canadian oilpatch technology guidebook tech...

canadian oilpatch technology guidebook

drillingproductionfracturingdata/software/ communicationshealth, safety & environmenttight oil & gas

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2011tech

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Table of conTenTstech guide

2

table of contentsNote From the editorTriple Play 4List of Advertisers 6

drilliNg 11

High-Tech Hammer 12BBJ Tools transforms the traditional fluid hammer into a revolutionary drilling tool

A New Twist On Torque 13New electronic sensor measures the level of torque on the drill string

Simple Solution 14VAC-Screen technology helps drillers recapture oil-based mud

Bit Of A Gamble 17Junior drill bit manufacturer dodges recession, takes on the majors

ProductioN 19

Looking To Repeat History 20Conventional heavy oil producers on the lookout for another game changer

Tweaking The Pumpjack 24For western Canada’s oil producers, retooling a Prairie icon could mean power savings and a greener profile

Seeing The Light 25Using fibre optic technology to improve recoveries

Losing The Water Without Losing The Gas 28Technology startup deploys artificial lift system on coiled tubing

FracturiNg techNology 33

Out Of Harm’s Way 34Frac Shack removes human element from risky refuelling mix

Bigger, Faster, Cheaper 35As the industry trends to more frac stages, Packers Plus responds with QuickFRAC

Green Fracking 38As the frac debate rolls on, service firms develop cleaner fracking products

No Limits 40Mongoose advancement offers unlimited pinpoint fracs

Under One Roof 42Canadian fracturing database service goes online

Beyond Dots In A Box 43The big players in the development of microseismic monitoring are now focusing on interpreting the data

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Table of conTenTstech guide

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data/SoFtware/ commuNicatioNS 45

Defence To Offence 46Forum’s software helps Canadian Forest stay on top of its game

Cost Estimating Made Easier 47Software successful in accurately predicting facility costs

Keeping Pace 48IHS works to seamlessly integrate data for better exploration and production

Drying Up The Benzene 50Calgary-based company’s software and service save energy, time and money

health, SaFety & eNviroNmeNt 53

Safe & Sound 54Detection tools for pipelines continue to evolve

Tailings Triumph 58Suncor’s TRO technology slashes the time to reclaim oilsands tailings by two-thirds

Right As Rain 59Calgary-based company finds niche cleaning shale gas operations’ water

Closer To Zero 60Noel project an environmental feather in the cap for BP Canada

59

tight oil & gaS 63

Best Choice 64Amid plenty of debate, unconventional resource players search for best approach to horizontal, multifrac wells

Analyze That 66Producers get methodical about the optimum number of fracs for tight oil

Decline Curve Challenge 68From nanotechnology and geochemical processes to propane fracs—all technologies are on the table in industry’s quest for sustained and profitable shale gas production

directory 70

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next several years. “In fact, the natural decline in produc-tion that has been exhibited for over 10 years is expected to be reversed in the near term,” CAPP states.

Even though oilfields in the Western Canadian Sedimentary Basin are relatively mature, CAPP says, “future technology improvements could increase the rate of recovery for the oil-in-place, which is currently only around 26 per cent. In fact, the use of horizontal wells and multi-stage fracturing techniques in conven-tional wells has yielded better than expected results in recent years, suggesting that we may have previously underestimated the impact. In 2010, the decline in con-ventional crude oil production was effectively halted for the first time in over 10 years, which can be attributed to the increased use of this technology that was encouraged by a higher price environment and favourable royalty changes in the province of Alberta.”

By 2025, total Canadian production is now forecast to climb to 4.74 million barrels per day, up from 2.83 million barrels a day last year and a significant increase of 401,000 barrels per day higher than CAPP’s 2010 forecast. Nearly one-half of that will come from conven-tional growth in the early part of the forecast period.

The trend is reflected in other statistics as well. Close to half of drilling permits in Canada in the first half of 2011 were for horizontal wells, establishing a new record. And producers added 490.87 million barrels of proved, conventional oil and liquids reserves through discoveries and extensions last year—the biggest gain since 2006—as companies targeted tight and conventional oil drilling.

Which is not to say shale gas and oilsands output isn’t keeping pace. Despite fewer wells drilled, Canadian natural gas producers were able to more than replace production with new reserves last year due to success with tight gas and shale gas resource plays, with proved reserves added from drilling activities in 2010 the high-est recorded since 2005. This while the oilsands sector ramps up to levels of activity not seen since the financial collapse of 2008. All thanks to the application of innova-tive new technologies that have transformed what was believed by many to be a sunset industry to one of the country’s primary economic drivers.

In this issue of the annual Canadian Oilpatch Technology Guidebook, we take a closer look at this unfolding new wave of technology application as it applies to tight oil, as well as the latest developments in categories ranging from drilling and production to fracturing, software, communications, and health, safety and environment. Complementing that coverage is our comprehensive list of Canadian technology providers. As well, an online version of the Tech Guide is available on the New Technology Magazine website (newtechmagazine.com).

Maurice Smith, [email protected]

noTe from The ediTortech guide

4

FirSt, it waS the successful applica-tion of new extraction techniques to Alberta’s massive oilsands resource, which from its first commercial suc-cesses over 40 years ago (first with mining, later via in situ methods), has created an entirely new, uncon-ventional oil sector in Alberta. Then, it was the application of horizontal drilling and multistage fracturing to previously unrecoverable shale gas plays that transformed the natural gas sector, from its inception in the United States to fields in Canada and now around the world. And finally, as the last couple of years have shown, the adaptation of those technologies for tight oil resources is now leading to a similar transformation across North America where oilfields consid-ered depleted or never commercially viable have become—assisted by buoyant oil prices—the latest roaring success story.

The common denominator in all three cases has been the rise of new technologies. The impact has been the continuing revival of the oil and gas industry across the continent, a revitalization that has not only lured back the supermajors that had all but given up on the industry’s future here, but enticed new investors from energy-hungry developing nations as interested in our advanced technolo-gies as our resources.

The most recent impact of techno-logical change in conventional oil is only now sinking in. The Canadian Association of Petroleum Producers (CAPP), in its 2011 crude oil forecast in June, saw fit to revise its conven-tional oil outlook upward due to the growing impact of new extraction technologies. As opposed to the steady annual decline predicted in previous outlooks, CAPP now fore-sees slight annual increases for the

Triple PlayCanadian Oilpatch Technology Guidebookwww.newtechmagazine.com

editorial and productionpublisher | stephen marsters [email protected] | maurice smith [email protected] director | andrew brien [email protected] services | martha boctor, lyuba Kirkovaad traffic coordinator | denise mackay writers | Godfrey budd, mike byfield, lynda harrison, richard macedo, James mahony, elsie ross, r.P. stastny, Paul Wellseditorial assistance | Kate austin, Tracey comeau, brandi haugen, samantha Kapler, marisa Kurlovichdirectory data | Vienna blimkiesales sales manager – magazines | maurya sokolon [email protected] account executive | Tony Poblete [email protected] | Jerry chrunik, nick drinkwater, nicole Kiefuik, diana signorilesales administrator | craig cosenscirculationcirculation manager | donna rideout [email protected]

PUblicaTions mail aGreemenT no. 40069240 reTUrn UndeliVerable canadian addresses To oUr circUlaTion deParTmenT 816 - 55 ave ne, 2nd flr, calgary, ab T2e 6Y4

You may also send information on address changes by email to [email protected]. Please quote the code that begins with the prefix ntm. for members of the society of Petroleum engineers, please contact the sPe office directly with your address change.subscription informationdan cole, (403) 209-3533Toll free 1-800-387-2446issn 1480-2147canadian oilpatch Technology Guidebook is a product extension of new Technology magazine. new Technology magazine is published 10 times a year by JuneWarren-nickle’s energy Group, a subsidiary of Glacier media inc., a leading canadian information com-pany with interests in daily and community newspapers and business-to-business information services.

JuneWarren-Nickle's Energy Group2nd floor, 816 - 55 avenue necalgary, alberta, canada T2e 6Y4T: (403) 209-3500f: (403) 245-8666Toll free: 1-800-387-2446president & ceo | bill Whitelawgroup publisher | agnes Zalewskisales director | rob Pentneygroup art director | Ken bessiesenior publications manager | audrey sprinklepublications manager | rianne stewartcreative services mgr | Tamara Polloway-Webb

145

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lisT of adVerTiserstech guide

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List of Advertisers

Advantage Products Inc. .......................................22, 23 Advantage Products Inc. (API) (www.advantageproductsinc.com)

provides innovative solutions to common problems in the oil and natural gas industry. API is the leading provider of downhole tools, electric motors, torque anchors, progressive cavity pumps and custom design products.

Arrival Oil Tools ........................................................ 8, 9 Arrival Oil Tools (www.arrivaloiltools.com) specializes in the engi-

neering and manufacturing of downhole drilling tools for the oil and gas industry. Arrival takes a great amount of pride in being an inventive, dynamic and highly energetic company focused on the following three principles: innovation, responsiveness and delivery.

Baker Hughes Canada Company .......Inside Back Cover Baker Hughes Canada Company (www.bakerhughes.com) delivers

solutions that help oil and gas operators make the most of their reservoirs. Baker Hughes provides reservoir consulting, drilling, formation evaluation, completion, pressure pumping, and produc-tion products and services to the worldwide oil and gas industry.

Brother’s Specialized Coating Systems Ltd. ............. 29 Brother’s Specialized Coating Systems Ltd. (www.brotherscoat-

ing.com) develops and uses specialized coating techniques for the benefit of industry across western Canada. Brother’s is able to evaluate, identify and determine the most cost-effective means of protecting equipment from the effects of corrosive and erosive environments.

Calfrac Well Services Ltd. ...............Outside Back Cover Calfrac Well Services Ltd. (www.calfrac.com) has become a lead-

ing independent provider of specialty designed fracturing, coiled tubing, cementing and well servicing solutions that are designed to increase the production of hydrocarbons from wells drilled throughout western Canada, the United States, Russia, Mexico and Argentina.

Ensign Energy Services Inc. ........................................15 Ensign Energy Services Inc. (www.ensignenergy.com), Canada’s

second largest land-based drilling contractor and third largest well servicing contractor, provides land-based contract drilling, underbalanced drilling services, well servicing and manufactur-ing, wireline and production testing to the crude oil and natural gas industry.

E-T Energy Ltd. ..............................................................7 E-T Energy Ltd. (www.e-tenergy.com) is engaged in the business

of developing, operating, producing and selling recoverable bitumen found in the Athabasca oilsands deposits using its proprietary ET-DSP in situ method of production. The ET-DSP method process involves passing electrical current from surface power distribution equipment.

Expro Group Canada Inc. ......................................30, 31 Expro Group Canada Inc. (www.exprogroup.com) leads the way

in well flow management. Expro, which operates in all the major hydrocarbon producing areas of the world, provides the services, products and expertise its customers need to measure, improve, control and process flow from their oil and gas wells.

Flexpipe Systems ..........................................................1 Flexpipe Systems (www.flexpipesystems.com), a division of

ShawCor Ltd., manufactures and sells a spoolable composite pipeline system used for oil and gas gathering systems, water disposal, CO2 injection pipelines and other applications where a corrosion-resistant, high-pressure pipeline is required.

geoLOGIC systems ltd. .....................Inside Front Cover geoLOGIC systems ltd. (www.geologic.com) was founded in 1983

as an independent software company with a goal of providing improved software and data to the oil and gas industry and deliv-ering a more comprehensive, relevant data solution. geoLOGIC saw the need for a more comprehensive, relevant data solution and answered that need.

JuneWarren-Nickle's Energy Group ........18, 44, 52, 57, 61 JuneWarren-Nickle’s Energy Group (www.junewarren-nickles.com)

is Canada’s oldest and most-recognized energy publishing house, with products such as new Technology magazine and the Tech Guide. Providing authoritative print and online publications, data sets, maps, charts and directories, JuneWarren-Nickle’s Energy Group is the Canadian leader in oil and gas, construction and alternative energy publishing.

Kenwood Electronics Canada Inc. ..............................51 Kenwood Electronics Canada Inc. (www.kenwood.ca) of

Mississauga, Ont., is a leader in developing and marketing high-performance audio and communication equipment. A subsidiary of Kenwood Corporation, Kenwood Canada provides mobile and home multimedia systems and commercial land mobile radio products.

Logan Completion Systems ........................................62 Logan Completion Systems (www.loganinternationalinc.com) is an

innovative well completions technology and service company that specializes in open-hole, multistage horizontal fracturing systems. Its has developed the proprietary MultiStim Fracture Isolation Liner System — a multistage fracturing technology for horizontal wells.

NCS Energy Services ...................................................37 NCS Energy Services (www.ncsfrac.com) specializes in downhole

completion tools and services, and coiled-tubing-deployed frac tools. NCS has recently combined its Mongoose Frac System with a new sliding sleeve that eliminates the need for perforating at the frac-initiation point, creating the Multistage Unlimited Frac-Isolation System.

2

E-T Energy Ltd.hpv

lisT of adVerTiserstech guide

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NGC Product Solutions .............................................5 NGC Product Solutions (www.ngc-ps.com) is a Calgary-based

company that makes, distributes, innovates and creates the next generation products and solutions for the most challenging envi-ronments in construction, process and fluid handling applications while adhering to the highest-quality design standards.

Pure Energy Services Ltd. ......................................27 Pure Energy Services Ltd. (www.pure-energy.ca) is an oilfield

services company that provides completion and drilling related services to oil and gas exploration and development entities in Western Canada and, through its subsidiary Pure Energy Services (USA), Inc., in the Rocky Mountain region, North Dakota and the Appalachian Basin of the United States.

Sanjel Corporation .................................................32 Sanjel Corporation (www.sanjel.com) is a Calgary-based

international oilfield service company with over two and a half decades of industry experience. As a major competitor in the global oil and gas market and the largest privately owned oilfield service company in Canada, Sanjel offers five special-ized service lines including acidizing, cementing, coiled tubing, fracturing and nitrogen.

Savanna Energy Services Corp. .............................10 Savanna Energy Services Corp. (www.savannaenergy.com) is

a premiere drilling, well servicing and oilfield rentals company. Its fleet of drilling and well servicing rigs is among the newest in the world and its commitment to talent and technology has allowed for a strong foothold within Canada, enabling Savanna to expand to international markets.

Schlumberger Canada Limited ...............................49 Schlumberger Canada Limited (www.slb.com) is a leading

oilfield services provider, trusted to deliver superior results and improved E&P performance for oil and gas companies. Schlumberger Limited provides the industry’s widest range of products and services from exploration through production.

Contact Tony Poblete at [email protected]

for inquiries about advertising in the 2012 edition of

Tech Guide: canadian oilpatch Technology Guidebook

Low Cost Production of Bitumenin the Athabasca Oil Sands

E-T Energy Ltd. is leveraging the proven ET-DSP™ technology to produce bitumen reserves that are too deep for mining and too shallow for SAGD production.

To date, our technology is demonstrating:

Monetization of capital and generation of cash flow in less than a year

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ET-DSP™ is a heavyweight solution to the Oil Sands Opportunity – with an ENVIRONMENTAL EDGE.

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The five partners that comprise the management team at Arrival Oil Tools Inc. have their names on over 43 pat-ents. With three of them being professional engineers, they formed the company in 2009 to provide innovative downhole tools and solutions for some of the toughest challenges in today’s rapidly evolving drilling sector.

technologyprofileadvertorial

Arrival Oil Tools Inc.Innovator’s new downhole tools geared for today’s horizontals and big frac jobs

Accumulation of cuttings is often an issue in today’s deeper, high-angle horizontal wells where there are pressure and flow-rate limits.The Cuttings Mobilizer (which can be run in casing or open-hole) can benefit field operations in other ways. Because cuttings are circulated as the bit drills a formation, geologists can get real-time data from samples. Also, when running a liner, it can shave as much as six or eight hours off a 20-hour operation. “One client said that without it, it was sometimes impossible to set the liner all the way to TD [total depth],” says Robson.

Arrival has just introduced a tool that’s geared to current completion challenges. Called the Typhoon, it’s a bi-directional reamer that reams and back-reams and has a cutter block that can be replaced in the field.

The proprietary tool was developed to assist operators who were encountering

drag and other challenges as they set frac equipment with as many as 50 ports downhole. “Wellbores are often spiralled with resulting drag. The Typhoon reamer includes the flow director and accelerator components used in the Cuttings Mobilizer so as to help move cuttings up into the mud-flow,” says Konschuh.

Arrival is also introducing a shorter version of the VersaStabe, a downhole, hydraulically-activated stabilizer that improves wellbore inclination control in 2D drilling applications. The tool, which reduces spiralling and saves tripping time as control of the variable gauge tool is activated while rotating, has been available in a 3.5-metre-long version. Now a shorter, two-metre version, which can achieve the same results, is being field-proven in Canada this summer. “This shorter VeraStabe length ensures MWD [measurement-while-drilling] readings are closer to the bit,” says Robson.

For more information, please contact:Dan Robson, president

Arrival Oil Tools Inc.T: 403-730-6660F: 403-730-8965

E: [email protected]

And further patents are pending or soon to be applied for as the company continues to design, develop and commercialize new tools. “The main focus at Arrival is to design and build drilling tools to be rented or sold to the industry. These are tools we believe are needed to improve drilling efficiency,” says Dan Robson, president and one of the partners at Arrival.

The Cuttings Mobilizer is a case in point. Commercialized just over a year ago, the mechanically-based device is a debris management tool designed specifically for horizontal and deviated wells to reduce torque and drag by removing cuttings on the low side of the wellbore. Assisted by stabilizers, its rotor blades lift cuttings and debris off the low side and augur them into the mud flow, reducing equivalent circulating density (ECD). About 60 are rented in western Canada, and nearly 40 are in use overseas. “Today, companies want to drill horizontals fast, so there’s increasing need to manage debris and cuttings efficiently so they don’t clog the wellbore,” says Robson.

With older plays like the Cardium now being drilled horizontally, well paths are often irregular as the drill bit follows a thin pay zone. “With a geologist directing the drill path, you can have a more tortuous path than planned for,” says Chris Konschuh, a partner and mechanical engineer at Arrival.

Cuttings accumulation can be mechanically moved by pipe rotation or by a tool like the Cuttings Mobilizer which lifts the cuttings off the low side of the hole and moves it up into the mud-flow.

Arrival's Cuttings Mobilizer tool

full page826481-6

Arrival Oil Tools

Innovative engineering. Downhole excellence.

the ULTIMATE in hole cleaning

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2

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Debris Management Tool

Cuttings Mobilizer

Arrival Oil Tools Inc.

403.730.6660 | www.arrivaloiltools.com

TM

Designed for maximum performance and easy handling in horizontal or deviated wells, the Cuttings Mobilizer is useful in reducing torque and drag problems by removing cuttings resting on the low side of the wellbore, while strategic placement of clusterite and stabilizer orientation are tailored and built into the tool to assist in reaming operations.

By keeping the wellbore clear of cuttings, another major benefit of the Cuttings Mobilizer is the reduction of the ECD (equivalent circulating density).

The Cuttings Mobilizer incorporates the following features:

Short Overall Length: Designed for easy rig floor handling and more cost effective manufacturing and transportation.Conventional Right-Hand Wrapped Stabilizer: Full 360° support minimizes wear to the major diameter of the tool joint and rotor blades.Combination Left/Right-Hand Wrapped Stabilizer: Assists in hole cleaning and moving cuttings and debris during back-reaming operations.Clusterite Covered Leading Edges: Aggressive stabilizer edges break up large hole debris and cuttings but will not affect hole gauge.Cuttings Agitation: Rotor blades lift cuttings off of the low side of the borehole and auger them into the mud flow.

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Savanna Energy Services Corp.full page

www.savannaenergy.com

Canada • USA • Australia

Drilling • Well Servicing • Oilfield Rentals

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Savanna Energy Services Corp.

S1 YEARS2001-2011

DRILLINGtech guide

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DRILLINGtech guide

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The BBJ fluid hammer’s percussion mechanism trans-mits powerful left-hand reactive torque to the housing. “Reactive torque was our most difficult engineering hur-dle,” Cote comments. “We came up with an anti-backoff connection that in itself is a breakthrough. This concept has other possibilities that we’ll work with in the future with respect to mud motors.”

From hockey enForcer to technology developerBrad Cote spent much of his boyhood in North Battleford, Sask., on the ice. While still in high school, he competed at a major-junior level in the Western Hockey League, playing for the Portland Winterhawks and later the Moose Jaw Warriors. However, “to save my hands,” the hard-hitting left-winger quit hockey and entered the oilpatch.

“I’ve always wanted to know how things worked,” recalls the president of BBJ Tools Inc. The mechanically inclined youth was soon roughnecking for a major drill-ing contractor. “From the moment I first set foot on a rig, I developed a passion for the industry and technology,” Cote recalls.

Eventually, he became toolpush of one of Canada’s deepest-rated rigs and a senior troubleshooter. “The inspiration for BBJ Tools’ technology originated from a desire to improve project efficiencies in the oilsands and Foothills,” the company co-founder comments.

BBJ was launched in 2004, making its first mark with the slotted-liner assist tool and cuttings bed removal tool. Combined, these two devices broke new ground for drilling modern extended-reach and steam assisted gravity drainage wells. The fluid hammer followed, outclassing any competitive device from a major company. “Luis Guzman [a co-owner of BBJ] and I produced this tool in less than two years,” Cote says. “I’m still amazed at what our small team has been able to achieve in a short time.” ■

In the sprIng of 2010, Suncor Energy Inc. drilled a Foothills horizontal wellbore to 6,500 metres using a fluid hammer from top to bottom. That feat had never been achieved previously with this type of tool. “ROP [rate of penetration] was improved by 30–50 per cent,” explains Brad Cote, president of Calgary-based BBJ Tools Inc. “Our fluid hammer represents a revolutionary improvement in terms of maintaining drill bit integrity, steering ability, operating flexibility and other critical performance factors.”

BBJ carries fluid hammers for all standard hole applica-tions. Its patent-pending proprietary hammer maintains the drill bit in constant contact with the rock face, creating axial percussion force directly above the bit and exerting tremendous percussive force at hundreds of cycles per minute. BBJ’s fluid hammer incorporates a positive displacement motor and adjustable housing, which enables the driller to steer the drill bit, unlike con-ventional fluid hammers, which cannot be steered.

