, so we chose carbon dioxide for the test case. The offset


22001111 CA CADDEE■• CAO D C D r i l l i n g C o n f e r e n c e

with 20 tonnes in the Cardium. Total well costs in the Viking are $1.18 million, and Penn West would like to see those drop to $1.05 million in the upcoming year. “We are currently appraising the Viking to the north and west, and now west into central Alberta,” said Nunns. “It provides solid returns and significant running room for Penn West.” At Amaranth in southwestern Manitoba, Penn West drilled 56 of the 149 wells drilled in the play last year. It plans on drilling more than 80 wells in the area in 2011. Here, it is drilling monobore wells with 660-metre horizontal legs, with an average of 20 frac stages. Frac sizes range from five to 10 tonnes. Nunns said the carbonate play at Swan Hills and Red Earth would emerge as a major focus for Penn West as 2011 advances. “The carbonates are about six months behind the Cardium in the appraisal cycle,” he explained. “By year-end, we will be through the appraisal stage in the central areas. Pushing out to the edges will take a little longer.” Penn West has 160,000 acres in the carbonate play and has identified over 400 current drilling locations. It operated 16 of the 56 wells industry-drilled in the play last year and plans on 30-40 wells in 2011.


wells adjacent to the injector more than doubled in production, and 10 months after the injection, they’re still producing 50 per cent higher than what they were producing before we did the injection, so we think continuous injection will have quite a positive impact on the play.” Smith said the next step is to further develop enhanced oil recovery (EOR) plans using natural gas. “Using natural gas should look like carbon dioxide without the corrosion issues,” he explained. “Natural gas is cheaper than carbon dioxide and at the end of the day, we will recover most of the gas back, so it ends up acting as a physical hedge, and hopefully the price will be higher as well.” PetroBakken plans on spending $20 million on its EOR plans in 2011. Outside the Bakken, the Cardium is the busiest of the new tight oil plays. There are between 10.5 and 12.5 billion barrels remaining in the Cardium play, and a number of companies believe the multistage fracturing revolution can be used to exploit some of that resource. Penn West Exploration (the operating entity of Penn West Petroleum Ltd.) is the most active player in the Cardium and the most active oil driller overall across western Canada. It has over 650,000 acres in the Cardium play, and has identified over 2,500 drilling locations. The company is drilling monobore wells with horizontal legs averaging 1,000-1,400 metres. Each well has an average of 17 fracture stages. In March, Penn West president and chief operating officer Murray Nunns reported to shareholders during the company’s year-end conference call that after spending 2010 appraising its various tight oil plays, the company is ready to start development in earnest this year. And its major target will be the Cardium. “We have the appraisal of significant areas of the play done and that has allowed us to prioritize our 2011 capital spending,” said Nunns. “The bulk of our efforts will be concentrated in the high-productivity areas of West Pembina and Willesden Green, as well as some other selected areas along the play trend.” Nunns said Penn West has eight rigs currently working the Cardium and has drilled 16 wells so far this year. It plans to drill 80 or 90 wells into the play. Penn West’s current focus is on reducing the costs of drilling and completions in the Cardium. Pad drilling is being used as one means to reduce costs. Penn West estimates that by drilling four horizontals per pad, it can reduce lease construction costs from $600,000 per well to $250,000. Drilling times are reduced from 18 days to 12 days, and rig moving costs are reduced from $200,000 per well to $40,000. The company is also refining its fracturing fluids to improve reliability and optimize production. Nunns said they have been testing slick water fracs and hydrocarbon-based fluids side-by-side in well pairs. “The slick water fracs are not there yet,” he noted. “Right now, things slightly favour hydrocarbons, but that could shift in the next few months.” Penn West is also extremely active in a number of other tight oil plays, including the Viking play near Dodsland, Sask., the Amaranth play in southwestern Manitoba, and the Devonian play at Swan Hill and Red Earth in north-central Alberta. At Dodsland, it drilled 52 out of the 121 wells industry drilled in the Viking play in 2010, reporting initial average production of 55 barrels of oil equivalent per day from each well. The company is drilling monobore wells with 660-metre horizontal legs, and using 18 fracture stages per well. Fracture sizes are 12 tonnes, compared

A well workover in Turner Valley by Legacy Oil + Gas.


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In the carbonates, it is drilling 1,000- to 1,400-metre horizontal wells, with an average of 15 frac stages per well. Unlike in the Cardium, acid is used for completions in this play. The Lower Shaunavon play in southwestern Saskatchewan is dominated by Crescent Point, which has 570 net sections of land on lease and more than 1,500 drilling locations inventoried. “The Lower Shaunavon has an estimated 4. 3 billion barrels in place, r anking it as the third-largest pool in western Canada ,” said Tisdale. “ In terms of development , it is about three years behind the B akken.” Currently, Crescent Point has about 8,500 barrels of oil equivalent per day of production coming out of the Lower Shaunavon. But its upside growth remains huge, and the company has added to that potential with drilling in the Upper Shaunavon as well. “We’ve been able to leverage off our experience in the Bakken by applying similar horizontal drilling and multistage fracturing techniques,” Tisdale explained. “In addition to the Lower Shaunavon, we have now successfully drilled into the Upper Shaunavon and delineated a 350 -million-barrel oil The Little Chicago gas plant in pool and identified Turner Valley, operated by another 250 drilling Legacy Oil + Gas. locations.” With the Bakken and Shaunavon plays commercialized, Crescent Point is now looking to expand its resource inventory further through targeting the Alberta Bakken play. The company has accumulated over one million acres of exploration land in southern Alberta targeting multiple zones, including the Bakken/ Three Forks formations. Tisdale said that to date, the company has drilled one well into the play and has plans to drill 19 wells in 2011. “It’s early days, but we plan on applying what we learned in the Bakken and Lower Shaunavon to the play,” he said. The Pekisko play is being driven by Crew Energy Inc. at Princess in southeastern Alberta and by Second Wave Petroleum Ltd. at Judy Creek in central Alberta. Crew Energy exited 2010 with 8,000 barrels of oil equivalent per day of production at Princess, and has plans to drill around 120 net wells in 2011. It has over 900 drilling locations in the Pekisko. Second Wave has around 600 drilling locations at Judy Creek, and continues optimizing its completion technology for the Pekisko play. The company began completing horizontal wells using an acid squeeze technique, but has since switched to a multistage acid fracture technique. So far, it has found the multistage acid fracs result in a two- to threefold increase in production.