The recent Foothills well was drilled with tri-cone insert rock bits. Today, however, most wells are drilled with polycrystalline diamond compact (PDC) bits. “The synthetic diamond cutters are much more delicate than roller cones, so we had to undertake focused research and development to tailor the fluid hammer to PDC applica-tions,” Cote says. The fluid hammer has been proven viable for a number of PDC applications. BBJ credits Tourmaline Oil Corp. as a tremendously helpful cus-tomer for its PDC development.

The percussion force is developed in the lower hous-ing directly above the bit box. When weight is applied to the bit, the fluid hammer engages while keeping the bit in compression, delivering axial movement to the outer housing. “This design provides efficient weight-to-bit transfer for centre percussion force,” Cote says. “This design allows for diversified percussion control as rock formation compressibility variations are encountered. For example, when the driller needs more force, he

simply puts more weight on the bit. If all weight is removed from the bit, the hammer cycle stops, which is unique to BBJ’s fluid hammer design.”

The BBJ fluid hammer is integrated with major com-ponents of the mud motor. “Not only can our tool com-pete in every application where a mud motor is used, it outperforms them,” Cote says. “Mud flow and type are not restricted or diverted. Our technology elimi-nates flow issues for LCMs [lost circulation materials, like sawdust], high solids content and torque beads. In addition, there are no interruptions to the MWD [mea-surement while drilling] signal. With the cycling of the hammer, it develops movement to the outer housing which acts like an agitator tool, eliminating drag to the bit and increasing ROP.”

↑controlled impact

Traditional fluid ham-

mers exert continu-

ous percussive force

whether the rig is

drilling ahead or not, an

action that cannot be

controlled from surface.

The BBJ hammer is

operator-controlled

through the weight

placed on the drill bit

— less WOB and the

mechanism stops.

| BBJ Tools |

High-Tech HammerBBJ TooLs TRaNsfoRms The TRaDITIoNaL fLuID hammeR INTo a RevoLuTIoNaRy DRILLING TooLBy Mike Byfield

Photo: BBJ Tools Inc.

DRILLINGtech guide

13| Rigworks oilfield solutions |

A New Twist On TorqueNew eLecTRoNIc seNsoR measuRes The LeveL of ToRque oN The DRILL sTRINGBy James Mahony

For years, garage mechanics have known what can happen if a car’s wheel nuts are over-tightened, say, when a tire is changed. Threads on the nuts or bolts can be stripped and the bolts broken right off. It’s costly, and someone, whether mechanic or customer, has to foot the bill at the end of the day.

In drilling oil and gas wells, a simi-lar problem can arise. Unless coiled tubing is used, heavy joints of steel drillpipe are screwed together sequen-tially as drilling proceeds. When a new joint of pipe is added, its narrow end is screwed into the open end of the old joint in a process that’s repeated as the well deepens. But the over-tightening doesn’t arise here.

Well operators are usually under pressure to drill quickly. While onshore costs pale in comparison to those incurred in the offshore, the former are easily high enough to discourage any laxity in the pace of drilling. Pressure is also put on drill-ing contractors, who are expected to drill quickly to total depth and cut overall well costs.

For drillers, more weight-on-bit usually means faster drilling, while increasing torque—a force akin to that in a twisted elastic band—often achieves the same result. As with wheel nuts, though, there’s a happy medium for torque, beyond which over-tightening of threads can inflict damage to drillpipe.

The damage that over-torquing does to drillpipe is far more costly than a few nuts and bolts, however. The pipe must be re-machined and re-threaded. According to Steve Collier, chief operating officer of Rigworks Oilfield Solutions Inc., few studies have addressed just what torque-induced damage costs the oil industry each year, but anecdotal evidence suggests it’s plenty.

torque, among other parameters, is being pushed too high. But the Sentry will allow less experienced drillers to achieve maximum rate of penetration (ROP) without damaging the drillpipe through excessive torque.

“That’s where our torque system comes into play,” he says. “We all know what will happen over the next 21 months with [drilling] personnel and rigs. We’re going to have more inexperienced drillers coming up the ranks, while the more experienced ones are retiring.”

The Sentry system will work with most automatic drilling systems, allowing drillers to pre-set parameters so that, if a certain level of torque is reached, the system will automatically take weight off bit. “It will still give you maximum optimization and weight on bit, but it will reduce the amount of torque on the pipe, allowing for a more consistent ROP,” he says.

drIll hIstoryDesigned strictly for rotary drill-ing rigs, the current Sentry system includes software that lets the opera-tor look back and check the well’s history, viewing the points when torque or weight on bit peaked. That feature, Collier says, could be impor-tant for contract drillers, especially when it comes to sorting out who foots the bill for torque-induced damage to drillpipe.

Under many contracts, the well operator is liable for such damage, but that’s not always the case. Much depends on the contract between drilling contractor and operator, and liability for damage may also depend on other factors, such as the operator’s instructions to the driller, according to Collier.

In the past, the question of who was responsible for damaged drill-pipe was often a grey area. “Today, upon hole completion, they can go back through the drilling program and say, ‘Well, we spiked here, but the engineer said move forward and that’s when we damaged the pipe,’” says Collier.

The man who developed the Sentry system, Brady Marshall, is Rigworks’ founder and president. A heavy duty mechanic by trade, Marshall worked on drilling rigs worldwide, having developed and built oilfield equip-ment over the years. While the core

↗torque gauge

The Sentry system is

mounted on the drive-

shaft running between

the right-angle gearbox

on the drawworks

and the rotary table.

Image: Rigworks Oilfield Solutions

“You can quantify [the damage] by the fact that there are at least 15 shops [in Nisku, Alta.] that repair threads on damaged pipe,” he says. “About 90 per cent of the time, that damage is due to over-torquing.”

Apart from being the base for some drilling contractors, the industrial suburb of Nisku is home to Rigworks, which rolled out its own instrument to measure torque on the drill string about four years ago. The Sentry Torque System was designed to help drillers make optimum use of torque and avoid the drillpipe damage that keeps Nisku’s machine shops hopping.

Other methods of gauging torque on rigs rely on hydraulics, but the Sentry sensor is electronic, giving the driller a digital readout of torque on an electronic display. Hydraulic sensors, Collier says, only render an indication of torque, while his system provides a truer, more accurate measure.

For the industry’s more experi-enced drillers, Collier concedes that the Sentry may be of less use, since old hands can often sense when

DRILLINGtech guide

14

of the torque sensor was designed and made by a German company, Rigworks developed the Sentry sys-tem for rotary drilling rigs, and a patent is pending.

Although new to most people, the Sentry Torque System has been under-going field testing in western Canada for more than three years. In that time, at least two drilling contractors, Calgary-based Ironhand Drilling Inc. and Red Dog Drilling Inc., have used the system. The Sentry unit, which resembles a rotary bench grinder, has been working on Red Dog’s rig num-ber two since February 2007.

“It basically saves the life of our drillpipe,” says Wayne Zandee, presi-dent of Red Dog, based in Estevan, Sask. “I don’t have to replace the drill string as often.”

When Red Dog’s drillpipe suf-fers thread damage while drilling,

the well operator pays the freight. Nevertheless, the Sentry system has been worthwhile, Zandee says. “Every time you have to repair [drillpipe] threads, you lose a bit of life out of that drillpipe. Eventually, I’ve got to replace the pipe, and it gets costly,” he says.

Apart from shortening the life of drillpipe, Zandee says repairing thread damage means losing a few inches with each repair. “A tool joint is eight inches long, and if you take a few inches out of it every time, you’ve got to throw it away, because [eventually] you don’t have a tool joint left.”

Zandee did not monitor what Red Dog spent each year on torque-induced thread damage before install-ing the Sentry, or what the company has since spent, for comparison pur-poses. But quantifiable or not, he says he is satisfied he has seen savings. ■

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 [recently] 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 to have successfully established a way to blend vacuum and rig shakers to recapture oil-based mud, or any drill-ing fluid for that matter. Focused on ensuring that 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 drill-ing applications.

“With emerging concerns for orga-nizations 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 cut-tings disposal.”

Pomerleau says the genesis for what would eventually become VAC-Screen began while the company was working in the Alberta Foothills. A 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 sys-tem and the introduction of fines causes significant issues when it comes to maintaining a drilling fluid.

“That’s because by its very design, the rotary vacuum dryer fluid recov-ery and cuttings drying system degraded the drilling cuttings that it processes and when this occurs, some of that stuff gets in the recovered fluid and it becomes very difficult to remove particles that are below 20 microns. Once they go down the hole and start coming back up sub-five microns, then you’re really up against it,” Pomerleau notes.

Given the scenario that was unfold-ing, FP Marangoni initially opted for blowing mud through the shaker screen using compressed air and air

Pho

to: F

P M

aran

goni

→not too tight

Ninety per cent of

damage to drillpipe

is through over-

torquing. The Sentry

system gauges torque

as well as creating

a digital record of

torque through the

drilling program.

continued on page 16

Simple Solutionvac-scReeN TechNoLoGy heLps DRILLeRs RecapTuRe oIL-BaseD muDBy Paul Wells

It’s not always rocket science. Sometimes, the simplest of 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 solv-ing an old problem. Not to mention a technology that the company claims is paying dividends for producers looking to cut costs while improving

Rigworks oilfield solutions | fp marangoni

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up

155

Ensign Energy Services Inc.full page

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DRILLINGtech guide

16

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,” Pomerleau says.

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.

“In fact, most of our customers are now running shaker screens that they couldn’t run before, because if they did use really fine screens, the mud would have just flowed off of the end of the shaker,” Pomerleau says. “With this thing, it acts almost like a flow brake, so they can ramp up to 250 or 325 mesh screens. The mud that goes through those screens is excellent—it’s very useful. Imagine managing most of the mud solids with your shakers.”

Essentially, the fluid that comes out of the end of the shaker flows onto the vacuum manifolds where it is then recovered and the cuttings dry out. The newly created design incorporates a “processing area” eight inches in length, which ensures that the cuttings are dried out efficiently and are easy to dispose of.

“The processing area just sits there, the cuttings move across and we pull off the excess fluid and recover it,” says Pomerleau. “Some of our clients put that fluid through a centrifuge, some don’t.”

After running a prototype VAC-Screen over a three-month period from February through April, the technology was commercially intro-duced in June and has quickly caught on. Currently, VAC-Screen technol-ogy is running on about 20 rigs in Canada and the United States, and more producers are showing a keen interest in using the technology. “We currently have inquiries from major oilfield service companies operating in Dubai, California, North Dakota and even Thailand,” Pomerleau says.

Pomerleau notes the VAC-Screen technology reduces costs and envi-ronmental impact and “benefits oper-ators in a number of ways,” includ-ing: reduced fluid losses at surface;

reduced chemical additions for main-tenance; increased shaker separation performance; reduced shaker screen consumption; reduced centrifuge operation; elimination of or severely reduced shaker screen washing and significantly reduced mix-off and trucking requirements.

Still, the main benefit is that the recovered fluid has no detrimental effects on the drilling fluid system.

The system is currently compat-ible with a number of industry-leading shakers readily available in the marketplace.

Pomerleau claims that from the get-go the technology proved its worth in the field, as during the first job that the VAC-Screen ran, it saved the client about $92,000 net on the oil mud sec-tion and over $100,000 on the water-based section of the well.

“The going rental rate for our system is 30 per cent of the cost of

competitive quality systems, which can run in excess of $1,500 per day, so we’re at the bottom end of the pricing. And we provide a product that’s actu-ally better than anything you can get even with high-end systems,” he says.

“So, if a client is recovering $1,000–$5,000 worth of drilling fluid every day, and he’s paying a small fraction of that value to do that, that’s something. That kind of tech-nology doesn’t show up every day. There are a lot of people who have helped us along the way—certainly [National Oilwell Varco, Inc. brand] NOV Brandt and Richfield Equip-ment [Limited] have been supportive, as well as several E&P companies that have been willing to try this leading-edge technology.”

Al Toney, drilling fluid specialist for Talisman Energy Inc., has used the VAC-Screen technology and has been pleased with initial results. That said, he notes it’s too early to determine the actual benefits.

“To be honest, we are still waiting on some key data from the field to meaningfully scrutinize the vacuum system. Superficially it looks like it is saving some money on waste gener-ated and [on] recovering free fluid from the shakers.”

For example, Toney says on the last well the product was used it reduced losses of oil-based mud from what are typically 120–160 cubic metres down to 105 cubic metres.

“This hasn’t taken into consid-eration the quality of fluid and the reduced sawdust mix required on cut-tings. Unfortunately, we are dealing with breakdown issues with the unit and trying to see if it can handle the rigours of our operation,” he explains.

(FP Marangoni has since replaced all of its aluminum manifolds with stainless steel and this has success-fully overcome the breakdown issues, the company says.)

“I think it was an interesting test and [I] am looking forward to results on another trial to prove up the tech-nology. The vacuum manifolds will be set up on a new Talisman rig in [mid to late October],” says Toney.

Meanwhile, FP Marangoni is not sitting idle as the company is intro-ducing a new shaker technology that it hopes will be an order of magnitude greater than VAC-Screen and a “para-digm shift” in shaker technology. “What’s really funny is this new idea is even simpler,” Pomerleau says. ■

Continued from page 14

↑shake it up

The screen and

vacuum manifold at

the front of the shaker.

| fp marangoni |

Pho

tos:

FP

Mar

ango

ni

DRILLINGtech guide

17

drIlFormance Ulc began making polycrystalline diamond compact (PDC) drill bits in 2008, just as rig counts began plunging across North America. Besides timing its launch to the worst upstream market condi-tions in the past decade, the Alberta-based manufacturer had jumped into an arena dominated by oilfield giants: Schlumberger Limited (Smith Bits), Halliburton Company (Security DBS), National Oilwell Varco, Inc. (ReedHycalog) and Baker Hughes Inc. And there are other players, including Chinese price lowballers.

So how’s business? “We’re doing pretty well,” says Sean Gillis, engineering manager at Drilformance’s plant in Leduc. At age 30, he runs research and manufacturing under company chairman Rusty Petree, a well-known entrepreneur from Houston, Texas.

“The industry slowdown has benefitted us on the sup-plier side. Steel is instantly available, for example, and everyone bends over backward to help,” Gillis says. “On the buy side, customers are attracted by the fact that our bits reduce their drilling costs. Drilformance’s technology is the cream of the crop in terms of durability in tough rock and steerability for directional drilling.”

Although the new firm’s payroll is small—about 30, including sales offices in the United States and over-seas—the firm can nonetheless access state-of-the-art manufacturing technology. “We use some of the world’s most sophisticated CNC [computerized numerical con-trol] programs and machinery,” Gillis says. “Compared to larger companies, we’re more willing to push the design envelope if a customer wants to try out an idea, and our team can move quickly.”

Drilformance PDC bits are milled from a single block of steel. The compact unibody, flat profile and PDC cut-ter layout are engineered to generate smooth, consistent reactive torque, which enhances directional responsive-ness downhole. The company has developed several manufacturing technologies, including:• Rhino Armour Gauge Protection, a proprietary hard-

facing process that reportedly provides maximum pro-tection to critical bit surfaces.

• After the armoured bit cools, PDC diamond cutters are brazed into place. Drilformance is in the process of patenting Cryo Edge, a technology that enhances the thermal stability of its polycrystalline diamond wafers.

• The company’s Shadow Path work sharing system is another patent-pending element, designed to mitigate heat buildup while adding diamond volume to the bit shoulder.

• The HeliPath stability system (also patent pending) is a radial spiral breakthrough that reportedly increases depth of cut while increasing bit stability.

• Opti Trac Directional is modelled for good steerability, utilizing optimal custom back rake, side rake and other design elements.

Drilformance has case studies demonstrating superior rate of penetration in tough geological formations like the Basal Belly River, Glauconite and Ellerslie. For instance, in British Columbia’s Montney tight gas play, Encana Corp. reportedly drilled two offsetting wells, one using a Drilformance 156-millimetre PDC bit and the other with a competitor’s bits. “The drilling crew com-pleted the horizontal portion of our well in 133.5 hours, compared to 201.3 hours for the other well,” Gillis says. “That’s a 34 per cent improvement under very similar operating conditions.”

The professional engineer says that “for me, coming to work each day is like going to the race track. I’m always examining how fast and how far we went, and think-ing about how that performance might be improved. Our people on the floor are great to work with. They’re experienced hands who truly understand the practical aspects in manufacturing—the precise temperatures and methods for making bits that will perform consistently in the field.”

Gillis himself worked in machine shops during summer breaks while still in high school and later when he was studying mechanical engineering at the University of Alberta. “Too often I heard machinists cursing engin-eers for poor designs. I took those complaints to heart,” the engineering manager says. “Theory isn’t enough, not even close. I’m grateful that I had the opportunity to ‘touch the steel’ and learned to respect the manufac-turing process.”

Drilformance is preparing tools well beyond its cur-rent PDC bit lineup. In 2009, Petree said publicly that his company is preparing “a downhole drilling system with the potential to create a step-change improvement in drilling performance for both vertical and directional applications.” Gillis won’t even hint further at this point about what’s in the works: “Let’s just say that our guys are always interested in developing new and exciting ways to destroy rock!” ■

Bit Of A GambleJuNIoR DRILL BIT maNufacTuReR DoDGes RecessIoN, Takes oN The maJoRsBy Mike Byfield

↑choice bit

Drilformance strives

to create bits that

provide superior rate

of penetration and

reduced drilling costs.

“The drilling crew completed the horizontal portion of our well in 133.5 hours, compared to 201.3 hours for the other well. That’s a 34 per cent improvement under very similar operating conditions.”

Pho

tos:

Dril

form

ance

ULC

4959

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productiontech guide

19

Pho

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com

(m

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Jun

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production


20

Looking To Repeat Historyconventional heavy oil producers on the lookout for another game changerBy Maurice Smith

Heavy oil producers saw trouble ahead as pro-duction in the Lloydminster region straddling the Saskatchewan-Alberta border began to flatline in the 1980s. Output from individual wells was anemic, there were fewer drilling location opportunities, capital and operating costs were on the rise, regulatory requirements were increasing and, with oil at under $10 a barrel, some companies were slipping into the red.

Then along came a creative new production technique that involved working with formation sand rather than fighting it (cold heavy oil production with sand, or CHOPS) and the essential enabling technology that made it feasible—the progressive cavity pump (PCP).

In 1997, Husky Energy Inc. took the decision to try the emerging technology on an unproductive well, according to Darryl Greening, who outlined the impact of the technology at a seminar for small- and medium-sized enterprises sponsored by the Petroleum Technology Alliance Canada (PTAC) last October. The decision ended up turning the company’s fortunes around, he said. “The PC pump really was a game changer for us.”

Production from the initial well, which struggled to produce a cubic metre a day in the early 1980s, shot up to 10 to 11 cubic metres a day using the then-new PCP tech-nology. A well that produced about 1,200 cubic metres in its first four years went on to produce some 60,000 cubic metres from 1997 to 2010, he noted. “A significant step-change occurred with that technology change.”

Multiply that over thousands of wells, and it’s easy to see the impact of the technology. Today, Husky claims to be the largest user of PCPs in the world. With over 14,000 wells actively producing or injecting, Husky has about 7,000 wells with PCP artificial lift and about 3,500 located in its Heavy Oil Business Unit around Lloydminster.

But that success could only go so far. The company’s Lloydminster-area production profile shows output ris-ing to a peak in 2004, reaching a plateau for three years and then falling in each of the following three years through 2010. “We are struggling to keep ahead of that decline no matter what we are doing with it—with the [PCP] and CHOPS approach,” Greening said.

depletion dilemmaIn the Lloydminster area, depletions are a problem com-mon to the handful of major conventional heavy oil producers, which are again running out of primary drill-ing opportunities with only about 10 per cent recovery from the massive heavy oil resource of the region.

“We are pretty much in a similar position,” says Jerry Shaw, Devon Canada Corporation’s senior technical adviser for the unconventional resources team, which is respon-sible for E&P technologies in the company’s Canadian unconventional programs. “Increas-ing oil recovery will require us to go beyond simply the drilling of new wells and instead look at some form of enhanced recovery.”

Whereas in the 1990s, companies were looking at a near-wellbore type of enhancement, they are now look-ing to reservoir recovery enhance-ment. “We depleted the reservoir energy through primary production, with what we call foamy oil flow, and also the creation of wormholes as a result of the sand production, so what we are looking at is ways to re-energize the reservoirs and ways to potentially look at thermal types of recovery. So there are a number of different options we are currently evaluating.”

There is an increasing sense of urgency to that task because as CHOPS wells run dry, they are being aban-doned in greater numbers. Once that occurs, the added cost to re-establish production can make reactivation uneconomic. “If we abandon all the wells, then we are going to have a really hard time doing [enhanced

Declining Canadian Heavy Oil Production Source: NEB 2007

2000 2005 2010 2015 2020 2025 2030

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↑Declining Canadian

heavy oil production.

| husky energy | devon canada |


21

recovery] later,” says petroleum engineer Bruce Peachey, New Paradigm Engineering Ltd. president and a PTAC technical adviser.

Lighter than the nearby oilsands, but heavier than the oil found at nearby Pelican Lake and Brintnell, the Lloydminster heavy oil belt is uniquely challenged. While thermal production works in the oilsands and waterfloods with polymers are proving more successful than anticipated at Pelican Lake and Brintnell, Lloydminster for-mations are generally too thin for the former and too heavy for the latter to work effectively.

Being also too thin for vapour extraction (VAPEX), which requires a vertically spaced well pair, Peachey notes a solvent-based process using a single horizon-tal well with solvent and gas mixtures, known as joint implementation of vapour extraction (JIVE), is under-going testing. Solvent recovery is a key economic driver there, he says.

In situ combustion is another possibility. Petrobank Energy and Resources Ltd. is piloting toe to heel air injec-tion in the region, where “it may be a better fit than in the oilsands,” says Peachey. Electric heating may be attempted, while PTAC has also identified the potential for portable direct contact steam generation technologies that may allow for thermal stimulations.

CO2 injection remains another option, despite the fact a multi-million dollar government-industry pilot pro-posed by Husky and PTAC in 2008 to capture CO2 from Husky’s upgrader and ethanol plant at Lloydminster and inject it into nearby reservoirs is no longer active.

Hot water vapour processThe most promising technique to come along recently is the hot water vapour process (HWVP), which would use the wormholes to allow low pressure injection of a gas saturated with water vapour. “It’s kind of a mild thermal process where we are saturating inert gas like nitrogen with water vapour, and that gets energy into the reser-voir without high temperatures,” explains Peachey.

Wormholes allow the injection of non-condensable gas saturated with water vapour at relatively low pres-sures. By avoiding the requirement for steam generation, the need for boiler feedwater and fresh water is avoided. Since the thin pay zones don’t justify high levels of investment, the technique would use existing infrastruc-ture and require the drilling of few new wells.

“What we are trying to do is get the energy down without exceeding the casing temperature limitations on the existing wells, which weren’t designed for thermal

operations. We pretty much have to keep the casing temperatures below 60–70 degrees C[elsius], so you can’t put steam down, and that’s why we are trying to put just water vapour, which still carries the energy but doesn’t

have the temperature.”The thermal energy added to the

reservoir is the latent heat of evapora-tion of the water vapour. By raising the temperature in and around the worm-holes by 30–50 degrees C, viscosity can be reduced by a factor of 10–100 times.

Saturating flue gas with water vapour increases its thermal carry-

ing capacity by several times over dry flue gas. The water vapour would condense quickly and deposit heat in the wormholes. The heat would transfer by the slower processes of convection and conduction to the volumes surrounding the wormholes, says Marc Godin, a consult-ing engineer and PTAC adviser, in a presentation of the technology. Additional cycles will expand the surround-ing heated volume. After 10 cycles, it is estimated 5,640 cubic metres of oil would be heated.

Heat balance calculations show that a temperature of about 60 degrees C would be reached during the first cycle, reducing heavy oil viscosity from about 4,000 centipoises to about 150 centipoises. Injection of a non-condensable gas increases reservoir pressure, Godin says, and the difference between reservoir pressure and bot-tomhole pressure drives gas and liquids back to the well-bore during production in a cyclic configuration.

Having completed two preparation phases, PTAC and a consortium of companies were on the cusp of launching Phase 3 of HWVP this summer, a $3-million field pilot.

Peachey notes commercial development of a process such as HWVP would create opportunities for small and medium enterprises such as those targeted by Husky last fall. “Once you have a new recovery method, you will need a whole variety of support systems to go along with that. With the HWVP method we are looking at, we will need a whole bunch of either nitrogen generation units or flue gas generation units. And we will probably be using insulated tubing and other things, so again that’s generating a demand for new technologies that haven’t been used much in the past.” ■

— with files from Pipeline News

Lloydminster Area Production Pro le

0

50

100

150

200

250

300

350

1991 1993 1995 1997 1999 2001 2003 2005 2007 2009

Growth

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↑Husky's Lloydminster

area production profile.

↓pumped

A new pad at

Husky's Pikes Peak,

Sask., steam assisted

in situ enhanced oil

recovery plant.

Imag

ery:

Hus

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| petrobank energy and resources |

108

Advantage Products Inc.advertorial

(technology profile)technologyprofile

advertorial

Advantage Products Inc. (API)New motor for PCPs eliminates downtime for changing speed range

completely controllable from the control panel. That’s the key,” says Jim Weber, president and CEO of API.

Although a prototype of the TorqDrive was first installed in the field several years ago, API has continued to tweak the design and develop new prototypes. Weber says that one of the challenges involved in the development of specialized control algorithms is to enable revolutions per minute to vary

while maintaining horsepower and torque.

With this hurdle cleared, operators can expect a drive system

with the highest efficiency in the market with no down time for speed changes and higher reliability. It should also help boost profits because it will be

quicker and easier to determine the optimal pumping revolutions per minute than with current drive systems.

“With today’s hydraulic units, operators can only

achieve about 50 per cent speed

range before they have to shut down the well and change the sheaves and belts to get additional speed range. With the TorqDrive, it’s as simple as setting the speed set point on

the control panel,” says Weber.The oilpatch veteran, inventor and product

developer, who recently moved manufacturing operations from Calgary to a 23,000-square-foot facility in Didsbury, has a

track record that should inspire confidence.Weber founded API in 1997.

Two years later, he introduced the TorqStopper. It has one moving part and is currently API’s flagship product. Today, there are over 40,000 units in use around the world with distribution through a range of manufacturers and suppliers including CE Franklin, Europump, Midfield Supply, National Oilwell Varco, R&M Energy Systems and Weatherford. The TX7, used for seven-inch casing, has been the most popular model, selling over 10,000 units alone.

The TorqStopper is an improved version of Weber’s original “no-turn-tool,” the patch’s first torque anchor, which he designed in the 1980s to set the tubing string and prevent it from rotating. Wells equipped with progressive cavity pumps experienced frequent break-downs back then, partly as a result of the vibration and torque stemming from the pump’s action. The torque and vibration would cause sections of a tubing string to back off, becoming unscrewed and drop down the wellbore.

The TorqStopper got rid of that problem. API’s TorqDrive looks set to solve a few more.

For more information, please contact:Jim Weber, president & CEO

Advantage Products Inc. (API)T: 403-264-1647F: 403-263-2369

E: [email protected]

A new kind of motor for progressive cavity pump (PCP) top drives is being made commercially available this fall—and it’s set to mark a major step change.

With the currently available drive systems, operators must first shut down the pump and change the belts or gears when increasing—or decreasing—the speed range at the drive-head.

But the new TorqDrive from Advantage Products Inc. (API) is a direct drive variable speed motor that can provide full-rated torque from 30 to 450 revolutions per minute. “The point of this type of design is that it eliminates the need for belts or gears or for changing them. The speed is now

108

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24

as icons go, the pumpjack has a long history in western Canada. Even in Alberta, where people argue over whether horses or haystacks played a greater role in the province’s history, it’s the ubiquitous pumpjack that has become the symbol of prosperity in recent years, both for Albertans and those living in neighbouring Saskatchewan.

If asked to come up with a short list of green technologies, however, few Canadians would mention a pumpjack, although steady advances in technology have improved it in recent years.

One Alberta company is tapping the broader North American market with hardware that will turn a pump-jack into a small-scale power plant. In effect, the new system allows oil well operators to cut their power costs by generating electricity at the wellhead and selling it into the prov-ince’s power grid.

That doesn’t mean oil producers can run pumpjacks for nothing. They’ll still get an electric bill at month-end, but some producers can offset the pumpjack-driven por-tion of their monthly electricity bill

Tweaking The Pumpjackfor western canada’s oil producers, retooling a prairie icon could mean power savings and a greener profileBy James Mahony

by churning out and selling their own power.

The potential environmental benefits and cost savings the technol-ogy promises could shift pumpjack dynamics, not only in Alberta and Saskatchewan, but beyond Canada, since the vast majority of North American pumpjacks are in the United States.

Indeed, the state of Texas alone has well over 100,000 of the devices, with at least another 50,000 in California and some 33,000 in Oklahoma, according to David Gray, president of CCW Inc., which assembles and markets the new pump-jack system from hardware developed in Italy and Spain.

Gray estimates there are over 500,000 pumpjacks in North America, a market that could be profitable going forward. “We do three things for the pumpjack operator,” says Gray. “We reduce direct [power] consumption and peak demand, and we regen-erate saleable power.”

Power bills for a pumpjack can run to $3,000 a month,

and since some producers have hun-dreds of wells, the monthly total can go much higher.

Gray says CCW’s technology can save operators 25–30 per cent per month on electricity alone, without counting environmental benefits. (The cost savings include revenue from power sold.)

On the cost side, he estimates that installing a CCW unit will run from $10,000–$30,000 per well, but says most wells will recover those costs in the first year of production.

A pumpjack’s ability to gener-ate power is partly a function of its design. Most are geared to alternately lift and drop the string of steel sucker rod that hangs from the iconic “horsehead” that is so familiar to farmers and ranchers. Running the length of the well, the sucker rod can be a mile or longer, weighing several tons. Power is generated not on the pumpjack’s upstroke, but on its down-stroke as the horsehead descends.

In effect, CCW’s technology turns the pumpjack’s electric motor into a power generator. Meanwhile, the variable-frequency (VF) drives that the company uses allow the operator to dial up or down AC power going to the motor, giving the operator more control, allowing the motor to run faster or slower.

CCW’s advantage is not just its VF drives, Gray says, but its way of managing the electricity flow coming from, and going to, the power grid. The system uses special software that eliminates electronic “noise” created by VF drives, something Gray says would otherwise reduce the system’s efficiency.

“The device itself smoothes out the power,” he adds. “When it takes [the power] in, it goes through a set of filters. It then gets manipu-lated by the device. Then when [the power] goes back out, it goes through the filters [again].” The result is a more fluid, efficient flow of power in both directions.

One producer that has test-driven CCW’s hardware is ARC Resources Ltd., which currently has three units, the first installed on a Pembina Cardium well in Alberta about 18 months ago. Later, units were added

| ccw |

↖nod to efficiency

CCW's new pumpjack

drive system captures

regenerative power

on the downstroke,

allowing it to convert

kinetic energy to

electricity for resale.

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tHe unconventional gas revolution is in full swing thanks in large part to the inventiveness and ingenuity of horizontal drilling and multistage fracture stimulation.

In tight gas and shale gas plays, for example, optimizing downhole opera-tions and maximizing the amount of gas flowing to surface means increased profitability. To help achieve this, a clearer picture of the reservoir is needed. Some major companies have been using existing fibre optic technologies and adapting them for this purpose.

The result is a more powerful downhole flashlight, so to speak, that’s allowing them to make better decisions during completion operations.

Royal Dutch Shell plc has been employing a strategy of using these fibre optic systems in its operations, including the Deep Basin and Groundbirch. The latter, located in British Columbia, is a top-growth area for the company. There, Shell is producing natural gas from a reservoir of tight sandstone, siltstone and shale at a depth of about 2,500 metres. The company is cur-rently producing enough gas to supply more than 400,000 typical homes for one year.

Last summer, Shell announced a collaboration for the use of QinetiQ Group plc’s OptaSense fibre optic Distributed Acoustic Sensing (DAS) system. QinetiQ is a Farnborough, United Kingdom–based global defence technology company spun off from the British government now involved in industries such as aerospace, defence, security and energy.

The technology will provide an ability to use standard telecom fibre optic cable to detect, discriminate and locate acoustic events during wellbore operations beyond what is currently available. This will allow for design and execution improvements that can boost recoveries and lower costs.

in the Pembina and on an ARC oil well in Estevan, Sask.

“We’ve seen a significant power reduction on the first two installs,” says Shayne Coward, ARC’s area production foreman for the Pembina field. The result has saved as much as 40 per cent of the company’s power costs, a saving Coward attributes to the improved efficiency. The savings do not include the value of power generated and sold back into the grid.

“One of the stumbling blocks has been the regenerative metering,” he adds, noting that ARC could not say just how much power was sold back onto the grid. ARC is still working with the power company on finding a metering system that will accu-rately gauge power sold into the grid.

“The [metering] has really been our stumbling block and [the reason] why we haven’t put more of these into service,” he says. As well, some of the power generated is redeployed on site rather than being sold back into the grid. Yet, the CCW system doesn’t suit every application, Coward says.

In particular, pumpjacks that use low-horsepower electric motors aren’t likely to see the same benefits, at least in terms of cost savings. “We have a lot of wells that would not be economic [for this],” he adds, esti-mating that the technology would be economic on pumpjack motors rated at 30 or more horsepower.

As for payout, Coward estimates the three ARC wells with CCW units should pay for themselves in about two years, although ARC’s calculation does not take into account the power being sold into the grid. As for the future, ARC plans to move forward with installing more units when its power-provider has ironed out a proper metering system to use with the units, he says.

Back at CCW’s Edmonton office, Gray says the company’s technol-ogy will do more than cut power bills. Because power consumption is reduced, CO2 emissions are also cut, and he estimates that emis-sions of about 20 tonnes per year are avoided for every system installed. Gray expects all metering issues to be resolved in the near future. ■

ccw | shell | QinetiQ group | pgs

Seeing The Lightusing fibre optic technology to improve recoveriesBy Richard Macedo

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The collaboration agreement between Shell and QinetiQ is a culmination of 18 months of jointly working on the technology through several successful field trials in Canada. Shell is working toward using this optical sensing system based on QinetiQ’s existing OptaSense DAS technology initially in onshore field development and exploration.

Shell officials say the technology has the potential to deliver significant value in the near term and, because of its wide potential application area, it can also be the catalyst for improvements to managing assets across its lifecycle, from exploration to operations.

The technology could also benefit hydraulic fractur-ing operations of tight gas and shale gas reservoirs, an increasingly important aspect of the company’s business.

“By analyzing back reflected light in an effective way, OptaSense is able to turn that fibre into an acoustic sens-ing array such that every several metres of that fibre acts as a microphone,” says Vianney Koelman, Shell’s team leader of in-well technology research and development,

based in Houston. “It has to do with disturbances in the coherence of the back-scattered light you can use to pick up acoustic signals.”

Shell staff was the first to recognize the potential break-through innovation of applying QinetiQ’s DAS technol-ogy (currently used for onshore pipeline monitoring) during the first field trial in February 2009. Given that most of this technology is in use today in the defence and security industries, Shell expects a relatively low development risk. “For Shell, this fits with our overall fibre optic R&D program,” Koelman says.

The technology helps complete the picture downhole, which lets the company make better decisions in the critical time during completion operations to improve production.

Mathieu Molenaar, a production engineer and sensor expert with Shell Canada Limited in Calgary, says the goal behind this is to improve wellbore monitoring for flow and hydraulic fracturing, adding that when com-pany officials came across OptaSense, they thought it could work for reservoir monitoring.

“We have monitored wells in different locations, different configurations and different formations,” Molenaar says. “We’ve got thousands of hours of recorded measurements downhole, which resulted in many terabytes of data.

“When developing tight and shale gas via hydraulic fracturing, it’s impor-tant to optimize operations downhole. More data can help with production versus cost decisions. It illuminates your wellbore,” Molenaar adds. “You can see a more complete picture of what is happening in your wellbore. The same is true when you start to produce the wellbore; it helps tell us more precisely where production is coming from.”

The company has tested the technology in its Canadian shale and tight gas plays in both vertical and horizontal wells. “I think the technical advance is that the information we’re getting is clearer,” Molenaar says. “We have other downhole measurements, but DAS is a valuable addition to the temperature-based monitoring that we’re used to.”

While the technology is helpful in tight gas and shale gas reservoirs, it has broader applicability, he notes.

The company, meanwhile, has other fibre optic R&D projects on the go with different technology providers. Shell and Petroleum Geo-Services ASA (PGS) earlier announced a collaboration to develop an ultra-high channel count fibre optic seismic sensing system. Higher channel counts with high-quality sensors recover more seismic energy and help cancel noise. The improved resolution and imaging translate into better exploration decisions.

PGS, headquartered in Lysaker, Norway, offers a broad range of prod-ucts including seismic and electromagnetic services, data acquisition, processing, and reservoir analysis and interpretation. Shell intends to use PGS’s optical sensing system for onshore exploration as well as res-ervoir monitoring. It says it will enable scalability far beyond what is currently available.

The collaboration was aided by Shell technologists who first recognized the potential breakthrough innovation of applying PGS’s underlying OptoSeis technology for onshore seismic.

In offshore applications OptoSeis, operational down to 3,000-metre water depths, offers a more cost-effective alternative to electrical sys-tems. Each durable sensor station contains three axis optical accelerom-eters and a hydrophone, which is designed for optimum performance and reliability.

Using these existing technologies is a way to offer technological solutions quickly and efficiently, according to Shell. Like OptaSense, given that most of this technology is in existence today, the company expects low develop-ment risk.

“We find the quality of seismic data on land inadequate for exploration purposes and also for reservoir monitoring,” Wim Walk, Shell’s manager of geophysical measurement technologies, noted during a conference call announcing the collaboration with PGS. “We really want to make a big step forward in improving that quality.

“By using PGS’s technology, we can make a step forward in improving the quality of seismic data on land without making the logistics and without mak-ing some of the issues around deploying the system cost- or effort-inhibitive.” ■

Sensing Fibre

Analysis and Visualization

Acoustic Signal

Interrogator Unit

Pulse

Acoustic Signal

Rayleigh BackscatterDue to Inhomogeneities

in Fibre Core

Micro Strain in Fibre

Laser

Pulse

shell | QinetiQ group | pgs

162

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28

For alberta’s coalbed methane (CBM) producers, working with coal has its advantages. Easy access is one, with formations like the Horseshoe Canyon relatively near the surface. But it has its downsides as well, includ-

ing a greater tendency to sustain formation damage due to an over-pressured wellbore.

According to an Alberta company marketing a system for removing fluid from oil and gas wells,

such damage, albeit temporary, commonly occurs during well cleanouts using traditional methods

such as swabbing.Steve Winkler, president of Quantum Downhole

Systems Inc., says that sort of damage is becoming more common in the industry, for both CBM and shallow-gas producers.

“Zones most prone to cleanout damage are low pres-sure and highly permeable,” he says, citing Horseshoe Canyon coals and Edmonton Group sandstones. “They release gas from the formation quite easily, but if you over-pressure the wellbore, the fluid or solids within will go back into the formation very easily. It’s very perme-able, like a sponge.”

Operators who swab to remove wellbore fluids some-times see a drop in production after the cleanout, which Winkler believes is caused by an over-pressured wellbore. In contrast, he says Quantum’s JetPak system operates differently. By working under-balanced, it reduces the occurrence of cleanout-driven wellbore damage and improves fluid recovery.

The JetPak combines two technologies. One is a purpose-built jet pump developed by Source Rock Energy Partners Inc. With no moving parts, the slim-profile

Losing The Water Without Losing The Gastechnology startup deploys artificial lift system on coiled tubingBy James Mahony

pump is carried downhole by coiled tubing. That coiled tubing, however, is different from the norm. Made by CJS Coiled Tubing Supply Ltd., it’s actually two standard strings of tub-ing, known as a FlatPak, held in a plastic case.

“Our system is essentially a quickly deployed artificial lift system on coiled tubing. We can quickly run in and pump fluid off these wells within 45 minutes of getting on location,” says Winkler.

When sent downhole, the twin-strand tubing lets the operator pump the cleanout fluid—typically water—downhole, while the return solution, including fluid from the wellbore, comes up the other conduit to sur-face. The two-way flow is part of a closed loop that sees fluid pumped continuously down one tube and up the other. Downhole, the jet pump uses the Venturi principle to create suction in the wellbore, drawing in fluid that will go uphole.

Since it went into commercial use in July 2009, the JetPak has serviced some 260 wells, says Winkler. While it began as a way to remove fluid and sand from relatively shallow, sub-800-metre wells, the JetPak can now handle wells as deep as 2,150 metres.

Until now, the usual methods of removing fluid from wells have included swabbing, nitrogen, foam and air cleanouts, all methods that put pressure on the formation as fluid and sand are removed, leaving the poten-tial for formation damage. Workovers may also be required as a result.

For one junior producer focused on CBM, water buildup has been a

pressure spray

The JetPak system

includes the FLATpak

string and the high-

pressure nozzle,

deployed using

slightly modified con-

ventional CT units.

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Brother’s Specialized Coating Systems Ltd.tqc


29

problem in some wells. Most of the company’s Alberta wells are in the 400–900-metre depth range. Although producing mainly from Horseshoe Canyon coals, many of the wells operated by Ember Resources Inc. also produce gas from Belly River and Edmonton Sands, often at rates of about 100,000 cubic feet per day.

Jim Kelly, Ember’s operations manager, says condensed water is the main issue. “As [methane] gas is produced, condensation forms as the gas expands in the wellbore. It’s a very small amount of moisture, but it accu-mulates with time. Eventually, we get water that covers [casing] perforations, inhibiting production,” he says.

“In some areas, we noticed a sustained loss in produc-tion after we cleaned the wells out. We’d see a very definitive change in the production curve for a while, and we attributed it to water imbibement as we lifted or swabbed the water past the open perforations.” On some wells, he noticed a pro-duction drop of as much as 25–30 per cent, which he calls “significant and measurable.”

Ember has used the JetPak on 70–80 wells thus far. There has been little or no production loss following fluid removal. Unlike the other two meth-ods of removing fluid, Kelly says the jet pump works without exposing per-forations in the casing wall to water.

For Ember—whose wells typically produce CBM and commingled gas from about 20 different zones, often over 300 vertical metres—the differ-ence is meaningful. “Any amount of imbibement or loss of fluid into these zones inhibits production in a very big way,” Kelly says.

At the same time, he also noticed some bounce-back in production. “Given enough time, we do seem to get back to where our original decline is, but that’s the other concern: there may be damage taking place that we can’t quantify at this point.”

In scenarios where sand rather than fluid is the problem, the JetPak can also assist. In sand-jetting mode, however, fluid is pumped down from surface through both conduits at once. Where a sand bridge has formed the JetPak uses its jet pump to blast it away. Pumping is then restarted, and fluid and sand are drawn out of the well.

Winkler says a variation of Quantum’s JetPak tech-nology, the JetVak, can be used on deviated and horizontal wellbores to recover fracturing sand or drilling fluid. ■

↑pump or jet

To pump, a CT unit sends the JetPak system

to depth. A pressure truck pumps fluid into

one side of the FLATpak string, which passes

through the pump creating a Venturi effect,

and the negative pressure allows the wellbore

fluid to enter the pump and up to surface in the

other side of the string. Or, fluid can be pumped

down both sides of the FLATpak for jetting.

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Expro Group Canada Inc.advertorial

Page 30462063-78


Page 31462063-78

Expro Group Canada Inc.full page

technologyprofile

Expro’s Canada operations cover both onshore and offshore operations and its investment and track record in developing technology means that the company is a major player in the oil and gas industry.