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Legacy Oil + Gas brings multistage fracs to historic Turner Valley field

Almost 100 years after the Dingman Discovery Well at Turner Valley launched the oil age in Alberta, a new breed of explorer focused on technological innovation is returning to the storied field in the hopes of capturing some of the over one billion barrels of oil that remain trapped under the surface. Trent Yanko, president and chief executive officer of Legacy Oil & Gas Inc., has enjoyed some success in the tight oil world. As the leader of Mission Oil and Gas, Yanko was one of the pioneers in the use of horizontal wells and multistage fracturing in the Bakken play in southeastern Saskatchewan. He’s now leveraging that experience at Turner Valley, with the hopes of creating another homegrown success story. In March, Yanko outlined his company’s plans for the Turner Valley field at an oil and gas conference in New York. “The overall governing factor for us is huge oil in place,” he said. “At Turner Valley, there are 1.3 billion barrels in place and a 12 per cent recovery factor. What we look at is, with our technical expertise in-house, can we improve that recovery factor and can we accelerate the recovery factor in this area?” Legacy has accumulated 86 drilling locations at Turner Valley. So far, the company has drilled three vertical wells in the play, with average initial production ranging from 60-80 barrels of oil equivalent per day. Yanko said the next phase of exploration is to apply horizontal technology to the field. “There have been 21 horizontal wells drilled in the field, and none have multistage fracs,” he explained. “We think that completion technology is applicable to this field, but it has never been attempted. We are going to drill our first horizontal well this month [March] and then recomplete it with a multistage frac to see if we can increase rates.” Yanko said the company’s land base at Turner Valley also provides an uphole opportunity to target the red-hot Cardium tight oil play. “There’s no production this far south in the Cardium, but we’ve mapped a number of different pools,” he explained. “We’ve recompleted a vertical well and had a good result, so we’re going to come back in and do some additional recompletions and see if we can expand the play.” Yanko added the company is currently extending its Cardium play to the northwest of its Turner Valley play area. It plans on drilling horizontal wells in this area. “It’s very early days, but the Cardium extension looks very similar to what people are chasing to the north at Caroline and Pembina.”

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By Maurice Smith


PPDM’s mam moth effort to stream line well description lingo is starting to catch on

ne need look no further than the Bible for proof of the power of common terminology. Speaking one common language, the builders of the Tower of Babel might climb to the very heavens— take that away, and the effort falls apart in confusion and disarray. Similarly, the lack of a lingua franca to describe something as basic and fundamental to the oil industry as a well has led to no end of miscommunication, misinterpretation and inefficiency, both within the industry and within companies themselves. With the amount of data surrounding wells increasing exponentially, a need was seen to come to a broad consensus about what everybody was talking about, says Trudy Curtis, chief executive officer of the Calgary-based Professional Petroleum Data Management Association (PPDM). The first phase of the PPDM’s What is a Well? project recently wrapped up with an interactive tool designed collaboratively by oil companies and leading data vendors around the world and is now available online at “The lack of consistent definitions for key well components has created inconsistencies that can represent significant obstacles for companies and regulatory agencies who need to perform comparative analysis and manage


well data from different sources and for different uses,” says Steve Cooper, PPDM’s chief communications officer. The impetus for the project came from the companies themselves, says Curtis. “Member company after member company came to me and said, ‘We are trying to integrate our data from our production systems or our accounting systems or drilling systems and find that connecting “wells” from different systems is really hard. What should we do?’ We realized we all needed to get together and come to consensus, because everybody has got the same problem. “You would think, it being our most important business asset, that we would know [how to define a well], but we didn’t,” she says, noting common terms are necessary not just within individual companies’ various departments, but among service companies, data vendors and various government regulatory agencies as well. “It’s not until we have a need to get all these different groups and organizations talking to each other that we discover all these jagged, spiky edges that we can’t make fit,” she adds. Consider, for example, the evolution of the well over the past 40 years, she says. “At one time, every well we drilled was essentially a

Photo: Joey Podlubny

What is a well?

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illustration: PPDM

Photo: Joey Podlubny

straw poked into the ground. Now if you look at well configurations, I might have one hole in the ground, but have 30 wellbores. And each wellbore might be completed into one formation, or it might be completed into a number of formations. In each wellbore, I could have one tubing string or I could have [several] tubing strings. It has [become] a lot more complex.” As well complexity has increased, terminology has diverged. One person’s wellbore is another’s borehole. One company’s sidetrack is another’s lateral. “Not only are there a lot of different terms that people use, but we don’t all mean the same thing when we use the same terms. As you go discipline by discipline—from the person in the land office to the drilling operations crew, the production accountants tracking volumes, geologists when they describe the well, et cetera—each group focuses on a different part or component of that whole well configuration,” says Curtis. And the complexity of the terminology has been embedded in companies’ methodologies, their software applications, their databases and their routines. “We have been messing this up for years and years—we are not going to fix it overnight. But if we never start, we are never going to get there,” says Curtis. The PPPDM is endeavouring to develop common names for well parts. While there may not be a right or a wrong way to label a well component or activity, the route chosen will have consequences, Curtis says, “in terms of the data and information that you can keep, the The What is a Well? working group initially tried to narrow way that you can describe it [and] the way that you can exchange down a definition of a well and to determine who deals with and share information.” wells at various stages in the wells’ life cycles, from conception to How, for instance, should an existing well be classified when it is abandonment. It identified a set of seven terms that identify the reentered and deepened years after it was originally drilled? “Is it important components of a well—such as well origin, wellbore the same wellbore, or is it a new wellbore? For example, if we make completion and wellbore contact interval—and created a term, a a decision that that’s all one wellbore, then what do we do with the definition and a set of clarifying statements that describe each. A original total depth of that first wellbore, which was its total depth series of simplified illustrations found on the association’s interactive for perhaps 10 years?” website serve to describe the various wellbore configurations. Inconsistencies can be found in many areas, such as how In addition, narrative text outlines a typical well’s history. “You production is reported or how the numerous regulatory agencies can click through the whole story and see what’s happening to that an international oil company will encounter are dealt with. wellbore over its lifetime. It can serve as very good educational The Canadian and U.S. well-numbering systems, for instance, material for somebody who is new to the industry or be used as a are “vastly different” from each other, Curtis says. “Each of them very good communications tool so that different people can come to handles well information in a different way, sometimes in very, a consensus about what they are dealing with,” says Curtis. very different ways, and sometimes only in subtly different ways, The initial What is a Well? working group included a number of but they can have profound impact on the information that you are major operators, including Chevron Corporation, ConocoPhillips submitting to that regulatory agency. Company, Encana Corporation, Hess Corporation, Nexen Inc., Shell “Once you start getting into this, it’s amazing the kinds of Canada Limited and Talisman Energy Inc., in addition to data vendors problems that you find exist. If you have been working in an area geoLOGIC systems ltd. and IHS Inc. Regulatory agencies representing a long time, you find the really experienced people know this, but five Canadian provinces, 24 U.S. states, six Australian states and five it’s not written down anywhere. And with new people coming into European countries are represented in the interactive tool. the industry very fast, we have got to ramp them up very quickly in If anything, the economic downturn seems to have increased such a way that they will not make incorrect interpretations about interest in the PPDM model, says David Hood, PPDM chairman what they are seeing. At least with What is a Well?, they have the and president of geoLOGIC. information compiled, so they have a fighting chance of figuring it “PPDM itself is being rapidly adopted by companies both at the out, and that’s part of what What is a Well? is all about.” supermajor scale and [among] smaller companies—we are really finding