Expro is one of the market leaders in providing a complete solution for all customers’ well integrity needs using a combination of calipers, logging tools and downhole video cameras. All of these services can be deployed on electric line or slickline to ensure the customer is offered the maximum versatility.

Expro’s Calgary operations have an emphasis on downhole video in vertical and horizontally completed oil and gas wells.

The range of downhole video camera systems offer operators a cost effective way to ’see’ downhole problems rather than inferring them or just plain guessing. Downhole video is a proven technology and more than 5,000 downhole video surveys have been run in a wide range of oil and gas well conditions.

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Expro’s market leadership in downhole video is based on technology and service. Our operators are skilled at well preparation to ensure the greatest chance of successful pictures. Patented lighthead design,

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view the pipe wall on the same trip in the well. By alternating the power sent to the tool, the video operator can switch between cameras to rotate the camera to get a circumferential view of the pipe or look ahead.

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Sanjel Corporationfull page

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Committed To Helping Our

Clients Make the Most of Their

Production

With nearly three decades of delivering on our mission to provide clients with exceptional value through superior operations and innovative solutions, Sanjel is your fracturing specialist with:

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As new technologies used to drive North America’s booming shale gas revolution—horizontal drilling combined with massive multistage hydraulic fracture-stimulation jobs—spread across the continent, gaps in equipment design were bound to arise.

One such gap involves the potentially hazardous refu-elling of the frac pumpers that run continuously, some-times for days, during a frac job. As fracs have grown ever larger and more complex, running into the dozens of stages along the length of a horizontal well, companies have mostly continued to refuel the units manually, an inefficient, unreliable and potentially explosive practice.

When brothers Todd and Scott Van Vliet, co-presidents of Environmental Refuelling Systems Inc. (ERS), witnessed their first large-scale shale gas frac in northeastern British Columbia, they were aghast. They almost immediately began work to design, from the ground up, a safe and efficient alternative—the newly christened Frac Shack.

“The solution actually came out of us trying to do tra-ditional refuelling, the old-style refuelling, up at one of the sites north of Fort Nelson, [B.C.], a couple of years ago. Both my brother and I, when we went up there to see what our guys needed to do, immediately thought, ‘There has to be a better way to do this,’” Todd Van Vliet says.

He had his own vivid description of the practice he sought to replace. “Imagine it is 2 o’clock in the morning and the frac pumpers, maybe 24 on one site, are ham-mering away. These pumpers are about as wide apart as your shoulders, so you have to go sideways in-between them, pulling the fuel hose, which is full of diesel. The pumpers are operating at about 300 degrees Celsius, above your head, operating at about 95 decibels, so you need two levels of hearing protection to be there, and most companies require that refuellers wear a fire suit, so you are sweating, it’s dark and the ground is unsteady.

“And now you have to take the cap off the fuel tank, while you have a flashlight in one hand and the hose nozzle in the other. So you tuck the flashlight under your chin or in your shoulder, and then you want to be careful because those pumpers can move quite violently while they are pumping—you don’t want the fuel splash-ing out. You quickly lift up the cap and jam the fuel nozzle down into the tank.

“Now what you hope is that the fuel nozzle is going to kick out when the fuel gets up to the top, but often it doesn’t because the back pressure in those big tanks isn’t sufficient. So you have got to be watching down inside that fuel tank while you are filling it, and you hope that you don’t overfill it because if you do there is fuel out on the ground. Or if there is any fuel splashed up onto the engine, right by your head, you could start a fire and that fire could burn down the entire frac pad.”

Van Vliet says that in his research, he has not come across a fire actually caused by such refuelling, but he has

Out Of Harm’s Wayfrac Shack removeS human element from riSky refuelling mixBy Maurice Smith

found cases where the method contributed to a fire that started elsewhere, spreading to destroy entire frac spread operations. His company’s brochure features the stark photo of a string of gutted, burned-out pumper units resulting from one such incident. Needless to say, the situation was ripe for someone to provide an alternative.

DesigneD for sAfetyERS’s answer is a modular frac fuel delivery system that automates the process and entirely removes workers from the “hot zone.” The Frac Shack closed fuelling system eliminates atmospheric fuel on the frac pad while ensuring environmental protection during the hot fuelling process.

The Frac Shack, which can feed 10 pumpers at a time, places the operator in a control area behind blast-proof glass. Low-pressure fuel delivery lines snake from the shack to each pumper, negating the need for manual insertion. Each hose is fitted with a patent-pending connector—adaptable to various fuel tank inlet neck sizes—with three built-in components providing the fuel supply, a breather (so the fuel can displace the air inside the tank safely) and a sensor to provide real-time data to the operator.

“Using that connector, the operator can see in real time how much fuel is in each pumper’s tank, deliver however much fuel it needs and turn it off when it’s done, or let it close automatically,” says Van Vliet. “If there is a problem, everything fails closed so no fuel gets delivered unless

↑automated fuel delivery

The Frac Shack's modu-

lar control power shack

and optional 20,000-

litre double-walled fuel

tank remove workers

from the hot zone.

| environmental refuelling Systems (erS) |

Photos: E

nvironmental R

efuelling System

s Inc.


35

it gets manually overridden. It is all done safely by one person in a lighted, heated, air conditioned environment with real-time information to actually base decisions on.”

The Frac Shack was designed “from first principles,” Van Vliet says. “We decided what standards we wanted the system to uphold and then we designed to the standards. Instead of saying, ‘How do we solve the problem,’ we started from the standards and worked back to the prob-lem. It was one of those situations where, once you arrive at the solution based on the standards, it seems obvious. But if you go the other way around you end up with sev-eral Band-Aid solutions and then you have got a problem with your standards.”

In the Horn River Basin in northeastern B.C., Nexen Inc.(one of the largest shale gas players in the area), used the Frac Shack at Dilly Creek. In the third quarter of last year, Nexen completed a 144-frac program on its eight-well pad at an industry-leading pace of 3.5 fracs per day with a 100 per cent frac success rate.

Randy Arkinstall, Nexen Health and Safety Environ-ment (HSE) supervisor, says he was impressed with the technology. “It worked superbly. They have very profes-sional crews and the job was done very well. We felt that it eliminated a lot of risk with our firefighters.”

totAl fuel mAnAgementThe Frac Shack is part of the company’s “complete fuel management philosophy,” says Van Vliet, to provide turnkey fuel logistics that eliminate the headache of having to worry about maintaining uninterrupted sup-plies of fuel, the lifeblood of the oil and gas industry, in remote areas.

The five-year-old company brokers large volumes of fuel from Alberta refineries and maintains fuel depots around the province. Its tanks are hard-wired with tech-

nology that allow ERS to constantly track fuel consump-tion, with satellite, GPS and cellular communications feeding data instantaneously to where it’s needed. The company’s goal is to know where every drop of fuel goes, in real time.

As of the end of 2010, ERS had manufactured three Frac Shacks in Alberta and was gearing up to produce more. “We have been in discussions now with several of the E&P companies and service companies and I expect we will be producing several more of them for the summer frac season,” says Van Vliet. ERS is also in discussions with U.S.–based companies and anticipates moving equipment over the border in the not-too-distant future. ■

one formiDAble cAnADiAn oilpatch pioneer that keeps on pioneering is Packers Plus Energy Services Inc. Its StackFRAC multistage completions technique, coupled with horizontal drilling, opened Saskatchewan’s Bakken light oil resource play when producer Petrobank Energy and Resources Ltd. first agreed to give them a chance less than a decade ago.

What worked in unconventional light oil soon migrated to and proved itself in shale gas basins such as British Columbia’s Montney and Horn River plays. But even as the StackFRAC’s open-hole fracturing system started to take hold—fracking five to eight stages along a lateral—producers were already asking for technology that could generate a denser pattern of stimulations.

“The reservoir models the industry initially relied on were revised as pro-ducers found that the fractures they actually got were anything but the frac-tures they had drawn,” says Dan Themig, president of Packers Plus. “They weren’t these nice flat-looking things that uniformly extend out.”

So Packers Plus launched its StackFRAC HD (high-density) system, which effectively increased the number of stages to 20. Producers almost immedi-ately ran to the higher end of that system’s capabilities and still didn’t see interference between fracs.

“The mobility of gas in some of these plays like the Horn River has [been] shown to be much less than was initially figured,” Themig says. “I recently saw [a major frac service company] present at a conference some new reservoir modelling to fit the Horn River. One of the charts was of the anticipated reservoir pressure change after 15 years on the current frac spacing, and it showed that they expected to still have virgin pressure between fracs.”

What that means is that 15 or 20 fracs are not going to effectively drain the Horn River play. Nor will it effec-tively drain the Marcellus, the Haynesville, Eagle Ford, Cardium or perhaps any other resource play. Tighter spacing may be the key—even much tighter spacing.

“As we get into more complex reservoirs now, what we’re finding is [that] some of these wells require more than 40 stages,” Themig says. “Currently, we even have proposals out for 60 fracs in a well, and we’ve got some companies saying they’ll need to go to 100.”

Bigger, Faster, CheaperaS the induStry trendS to more frac StageS, PackerS PluS reSPondS with QuickfracBy R.P. Stastny

↑fill 'er up

Environmental

Refuelling System's

Frac Shack can safely

and efficiently fill up

to 10 frac pumper

truck tanks at a time.

erS | Packers Plus energy Services

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implicAtionsPackers Plus hasn’t yet released its repeater-port technol-ogy, which it says will have the capability of delivering an extraordinary 100 fracture stages. But it has already rolled out its new QuickFRAC system, capable of doing up to 60 stages.

But even in fracking 40, 60 or more stages, Packers Plus had to figure out how to get the job done faster.

“If 15 fracs aren’t going to do it, you have to consider the business implications of putting many more fracs in the ground. And the first thing you realize is that cemented liner plug-and-perf systems reach an economic limit,” Themig says.

That limit is time. Calfrac Well Services Ltd. recently announced that it performed a large-scale project in the Horn River that resulted in the completion of 144 frac stages in a number of wells in 42 days using a cemented-liner plug-and-perforate completion technique. The point is that cemented well completions take longer than open-hole completions. (Packers Plus frac systems are open-hole.)

“With the shortage of frac equipment, with the num-ber of stages increasing and people now trying to run a few more rigs up, there are too many forces working in the wrong direction,” Themig says.

Packers Plus wants to ease that pressure with Quick-FRAC’s “batch fracturing” technology. QuickFRAC can deliver up to 60 fracture stages downhole while only pumping 15 treatments at surface. By using limited-entry diversion techniques and a proprietary technology, QuickFRAC distributes a single pumping treatment on surface into two to five stages downhole at one time.

Producers are rewarded with potentially increased production. For the operator, pumping time and costs are reduced. In the Horn River, QuickFRAC has demon-strated a hefty 60 per cent reduction in operation time compared to the StackFRAC system.

“Recently, our technical engineers came up with a tech-nical proposal for a producer in the Horn River that had

↖record pace

Using its new QuickFRAC

completion technology,

which allows the frack-

ing of four or five iso-

lated stages in a single

treatment, Packers

Plus managed a record

23-stage slickwater frac

in less than 10 hours.

55 stages,” Themig says. “Theoretically, we could execute 55 stages in a couple of days. If you look at Calfrac’s example of 42 days to get 144 stages, you can do the math.”

Themig says that doing more frac stages may potentially save water and proppant. In the Montney and some other areas, Packers Plus has shown that more stages actually use less fluid on not only a per-stage basis, but overall.

He says the industry may be coming to the realization, recently echoed by a Schlumberger Limited executive discussing its Smith International merger, that the sledgehammer approach to hydraulic fracturing isn’t the way of the future.

re-entryIf a shale gas producer sees re-stimulation in its future, current wisdom maintains that it needs to be doing cement-lined plug-and-perf completions. That, however, may not be the case.

“There’s a lot of wrong information out there,” Themig says. “Devon [Energy Corporation] is now attempting to refrac some of its Barnett wells and is finding it doesn’t have any mechanical means to isolate the stages. So they’re ending up with kind of a Hail Mary frac.”

Cemented liners with hundreds of perforations from end to end, not sur-prisingly, are difficult to refrac. Open-hole, on the other hand, Themig claims, accommodates re-fracking and is actually the only technology that does.

So Packers Plus is in the process of developing two new tools to capture the full life cycle of the well stimulation business.

“One tool is a port system that allows you to go back and set everything up again years later like the original frac,” Themig says. “The other is a series of re-frac tools to individually re-frac intervals.” Packers Plus expects to release those technologies in the next few months.

In Themig’s vision of the future, the sun shines brightly over Packers Plus. As producers move to much more densely staged fracking, cement-cased plug-and-perf completions will struggle to compete with the efficiencies of QuickFRAC open-hole frac completions. Packers Plus’ market position will also grow stronger as the industry recognizes the advantages of open-hole recompletions.

“Certainly in the Montney and in the Horn River we’ve seen step-rate changes in both IPs [initial production rates] and in decline curves,” Themig says. “We think ultimate recoveries are going to change in favour of open-hole systems somewhere in the range of 25 per cent to 70 per cent as opposed to cemented.” ■

| Packers Plus energy Services |

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NCS Oilfield Services Canada Inc.full page

New Multistage UnlimitedTM frac-isolation system

All the fracs you need, exactly where you want them, in a fast, nonstop completion sequence

No actuating balls, no pumpdown plugs, no perforating

THE MULTISTAGE UNLIMITED SYSTEM delivers all the pinpoint fracs you need to optimize well production, yet thesystem is so simple and the operation is so fast that it costsless than methods that limit your completion options.

Only 5 minutes between fracsThe system requires no pump-down plugs, actuating balls,or perforating tools. Here’s how simple it is:

• Run the casing with a Multistage Unlimited sliding sleeve in the string wherever you plan to frac. You can either cement or run swellable packers to seal the annulus.

• Run the Multistage Unlimited frac-isolation assembly oncoiled tubing to the lowest sliding sleeve.

• Set the resettable bridge plug inside the sliding sleeve andshift the sleeve with string weight and annular pressure.

• With the bridge plug sealing below the open frac ports,pump the frac down the casing/coiled tubing annulus.Monitor frac pressure at the surface via the coiled tubing.

• When the frac is away, pull up to open the equalizing valveand unset the bridge plug. Move to the next sleeve and repeat. In about 5 minutes, you’re ready to frac again.

Add stages on the flyYou can add a stage where there is no sliding sleeve by usingthe integral jet-perforating sub. The added stage is frac-readyin less than 40 minutes.

Full-open, production-ready wellboreWhen the frac-isolation assembly is pulled from the well afterthe last frac, you have an unrestricted wellbore all the way tothe toe, with nothing to retrieve or drill out.

Uses 10% to 20% less waterThe Multistage Unlimited system cuts water requirements by eliminating pump-down components, by circulating lead-ing-edge fluids down instead of bullheading them, and by re-ducing casing volume by the volume of the coiled tubing.

Ultra-reliable operationThe Multistage Unlimited system is easier to operate andmore reliable than any other multistage equipment:

• All-mechanical operation. An automatic j-slot sets and unsets the bridge plug with up-and-down string motion.

• The resettable bridge plug has been used for more than10,000 stages and has been cycled more than 40 timesduring a single completion operation.

• With its sand-friendly design, the system is impervious tomalfunctions caused by contamination.

• Sand-outs can be quickly reversed out.

The Multistage Unlimited system is currently available for 41⁄2-in (114 mm) and 51⁄2-in (140 mm) casing. Call us or visit ourwebsite for more information.

www.ncsfrac.com 409.925.7160 (U.S. Sales) 403.816.1011 (Canada Sales) 403.720.3236 (Central Dispatch) [email protected]

©2011, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited and “Leave nothing behind.” are trademarks of NCS Energy Services, Inc. Patents pending.

Leave nothing behind.TM

Coiled tubing

Frac ports

Equalizing valveStandby jet perforating sub

Resettable bridge plugSliding sleeve


38

functional and disclosable, providing comparable technical performance to conventional additive systems.” The OpenFRAC products can be used for shale and tight gas formations, the company says.

OpenFRAC SW is for slickwater fracking, where drag reduction and less-complex fluid systems are a pri-ority. OpenFRAC WF fluid is a linear gel variant, providing improved bal-ance between “taking care to provide disclosure and protecting our intel-lectual property,” Lima says.

Lima describes OpenFRAC as “a step-change. It’s designed to avoid use of priority pollutants and national primary drinking water contaminants, as defined by federal regulation.” The two categories are covered by U.S. Environmental Protection Agency regulation.

In developing the product line and providing a list of fluid ingredients to clients, the company sought to strike a balance between “taking care to provide disclosure and protecting our intellectual property,” says Lima.

Noting that practically all prepared foods must include ingredients on their labels, he says that, even with the list of ingredients, duplicating the actual OpenFRAC products “would be very difficult to reverse engineer.”

slicKwAter systemSlickwater frac liquids are standard fare in shale, tight sands and other low-permeability formations. “In conventional oil wells in high- permeability, high-porosity forma-tions, you want to prevent the fluid from leaking off, so gel is used to increase viscosity. Now, with shale, it’s the opposite. You add friction reducers to make the water more

the oil AnD gas industry in North America has been responding to increasing pressure to demonstrate to legislators and the public alike that fracking fluids, injected deep under-ground, pose little or no threat to the water table or other ecosystems.

Two key developments largely account for the pressure on industry. One is the vastly expanded role of fracking. Today, according to a July 2010 primer on the role of hydraulic fracturing in U.S. gas production on the American Petroleum Institute’s website, “Hydraulic fracturing is so important that without it, we would lose 45 per cent of domestic natural gas production and 17 per cent of our oil production within five years.”

The second development can be expressed in one word: Marcellus. Described by experts as a super-giant, the gas play is located in the densely populated U.S. northeast, where, among other things, local residents understandably want to ensure that the region’s vital watersheds (which cities like New York depend on) remain a safe source of potable water. As the play loomed increasingly large, a robust combination of media out-lets, environmentalists, shareholder activists and Ivy League university professors with impeccable credentials

Green FrackingaS the frac debate rollS on, Service firmS develoP cleaner fracking ProductS

raised the alarm about the amount of oil and gas activity and the risks atten-dant on rapid development. Much, but by no means all, of the resulting debate has focused on fracking fluids.

The upshot is that companies in the Marcellus have been facing mas-sive regulatory uncertainty, concerns of shareholders and others about the level of business and environmental risk, demands for disclosure of frack-ing ingredients and the tantalizing prize of a super-giant gas field next door to some of the biggest markets in the world. Tougher legislation and clearer rules for the industry—at both state and federal levels—are widely expected. Meanwhile, some manufac-turers and suppliers have concluded that product rollouts of non-toxic fracking additives and disclosure of ingredients are a good place to start addressing some of the issues.

And disclosure of the ingredients does not necessarily entail surrender-ing proprietary information to the competition, according to Joe Lima, Schlumberger’s product champion for OpenFRAC, a new group of fracturing fluid additive systems. All OpenFRAC products are water-based.

On July 30, 2010, the petroleum services giant announced the new product line, describing it as “fully

Composition of OpenFRAC SW FluidComponent Mass, %Water

99.82Sodium chloride <0.05Magnesium chloride <0.04Amphoteric alkyl amine <0.03Calcium magnesium sodium phosphate <0.021Propan-2-ol

<0.015Acrylamide copolymer <0.015Ammonium sulfate <0.01Sodium sulfate <0.004Potassium chloride <0.002Urea <0.001Hypochlorous acid <0.001Noncrystalline silica <0.0005

Schlumberger | trican well Service | Sanjel

↑ingredient list

With Schlumberger's

OpenFRAC hydraulic

fracturing additive

system, operators

receive full disclosure

of additive compo-

nents, disclosure

similar to that used

in the food industry.

←safer slickwater

OpenFRAC formulation

systems are used for

slickwater fracking and

have the advantage

of fully disclosed fluid

additives, and can be

used with produced

or recycled water.

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slippery,” says Dave Browne, corpo-rate director of technology at Trican Well Service Ltd.

Friction reducers enable a very rapid, laminar flow, says Browne, reducing horsepower requirements. In the past, he says, it was not neces-sarily the polymer friction reducer that was toxic, but sometimes the carrier fluid was, if, for example, die-sel fuel was used.

With the stated goal of eliminating contamination risks to formations, aquifers and product handlers, Trican recently unveiled its EcoClean-GSW slickwater system, which includes additives the company describes as “non-toxic, biodegradable and non-bioaccumulating, individually or in combination, and each will pass the stringent Microtox test. A product or chemical that passes the Microtox test is considered safe for drinking water, and will often meet the criteria set out in other regulatory examinations.” In the past, friction reducers were non-biodegradable, says Browne.

In late July, Trican announced a minimum two-year contract to pro-vide fracking services to “a major U.S. customer operating in the Marcellus shale play.”

Industry response to the new suite of slickwater products has been favour-able, overall, with some EcoClean products already being used in B.C.’s Horn River Basin and in Texas. “Some

←clean job

Trican's EcoClean-GSW

slickwater system is

designed to eliminate

contamination risks

to geological forma-

tions, aquifers and

product handlers.

[companies] are happy with what they are using now and want to do their own testing first. But some U.S. customers have said they are going to switch to it. We also anticipate using it in the Marcellus,” says Browne.

Among the additives that comprise the EcoClean-GSW suite, GFR-1 is a salt-tolerant friction reducer that includes a non-toxic carrier fluid, and is designed to improve fluid flow in slickwater fracking. GBO-1 is an oxidizing agent that breaks down friction reducers and aqueous gels downhole to facilitate flowback of frac fluid. The biodegradable additive has “very low toxicity,” according to Trican, and has a delayed breaking action, so it won’t affect the friction reducer’s performance. The suite also includes a biodegradable scale inhibitor, a biodegradable biocide for downhole sulphur reducing bacteria, a chloride-free clay stabilizer and a biodegradable flowback enhancer.

“Some of these additives are going to cost a little more, but we’ve been pleasantly surprised that there’s not a great increase,” says Browne.

new friction reDucerNeil Warrender, vice-president of technology at Sanjel Corporation, the largest privately held oilfield services company in Canada, says introduc-ing enviro-friendly fracking fluids and additives is not without its chal-lenges. “In the short term, in some cases, there could be higher costs and lower efficiency with some products. But, remember, we’re trying to shoe-horn new products into an existing matrix of products.”