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illustration: PPDM

“Calgary is a unique market in many respects, with the concentration of technology companies together with operating companies—a very close-knit group—and also the cross-pollination between the software and data companies and operating companies,” he notes. “We also have government regulation [Energy Resources Conservation Board] that ensured data was freely and openly disseminated, and that had a big effect in creating that culture. “This whole initiative was born in Calgary, and is now going worldwide.”

The growth of horizontal drilling has added a new layer of complexity to the PPDM's efforts.

that, in the times we are in, the ability to use a common standard data model and agreed terminology really improves efficiency and cuts costs,” he says. “Part of the strength of the organization is that oil companies come together collaboratively and work to provide an open source standard right across the world.” While the What is a Well? project is just one of several PPDM initiatives, Hood says some companies have told him adopting What is a Well? alone has justified belonging to the association. He says the distinct characteristics of the Canadian oilpatch are responsible for the direction taken by the organization.

Clarifying well status and plot symbology Building on the work in What is a Well?, the PPDM has worked toward simplicity and clarity in well status and classification. “Well status and classification is about establishing baseline definitions for how we describe wells,” says Cooper. “The benefits realized from What is a Well? have brought more companies to the table so that we can continue to improve the way we manage wells in our business.” Working with a group of sponsors, the PPDM has developed a series of 15 facets for describing groups of wells. Each facet comprises a concise definition, a set of mutually exlusive values with their own definitions and a set of qualifiers where it is necessary to break down the facet values further (e.g. Facet = Fluid, Value = Oil, Facet Value Qualifier = Crude). A set of map symbols were then generated by combining the fluid type and wellbore status facets through a matrix. By taking this approach, there is logic to the map symbol set that will lead to improvement in communication and interpretation.

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King Unleashing the newest technology in older formations like Pembina, Cardium and Viking coaxes new production out of once-uneconomic wells By Graham Chandler


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PHOTO: Trican Well Service

A Trican fracture crew on the job in western Canada.


n industry armed with staged fraccing as the latest in weaponry has invaded western Canada’s low-permeability legacy fields and it’s becoming the proverbial blitzkrieg. The rush to horizontal well exploitation of tight oil reservoirs is gathering speed in 2011 even after setting new records last year. In fact, it’s pushing overall activity well ahead of the last two years. Just two months into 2011, the breakneck pace promised this year should smash the record for horizontal wells again: latest January-February stats show 1,577 new horizontals licensed—more than double the number of conventional verticals—already beating last year’s record of 981 horizontals by 61 per cent. With technology undreamed of when these formations were first exploited, revisiting them today is a bonanza. “These fields already have lots of wells in them giving the geologists plenty of correlation for how thick the rock is and how permeable it is from well to well,” says David Browne, corporate director of technology at Trican Well Service Ltd. “That takes the exploration risk out of the picture; they don’t need to explore, they know the oil- and gas-bearing zone is there, and that’s what people who lend to the oil companies really like.” Exploration now shifts horizontally between old wells instead. “There’d be areas on the margins of those wells—sometimes there are two lobes—where you’ve got two sweet spots with high permeability and a spot in between that wasn’t economic,” says Browne. “What we are doing now is drilling in between these existing wells. Some of them were good wells and some were poor.”

And that’s where modern multistage horizontal fraccing technology excels. “What the [drillers] are finding is they are amazed at what really good pockets of oil and gas are down there; that they can access by drilling this long horizontal and then doing a whole bunch of hydraulic fracturing jobs,” says Browne. It’s a unique skill in these formations. “They try and drill the horizontal perpendicular to the way the cracks in the fracture will be going,” he explains, noting that the technique is based on horizontal stresses caused by natural tectonics. “In Alberta, generally all the fracs go one way. There are local differences, but generally you try and get the frac to be perpendicular to the wellbore.” It makes the process advance as cheaply and efficiently as possible. “To do it cheaply you have to do it quickly, and that is where the technology comes in,” says Browne. “You have these systems like the Burst Port System [BPS], or the external packer system. [The latter] is great for going into the legacy fields, because you drill a horizontal well, put in that packer system which divides it up into maybe 15 zones, and you can frac them all.” It’s critical then to drill straight, he adds. With any crookedness, “you have to put in all these complex tools,” he says. “It’s not as critical for the BPS because it is part of the casing and we cement it in.” Using the packer system, he adds, it’s critical to have to all the packers able to seal. Each has its pros and cons, says Browne. “The advantage of the external packer system is you can do many fracs all at once because