The company last year introduced its ENVIROjel fracturing system, designed to meet requirements set by Alberta’s Energy Resources Conserva-tion Board in Directive 27. The direc-tive sets standards for frac fluids that may come in contact with aquifers or other sources of drinking water.

“ENVIROjel could be used in shale, but the cost would be high. It’s more for shallow conventional fracking where there is concern about ground-water. It could be used in shale where there is a low-volume requirement,” says Warrender.

The water-based fracturing system uses a fast hydrating hydroxyethyl cellulose polymer suspended in an ultra-clear mineral oil. Its rapid hydration enables on-the-fly mixing, saving time and cutting costs, and is foamed with nitrogen, providing

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ncs energy services Inc. has taken its proprietary Mongoose System frac tool and Mongoose Jet Frac System up another notch when it comes to delivering fast, effective fracture stimulation, without stage limits, with the aid of coiled tubing.

The company’s new Multistage Unlimited stage-isolation system uses sliding frac sleeves that are operated in conjunction with the Mongoose tool, says Don Getzlaf, who with long-time business associate Marty Stromquist is a principal in NCS’s Canadian operation.

The assembly is run on coiled tub-ing to the lowest sliding sleeve. The Mongoose resettable bridge plug is then set inside the sliding sleeve and the sleeve is shifted with string weight and annular pressure. With the bridge plug sealing the well below the open frac ports, frac fluid is pumped down the casing/coiled tub-ing annulus. Real-time bottomhole frac pressure is monitored at the sur-face via the coiled tubing.

Once the frac is away, the coiled tubing is pulled up to open the equalizing valve and unset the bridge plug. Then it’s a simple matter of moving to the next sleeve and open-ing it, which takes six to nine min-utes. There is no limit on the number of potential frac sleeves; so far the record is 53 in one well. “Since we watch the ‘dead string’ pressure we can interrupt net pressure in the fracture and in turn know what the formation is accepting and may not accept, reducing unplanned sand offs,” says Getzlaf.

A big advantage of the Mongoose system is that it can still circulate cleanly after a screenout (when solids such as proppant produce bridging across perforations), allowing NCS to be significantly more aggressive on the sand concentrations.

When the stage-isolation assembly is pulled from the well after the last frac, the well has an unrestricted

No LimitsmongooSe advancement offerS unlimited PinPoint fracSBy Elsie Ross

enhanced proppant-carrying capabili-ties and improved fluid recovery.

New products are tested with fresh water but, Warrender says, “You can’t assume the same result with pro-duced water, where salinity, density, pH, acidity etc, are different.”

wAter issuesDwight Bobier, vice-president of tech-nical services at Calfrac Well Services Ltd., makes a similar point. “Each time you change the water, you affect or alter the effect of the frac fluid.”

The development of fracking fluids and additives that work well with brines and mixed brines is likely to be an ongoing process for Calfrac and others in the field. “Slickwater frack-ing uses a lot of water, so recycling and reuse of water is where most companies are headed. In shale, uti-lizing all the water that comes out of the well is important,” says Bobier.

Noting that sea water contains three to five per cent salts, he says that produced water in the Marcellus can have as much as 20 per cent salts. “What works in fresh water may not

work as well in 20 per cent salt water. The friction reducer that will work with very briny water will probably be the most expensive.”

Bobier says some industry players in the Horn River shale are using water from the Debolt formation. There, both the government of B.C. and companies operating in the province’s northeast appear to be adopting a suc-cessful, proactive approach to water issues in the Horn River shale play. The BC Oil and Gas Commission has laid out some of the issues and solu-tions in a report released last August, as the regulator wants to set some ground rules and avoid conflict.

A new Oil and Gas Activities Act will expand the commission’s power to man-age water withdrawals and provide for monitoring, water testing, and reporting of drilling and fracking programs.

In the United States, a 65-page report, released July 8, 2010, and titled Frac Attack: Risks, Hype, and Financial Reality of Hydraulic Fractur-ing in the Shale Plays, predicts tougher legislation that could raise costs slightly but that the shale sector will morph from trial-and-error to a more institutionalized affair and that “new industries are already growing up in shale territories to treat waste water and replace some chemicals with greener ingredients.” ■

↙lab to field

Sanjel's new fracking

fluids are developed

at the company's

Calgary lab.

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ited system requires about one-third of the horsepower, which means fewer trucks on a lease at one time. “We will be on location a little bit longer, but it takes less energy on a per frac basis,” says Getzlaf.

For an operator, having some degree of confidence in the number of fractures created, and their dimensions and locations can be invaluable in the long-term man-agement of the reservoir.

The new system also uses about 10–15 per cent less water than other fracture methods. “With coiled tubing in the hole, we can circulate the fluids down to the bot-tom and frac so we can get the leading edges really close to the formation,” he says. The coiled tubing in the hole also displaces the volume of water that would otherwise be required. “In some cases we will reverse circulate the pad and as much as 5,000 kilograms of the proppant into the annulus before shutting in the tubing and injecting into the formation, completely eliminating any bull-headed pre-pad fluids,” says Stromquist.

The concept of the sleeve came into fruition in October 2010 and NCS shifted the first sleeves in late November. Since then, the demand for the technology has been coming from completions engineers who want to get in more fracs in a day.

At Red Earth in north-central Alberta, the Multistage Unlimited system was able to improve the output of a frac crew from three stages per day to a routine placing 10 fractures with time left over to have the frac equip-ment serviced and the crew back to base and off the clock within their 12-hour shift. “The technology is getting a great deal of interest as operators consider the impact on how much work they can execute with today’s limited access to frac crews,” says Getzlaf.

So far this year, 800 sleeves have been installed in 60 wells, including 20 stages completed in a 10-hour period and a 30-stage horizontal well completed in three days (including one day of preparation). The system is currently available in all weights for 4 1⁄2 inch and 5 1⁄2 inch casing.

Last year, NCS did approximately 10,000 fracture stages with the Mongoose Jet-Frac System at an average of 12–13 fracs per well, improving the performance of some 1,000 wellbores. ■

wellbore all the way to the toe with nothing to retrieve or drill out of.

The Multistage Unlimited system has a special profile in the sleeve which is located exclusively with the Mongoose, says Getzlaf. “That sets the tool exactly where we want it and then we pressure test it and shift the sleeve down,” he says. “As the sleeve shifts down, the locating profile disap-pears so you’ve got positive proof that the sleeve has shifted and that you have direct access to the formation.”

An additional benefit stemming from the sleeve design is the enhanced energy available for initial formation breakdown. As the fluid column is accelerated with the shifting of the sleeve, it creates a water hammer effect that often exceeds the formation breakdown pressure. The effect is similar to that of abruptly shutting off a water tap while there’s still water movement within it. The energy is instantaneously converted to pressure as the fluid decelerates from the sleeve, shifting velocity.

Initially, it was thought that in cemented casing applica-tions there could be high breakdown pressure observed, but NCS found that shifting the sleeve with string weight and annular pressure provides extremely good access to the rock, says Getzlaf. “One of the reasons for that imme-diate formation breakdown is this water hammer effect,” he says. “We just shut [off] the tap very fast and the water has to stop and it has to go someplace and it goes out into the rock formation.” The company believes this to be of significant potential value in assuring fracture initiation, and has patents pending on the process.

Because the Mongoose assembly is an integral part of the Multistage Unlimited process, if a sleeve for any reason doesn’t get access to the formation, it can still be jet-cut and fracked. Stages can also be added on the fly even if there is no sliding sleeve with the jet-perforating sub having the targeted interval frac-ready in about 30 minutes. “The pacesetter well for multistage fracs with the Mongoose tool is 44 stage fracs completed on a single trip into the well with coiled tubing,” says Stromquist.

Compared to the plug-and-perf technology that is standard in British Columbia, the NCS system has a smaller footprint. Because only one interval at a time is fracked, rather than three or four, the Multistage Unlim-

←open and shut

Multistage Unlimited

stage-isolation system

consists of sliding

sleeves that run as part

of the completion string

and an isolation assem-

bly that runs on coiled

tubing to shift the slid-

ing sleeves, open the

frac ports and to seal

the casing below the

ports during fracturing.

→frac and perf

The Mongoose frac system allows

multiple zone frac treaments.

The Jet Frac system allows for

multi-zone perforating, isola-

tion and frac stimulation

| ncS energy Services |

Jet perforating sub Equalizing valve Resettable bridge plug Sleeve locator latched

Coiled tubing Frac ports closed Sliding sleeve

Frac ports open Sliding sleeve shifted Sleeve locator receptable closed

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in recent yeArs, producers need-ing fracturing data on wells drilled in western Canada have been challenged, having never had a single, comprehen-sive database to draw on.

That changed last fall, with the launch of a service that offers a wide range of fracturing data from thou-sands of wells in the Western Cana-dian Sedimentary Basin (WCSB), most of them drilled in Alberta, British Columbia and Saskatchewan resource plays in the past five years.

While producers have long had access to drilling, geological and well data from such sources as the Energy Resources Conservation Board, frac-turing data, especially on recent wells, has been harder to come by.

Jointly developed by Canadian Discovery Ltd. and Introspec Energy Group Inc., the Western Canada Frac Database (WCFD) offers the online user a broad cross-section of data. In addition to well-identifying details, specifics are available on individual frac jobs, including depths, configu-ration, proppant amounts, pumping details, pressures and cost data.

A chief aim of WCFD’s online service is to ease the search for analogous wells, plays or prospects, where data from fracturing and completion strategies can be transferred to related prospect areas or basins to more effectively achieve maxi-mum production and reserves, according to Canadian Discovery.

The companies bill their database as “searchable, reliable, comprehensive and analysis-ready.” As for the tool’s usefulness in searching fracturing data, one of its developers relates it to the resource plays proliferating across North America.

“These plays are expanding much quicker than ever envisioned,” says Pete Singbeil, Introspec president, at the Calgary rollout of the WCFD online service last fall. He estimated that unconventional oil and gas now make up about 10 per cent of world production. The figure is growing and, to some degree, offsetting declining conventional volumes.

Under One Roofcanadian fracturing databaSe Service goeS onlineBy James Mahony

“You’re going to see more natural gas around the world, and probably more tight oil, as it’s explored for and found. As a result, [resource plays] are here to stay,” he says.

As horizontal drilling and multi-stage fracturing continue to expand, Singbeil points out that drilling costs, once the biggest expense for produc-ers, now often takes second place behind completion costs, including fracturing. In the past five years, pro-ducers in western Canada have sunk $3 billion to $4 billion into comple-tions alone, he says.

“We’re in a learning curve, and that’s why I believe this database is so important,” he says. With the new database, users can search well costs and time factors. Data can also be imported into other software to cre-ate spreadsheets. Much data can be viewed graphically, and the database includes bookmarked links to some original data sources.

The frac database is searchable using different variables, and is described as reliable and compre-hensive, since all current western Canadian resource plays are included, according to Heather McCrank, a managing director of Canadian Discovery.

Citing the three years from July 2007 to July 2010, McCrank noted that the rising number of horizontal wells drilled as resource plays have multiplied in Western Canada. Dur-ing that period, 147 horizontal wells were drilled in the Cardium, 207 were sunk in the Viking and 647 were drilled in the Montney.

In terms of access, the online WCFD database can be accessed using any Internet browser, regardless of the user’s operating system—be it Micro-soft Windows, Apple or independent Linux. The database is updated daily, the company says.

stress AnAlysisAlso last fall, Canadian Discovery released an earlier study by Rakhit Petroleum Consulting Ltd. and BJ

| canadian discovery |

←data consolidation

Western Canada Frac

Database can present

such information as

average frac spacing

versus fluid rate charts

and stages graphing.

Services Company. Kaush Rakhit, Canadian Discovery president, says the study, being marketed separately from the online WCFD, examined stress analysis in Tertiary, Cretaceous, Jurassic and Triassic reservoirs in central Alberta.

The study looked at stress patterns in the WCSB, after analyzing over 15,000 fracture completions done in an area from Alberta townships 25–80, and ranges one, west of the Fourth Meridian to 13, west of the Sixth Meridian. The study compiled the largest frac pressure database in the world, Rakhit says. From that base, engineers estimated minimum principal horizontal stress using various pressure data.

A key theme of the stress study is that the task of finding unconventional gas often becomes a hunt for permeability. The study highlights the relationship between rock stress and permeability, showing that, in the Mannville coals, for example, as stress rises beyond a certain point, producing gas from the coal becomes more difficult.

The study also relates rock stress to rate of penetration (ROP). Where stress is high, drillers tend to get lower ROP, whereas when stress is low, ROP tends to improve. The main topics of the study include minimum, principal horizontal stress and stress-gradient maps for 15 geological units ranging from the Triassic to the Tertiary periods. ■

Images: C

anadian Discovery Ltd.


43

Beyond Dots In A Boxthe big PlayerS in the develoPment of microSeiSmic monitoring are now focuSing on interPreting the dataBy R.P. Stastny

At trADe shows just five years ago, Shan Jhamandas spent most of his time explaining what micro-seismic monitoring is. Today, the marketing manager of Engineering Seismology Group (ESG) Solutions, a leading microseismic provider based in Kingston, Ont., finds he’s mostly talking about what makes his com-pany different from the competition, what’s new in microseismics and where the technology is heading.

“That’s largely due to the rise of shale gas plays,” he says. “Microseis-mics is really a great science for pro-viding feedback on fractures in these reservoirs and helping to optimize shale gas development.”

Another driver is the oilsands. Since ESG first put microseismic to work at Shell Canada Limited’s Peace River cyclic steam stimulation project in 2002, it has developed a strong steaming group. Further branching out into the monitoring of depleted conventional reservoirs has rounded out ESG’s expertise.

rivAlry“We’re in the process of finalizing what will be the largest permanent downhole microseismic monitoring program in the world,” Jhamandas says. “It’s in [the Mideast sultanate of] Oman. We have about 26 monitoring wells monitoring in two fields, so it’s complete field-wide monitoring.”

ESG has also just completed a record-setting frac-monitoring micro-seismic job in the Horn River Basin for Nexen Inc., monitoring 143 fracture stages over 43 days. But don’t tell that to Peter Duncan, founder and presi-dent of Houston-based MicroSeismic, Inc., because that will spur him to tell you about his company’s microseis-mic program south of the border.

“We actually put in a permanent array on the Whiting Sanish Field in North Dakota in the Williston basin, which we turned on March 1 last year and [which] has been recording data 24-7. We have a 152-square-mile permanent array in that field that’s recorded an average eight wells per month and an average of 25 stages per well, so I think we have surpassed—at least in stage count, and certainly by number of hours of recording—ESG’s numbers,” he says.

You’ll have to forgive Duncan’s one-upmanship, but there’s a ker-fuffle going on between downhole and surface microseismic providers. Duncan’s a surface guy. Jhamandas is mostly a downhole guy. Both are jockeying for the advantage.

As in most debates with rapidly evolving technology, the answer is all but clear. The common perception is that downhole monitoring is more accurate, but that surface monitor-ing can be more cost-effective when doing field-wide monitoring.

The surface guys are passionate about correcting industry views on sur-face seismic accuracy—or the lack of it.

“It’s a common perception that downhole microseismic is more accu-rate,” Duncan says. “If you’re moni-toring within a few hundred feet, say up to 1,000 feet, of a monitoring

eSg Solutions | microSeismic

↗micro data collection

ESG's downhole micro-

seismic monitoring

has application for frac

mapping and to long-

term reservoir map-

ping. ESG's wireline

truck on location at a

mircroseismic collec-

tion project (top right).

well, the downhole data are likely to have better positioning accuracy than surface—but not always, as Mother Nature can be tricky. Beyond that, for reasonable signal-to-noise condi-tions, surface monitoring is every bit as accurate.”

benefitsWhat both providers agree on is the long list of benefits and applications for microseismic monitoring, from frac mapping to long-term reservoir monitoring.

Microseismics can help detect a bad cement job that’s allowing fluids to run up behind pipe. Or identify a fault that’s become a thief zone, stealing proppant and fluid instead of cracking rock. Or if there’s an aquifer below the target, operators can watch the progress in real time, push the limits, and harvest all the gas and not water out the well.

Microseismic also allows operators to understand the length, width and height of a frac. Knowing this can inform the placement of the next well.

In the oilsands, microseismic is an important tool for monitoring cap-rock integrity, but it also has value in understanding where the steam is going, identifying how the reservoir is responding to steaming and identi-fying potential leakage pathways.

Microseismic also has limitations, the main one being that in fracture stimulations, it monitors the fluid, not the proppant. It can see the fluid frac-turing rock but not the sand that goes in after to hold open the fractures.

“Microseismic is a tremendously valuable tool in determining what the fracs look like,” says Dan Themig, president of Packers Plus Energy Services Inc., a pioneer of multistage fracture systems. “But you have to have a really clear understanding that you’re looking at fluid moving out and not proppant. I think if, as an industry, we could ever get to where we could see how far the sand is mov-ing into the formation, the benefits would be multiplied tremendously.”

Duncan essentially agrees. Moni-toring the movement of proppant with microseismic is a fertile area of research, which he believes will yield new capabilities soon.

rise of surfAce monitoringIn an oil and gas application, the average microseismic event gives off very little energy, about the same as dropping a can of pop from the

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44

futureBoth surface and downhole micro-seismic providers say the quality of monitoring equipment will continue to evolve and costs will decline. But that progress will be linear compared to the revolution underway in the interpretation of microseismic data.

“There are opportunities for mak-ing real strides in the interpretation of data, pushing the technology

towards more accurate, more pre-dictive models. So far, microseismic is only at the beginning of this journey,” Duncan says. By replacing the data “dots with little fracture planes that have a sense of motion to them,” for example, a lot more information about the reservoir and the geology can be plugged into the reservoir simulator and linked with all of the other seismic data.

Jhamandas talks a lot about inte-gration, seeing microseismic as just one piece of the puzzle, and inte-grating it with engineering and geo-mechanical modelling to create a more robust picture of how frac-tures develop, and how the reservoir is behaving.

“How is the rock failing? Is it an isotropic volumetric failure? Where is it going to create a channel of permeability?” Jhamandas says. “That’s important for us to iden-tify as opposed to just identifying a shearing event, which is a rock failure but isn’t necessarily going to create a channel of enhanced permeability, by which the gas can flow to the well and provide increased production.” ■

eSg Solutions | microSeismic

height of a person’s hip. So the tech-nology developed around the idea of putting the geophone downhole, closer to the events.

“Makes sense, right?” Duncan says. “The problem is, if you think about triangulation, you need to have points all around the event as it occurs so that you can triangulate in. But it’s expensive to drill a bunch of monitoring wells, so you typi-cally have one well with a bunch of geophones on a long string. It’s not quite as good. I guess you’d call it ‘bi-angulation.’”

Duncan’s background is in more conventional 3-D seismic, which relies on essentially the same equip-ment and processes. It’s the sum of all the geophones laid out on the surface that amplifies microseismic events sufficiently to map.

In many cases, surface monitoring can overcome the limitations of down-hole monitoring. “I’ve got some clients that monitor 100 per cent of their wells,” Duncan says. “By putting a per-manent array over the entire field, I can drive the cost down from what used to be $20,000 or $30,000 per frac stage to $2,000 or $3,000 per frac stage.”

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MicroSeismic's surface

acquisition offers the

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Illustration: MicroS

esimic Inc.

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Data/software/communicationstech guide

45

Data/software/ communications

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46

Cost Control is essential for oil and gas producers operating in the high-cost Western Canadian Sedimentary Basin, which has now become even more vital for gas pro-ducers facing persistently weak prices with no sign of relief on the horizon.

Only the strong survive, the old saying goes, but for companies drill-ing for oil and gas in the basin, the mantra is that the lowest cost opera-tors will remain standing. While many companies have focused exclusively on analyzing and reduc-ing operating costs, a more powerful approach is to maximize production volumes from existing assets, thereby reducing per-unit operating costs and maximizing cash flow, say propo-nents of a new piece of software that helps producers pinpoint where they are losing money.

David Anderson, the president of Canadian Forest Oil Ltd.(which has been working with Calgary-based Forum Energy Services Ltd. for the past two years on developing soft-ware to improve volume awareness), recognized the need for a better, more effective way to manage the company when he returned to head the organization in 2008 after a stint away. The key was to allow all employees, from management to engineers and field operators, to have key information at their fingertips.

“When David originally described his vision to us, we quite candidly responded: ‘We’re not sure if what you want is achievable,’” recalls Marcel Preteau, Forum’s president.

Undaunted, his team starting build-ing the first version and components of what’s become known as The Bridge, a name that highlights the linking of production and sales infor-mation across the entire organization.

The technology allows Canadian Forest, a subsidiary of Denver-based Forest Oil Corporation, to track pro-duction, examine variances and tackle small problems immediately before

Defence To Offenceforum’s software helps canaDian forest stay on top of its gameBy Richard Macedo

they become painful headaches. Anderson estimates the company has had a five per cent increase in produc-tion volumes attributed to the software.

“A huge challenge is convincing the industry that what we’re doing is possible,” Preteau says, explain-ing that, historically, the oil and gas industry has focused on exploration, exploitation and capital deploy-ment. “After they make the decision to spend their capital, number two is making sure you get a maximum return by optimizing production. But historically the industry has not paid enough attention to tracking and fully leveraging daily production and sales volume data.”

Information that’s been collected has traditionally not been packaged and delivered in a way an engineer or company executive can examine quickly and easily to make immedi-ate, well-informed decisions.

“There are massive volumes of data,” Preteau says. “If you look at all the individual volumetric-based data points that are used by [Canadian Forest] over the course of a month, that’s five mil-lion pieces of data a month. Managing that in a coherent way and making it quick and easy for people to access was a remarkable challenge.”

Forum says little has changed over the past decade in the way companies track, assemble, and analyze daily production and sales

External Prod Accounting

FinancialAccounting

The interface allows The Bridge to import

field data from any system

Wellhead volumes (WI%)Gathered gas allocationSales gas yieldsField condensate yieldNGL component-level yieldsSales oil deliveriesRest-of-month forecastingAuto-fill for missing dataCrown volumes (all products)Crown royalty exemption depletionFreehold and override volumesProduction and sales volume trendsLost production and sales volumesValuation of all productsAccounting actualsForward month forecastingFacility outage adjustmentSummarization, for reporting

DATA INPUTPrimary focus on field data already in-house: input and balanced before end-of-day

DATA OUTPUT Reports, graphs and

Excel extractions available first thing every morning

CALCULATION ENGINE AND DATA WAREHOUSE

Automated overnight (or on demand) process to generate daily and

monthly results sets

Your fielddata capture

Economics

Your producing oil and gas fields

volume results, unlike other indus-tries that have invested heavily in leveraging information technology. Instead of daily information, many oil and gas producers are left with manually compiled once-a-week or once-a-month summary snapshots that come too late to ensure a quick response to operational problems.

“Ultimately, from the highest busi-ness level, this is about making more money,” Preteau adds. “It’s about knowing where you are at every day. It’s about keeping an eye on small problems, being aware of them and making sure people respond before they become big problems. When a company is delivering a product to a plant for processing, it is making sure that they are getting all of the prod-ucts to which they are entitled.”

The Bridge gives a company the ability to know where production problems are occurring and the costs in terms of lost sales. Staff is able to view the corporate portfolio and drill down into individual properties, wells and the downtime reasons in seconds. This helps engineers and operations management ensure that staff is aware and focused on specific problems that are costing the com-pany the most money.

The software targets daily produc-tion optimization and includes down-time and lost production tracking, variance reporting, sales monitoring,

| forum energy services |

↑how The Bridge works

The Bridge highlights

the linking of pro-

duction and sales

information across the

entire organization.


47

the average development phase of a large oil and gas project typically comprises 18 per cent of the project’s life cycle, according to cost estimating and engineering firm Grantech Engineering International Ltd., citing industry studies.

Cost estimating is a critical time for proposed oil and gas projects. Underestimating, resulting in cost over-runs, can punish economics. On the other hand, early overestimates can cause decision makers to abandon what could become solid, money-making projects.

Grantech introduced its proprietary Oil & Gas Advisor (O&G Advisor) software a few years ago to provide more accurate high-level cost estimates in a shorter amount of time and the results have been positive, according to software users. The software is currently being used exclusively by Grantech engineers and cost estimators in consultation with their clients.

TransCanada Corporation has used estimates from O&G Advisor in the past for feasibility studies the com-pany has been doing for clients that are investigating the use of its marine compressed natural gas (CNG) transport technology. There have been benefits, notes Greg Cano, director, CNG business development with TransCanada.

“It provided a check estimate for components that we had developed from historical curves and rules of thumb for order of magnitude cost estimates at the feasibility phase,” he says. “The main difference with comparable methods is that O&G Advisor provides a more detailed breakdown.”

The software was developed over several years by Grant Shomody, Grantech’s president and chief execu-tive officer. It uses a historical database of actual costs to simulate accurate capital and operating cost estimates.

The company has reported several successes with the software. The esti-mating tool has been benchmarked against actual facility costs and is typically within +/-10 per cent. The database is kept current with new information and emerging trends.

“First and foremost Grantech is an engineering firm, so we use our engineering resources to help clients scope out what they need in a facil-ity,” says Tim Bernard, director of cost estimating with Grantech. “We help them lay out what they need, then we go into our software, which has a pick list of various pieces of equipment.

“We take information from projects that we’ve executed to continuously update the software,” he adds. “We’re constantly improving it through our feedback loop with the engineering side of the business.”

He described a project where the software was used to help generate a high-level cost estimate for a gas plant in western Canada of roughly $13 million. The client received an

Cost Estimating Made Easiersoftware successful in accurately preDicting facility costsBy Richard Macedo

the ability to examine performance against targets and forecasting, gas plant yield analysis, royalty calculation and verification, and overall revenue verification, among other functions.

Daily data input is done using a company’s existing field-data cap-ture system. The Bridge’s calculation engine processes the raw data to generate daily and monthly results that are then used to create reports, graphs and Excel extractions.

The software also helps Canadian Forest navigate the intricate and complex world of daily sales gas receipt balancing. As daily sales gas is received onto a shipper account, staff can confirm that the receipts are in-line with daily production from the field. This helps to eliminate material month-end sales imbalances and associated costs.

The Bridge also helps flag situa-tions where a producer may not be receiving all the sales volumes to which it is entitled, which includes all by-products. Reservoir engineers use this information to ensure that economic models reflect accurate yields. Unknowingly losing $200,000 here and $300,000 there can add up quickly. Anderson says that prior to using The Bridge, accessing accurate information quickly was difficult.

“If I asked five different people for production, I would get six or seven different reports,” he says. “There was not a central, cohesive system. From an operational standpoint, there wasn’t any software in the market that truly did all that. Everyone in the company now uses the same base source of information.”

What this has done is change the mindset at Canadian Forest from defensive to offensive, Anderson adds.

Gord Ratuski, vice-president of product development with Forum, says creating the software was an involved process.

“Production, sales, revenue and royalty processes usually take quite a long time to crunch out the num-bers,” he says. “Our goal was to pro-vide a way to achieve some of those same complex calculations quickly, without sacrificing accurate results, each and every day.

“You tend to see departments coming more out of their silos and sharing data and better appreciating where they fit in the whole equation across the operations in the com-pany,” he says. ■

| grantech engineering |

↖project costs

O&G Advisor enables

generation of cost

results for a wide array

of oil and gas process-

ing equipment. Reports

are instantly generated

to show a breakdown

of capital and operat-

ing costs in a clear

and concise fashion.

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estimate from another firm that was double this amount.

“We ended up building it and I think we were just over $12 million,” Bernard says, adding that the software reduces the time and money spent on capital and operating estimates and increases accuracy. Estimates that traditionally took days or weeks can now be completed in minutes.

The software uses a web-based drag and drop interface to enter specific requirements. The estimating tool accesses the historical database and tailored algorithms from the O&G Advisor server to produce the costs. A report is generated showing capital expenditures and operating costs with cost adjustments reflecting where the facility is located or constructed.

It can be used to get estimates for conventional oil and gas facilities that include compression, dehydration, liquids removal, fractionation and gas sweetening, among other features. It can also generate reports for oil batter-ies, storage terminals and single well-sites to plants with capacity of over three billion cubic feet per day.

“It gives a consistent methodology for evaluating projects, which is a necessity when you are comparing multiple opportunities,” Bernard says. “We use different location fac-tors depending on where that facility is being built. It costs more to build something in northeast B.C. than it does in central Alberta and so we make those adjustments for location within the software.”

It’s also designed to be user-friendly, allowing the client’s project to be worked through step by step, despite the complicated nature of the information.

The software is beneficial in both low and high cycles. During boom periods when industry is run off its feet, it won’t take long to get an esti-mate. Since the O&G Advisor isn’t costly, it’s valuable during a down cycle when companies carefully con-trol spending. “We can show value to our clients whether the market’s high or low,” Bernard says.

Phil Lindsay, manager of project development, says the software has the capability to have client-specific cost factors and components, which may be hidden from other clients. The software is also designed to get high-level estimates for a decision maker who may not be a chemical engineer, for example. ■

With the rise of exploration and development in unconventional reservoirs, the world has been shifting rapidly toward horizontal drilling, and further away from vertical drilling.

This trend means that service companies need to keep up with the monumental shift in industry opera-tions. In Canada, producers have been opening up shale gas plays through horizontal drilling and multistage fracturing. The technology has also been used to open up old oil plays like the Bakken in Saskatchewan.

Recognizing this, information and software provider IHS Inc. has been improving several aspects of its soft-ware services to help customers make better decisions finding and produc-ing oil and gas in this new world.

For many customers, IHS data is the primary source of well and production information, which is vital to under-standing ongoing changes in hundreds of thousands of wells across Canada and the United States. Many have developed best-practice processes for creating and re-populating their pro-jects with a combination of proprietary and the most up-to-date IHS data.

In the past, this required manual effort or the development of custom

Keeping Paceihs works to seamlessly integrate Data for better exploration anD proDuctionBy Richard Macedo

data transfer interfaces. To address this issue, IHS introduced direct connection to IHS well and produc-tion information through IHS Web Services and their application program interfaces.

IHS continues to integrate its infor-mation into analytical tools, like IHS PETRA—a product used by geoscien-tists and engineers to visualize, ana-lyze and manage well production, well log, drilling, reservoir, seismic and other related information—by connecting more information types to more of its products across the globe.

The company’s investment in seamlessly integrating information to the projects that customers work on every day extends to their proprietary systems as well as third-party systems such as OpenSpirit, GeoGraphix, SMT and others. This capability gives customers a more complete set of integrated data and tools for finding and producing oil and gas.

Since direct connection between critical information and PETRA was introduced, IHS and industry vendors have extended the number of applica-tions and middleware that give users quick access to this information. This means customers no longer need to manually move data from other sources as they work on projects.

One of the new integration solutions IHS offers is the compre-hensive connection between PETRA, IHS PetraSeis and IHS GeoSyn. When these three solutions seam-lessly connect, geological and seismic workflows are streamlined with easy-to-interpret data and modelling tools. This integrated bundle allows customers to access, view and manipulate information within the same project, create multi- dimensional seismic models and syn-thetics, improve workflow collabora-tion and deliver comprehensive pro-posals for new prospects. Customers are able to get to the field faster with seismic, well, production, log and economic data at their fingertips.

Reliable data that is seamlessly integrated with engineering, eco-nomics and interpretation applica-tions is a powerful ally, the company says, adding that the ability to browse and add data to a project from within the application environ-ment keeps the focus on the search for opportunities. ■

grantech engineering | ihs

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Petra's directional well

module and decline

analysis are two tools

for well and production

information from IHS.

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50

While it has the noble aim of pro-tecting public health from a known carcinogen, when Alberta’s oil and gas industry regulator established that any company with a glycol dehydrator had to start reporting benzene emissions, it created a lot of work for some companies.

Directive 39, from the Energy Resources Conservation Board (ERCB), says that as of Jan. 1, 2007, licensees must complete a dehydrator engineer-ing and operations sheet (DEOS) for each and every glycol dehydrator, which must be revised annually, upon relocation or after a change in status.

The DEOS must be posted at each dehydrator for operators and the ERCB to see, and licensees must com-plete and submit an annual inven-tory of all of their “dehys.”

To help, a small Calgary company of engineers has devised a compre-hensive online system to calculate,

Drying Up The Benzenecalgary-baseD company’s software anD service save energy, time anD moneyBy Lynda Harrison

report and manage benzene emissions from dehys. Their combination of software and service, called Benzene Emissions Advisor, is designed to not only make dehy operators’ jobs easier, but cut costs through energy savings too.

Benzene Emissions Advisor cap-tures clients’ data, reviews that infor-mation and feeds it into simulation models. It then runs those models for a few cases and the results from the simulation are put back into Process Ecology’s database, which clients access through its website.

Alberto Alva-Argaez, Process Ecology’s project manager and com-pany principal, estimates that there are 4,000 glycol dehydrators in Alberta, found at natural gas plants and compressor stations and well-sites, where the glycol, a viscous liquid, removes water and benzene from the gas. Water removal has

several purposes. One is to avoid the formation of hydrates in pipe-lines, which can block the lines and cause production problems.

The rich glycol is heated, boiling off the water, which is usually vented to the atmosphere. The rich glycol is regenerated and reused. “It’s a bit of a closed-loop system. Of course there is some glycol makeup and some losses but it’s a circuit of glycol,” says Alva-Argaez.

The problem is that the benzene also enters the atmosphere and that is the point at which the Benzene Emissions Advisor calculates the benzene coming out with the water. Operators can add a condenser, flare, incinerator or vapour recovery system to reduce or eliminate the benzene release.

Alternatives to glycol dehydrators include molecular sieves that capture

1 de�ne unit con�guration 2 record operating parameters 3 obtain inlet gas analysis

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continued on page 52

| process ecology |

↑advisor

Process Ecology's DEOS

compliance workflow.

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52

water. “I don’t think they’re as cost-effective as glycol, although glycol has its own problems,” he says.

Benzene Emissions Advisor has been on the market for almost three years, shortly after Directive 39 came into being, created by Alva-Argaez and two other process engineers, James Holoboff and Mohammad Khoshkbarchi.

The three of them met while working at the highly successful Calgary-based Hyprotech Ltd. which developed HYSYS, a process model-ling tool. Hyprotech has since been acquired by a United States—based company and Alva-Argaez’s company has grown to eight engineers.

Originally, Process Ecology’s soft-ware was designed for natural gas producers, but it’s no longer just for benzene reporting; it can also report emissions of greenhouse gases such as methane and CO2 as well be used for energy optimization purposes.

There are 10—15 companies of various sizes operating about 900 units so about 25 per cent of the market is using the Benzene Emissions Advisor.

Its closest competition, a similar product from the United States, is “a good little piece of software,” but it’s only for benzene emissions, whereas Process Ecology’s software is flexible, rigorous and robust, says Alva-Argaez. It allows the engineers to modify parameters and make sure they’re matching the experimental numbers, giving them the flexibility to make as accurate predictions as possible, he says.

“What we’re saying is, ‘Look, if we’re going to ask our clients to gather data, go to the effort of

sampling their gas and everything, there is so much more we can do with this.’”

Also, the competition under- predicts the amount of water in gas, says Alva-Argaez. It could be say-ing the gas is dry and it isn’t, off by a good 50 per cent in some cases according to some of Process Ecology’s comparisons, he says. That’s when it gets dangerous. People might think they can use less glycol and start hav-ing operating problems, he adds.

When Process Ecology does its simulation to calculate benzene emissions, its model predicts how much energy the plant will need to vapourize the water so it has a measure of the energy the plant is using. The engineers can compare that to best practices and then quantify the gap.

“Some companies are operating hundreds of these units, and I think for them it’s valuable to know where their top 10 opportunities for savings are,” says Alva-Argaez.

Many of these plants, if not most, are using more glycol than they need, he says, because operators want to be on the safe side. “But we’re telling them they can use less glycol and still be OK. It would be a simple matter

to go to the site and turn the pump down and start saving energy.”

Directive 39 requires a big data-gathering exercise of Devon Canada Corporation, says Troy Halsall, Devon’s environmental advisor. The company has about 200 dehydrators in Alberta and British Columbia using Process Ecology’s emissions advisor whose readily available electronic database has streamlined much of that work, he says.

Being process engineers, Process Ecology’s principals are very familiar with the upstream oil and gas pro-cess. They also use HYSYS, a program Devon considers better than its com-petitors’ models, says Halsall. “We’re quite happy with the accuracy of the data we’re getting back, and with their knowledge and understanding of the data they’re able to identify the misinformation that may be com-ing back from the field,” he says.

On the data management side Devon is now “years ahead of where we were before,” he adds. And the company has been able to recognize some operating savings, although he couldn’t put a number on it. “It may be just as easy as turning the circula-tion rate down on your glycol pump, not only to reduce your benzene emissions but also your operating costs,” says Halsall.

Instead of just a big table of num-bers, the system also features graphs and maps, which Halsall appreciates because they allow Devon to priori-tize reductions at units that are near where people live.

“I can talk for days about this program,” says Halsall. “I’m a big promoter because I think the data analysis they do and the service they provide have been second to none. They’ve been very good.” ■

Continued from page 50

↑easier compliance

Directive 39, from the

ERCB, says that

licensees must

complete a dehydrator

engineering and opera-

tions sheet (DEOS)

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HealtH,Safety & environment

HealtH, Safety & environmenttech guide

53

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HealtH, Safety & environment54

Safe & SoundDetection toolS for pipelineS continue to evolveBy Lynda Harrison

latest in inline pipeline inspection technology.

“I was asked to give a 10-minute presentation and I ended up answering about two and a half hours of ques-tions,” Foreman tells New Technology Magazine.

The NTSB asked him if an inline inspection tool exists that could have detected that flaw in PG&E’s pipeline. Yes, he says, and tells them about the latest in electromagnetic transducers, or EMAT.

EMAT is a method of ultrasonics being tailored for use in gas pipelines, he says, and provides some back-ground. In the early days, everybody was looking for corrosion because it was the big threat. Pipelines were failing because of it. Twenty years ago magnetic flux leakage detection tools were created to look for internal and external corrosion in gas and oil pipelines, and they became the most common type of smart pig.

A “pig” is a bullet-shaped device used to internally inspect and clean pipelines, named for the squeal-ing noise they make as they travel through the pipeline. They remove wax, paraffin and water, and contain instruments that measure and record various aspects of pipeline integrity. A typical smart pig will take samples of a pipe every one-eighth of an inch along its entire length, and 360 degrees around its circumference in quarter-inch intervals. After the data has been collected on the tool and retrieved, complex data interpreta-tion is performed.

↓catastrophic failures

Enbridge clean-up

crews placing booms

in the Kalamazoo

River after the 6B

pipeline rupture.

| Ge pii pipeline Solutions |

On Sept. 9, 2010, at about 6:11 p.m. local time, a Pacific Gas & Electric Company (PG&E) natural gas transmission pipeline ruptures at the intersection of Earl Avenue and Glenview Drive in a residential area of San Bruno, Calif.

An estimated 47.6 million cubic feet (mmcf) of gas is released and ignited. Eight people are killed, numerous individuals are injured, 38 homes are destroyed and 70 are damaged.

Earlier that year, more than 20,000 barrels of oil leak into a Michigan river when Enbridge Inc.’s Line 6B rup-tures on July 26, closing the line for nine weeks. No one is killed, but Enbridge estimates the total cost will reach US$595 million, not including any fines or penalties that may yet be levied by local, state or federal authorities.

Investigators found the problem in the San Bruno case was in the pipeline’s welding, that although the records of the pipeline operator indicated the pipeline in the area of the rupture was constructed of seamless pipe, it was instead, at least in part, constructed of longitudinal seam-welded pipe. In addition, some of the seams of this section of pipeline were welded from both the inside and the outside of the pipe, while others were welded only from the outside.

Accidents happen, despite the pipeline industry’s best efforts. Pipeline companies monitor their pipelines 24/7 from remote control centres across the country, equipped with sophisticated, computerized sensing and control systems, including automatic leak detection alarms and automatic shut-off devices. They conduct regular visual surveys of pipelines by aerial and ground patrols and implement preventative maintenance programs including regular inspections, excavations, repairs and replacements.

They also pursue technologies that will make pipelines as safe as possible.

In early March of this year, Geoff Foreman, growth and strategy leader for GE PII Pipeline Solutions in Calgary, gave expert testimony at a public hearing of the U.S. National Transportation Safety Board (NTSB) regarding the San Bruno incident. He also filled them in on the

Photos: P

hotos.com (rip, flam

e); EnB

ridge Inc. (pipeline rupture/cleanup)


55

There are two types of crack-ing problems, explains Foreman, an engineer who has worked on inline inspections for 34 years. One is due to either fatigue, poor manufacturing, being dormant for years or the morphology in the steel itself. The other is due to stress corrosion cracking, repre-sented by an external crack in the body of the pipe or in the welds. It is a combination of corrosion and stress usually due to the environment it is in, and usually occurs when the protective coating breaks down.

Ultrasonic pigs were developed for these conditions but until EMAT was introduced, they only worked well for oil pipelines, says Foreman. Similar to an ultrasound for detecting heart beats in human fetuses, which uses gel to conduct sound, the pigs’ transducer needed a liquid coupling to perform that task and oil pipelines provided that natural bond. Gas pipelines, though, are generally dry.

It’s taken up until now to perfect a new methodology of an old technology, enabling people to put ultrasound in a pipe without that gel and coupling, he says.

EMAT is a combination of strong magnets and an electric pulse. Instead of having a transducer with a crystal that vibrates and creates a sound that goes through the gel, it makes the pipe itself vibrate. The pipe becomes its own transducer and generates sound waves inside the steel that pick up the reflections that come back from cracks.

“It was pioneered as an inspection tool by GE in 2000 and took until 2009, with the third generation of the tool, to the point where we’re confident enough to use it commercially,” says Foreman. It’s used mainly in Canada and the United States, and the technology is en route to Australia.

There is only one prototype and it has been completely booked out and will continue to be so all of this year, he says. GE is contemplating building a second one to meet demand. “It’s expensive to use and it’s very expensive to build,” says Foreman, declining to be more specific.

Using it is costly in two ways, he says. It uses a lot of energy via expensive batteries and its results are highly complex to analyze. On a standard tool one person could probably analyze one kilometre of data in one hour. On an EMAT, that would take 30 hours. That’s because EMAT uses more than one sensing technique; it measures four or five modes or frequencies of sound.

EMAT is probably the closest to being a game- changing technology for crack detection on gas lines, agrees Bruce Dupuis, program manager of liquid integrity at TransCanada Corporation.

TransCanada inspected multiple sections of its line using EMAT this year and is currently working with two vendors to automate their analysis process and leverage their networks, “to help them separate the wheat from the chaff,” says Dupuis. “Right now it’s still in its early infancy and it’s extremely time-consuming to analyze the data. That’s probably the biggest constraint. Even if we could run every mile of our line it would probably be decades before we could analyze all the data.”

Yet with all of this technology, it is still possible to miss the detection of a flaw, Foreman tells the NTSB. It depends on the size of the flaw and the type of tech-nology trying to find the flaw.

| transcanada |

↓pipeline integrity tool

After nine years of develop-

ment, GE commercialized

its advance EMAT pipeline

inspection technology in

2009. Its sole prototype is

booked for well over a year.

↑EMAT inspection

EMAT technology

detects and measures

a full range of cracking

defects in gas pipelines,

without having to

have liquid as a signal-

transmission medium.

EMAT sensor

Special arrangement of magnets

Special arrangement of electromagnetic transmitter coils

Pulse of electromagnetic waves

Ultrasonic pulse propagation

Oscillating metal grid generates an ultrasonic pulse

Pipe wall

Gap of less than 0.039" between EMAT sensor and pipe wall

N S N S

N S N S

“I don’t see any significant accidents in the next 20 or 30 years because the coatings are very good right now, but Canadian pipelines constructed in the 1970s or early 1980s—most pipelines were coated with either asphalt or polyethylene. They were not excellent and after 30 or 40 years these types of coatings will definitely lose their ability to provide protection.”