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PHOTO: Trican Well Service

it’s one continuous operation—you don’t stop. You do the first zone, you drop the ball, seal off the first zone and it opens the second zone. In a 12-hour shift you can do eight or nine fracs. With ours [BPS], it takes maybe 10 minutes between zones and that adds up, so we take a little longer. But our advantage is if you ‘sand off’ [sand piling up in the valve or frac necessitating a premature shutdown to clean it out] we’ve already got the coil tubing there in the well, so we can reverse circulate, get the sand out and start over in an hour or two rather than a day.” Reduced reservoir pressure in many of these depleted formations deserves special attention applying the new technology. “Although many [fields] have been on some sort of pressure maintenance scheme, much of the area is not under any kind of pressure maintenance,” says Brad Rieb, region technical manager of the pressure pumping division at Baker Hughes Incorporated. These include Dodsland, Kindersley and Viking plays, and now even the Bakken, he says. “Often the reservoir pressure is 15-35 per cent less than discovery pressure; in some areas it’s 50 per cent. And in an oil reservoir, pressure is everything.” For these reservoirs, Rieb says there are a number of techniques they consider. “One is ensuring we have an appropriate level of fracture conductivity between the induced hydraulic fracture and the wellbore,” he explains. “That may sound obvious but the point is, when we are pumping into these reservoirs we have to be very conscious of the fluids we use.” Another consideration is the proppant. “When you had full reservoir pressure, you could use standard 20-40 proppants

and even sub-grade proppants because the deterioration in conductivity is not that pronounced when you’re at full pressure,” says Rieb. “When you’re depleted and you are trying to push oil through that proppant pack we have to make every effort to put larger proppants into place like 16-30 high-grain proppants, and often that can be challenging because they’re just bigger marbles you’re trying to put into that crack.” Rieb explains that misapplication of stimulation fluid alone can kill a well. With fully pressured reservoirs, it’s easy to rely on the reservoir pressures to overcome the water that’s been forced into that complex frac geometry. “However, when you’re depleted, you don’t have that,” says Rieb. “So by parking that high capillary pressure inside that small matrix where you don’t have reservoir pressure to push it back out, you’ve altered and damaged the permeability of the well.” To deal with that, Rieb recommends the latest in foam-based systems to his clients: 85 per cent nitrogen and 15 per cent water, “all foamed up like shaving cream. It limits the amount of fluid you’re putting in the reservoir by 75 per cent because the only fluid component is the film of the bubble,” he explains. The latest in foams are the viscoelastic fluids. “It’s like soap,” he says. “You are putting less fluid in. And the fluid you are putting in has a very low surface tension.” It’s more compressible, but that’s the beauty of the design work, he claims. “If we know the bottomhole reservoir pressure and the bottomhole treating pressure, we know how compressible nitrogen is, so we design these very predictable and robust foam fracturing systems.”

Running Trican’s burst port systemTM (BPS) on a casing string for selective stimulation of multiple zones.




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The other technique, common in the Cardium where some areas won’t readily tolerate water, is to use hydrocarbon-based fluids such as frac oil, a refined product resembling stabilized condensate. “It has a gravity of 0.8, a very low surface tension and is compatible with almost all reservoir fluids,” says Rieb. “And because you have an oil well and you are pumping oil into it, it’s not a foreign material. You pump it in and you can either flow it out with the produced crude oil or you can pump it out, treat it for its contaminants and sell it as crude oil.” He says a fluid chosen has to be compatible with both the rock and the fluids. Oil fracs have been used in the Cardium for decades,

developed in 2010. “We have nearly 2,000 in the ground now, are run almost exclusively in the Viking Kindersley area and are expanding fast into the Spearfish in Manitoba.” He says they’re now averaging eight minutes from ending one frac to initiation of the next, “like a manufacturing operation.” A new technology from Wavefront Technology Solutions becoming more widely known in the industry is Powerwave—using pulsed water to enhance recovery—and it’s now being applied in legacy fields. Brett Davidson, president and chief executive officer of Wavefront, says it’s complementary to fraccing.

“To do it cheaply you have to do it quickly, and that is where the technology comes in.” ­­­— David Browne,Trican Well Service

but have now evolved with sophisticated chemistry and high-grade refined fracturing oils. But frac oil is becoming expensive as it tracks prevailing crude oil postings: the pricier it gets, the more people are tempted to go to water-based systems, says Rieb. “Viking is almost exclusively foam, in the Bakken we are waterbased and in Manitoba mostly water-based with some foams— choice depends on a lot of things.” With both foam and oil-based fluids, Rieb says they employ his company’s successful new fraccing sleeve called OptiPort,

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“You’re getting more uniform distribution,” he explains. “With Powerwave, you up your chance of getting injectivity across the largest section of the wellbore. In the waterfloods, we are now in the Pembina and the Viking formations with great success.” Davidson says being effective in these low-permeability formations comes down to the type of tool they use to deploy Powerwave. “If you add a pulse through the injection stream you tend to build up pressure more uniformly in the near wellbore environment very quickly,” he explains. “Now if I add a successive pulse, my pressure keeps increasing and I really have no differential. In order





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PHOTO: Trican Well Service

to propagate a pulse, I need that differential between the back pressure from the reservoir and the injection pressure coming from the surface pump.” So he says you need to be able to create a pulse and then artificially create a bleed-off in the reservoir. “So I have a positive pressure pulse when I’m banging fluid into the reservoir, but then I have a negative pulse or a vacuum to artificially drop the pressure so I can hammer a next pulse to get the fluid distribution.” These are some of the special approaches needed whatever is being deployed—multistage fraccing or Powerwave—to give best benefit, says Davidson. Some operators combine technologies. “We have one client with a field in the Viking, an old established waterflood, who is drilling with multistage fraccing, but they are also using Powerwave in the older sections to boost recovery,” he says. “You’ve got a young company that’s looking at a lot of different tools thinking, ‘How can I attack this legacy pool from different sorts of directions?’” The legacy field technologies keep evolving. For example, “we are looking at co-injecting proppant,” says Davidson, “especially in these tighter formations. What we’d like to do is work with an operator to see how pulsing can be used in conjunction with what I would call ‘micro-fraccing’ during well development.” Leaving a pulsing tool in place for a period of time, he explains, can create many microfractures and open up dendritic river patterns of fractures, allowing more liquids in. “And we’d be putting in proppant in the same action.” With these kinds of technological ambition, 2012 may crack yet another record for horizontals.

Trican’s BPS on a casing string.