Dia

gram

and

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GE

PII

Pip

elin

e S

olut

ions

HealtH, Safety & environment

The one anomaly still impossible to detect is pinholes or microbiological corrosion, sometimes referred to as wormholes, too small to see, he says. However, phased arrays for liquid operations could provide a three-dimensional image of a wormhole sometime in the future, as an MRI machine does in a human body, he adds.

“Advanced coatings and cathodic protections have largely rendered corrosion concern a thing of the past,” says Alex Pourbaix, TransCanada’s president of energy and oil pipelines. Cathodic protection comes from a low-voltage electric current induced in the vicinity of the pipeline to inhibit external corrosion.

TransCanada is also looking at installing temperature sensors underneath pipeline rights-of-way so that if there is a small leak the heat from that oil will register a heat signa-ture that’s different from the surrounding soil, he says.

The company is also putting in the rights-of-way acoustic sensors able to register the very, very tiny acous-tic signature of a leak, he adds.

In operation since late 2000, the Alliance pipeline transports about 1.34 billion cubic feet a day of natural gas from northeastern British Columbia and northwest-ern Alberta to Illinois. Because it is so new, Alliance Pipeline had the advantage of being able to use the latest in metallurgical science and to design the system to incorporate very up-to-date technologies to address threats, says Arti Bhatia, senior manager, pipeline integ-rity and corridor management.

For example, putting very tight controls on all aspects of the pipe manufacturing process produced exceptionally high-quality line pipe. In addition, the system is comprised of heavy wall pipe, which is gen-erally 40 per cent thicker than conventional pipeline design, says Bhatia.

Frank Cheng, Canada Research Chair in pipeline engi-neering at the University of Calgary, says pipeline safety guidelines were set up 20 or 30 years ago and probably need to be updated for frequency, especially for aging infrastructure.

How frequently they should be inspected depends on each individual pipeline, he says. Some pipelines are still OK after 40 or 50 years of service, he says, suggest-ing some aging pipelines might need it as often as every three months.

Pipeline coatings used today are excellent but that wasn’t the case prior to the early 1980s, says Cheng. “I don’t see any significant accidents in the next 20 or 30 years because the coatings are very good right now, but Canadian pipelines constructed in the 1970s or early 1980s—most pipelines were coated with either asphalt or polyethylene. They were not excellent and after 30 or 40 years these types of coatings will definitely lose their abil-ity to provide protection,” he says.

In the late 1980s the pipeline industry started to use fusion bonded epoxy (FBE), which is very good, and after 2000 started using high-performance composite coat-ing, says Cheng. The top layer is polyethylene tape, the middle layer is a modified polyethylene whose content

is an industry secret and the bottom layer is FBE. Performance is excellent and it is the best coating

available, he says.But 40-year-old pipelines, due to their coatings,

will fail, and very extensively, he says. It’s impossible to repair pipelines of any length longer than a few

dozen metres. “If coatings fail over one kilometre, how can you repair it? It’s not easy to fix this problem.”

A new, hot research topic today is what to do with old, abandoned pipelines, which have the potential to harm the soil and water when they erode, says Cheng. He estimates there are a couple of hundred kilometres of such long-distance transmission and gathering pipelines distributed throughout North America, including Alberta and British Columbia, most of them in urban areas.

Companies empty the pipelines, try to clean them and just leave them there, he says. He believes industry is very concerned about this and is asking universities and industry organizations to research the issue.

Canadian Energy Pipeline Association (CEPA) member companies have always maintained that pipelines are the responsibility of the pipeline operators for the full lifecycle of their pipelines, which includes their design, construction, operation and maintenance, and when necessary, abandonment, says the association. “Our member companies have not abandoned any transmis-sion pipelines, nor do we plan to in the near future.”

Age is not in itself an indicator of risk, says CEPA, whose members transport 97 per cent of Canada’s oil and gas production. In fact, the age of a pipeline is irrelevant, provided the infrastructure is properly moni-tored and maintained throughout its operating life, says the association.

Brenda Kenny, CEPA president, says everybody’s deal-ing with best-available technology so safety techniques do not vary much across industry. There is no need to be concerned about the safety of aging pipelines, she says. “It’s all about the maintenance, and the more sophisti-cated our inspection tools, the better we can do that.”

“There have been advancements in pipeline design and construction materials, but the most profound changes relate to the way in which pipelines are operated. Because of advancements in our ability to monitor and maintain pipelines, a 40-year-old pipeline, appropriately inspected and maintained during its operational life, is just as safe as a brand new pipeline,” says the industry association.

According to CEPA, significant failures on transmission pipelines are extremely rare and the number is declining. Based on recent National Energy Board data, ruptures on federally regulated pipelines during the eight-year period from 2002–09 averaged slightly more than one per year—a decline of 55 per cent from the previous eight years. Between 2002 and 2009, significant failures on CEPA member pipelines declined despite a 27 per cent increase in the number of kilometres of pipeline. ■

Ge pii pipeline Solutions | transcanada | cepa

↑better knowledge

The pipeline industry

will benefit from the

latest in metallurgical

science and construc-

tion materials for

new pipelines, but

advancements in the

ability to monitor and

maintain pipelines

will also lengthen

the operational life

of older pipelines.

Photos: P

hotos.com (top); JuneW

arren-Nickle's E

nergy Group (bottom

)

tech guide56

4953

In-House Technology Starsfull page

The first liquid-fueled rocket was launched in 1926. Rocket technology has since gone on to produce rocket cars, gliders, planes, artillery fire and space travel.

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58

SuncOr energy Inc. estimates that its tailings reduction operations (TRO) technology will slash the time required to reclaim oilsands tailings from 30 years to 10 years or less.

“Thanks to this development, we’ve eliminated the need to con-struct new tailings ponds at our bitu-men mining operation,” says Bradley Wamboldt, TRO director for Suncor in Fort McMurray, Alta. “In addition, we plan to reduce the eight existing ponds to just one over time.”

Oilsands producers use hot water to separate bitumen from sand and clay. The clay is then stored in shal-low ponds, which currently cover a total area of 170 square kilometres. (This figure, equivalent to an area 13 by 13 kilometres, includes all oil-sands mining companies.)

The clay particles are suspended in water with traces of hydrocarbon, forming a thick soup that requires centuries to consolidate on its own.

Tailings TriumphSuncor’S tro tecHnoloGy SlaSHeS tHe time to reclaim oilSanDS tailinGS by two-tHirDSBy Mike Byfield

Consolidated Tails (CT), a process pioneered by Suncor in the 1990s, accelerates consolidation by adding sand and gypsum.

As oilsands bitumen output contin-ues to increase, however, the CT time frame wasn’t fast enough to halt the expansion of the huge slurry ponds. Suncor began experimentation with drying out tailings in 2003.

The TRO process, first field tested in 2008, is based on clay particles clinging to a polymer material. The resulting flocs readily come out of suspension in water. (The chemical term is flocculation.)

“Mature fine tailings [MFT] and polymer solution are both viscous materials. They must be mixed, but not too much. Over the past two years, we’ve worked out operating parameters which we can now pretty much just dial in,” Wamboldt explains.

After flocculation, the MFT/poly-mer flocs are dried in thin layers over gently sloped sand banks, then left in place or moved to another location for final reclamation. From time to time, the flocculent beds are ploughed, exposing more wet material to the air. The entire dry-ing process occurs within weeks. The TRO process can only take place in months without a firm freeze-up. During that period, Suncor’s project work force rises to the range of 200.

Suncor processes 180 million tonnes of oilsands annually, ingest-ing 50,000 tonnes per day of fine clays. Half of these fines are captured in the tailings beaching operation as they are pumped into the big ponds. The remaining 25,000 tonnes per day eventually settle into MFT and will be treated by the TRO process.

“In 2009, our team processed MFT at a rate of 1,500 dry tonnes per month, utilizing 30 hectares of land,” Wamboldt says, while 2010 “was our big ramp-up.” At year-end, the com-pany had four drying sites totalling 350 hectares, capable of handling 25,000–30,000 tonnes per month. “Remember, though, that we can’t dry in winter. So we plan to add 90 hectares annually for the next three years—it’s mostly a matter of clearing the land.”

In 2009, the Alberta government introduced regulations that impose

annual targets for reducing MFT. “We are in a position to meet or beat those targets,” Wamboldt says. The company has spent “in the low hun-dreds of millions” of dollars develop-ing the TRO method, he says, with a further billion dollars budgeted for MFT processing in the years ahead. The patented process remains confi-dential. Suncor is willing to share its innovative methodology with other oilsands miners—if they help pay some of the TRO technology research and development cost.

taIlIngS breakthrOugh wIll Save mOneyWamboldt rejects the notion that enviro-lobby groups bullied Suncor into cleaning up its tailings act. “Tailings management has always been integral to this industry’s plan-ning, long before it became a high-profile issue beyond Alberta,” says the chemical engineer, a graduate of McGill University in Montreal. “Any oilsands operator is legally obliged to restore its leases back to their origi-nal condition or a comparable state. Nothing new there.”

The key question was never if, but how. “Producers have been chasing a solution for MFT for a long time,” admits Wamboldt, who has worked overseas as well as in Canada. He came to the oilsands in 1997, help-ing with initial development of Shell Canada’s Muskeg River Mine project.

“Technically, tailings have proven to be a challenge, as they are for many other mining indus-tries,” says Wamboldt. “Now we have the necessary technology to address the problem.”

Before TRO technology was developed, Suncor planned to con-struct five more tailings ponds. “Dikes aren’t cheap to build, and these would have been large struc-tures,” Wamboldt says. “Suncor will also generate a significant cost sav-ing by shortening the distance that mine waste material has to be trans-ported. We crunched the numbers and TRO came up the winner both economically and environmentally. That’s not really surprising. New technology that’s environmentally sound often makes financial sense as well.” ■

↑drying beaches

The Suncor TRO

process includes

pumping a slurry of

mature fine tailings

over a gently inclined

slope for drying.

| Suncor energy |

Pho

to: S

unco

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nerg

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59

anyOne In the oil and gas industry knows water is a huge issue for many operators, either because they produce too much and have trouble disposing of it amid ever-tightening laws, or because it’s scarce and so they need to use wisely what they have available.

Often that means they have to use brackish ground-water containing high levels of salt or other solids that must be removed before it can be reused or safely dis-charged to streams.

A Calgary-based company, Aqua-Pure Ventures Inc., says it has the solution for dealing with flowback and produced water from shale gas operations. Its NOMAD 2000 mobile oilfield evaporators can recycle waste water for sale, re-use or environmental discharge.

Fountain Quail Water Management, LLC, a wholly owned Fort Worth, Texas-based subsidiary of Aqua-Pure, is seeing growing demand in Pennsylvania, where last year the state government enacted stringent regulations regarding discharges.

In June 2010, Fountain Quail installed its NOMAD evaporators at the Williamsport, Pennsylvania facility of its partner, Eureka Resources LLC. Now users such as Range Resources Corporation, Exxon Mobil Corporation subsidiary XTO Energy Inc. and Chesapeake Energy Corporation truck their water to the plant, saving them a 120-mile trip to the closest alternative.

Dan Ertel, president of Eureka, which is leasing the equipment, says the evaporators are about 10–20 per cent more efficient than competitors.

Fountain Quail says the pure distilled water from the Marcellus Shale waste water it receives has total dissolved solids measuring well below 150 parts per million, and contains only trace chlorides.

Right As RaincalGary-baSeD company finDS nicHe cleaninG SHale GaS operationS’ waterBy Lynda Harrison

The 100-year-old technology was originally intended to concentrate things like orange juice and to clean up nasty water that leaches out of landfills, says Richard Magnus, chairman of Aqua-Pure. Aqua-Pure made the equipment more efficient and patented the process.

Magnus says the company’s president, Harold Lauman, found the technology about 18 years ago and tried for five or six years to sell it but was unsuccessful. Then about a dozen years ago he met up with the founding partner of Colt Engineering, Jacob Halldorson, whose expertise was in the oilsands. Halldorson revamped the technology for the oilfield, making it more rugged and portable, and joined Aqua-Pure as its chief executive officer 10 years ago.

There are now nine NOMADs operating—six in Texas and the three in Pennsylvania—none of them at oilsands projects. There will soon be two in the Fayetteville Shale play of Arkansas. Two more are coming out of the shop soon and the company is looking for a strategic partner to use them.

Salty water is certainly not limited to shale plays, but that is the niche Aqua-Pure has found, says Magnus.

“We’ve now cleaned 14 million barrels of flowback and produced water for Devon Energy Corporation in the Barnett [Shale play in Texas] alone,” he says. “That’s about 600 million gallons of water that would otherwise have been disposed of down a deep well, never to come back into the hydrological cycle. We use that water for the next frac, wherever that might be. Aqua-Pure is the only company that has cleaned that volume of water.”

Aqua-Pure’s NOMAD 2000 mobile oilfield evaporators use mechanical vapour recompression (MVR) evapo-ration. Here’s how it works: the feedwater is boiled to produce steam, leaving behind all dissolved solid contaminants. The steam is then condensed into pure distilled water. It takes only one-fortieth of the energy a boiler requires.

And the water it produces is cleaner than rain, says Magnus.

The NOMADs’ three skid-mounted components (a pre-treatment module, an evaporator and a compressor) are designed for truck transport. “We can pick them up and move them in nothing flat,” he says. More pre-cisely, an entire NOMAD site can be moved in a week, he later adds.

They are also easily cleaned. “It’s a few bolts [to unscrew] and one guy in there for eight hours with a power washer and we’ve got a fully clean piece of equip-ment and we’re right back in operation putting water out the other end—because we don’t get paid if there’s no water getting cleaned.”

Powered by electricity or natural gas, the units use 625 horsepower or 466 kilowatts and have a feed capacity of 2,500 barrels of water per day to produce 2,000 barrels per day of distilled water. The units stand about 13 feet high and the total system footprint is 2,500 square feet.

Its power efficiency, mobility and easy cleaning make Aqua-Pure a low-cost operator, he says, however he could not provide actual costs as each situation varies depend-ing on the water to be cleaned and equipment needed.

The recent low price for natural gas won’t last forever, so Aqua-Pure’s prospects for the future are not dim, Magnus insists. “[If] it gets over $6, the activity will go crazy again and it could do that this year quite easily.” ■

↖itinerant solution

The NOMAD water

treatment system,

which uses mechanical

vapour recompression

evaporation technology,

is contained on three

skid-mounted compo-

nents: a pretreatment

module, an evaporator

and a compressor.

| aqua-pure ventures |

Pho

to: A

qua-

Pur

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entu

res

Inc.

60

althOugh It waS part of BP plc’s asset sale to Apache Corporation last year, BP Canada Energy Company’s Noel project remains a feather in the cap for the company, as it was awarded the President’s Award from the Canadian Association of Petroleum Producers for responsible resource development in recognition of the achievement.

The accolade was well earned as the goal for the Noel project, near Dawson Creek in northeastern British Columbia, was to have near-zero emission wellsites for the natural gas wells drilled while also reduc-ing the project’s overall ecological footprint.

Phil Aldis, who had been BP’s pro-ject manager for Noel, explained that the project’s reductions can be broken down into two categories—carbon and ecological. Carbon reductions involved a near-zero emissions well-site design using solar energy and

Closer To Zeronoel project an environmental featHer in tHe cap for bp canaDaBy Paul Wells

electrifying compressors where 84 per cent of the power is hydro-generated. Ecological reduction included reduc-ing the number of wells and pipelines, drilling multiple wells on a single lease site and use of a water storage system collecting spring runoff and drawing from underground aquifers.

Aldis said that perhaps the most innovative aspects of the project relate to measures taken to reduce the company’s CO2 emissions as part of the company’s desire to create a greenfield natural gas development. “Two big things we’ve done here which have impacted the carbon footprint of the project as compared to a conventional one are our zero-emissions wellsites and the fact that we’ve elected to electrify the entire project,” he said in an earlier article for New Technology Magazine.

The largest gains were from the wellsites themselves, where the con-ventional approach has been to use

the natural gas coming from the well. “Basically, you’ve got pressurized gas and you can use it like a pneumatic source to open and close valves and things like that. The problem with using hydrocarbon gas to do that is [that] every time you stroke the valves, for example, that gas is vented [in]to [the] atmosphere and it’s actually more damaging than CO2 in terms of a greenhouse gas impact,” Aldis noted.

“What we’ve elected to do is use solar power—we have solar panels at our wellsites…that provide electrical energy to each wellsite, which can then move valves [and] make interven-tions, using that solar power energy.”

Aldis said that while electrification had the smaller impact of the two, it played a vital role in the company’s scheme to make the Noel project an industry leader on the environmen-tal front. In normal conventional projects, companies commonly use their own natural gas as fuel to feed engines that drive things like com-pressors and act as an energy source at main plants. But BP opted to go a different route in an attempt to cut emissions, buying electricity from BC Hydro and thereby eliminating emis-sions from exhausts.

“BC Hydro is obviously a pretty green company with something like 80-plus per cent of its electric-ity being hydro-generated,” Aldis

Photos: BP Canada Energy Company

4951JWN in-house

(Energy 4-pack) hp


61

explained, adding, “all the major processing sites are very green and should have very little emissions.”

The Noel project received BP’s internal approval in September 2008. It was also subject to B.C.’s regulatory and permitting requirements for nat-ural gas development. While under its ownership, BP had anticipated Noel’s early development to include two rigs working year-round.

The overall cost for Noel was expected to be in the neighbourhood of $1.4 billion. Expected peak produc-tion was to be about 130 million cubic feet per day with 301 square kilome-tres of subsurface land base antici-pated to be developed. Under BP’s original plan, about 140 wells were to be drilled over five to 10 years from 89 well pads, as grouping up to three wells per pad where geological condi-tions are favourable helps to reduce the environmental footprint.

The project’s sweet gas is contained in the Cadomin geological forma-tion, made up of low-porosity rock. Gas in this formation is called “tight” because it doesn’t flow very easily through the formation. Special hori-zontal drilling and completions tech-nology needs to be used to extract the gas. Wells would be drilled approxi-mately 2.6 kilometres deep and over one kilometre in length horizontally.

“The Cadomin development is a tight gas development and we’ve been drilling very long horizontal wells into that. Why is that green? It means you need far less surface footprint. If you did it in a more con-ventional way, drilling vertical wells you would need something like 500 or 600 vertical wells,” Aldis said.

“We’ve managed to reduce it through drilling extended long-reach horizontal wells. By doing that you’re touching the same volume of rock but you’re making less surface impact as a result. That [enabled] us to reduce our ecological or physical footprint.”

At the same time the project was designed to be pursuing sour gas, located in the deeper Doig formation.

This gas can be accessed using tradi-tional vertical drilling and comple-tions technology, with wells drilled approximately 3.3 kilometres deep.

Two of the three major facilities comprising the Noel project had been built as of last fall, with the third in the works when the take-over was underway. BP had drilled over 25 wells prior to fall. “So we [had] quite a few of these [near] zero-emissions wellsites…up and functioning,” and working well for the company, Aldis said.

With Apache taking over the reins for the Noel project, many of the individuals working on it were to continue to do so for their new employer. Not Aldis, though. The long-time BP employee planned to stick with the company and work on different projects. That said, seeing his pet project leave the BP fold was a bittersweet experience.

“From a personal perspective, we’ve had a big project team working on this for the last four or five years and we’ve accomplished a great deal. It’s been a memorable part of my pro-fessional life and I’m proud of what we’ve accomplished.” ■

↑aim for zero

Noel project's near-

zero emissions well-

site design includes

use of solar panels,

electrifying compres-

sors with hydro-

generated power.

| bp canada energy |

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MultiStim Fracture Isolation Systems

Logan Completion Systems’ MultiStim Fracture Isolation System - an innovative multi-stage completion technology - is especially designed for producers who are tackling multi-stage fracs. The MultiStim Fracture Isolation System features one-trip installation for faster completion times and frac valves with fully retrievable seats post-fracturing via coiled or threaded tubing…without milling or drilling! Use of the full-bore inner diameter - the key feature of the MultiStim System - allows conventional tools to be run after the seats are removed. Cementing, or plugging and perforating operations are not required. MultiStim is suited to extended reach horizontal wells. Sleeves can be selectively opened and closed post fracturing to allow customized stimulation of the entire wellbore. Fractures can be controlled from toe to heel for selective fracturing, testing, producing, and restimulating throughout the life of the well. The MultiStim Fracture Isolation Liner System and MultiStim Cup Frac Tool System (a straddle cup system) are suitable for use in sandstone, carbonate, shale, coal and other naturally fractured formations.

Reduce well costs, improve well production, and maximize your profits with Multi-Stim Fracture Isolation Systems. Contact us for more information.

Logan Completion Systems offers a comprehensive line of completion products:• Retrievable & Permanent Packers• Service Tools• Liner Hangers• Thermal Liner Hangers• Casing Patches• Flow Control• Open Hole Packers• Mud Motors• Custom Tool Design & Development

600 6th Avenue Southwest, Suite 210 | Calgary, Canada T2P 0S5 | 403.218.2041 | Fax 403.218.2069 | Toll Free 888.486.6583 www.logancompletionsystems.com

Multi-Stage Fracturing with Retrievable Ball Seats and Shiftable Sleeves

TighT oil & gastech guide

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The increasingly pivoTal role of shale gas within the North American energy reserve/production picture is the direct result of recent advances in horizontal drilling, hydraulic fracture stimulation and completion technolo-gies. But now that the tools and technologies are being widely applied, petroleum engineers are working to figure out how to make the best use of them.

This is no simple challenge. Experts agree that there is a need for better understanding of the geomechanical effects of unconventional well fracking and the perfor-mance of individual frac stages, increased data gathering, sharing and integration, and new predictive software. What is already clear to many shale specialists, however, is that good fracture design can play a pivotal role in a successful completion program, even though, as some say, “hydraulic fracturing is a very forgiving technology.”

compleTion road mapDespite its limitations, the currently available data can be distilled into some helpful principles, according to a Society of Petroleum Engineers (SPE) paper presented at the Canadian Unconventional Resources & International Petroleum Conference in Calgary last October. Based on data from 16,000 frac stages in the Barnett, Woodford, Haynesville, Antrim and Marcellus shales, the paper pro-posed “a road map for effective completion practices for shale stimulation.”