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More than 500 million barrels were wasted or left in the ground because of the production practices employed in this historic field. “Laying to rest an important industry icon,” is how Cuthill summarized his company’s work on Dingman No. 2. Downhole, they found old fishing tools, big chunks of wooden beams and cracked casing. The Energy Resources Conservation Board, the locals, the Turner Valley Oilfield Society and many other groups were kept informed of the process, which ended up taking much longer than

Photo Courtesy of Glenbow Archive NA-246-1

ost wells don’t produce for 90 years. But oil wells in the Turner Valley oilfield have a reputation. That’s why it took three attempts—in 1949, again in 1981 and then again in 2009—to abandon Dingman No. 2. Archie Dingman spudded his second well in the Turner Valley field on June 10, 1914, less than a month after his historic first well came on production on May 14, 1914. Back in the day, it took years to drill a well. And by 1939, 181 of the 305 drilled in Turner Valley had become producers. That’s a good ratio, even if most of the wells were gassers. The average well in Turner Valley took 8 to 10 months to drill with cable tools, but Dingman No. 2 took longer than most, and workers pounded away with cable tools into the earth until New Year’s Day of 1917. The sweet, wet gas from the well went through the first simple absorption plant that took off naphtha—gasoline—so pure that people just poured it right into the gas tanks in their cars. Turner Valley skunk gas was wild stuff; some of it escaped the tank as a vapour, the rest smelled like rotten eggs as it burned. Visitors to Turner Valley often went to the bridge over the Sheep River to see the leaking gas that burned there for decades. That flare is gone now, extinguished as part of the abandonment of the second Dingman well. That work fell to Kary Cuthill and Lionhead Engineering. He knows the legacy of western Canada’s first commercial oilfield, and that barely restrained flaring of gas in order to produce the liquids ended up compromising its sustainability.

photo: Lionhead Engineering

By David Finch

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photo: Lionhead Engineering

GE Oil & Gas Drilling & Production

To begin the abandonment process, Lionhead had to expose the original Dingman No. 2 wellhead.

Photo Courtesy of Glenbow Archive NA-246-1

expected. The final cost was millions more than the provincial government’s original estimate. Complaints about the smell from the burning gas at the bridge were part of the reason for reworking the well. Though Dingman No. 2 produced relatively sweet gas from the 3,170 level (feet, not metres), sour gas was escaping from the riverbank, probably using the old well as a way to get to the surface from a much deeper formation. Ongoing tests suggest the well is finally capped. But locals still notice the faint smell of sour gas in the area. So did rancher William Herron in the early 1900s when he came up Sheep Creek to get coal. In fact, gas still bubbles to the surface near the 1914 discovery well. A fence protects it from the people—and vice versa. But after a rainstorm, when a puddle of water forms on the ground, natural gas bubbles up just like it did 100 years ago. The centennial of the discovery of oil at Turner Valley is just three years away, on May 14, 2014. If it hadn’t been for the Dingman discovery wells, Alberta’s history might never have taken such a fortuitous turn. Mark that Wednesday on your calendar and hope for good weather. Several thousand people showed up at the discovery well in 1914, so plan to join the crowd that celebrates 100 years of prosperity in Alberta.

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Heading in the

right direction New directional technology helps with the precise placement of well pairs


hen it comes to technology and innovation, Oslo-based Statoil ASA has a reputation to defend amongst international oil majors. Whether it is environmental protection, finding more oil and gas or fine-tuning refining and processing plants, Statoil’s footprints are indeed deep and wide. In Alberta, too, where it has interests in four acreages in the Athabasca region with plans to produce at least 200,000 barrels per day of bitumen post-2020, Statoil Canada Ltd. is sparing no efforts to apply cutting-edge technology. “Technology is in our DNA and fits well with our core competence globally in harsh environments,” says Peter Symons, communications director of Statoil Canada. “While new to the oilsands, we have established a global heavy oil technology centre [HOTC] in Calgary to further increase our understanding of the oilsands and share that within our global heavy oil group. Our philosophy is to learn, share and contribute to the development of technology.” Besides the HOTC, another significant case in point is the latest steam assisted gravity drainage (SAGD) directional drilling method—developed jointly by Houston-based Halliburton and Statoil. The new rotary steerable technology is being put to use at the Leismer demonstration plant (LDP), which currently consists of 23 well pairs on four drilling pads. “From the beginning, the environment at Statoil was very collaborative,” says John Person, senior technical leader (heavy oil) at Halliburton’s Calgary office. “It felt like a team or partnership between the two companies throughout the entire project. There was always a systematic, step-bystep progressive approach to applying the various technologies in this new application. Several industry firsts were successfully used, including a combination of the newest and most cutting-edge directional, measurement, LWD [logging while drilling] and rotary steerable technologies.” Put simply, the new technology is an application to optimize well positioning for unconsolidated geological formations, using advanced azimuthal resistivity and point-the-bit rotary steerable technology. Person defined azimuthal as an imaging technology that renders an in-depth measurement away from the borehole, with 360-degree coverage. The new directional technology has three main components—ultradeep resistivity borehole imaging, rotary steerable system and wireless electromagnetic control. Person says, “The precise placement of well pairs is one of the most crucial factors in the successful execution of a

SAGD program. A SAGD drilling operation includes placing the producer well relative to the reservoir boundaries, as well as accurately twinning the injector well to the producer well.” illustration: halliburton

Recoveries Undoubtedly, increasing hydrocarbon recoveries and reducing drilling costs are prime reasons for oil companies investing big bucks in new technology, and Statoil is no exception. “It is probably still early days to give any statistics on the rate of increase in recoveries,” Person says, advocating a wait-and-watch policy. “As for the additional costs, they are relatively minor compared with the benefits that accrue by capturing the new reserves that may have otherwise been left behind by less-than-ideal placement. A desirable outcome of increasing drilling efficiency is decreasing the time it takes to drill the well,” he says. According to Symons, the new technology increases the bit-on-bottom time, as directional resets are not required. “The overall impact is in a reduction in time to drill the lateral section. The resulting wellbore has minimal tortuosity that directly reduced the pull-down forces required to install the production liners. Subsequent installation of completion equipment inside the liner proceeded with minimal drag issues,” he says. The LDP will probably serve as a benchmark for the successful application of the rotary steerable technology, as Statoil says it was able to achieve a level of optimization in horizontal bores that exceeded the prevailing industry standard for SAGD operations. Following its first application in late 2008 at the LDP, Halliburton has not looked back. “Momentum has gained in the use of the rotary steerable technology and azimuthal borehole imaging is already being applied by other thermal oilsands operators in Alberta,” Person says. — Ashok Dutta Reprinted with the permission of JuneWarren-Nickle’s Energy Group.


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VAC-Screen technology helps drillers recapture oil-based mud


t’s not always rocket science. Sometimes, the simplest ideas take flight and evolve into innovations that break the mould. Such is the case with Calgary-based service company FP Marangoni Inc., a small entity that may be on to big things with its VAC-Screen drilling fluid recovery system, which is a new take on solving an old problem. Not to mention a technology that the company claims is paying dividends for producers looking to cut costs while improving the efficiency and environmental performance of their operations. “The system is elegant yet simple, and we have eight patents filed and got 45 of 45 claims on our first review all listed as novel,” says Dan Pomerleau, FP Marangoni president. “I was down in Houston a few weeks ago talking to a major solids control equipment manufacturer, and one of their PhD engineers said to me, ‘Do you know how long people have been trying to make a vacuum work on a shaker?’ I said, ‘No idea.’ He said, ‘A very long time.’” According to Pomerleau, FP Marangoni is presently the only oilfield service company in the world that has successfully established a way to blend vacuum and rig shakers to recapture oil-based mud, or any drilling fluid for that matter. Focused on ensuring the needs of operators are met with regard to reduced costs and lower overall environmental impact, the VAC-Screen system is presently being utilized by several operators and has the potential to be used across a wide spectrum of drilling applications. “With emerging concerns for organizations to reduce costs and decrease their overall environmental impact, there is an industry-wide need for a system that can provide a solution,” notes Pomerleau. “The VAC-Screen technology that we’ve developed gives operators a sizable advantage in meeting progressively more stringent environmental regulations for cuttings disposal.” Pomerleau says the genesis for what would eventually become VACScreen began while the company was working in the Alberta Foothills. The client was losing drilling fluids off of the ends of shakers, and the surface losses were mounting. The operator decided to use a rotary vacuum fluid recovery and cuttings drying system, which recovered mud. However, the mud recovered increased plastic viscosity, indicating fine solids were being introduced into the mud system, and the introduction of fines causes significant issues when it comes to maintaining a drilling fluid.

Given the scenario that was unfolding, FP Marangoni initially PHOTO: FP Marangoni opted for blowing mud through the shaker screen using compressed air and air knife drying systems. So the team rigged up some air and blew the mud off the cuttings and through the shaker screen. Pomerleau said this process initially worked pretty well—at least until the group started to go to shaker screens that had more than 84 wires per square inch, called 84-mesh. “As soon as we got there, the high-velocity air created a fine mud mist which created a health hazard—it was all wrong,” he says. “I said, ‘You know, there’s got to be a better way.’” So FP Marangoni set about to find one: “We opted to build a vacuum manifold, parked it underneath the shaker screen and attached it to the rig vacuum. This method dried the cuttings as hoped, but they froze right on the shaker screen. So, wherever the cuttings were, their movement stopped right there.” In other words, it was a less-than-ideal outcome. However, after some fine-tuning, these issues were sorted out and the company was eventually able to run what was to become known as the VAC-Screen technology on whatever size of shaker screen a client wanted. Pomerleau notes the VAC-Screen technology reduces costs and environmental impact and “benefits operators in a number of ways,” including reduced fluid losses at surface, reduced chemical additions for maintenance, increased shaker separation performance, reduction in shaker screen consumption, reduction in centrifuge operation, elimination or severe reduction in shaker screen washing, and a significant reduction in mix-off and trucking requirements. Still, the main benefit is that the recovered fluid has no detrimental effects on the drilling fluid system, and the system is compatible with a number of industry-leading shakers readily available in the marketplace. — Paul Wells Reprinted with the permission of JuneWarren-Nickle’s Energy Group.


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drilling fluid recovery through surface control equipment in modern onshore drilling practices By Jarrett Dragani, Encana Corporation


rilling fluids are an integral component to any drilling operation. Likewise, the ability to control drilling fluid losses also carries a large importance, both mechanically and financially. The ability to control fluid losses through surface control equipment is one area that drilling operators can look to improve. Surface fluid losses can occur through a number of means, but the primary focus of this analysis is to evaluate the losses and possible recovery mechanisms experienced through the shaker and centrifuge systems. Understanding the volumes of drilling fluid lost through the surface equipment is an important statistic for several reasons. Firstly, it allows the operator to address its financial losses experienced through the loss of drilling fluid through surface processing equipment. Secondly, it allows the operator to evaluate the economic benefit of investing in new closed-loop drilling technologies directed at recovering drilling

Figure 1: Invert Life Cycle Illustration

fluids from surface equipment losses. Thirdly, it allows the operator to evaluate and potentially minimize the social cost of drilling fluids disposal, as it plays a detrimental effect on our surrounding ecosystem. Most operators within the Western Canadian Sedimentary Basin utilize an invert-based drilling fluid, which in recent times has ranged from 90 cents per litre to $1.20 per litre in raw costs. Factoring in chemical additives to the fluid, the per litre cost of the fluid can be increased by more than twofold. Traditional methods of drilling disposal have included mixing and burial through on-site sumps and more recently, mixing and transporting fluids to off-site facilities where largescale processing is facilitated. The schematic presented in Figure 1 shows the effective life cycle of an invert-based system during the drilling process. Figure 1 breaks the life cycle into three main categories: usage, storage and disposal. By evaluating the life cycle diagram in terms of inputs and outputs, a material-balance equation can be generated.

Pump downhole Mud tanks


Losses downhole to formation

Circulate back to surface


Shakers to remove cuttings Tank farm (on-site)

New fluid trucked to tank farm to replace used quantity

Mixed off with wood pellets at wellsite

Losses in oil retaining in cuttings Remains stored in tank farm

Trucked to disposal site for temporary storage

Tank farm hauled to another site for continual use


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The material-balance equation for the invert life cycle diagram is written simply as: Vol. at Rig Out = Vol. at Spud + New Fluid In – Surface Losses – Downhole Losses ... ... ... ... (1)

Generally, the invert volumes are tracked throughout the life of the well such that the only unknown variables from equation (1) are the invert losses experienced on surface and losses downhole. This methodology in this study focuses on the invert losses experienced through surface equipment, including the shale shakers and centrifuges. Here, it is assumed that no other invert losses on surface are considerable in quantity. Examples include small spills, washing and more. Once invert losses on surface are quantified, the material-balance equation can be completed to determine losses experienced downhole. The method of determining invert losses on surface was demonstrated through an applied analytical and experimental technique. Retort experiments were completed roughly every 100 metres of hole on six wells within the Canadian Deep Basin, for portions of the well being drilled with invert fluid. The retort samples were taken from the wet cuttings exiting the shale shakers as overflow. The retort provides information on the percentage of oil, water and dry material in both volumetric and mass terms. The experimental data can then be linked with analytical formulations to generate a realistic determination on the volume of invert fluid being lost through the shale shaker overflow. The same methodology can be applied to the centrifuge system; however, in the wells sampled in this study, the centrifuge was not processing enough volume of material to be considered in the analysis.

The retort study delivered a number of important parameters. It was statistically determined that the volumetric ratio of invert to dry rock material, R invert – rock , does not vary significantly with depth and drill bit size, and is equal to 0.85. This is also assuming that the ratio of base oil to water within the base invert is 90:10. Applying this value in equation (2) and (3) can provide the operator with an understanding of the surface invert losses on a rate basis. It can also allow the operator to evaluate the economics for invert recovery with the installation of closed-loop drilling systems. Applying this value in equation (4) can provide the evaluator with an estimate of what the expected invert losses through surface equipment will be for the entire life of the well. Returning to equation (1), the operator can also quantify the invert losses experienced downhole. It should be noted here that the rock expansion factor, Erock , is assumed to be 1.0 as there is no literature documenting the volumetric expansion for different rock facies across the Western Canadian Sedimentary Basin. The results of the six wells studied in the Canadian Deep Basin are seen in Table 1. Note that all wells considered here were drilled with a 222-millimetre diameter intermediate hole and a 156-millimetre diameter production hole. Table 1: Invert Losses for Six Wells in the Canadian Deep Basin


Percentage of Invert Losses

Downhole losses


Surface losses during intermediate hole


Surface losses during production hole




The equations applied for determining lost volumes are as follows: Q rock


Q invert

πD 2

(ROP) (1 – φ ) (Erock ) ... ... ... (2)


= R invert – rock (Q rock ) ... ... ... (3) n

Vinvert loss

=∑ =

i 1


πD 2 4


(mMD) i (1 – φ ) (R invert−rock ) ... ... ... (4)

= Volume of rock flowing over the shale shakers = Bit diameter ROP = Rate of penetration φ = Average downhole rock porosity Erock = Average rock expansion factor (assumed 1.0) R invert-rock = Volumetric ratio of invert to dry rock material (constant) mMD = Total measured depth of hole drilled n = Number of hole sections drilled with a different diameter drill bit Q rock D


It can be seen here that 36.5 per cent of the invert losses that were experienced occurred on surface, mostly within the shale shaker overflow. As an example, if an operator was to experience 120 cubic metres of invert losses, 43.8 cubic metres would be incurred on surface. On a life cycle basis, if the cost of the lost invert on surface was $2,000 per cubic metre, then the total economic opportunity for invert recovery here would be $87,000 on this well alone. Although it is evident that closed-loop drilling is not capable of achieving 100 per cent invert recovery efficiencies, the economic opportunity still remains quite viable and highly lucrative for a lowcost drilling environment.

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PRECISION DRILLING STRETCH SUPER SINGLE What application does this rig work best in?

Medium-depth vertical wells with long horizontal sections, directional wells, pad wells and well programs where casing drilling may be required. What does this rig do best?

Drill conventional and directional wells efficiently. Move on pad and from well to well efficiently, rig up and rig down efficiently, and provide the customer with versatility of application to suit various drilling programs. Drill with API range III drill pipe. The rig manages tubulars with nearly 100 per cent hands-off operation. Tubular handling is completed using remote control. The rig uses electronic controls systems for most drilling functions, including safety stops and interlocks. Why would a drilling engineer hire this rig?

The rig can work to any well depth that is limited in one way or another by the rig’s technical capabilities. The hoisting equipment is rated for 178,000 daN. The rig is rated at 4,300 m with 102 mm pipe, but is typically drilling 6,000 m measured depth wells. It has a large rotary bore, large mud volume, large mud pumps, a large-capacity well control capability, and no setback or tubular racking limitations. Whatever the maximum anticipated hookload is will limit the measured depth capacity.


What depth range can this rig work at?

PHOTO: Precision Drilling

This rig type provides the engineer with high available power capacity, a large-capacity mud circulating system, high-capacity mud pumps, drilling efficiencies gained from AC power and control systems, an efficient tubular handling system, an integrated top drive, is casing drilling tool capable, has large BOP stack capabilities, moving and rigging efficiencies and pad drilling capabilities in a package that is substantially smaller than rigs generally used to complete the same task.

RIG SPECIFICATIONS Rig power 3,200 kW AC electric variable frequency drive Depth rating 4,300 m with 102 mm API Range 3 drill pipe. Presently drilling 6,000 m measured depth directional wells (3,000 m horizontal legs). Mast size 178,000 daN, eight lines, 27.4 m clear height, casing drilling capable, telescoping single Substructure /moving system Integrated tubular handling system, integrated well control management system, integrated walking system


M ud pumps Dual AC-powered 1,600 hp triplex mud pumps, 35,000 kPa circulating system S hale shakers Three balanced elliptical motion shale shakers M ud tanks 110 m3 active volume, three (3) tank system BOP 346 mm, 35,000 kPa, three (3) ram and annular BOP stack

Number of loads 45 loads with pad equipment; 40 loads for single wells, including boilers and tubulars

ds for ulars

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Nabors 104ACTD “fitfor-purpose” pad rig What application does this rig work best in?

It is best suited for multi-well pad drilling. The more wells on pad, the more cost-effective the rig becomes. Nabors has had this style of rig working in the Horn River drilling shale, in Fort McMurray drilling heavy oil and in Saskatchewan drilling for potash companies. The rig walks around the pad on a tight footprint with no umbilical quickly, safely and efficiently, reducing overall costs to the operator What does this rig do best?

Without a doubt, batch drilling is the way to go with this rig style. The batch drilling approach has been designed so the operator can cut costs and minimize waste (environmental impact). This is achieved through drilling all surface holes on pad with an approximate move time of 40 minutes within 10-15 m of well spacing. Drilling mud, pipe and bottomhole assemblies all remain on the rig, creating increased efficiencies as there is no down time waiting on cement. This process is then repeated for all intermediate holes on pad. Why would a drilling engineer hire this rig?


Nabors has designed the “fit-for-purpose” rig specifically for pad drilling and has created a safe and efficient work environment reducing overall costs, drilling time and incidents on rig. Drilling engineers are always looking for the latest technology, compact yet powerful equipment, increased pumps/horsepower, top drives and increased safety initiatives, which are all features of rig 104ACTD What range can Nabors 104AC drill?

0-5, 200 m TVD

RIG SPECIFICATIONS Rig power Three each—3512B Caterpillar 1100 kW/set Depth rating 5,200 m with 5" drill pipe Mast size Alta North Boot Strap Triple Height— 43.3 m Maximum allowable load—222,400 daN Substructure /moving system Alta North one piece sits on a Columbia Moving System— walks 1 m every 2 1/2 minutes

M ud pumps Two each—PZ10 (1,300 hp/pump) Powered by WEG electric motor S hale shakers Four each—Brandt King Cobras 1,800 cycles/min M ud tanks Covered mud tanks move with the rig Two tanks with 196.8 m3 total volume Five mixing pumps MCM 250 series BOP 11" x 5,000 psi stack Custom six-station accumulator (680 litres) Number of loads 55


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AKITA RIG #6 (Schramm TDX) What application does this rig work best in?

This rig is ideally suited for both shallow heavy oil and gas drilling up to 1,400 m. It can manoeuvre on tight lease roads due to the telescoping nature of the mast. It is also adaptable to casing drilling if the situation requires. What does this rig do best?

This rig combines excellent crew ergonomics as well as proven performance metrics. Why would a drilling engineer hire this rig?

This rig is adaptable to a variety of situations. It provides modern drilling and ergonomics features including top drive, make/break equipment, casing drilling capability, pull-down capability and pipe handling capabilities. It combines these features along with mobile loads to give a drilling engineer a variety of options. What depth range can this rig work at?

PHOTO: akita drilling

Up to 1,400 m.

RIG SPECIFICATIONS Rig power Detroit Diesel DDC/MTU 12V2000 TA DDEC rated at 567 kW, c/w an integrated multi-pump hydrostatic power system Depth rating 1,200 m utilizing Range 3 drill pipe Mast size Mast hoisting capacity is 57,850 daN. Pull-down capacity of 14,240 daN. Substructure /moving system Drill module consists of 12-wheel tri-axle trailer w/floor motor, hydraulic pumps, cooling system, mast, top drive and hydraulic levelling cylinders. Clear height on sub is 3.05 m.


M ud pumps Gardner Denver PZ-8 rated at 800 hp powered by a Caterpillar 3412E S hale shakers Brandt Cobra three-panel M ud tanks Single tank, four-compartment, 44 m3 capacity BOP 229 mm, 21,000 kPa Shaffer spherical and two single-gate rams Number of loads 12 winter loads

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A dV e rti s e r s ’ I n d e x AKITA Drilling Ltd. ��������������������������������������������������������������������������������������38

NOV Downhole���������������������������������������������������������������������������������������������� 45

Allen R. Nelson Engineering (1997) Inc. ������������������������������������������������36

NuEra Oilfield Services��������������������������������������������������������������������������������� 14

Apex Oilfield Services (2000) Inc. ���������������������������������������������������������� 12

Orange Directional Technologies�������������������������������������������������������������� 38

Baker Hughes Canada Company����������������������������� Outside back cover

Packers Plus Energy Services Inc. �������������������������������������������������������������� 14

Barlon Engineering Group Ltd. ���������������������������������������������������������������� 10

Pajak Engineering Ltd.�������������������������������������������������������������������������������������31

BOS Solutions Ltd. ��������������������������������������������������������������������������������������30

Pinnacle Oil Tools Inc. ���������������������������������������������������������������������������������� 45

Codeco Energy Group�������������������������������������������������������������������������������� 41

Precision Drilling������������������������������������������������������������������������������������������������8

Cummins Western Canada������������������������������������������������������������������������36

Ryan Energy Technologies���������������������������������������������������������������������������� 24

D&R Directional Services Inc. ������������������������������������������������������������������46

Savanna Energy Services Corp. ������������������������������������������������������������������ 25

Encana Corporation��������������������������������������������������������Inside front cover

Smith Bits���������������������������������������������������������������������������������������������������������� 34


Strad Energy Services���������������������������������������������������������������������������������������4

Ensign Energy Services Inc. �����������������������������������������������������������������������20

Trinidad Drilling Ltd. ������������������������������������������������������������������������������������� 45

GE Oil & Gas��������������������������������������������������������������������������������������������������33

Tristar Resource Management Ltd. ����������������������������������������������������������� 34

HAZCO Environmental Services�������������������������������������������������������������29

Volant Products 2008 Inc. �����������������������������������������������Inside back cover

HSBC Bank Canada�������������������������������������������������������������������������������������� 21

Weatherford Canada Partnership�������������������������������������������������������������� 41

Katch Kan Limited������������������������������������������������������������������������������������������ 6

Xi Technologies Inc. �������������������������������������������������������������������������������������� 41

ModuSpec Risk Management Services Canada Ltd. ��������������������������� 14

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Every day, in oil and gas fields in Canada and around the world, our experts work with clients like you to evaluate their needs and then engineer wellbore construction systems and production solutions to match each application. The result: improved operating efficiency, lower risk, and maximum hydrocarbon recovery. Whether you are exploiting existing reserves or exploring new fields, you can count on Baker Hughes for innovative technologies and solutions that meet your needs in every phase of hydrocarbon recovery and processing. Š 2011 Baker Hughes Incorporated. All Rights Reserved. 31663

Contact your local Baker Hughes representative or visit us online and find out how we can help you cut costs while advancing the performance of your reservoir.

2011 CADE * CAODC Drilling Conference Guide  

On behalf of the CADE • CAODC Drilling Conference Executive Committee, it is my pleasure to welcome you to the 15th CADE • CAODC Drilling an...

2011 CADE * CAODC Drilling Conference Guide  

On behalf of the CADE • CAODC Drilling Conference Executive Committee, it is my pleasure to welcome you to the 15th CADE • CAODC Drilling an...