The paper emphasized that the uniqueness of each shale play, the heterogeneity within the play, variations of reservoir quality and often poorly understood produc-tion mechanisms entailed a “completion strategy and outcome [that] are complicated.”

This is in line, though, with the thinking of some petroleum engineers and frac specialists. “Where industry has run into problems is in adopting a factory approach, in effect dumbing down the [existing] techni-cal competence,” says Dan Themig, a petroleum engineer and chief executive officer of Calgary-based Packers Plus Energy Services Inc.

Minimizing the number of technical people on frac jobs, along with a one-size-fits-all approach, resulted in horizontal fracking practices that were inefficient and ineffective on some completions in the Barnett, Haynesville and other shale plays, he says.

Themig believes that high-density, open-hole fracturing systems that “allow more than 20 fracture treatments in a single, seamless operation” can address some of these problems—as well as cut costs and improve recovery.

There are two main methods for multistage fracking. The more traditional one involves first cementing the casing in the horizontal wellbore and then “plug-and-perf” stimulation.

The trouble with this, says Themig in an interview, is that the operator doesn’t know if the frac is optimally placed. Assumptions and guesswork, used for positioning the perforation, can be wrong, but gathering the requisite data is expensive, making both options unsatisfactory.

The open-hole multistage (OHMS) method, first used in 2001, doesn’t involve cementing the casing, but instead uses external packers that can create a seal between the casing and the wellbore, with two or more

packers along the casing isolating sec-tions of the annulus for fracturing.

OHMS might obviate some of the need for costly, sophisticated log data, and the thinking on how far apart to space the packers has been evolving as a result. Unlike the early days of OHMS, it is now thought that fracs do better over a wider area, with packers set, say, 100 metres apart. “The pressure found the weakest rock, the sweet spot,” says Themig.

ohms frackingIn the Bakken, Packers Plus has pro-vided equipment and frac services for some very long laterals, including one in North Dakota that was 12,500 feet long with 47 frac stages. The Bakken oil play in North Dakota and Saskatchewan, Themig says, has been more successful than expected. Oth-ers have not delivered as expected. Increasingly, operators in the Barnett, Haynesville, Marcellus and Montney plays are switching to OHMS frack-ing, says Themig.

A paper by Themig, published in the May 2010 Journal of Petroleum Technology, compared three-year cumulative production data from two direct offset wells in the Barnett shale—one cased cement, the other open-hole. According to one of the charts in the paper, recovery over a three-year period was about 50 per cent greater for the well that had used the open-hole method.

For some operators, the tide of debate around the best completion methods for shale plays is turning in favour of OHMS. In the Anadarko

Basin’s Granite Wash formation, a tight gas reservoir that has shown excellent rates of return, the best way to complete wells there has also been a subject of some debate, says Jason Edwards, the completions manager for Jones Energy Ltd.

Gas from the Granite Wash’s tight sand reservoirs has been successfully produced with both vertical and horizontal wells, but Edwards and his colleagues at Jones Energy have ana-lyzed 25 wells, all drilled horizontally over the last three years, with about half of them cement-cased and the other half open-hole.

The formation has a porosity in the eight-to-10 per cent range and permeability of from 0.05 to 0.1 mil-lidarcies—considerably better than for shales, says Edwards. Vertical wells were first drilled in the Granite Wash 40 years ago, but operators are now switching to horizontal wells with some high-rate wells in the Stiles Ranch area producing in the 20-million- cubic-feet-per-day range.

The study of 25 wells, published in an SPE paper, found that OHMS had a big cost advantage over plug-and-perf with a cemented liner. A frac completion with OHMS cost on aver-age US$1.12 million, compared with US$1.58 million for plug-and-perf.

“Most of the difference in cost is made up from the time involved with plug-and-perf. It takes three to five days on 10 stages, with three perfora-tion clusters per stage for a total of 30 fracs. But with ball-drop OHMS, 20

Best Choiceamid plenTy of debaTe, unconvenTional resource players search for besT approach To horizonTal, mulTifrac wellsBy Godfrey Budd

spe | packers plus | halliburton | cirque resources


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examined the question of optimiz-ing frac spacing along a horizontal wellbore. The study, which Schmelzl says supports his view, was prepared for presentation as an SPE paper at the conference in Calgary last October. To develop the evaluation, the study relied on detailed log analysis for res-ervoir characterization and diagnostic fracture injection tests to obtain a set of parameters, which then served as input data for the fracture simulator.

The study concluded that the use of 3-D, multiphase-flow, numeric reservoir simulation for economic optimization of horizontal wellbore and fracture spacing can significantly increase asset profitability.

Other conclusions were that unique individual studies should be done for “each reservoir, area and depth,” and that in the shale oil res-ervoir studied, reduced fracture spac-ing provided increased profit, with the maximum profit being observed with the tightest spacing studied. The tightest spacings examined in the study were 10 metres long. Optimal spacing for the shale gas reservoir examined was 75 metres.

refinemenTsAbout 10 years ago, operators started to give the open-hole option a closer look when they noticed filter cake and cuttings threatened to compro-mise a cement job’s integrity—and, therefore, the effectiveness of fracture compartmentalization. But OHMS has its operational challenges, too, especially with increased fracturing densities and stages, says Bill Boyd, senior vice-president of operations at Cirque Resources LP.

Conventional steerable assemblies commonly used to drill lateral sec-tions create spirals and ridges along the borehole, potentially compromis-ing the packer seal. “In a frac job, you need almost an ideal, very uniform wellbore, so the packers seal properly and hold in place when you pressure up, and don’t fail or leak,” says Boyd.

The solution involved deploying a rotary steerable system that was cho-sen by the operator for its simplicity and full-rotating capability, which plays a critical role in cleaning out the borehole. The system includes a “push-the-bit” tool that pushes against the wellbore to force a drill bit bias in the opposite direction.

In a case study (described in a 2010 SPE paper, co-authored by Boyd) of a

well drilled in the middle member of the Bakken forma-tion in North Dakota, an OHMS system that included 22 fracture sleeves and 21 open-hole packers was used to frac and complete along a 5,530-foot horizontal section. The well was completed ahead of schedule, “due to the absence of the reamer run,” according to the paper.

Another fracturing refinement that has been pro-posed is called the Texas Two-Step. Its aim is to alter the stress in the rock to facilitate branch fracturing and “to connect to induced stress fractures in a single, hori-zontal well,” according to a paper co-authored by Keith Rispler, a senior chemical engineer at Halliburton. “You change the stress profile so it’s uniform, so it’s more likely to create a complex frac network,” says Rispler, in an interview.

To accomplish this, the Texas Two-Step uses a com-bination of mechanically activated sleeve completions and fracking of intervals—albeit with an alteration of the sequence in which the intervals are fracked.

Starting at the toe of the horizontal, the first interval is stimulated. Next, a second interval is stimulated. Then, instead of continuing toward the heel, the third interval is fractured between the two previously fractured inter-vals, “to take advantage of the altered stress in the rock and to connect to stress-relief fractures from the previous fractures,” according to the paper.

Rispler expects that the Texas Two-Step, which can be used for cemented or openhole completions, will get a field trial sometime this year.

adding reservesMultistage horizontal fracking (MSHF) looks set to bring much more exploration and production activity to the fringe areas of the Cardium formation. The Cardium has an estimated 10 billion barrels of original oil in place (OOIP), of which about 1.75 billion barrels have been produced since 1957.

Since late 2008, MSHF has been hugely successful in opening up parts of the Cardium that were previously considered to be uneconomic to develop with vertical wells, according to a recent SPE paper. “The thickness in the fringe areas is from one to 10 metres. The pay zone in the main pool has about the same thickness range, but the fringe areas are mostly at the low end, with less per-meability, but fairly good porosity, although not as good as the main area. But horizontals can make the fringe areas economic,” says Ese Omatsone, a petroleum engi-neer at Sproule Associates Limited, and principal author of the SPE paper.

The fringe areas hold an estimated one to three billion barrels of OOIP. “This is above the 10 billion OOIP of Cardium. Assuming 1.5 billion OOIP, developing 70 per cent of that would produce 126 million barrels, based on 12 per cent recovery,” she says.

In this, as in many of the shale plays, there is an ongoing need for strategic data gathering and informa-tion, and it is possible that costs could rise in the Cardium, as they have in the Bakken shale oil plays. When Cirque first drilled the Bakken in 2008, it cost about US$4 million to drill and complete a well. Today, it can be as much as US$5.5 million, says Boyd.

Despite some caution in the sector, he doesn’t think activity will abate any time soon. “The [unconventional resource] plays are continuing to prove out,” he says. ■

fracs can be done in 24—36 hours. In both cases, we used 4.5-inch casing in a 6.125-inch hole,” says Edwards.

Comparing production, the study concluded, “The OHMS completion method outperformed the plug-and-perf method by 33 per cent over 12 months of production.”

cemenTed casingsIt’s a complex debate, and other stud-ies point in the opposite direction, says Eric Schmelzl, a sales manager with Halliburton, who concedes, however, that, “Short-term results, typically one to six months, appear better for open-hole. But are the dif-ferences due to open-hole?” Pointing to an analysis of 238 wells in the Montney play in northeastern British Columbia that adjusted for several factors, including the number fracs, he says that, “The net result was that there was a clear correlation on performance and in what portion of the shale the specific horizontal well resides, where in the vertical stack the well was drilled.”

Conceding that in some instances OHMS is the right approach, Schmelzl says that for most wells, over the long haul, the pinpoint accuracy achieved with cemented casings is one of the factors that make it a generally better system for optimizing an asset.

A recent evaluation of case histories in Canadian oil and gas shale plays

Illustration: Packers Plus Energy Services Inc.


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Analyze Thatproducers geT meThodical abouT The opTimum number of fracs for TighT oilBy Maurice Smith

known unTil recenTly as the darling of the North American oil and gas industry, shale gas may be temporarily falling out of favour as natural gas prices continue to languish. But the magic that unlocked the massive shale gas prize—horizontal drilling and multistage fracking—has hardly skipped a beat as it jumps to a new host and leads the resurgence of oil production in played-out or “vintage” plays across the continent.

Just as the technology has had to be adapted to each new shale gas play to be a success, producers are finding that adjustments to the techniques are necessary in emerging tight oil plays such as the Bakken and the Viking of Saskatchewan and the Cardium of Alberta.

With little in the way of detailed analysis undertaken or historical evidence to draw on, many companies are relying as much on trial and error and imita-tion as on hard data and science to complete their wells, say some producers.

“In my opinion, a lot of what has happened is there has been a few com-panies [that] have done it, and maybe been quite successful at it, and then everybody else just looks over the fence at what they are doing and follows them—they are doing it, but they don’t necessarily know why they are doing it,” says Dennis Hahn, senior engineering advisor with Enerplus Corporation.

“What I am saying is, you should be doing it with a certain element of technical work to know why you are doing what you are doing. We are try-ing to validate what our predictions are, calibrate them with some actual data and that way we are going to be able to optimize production.”

Hahn’s primary role over the last year and a half has been to provide direction on frac sizing and fre-quency. “I believe by doing the tech-nical work you can get to the end result quicker than drilling a bunch of wells, trying a bunch of things, and then having to wait a fairly long time in tight plays to see what your real results are.

“We are trying to build some cap-ital efficiencies into what we do by combining the technical aspects and then seeing what we see in the field results. It’s not so much a validation, it’s more a calibration, of your predic-tive tools. That’s the approach we are taking. And we have seen good results in our Viking oil and our Cardium oil.”

Despite their similarities in ben-efitting from horizontal drilling and multistage fracking, tight oil and shale gas need to be approached differently, Hahn says. “In the tight oil you spend a little more time trying to work with your frac fluids, and your jobs aren’t nearly as big. Their pays are much thinner, so you are working with a much more confined space within the rock deposition.”

The Canadian Bakken is a lot thin-ner and shallower than its American cousin and has neighbouring water zones that the United States generally lacks, so multistage fracking has to be approached delicately. “To get good coverage and make it economic, you put more fracs in there but they are a lot smaller and you pump them at much lower rates. Extra volume makes your frac grow more upwards and you end up in water, and then you end up with a water well,” says Hahn.

undersTanding The reservoirMurray Reynolds, senior completions technical advisor with TAQA North Ltd., who once consulted with Hahn, is on the same path. He believes there is too much of the attitude of “what-ever the other guy is doing is what I will do”—an attitude that is unneces-sarily costing producers.

“I think in general, people are put-ting too many fracs into the ground,” he says. “Over time, people have migrated to tighter and tighter spac-ing—I saw some out there as close as 30- or 40-metre spacing.” Whether they are using coiled tubing, mongoose- style fracs or plug-and-perf style, he

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notes, “every frac costs a significant amount of money.”

It is important to decide on opti-mum well length, fracture spacing and well spacing early on, he says. “I think the key is to understand the reservoir, what is the reservoir telling you, and do some modelling work to come up with an initial guesstimate, then go out into the field, complete the wells, review it in three to six months after you have got some production data and see if it still goes around.”

A good place to start is with some kind of analytical model, which are available from various vendors. Com-pared to numerical reservoir mod-els—which are far more complex and can take weeks to provide answers—analytical models take mere hours and require inputs that are relatively simple: “just your typical height, net pay, porosity, permeability, water saturation, reservoir pressure, oil properties, what do you think you are getting for frac half-lengths, that kind of thing,” Reynolds says.

In a relatively short period of time, an operator can do a number of sensitivities, he says, on aspects like permeability, net pay, frac half-length and number of fracs along the hori-zontal. “Then [the model] will pro-vide a forecast of initial production, a production versus time curve, pro-duction rate versus time and cumula-tive production recovery over time, so you can fairly quickly zoom in on what type of recovery you are going to get in, say, a 10-year period.”

Permeability is one of the key parameters. “If you have a higher perm reservoir you’ll need fewer fracs along the horizontal. In these types of tight oil environments where you have a range from maybe 0.05–0.5 millidarcy, if your average perm is 0.5 versus 0.05, it makes a big difference on the number of fracs, just because the oil can move more easily through the reservoir.”

In a study of Society of Petroleum Engineers (SPE) literature of the Bak-

ken and Cardium plays, Reynolds found a wide range of conclusions on opti-mum number of fractures. Anywhere from three to more than 40 frac stages have been pumped in Cardium and Bakken horizontal wells, with little con-sistency, even within the same operator, as to optimum frac stages.

In four SPE papers Reynolds highlighted, the optimum frac spacing range should be between 90 and 150 metres, with three of the four suggesting about 150 metres is the optimum. His own analytical modelling came to a similar conclusion.

“For the Bakken—not the deep, high-pressure North Dakota Bakken but more like the Viewfield Saskatchewan Bakken—optimum spacing is between 100 and 150 metres,” he says. Spacing may need to be tempered by the oper-ator’s view of heterogeneities in the reservoir, as well as future possibilities of waterflood and enhanced oil recovery operations. This may support some tighter frac spacing. The next question operators will be addressing is: are we happy with only 10–15 per cent recovery factors from producing these expensive wells by primary production?”

His study concluded that at both 0.5 and 0.2 millidarcy permeability, there was no advantage to pumping more than 10 frac stages (155-metre spacing) and that at 0.05 millidarcy permeability, optimum initial pro-duction (IP) and reserves recovery was at 20 stages (74-metre spacing). No cases showed an advantage to applying more than 20 stages (closer than 74 metres), while optimum spacing for all permeability ranges was between 75 and 150 metres.

daTa analysisHaving performed the modelling work and collected data in a busy season of drilling, Enerplus is in the midst of evaluating its results, Hahn says. “You calibrate what you have and you see if you can do better, or better under-stand what changes you want to make as you go forward, be it increasing your density, be it increasing proppant size or whatever other changes will optimize production.”

The company has come to some conclusions, such as determining that using foam rather than a gelled-water style frac has its advantages. “The beauty of foams is, of your total fluids volume that you are pumping down there, only 15 per cent of it is water, so you are not pumping nearly as much water.”

However, using foam (generally 85 per cent nitrogen) results in a lot of compressibility. “So to predict what your hydrostatic pressure and friction are is very, very difficult.” A key diagnostic tool, therefore, is a downhole pressure gauge at the point of fracking to get a reading on frac geometry. “That pressure signature tells you lots about how your frac is growing, how much height you have and how much lateral length you have,” Hahn says.

“We have had some really good well results where we haven’t seen damage issues, and we have got very good and quick cleanup—we got the water out that we pumped.”

Fracture spacing, which Hahn says is a function of rock permeability, has been about 60 metres in generally 600-metre laterals in the Viking, where hole stability is more of an issue, and about 125 metres in 1,000- to 1,200-metre laterals in the Cardium.

It has been suggested that boosting the number of fracs is sometimes used as a strategy to inflate IP rates, at a long-term cost to overall production. Reynolds and Hahn say it could have that effect.

“More fracs will give you higher IP but probably no higher cumulative recovery,” Reynolds says. “If you put more fracs in early, those additional fracs interfere with each other quicker, so you get a higher decline and ulti-mately you will get about the same recovery you would have had with a lot fewer fracs.”

“More is not necessarily better. It may give you good IPs, but [are] there economics to it if it stabilizes out at the same rate or an even lower rate?” asks Hahn. “Quite often when you pump bigger jobs you are just getting more vertical growth, so you are not getting more lateral exposure of your rock and thus you are not gaining anything. So there again the bigger ham-mer is not necessarily better, if there [are] no economics to it.” ■

“I think in general, people are putting too many fracs into the ground.… Whether they are using coiled tubing, mongoose-style fracs or plug-and-perf style, every frac costs a significant amount of money.”

enerplus corporation | TaQa north


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Decline Curve Challengefrom nanoTechnology and geochemical processes To propane fracs—all Technologies are on The Table in indusTry’s QuesT for susTained and profiTable shale gas producTionBy Godfrey Budd

in The wake of dramatic headlines beginning a couple of years ago that have trumpeted vast shale gas poten-tial for North America, the focus of much sober second thought has turned to the question of whether all the gas can be produced in the volumes predicted.

True, shale gas production has skyrocketed. Today, it accounts for almost 20 per cent of U.S. gas production, compared to 1.6 per cent in 1996. But, time and again, producers have been taken aback by steep declines; next door to a field of healthy producers, a new well is drilled and, within days of comple-tion, the newbie’s production has fallen off a cliff. “Rock proper-ties are sometimes quite dif-ferent just a few miles away. You’ve got to do the science before you start producing, but you can go bust learning everything about a shale play,” says Steve Drake, senior vice-president at Dallas-based Marsh Operating Co.

But, it can be argued, a grow-ing body of literature and company reports seem to promise sustainability for the shale gas sector. Industry has identified impairment mechanisms to fracture conductivity, like gel dam-age, embedment, proppant crushing and fines invasion. This has resulted in materials and methods to reduce their effect on fracture conductivity—and improve production.

Petrohawk Energy Corporation recently cited tighter well spacing, more proppant and Schlumberger HiWay technology as helping to improve production in the Eagle Ford shale. It also reported using restricted rate production practices and refining its well design with the aim of lower-ing pressure requirements.

But experts say that what works in one field might not be the solution in

another. They say the shale resource play is one of both complexity and variety—and both are a source of many of the headaches.

Adding to the uncertainties around shale plays is that they appear vulner-able to short-term fast-buck strategies that might boost initial production (IP) rates but work against long-term pro-ductivity, says Drake. High IP rates tend to be riskier, he says, where pressures downhole are greater—less so if the shale is hard or the pressure is lower.

arps analysisSeveral inappropriate practices are compounding the technical chal-lenges of shales, says James Crafton,

president of Performance Sciences Inc. They include imprecise or incomplete metrics when comparing well performance, poor flowback management with excessive emphasis on rapid load water recov-ery, insufficient cost- benefit analysis of long laterals and over-reliance

on Arps decline curve analysis for predicting shale reservoir behav-iour and production. (Arps decline curve analysis is a relatively simple and often used method to deter-mine reservoir performance.) “Arps decline curve is being used, but it doesn’t work well enough in complex shales,” says Crafton.

The issue of Arps curves surfaced in a recent paper presented in January at the Society of Petroleum Engineers (SPE) Hydraulic Fracturing Technology Conference and Exhibition in The Woodlands, Texas. “People are trying to make them work, but Arps curve analy-ses were not developed for the types of wells in shales,” says Christopher Clarkson, a professor in the department of geoscience at the University of Calgary and a co-author of the paper.

Based on a hybrid model that com-bines transient flow analysis with Arps, the paper proposes a forecasting method for multi-fractured horizon-tal wells (MFHW) with equal frac spacings and another for heteroge-neous completions, where frac spacings are unequal.

proppanT useAnother factor affecting decline curves involves the use of proppants, which scientists now believe undergo changes downhole that affect conductivity.

Understandably, the issue is a focus of research at Halliburton’s Duncan Technology Center in Duncan, Okla., as the use of proppants is central to MFHW completions. The research work stems from the view that today’s remedies for proppant crush-ing, embedment and so on don’t address the full range of proppant-related mechanisms that can reduce fracture conductivity.

An SPE paper by researchers at Duncan states, “Stimulated wells rarely achieve the theoretical con-ductivity of a given proppant. In addition, fracture conductivity often declines continuously, suggesting that there are other factors that influence long-term fracture conductivity.”

“It’s a rather overwhelming prob-lem,” says Jim Weaver, a co-author of the paper and senior scientific adviser, PE Methods and Materials, at the Duncan centre. He says that proppant pack porosity can drop from 40 to 10 per cent as a result of the downhole geochemical processes.

Based on field and lab data, the paper concludes that “coating prop-pant with a hydrophobic film reduces the action of water on the proppant and reduces the chemical reactions that lead to compaction. Coating both the proppant and the formation face with a hydrophobic film pro-vided by a new SMA (surface modifi-cation agent) appears to provide the best protection against geochemical reactions that lead to loss of fracture conductivity caused by porosity- filling and compaction mechanisms.”

gas fracsThe critical role of completions methodology and materials and the possible niche applications of hydrocarbon- rather than water-based fracs are highlighted by the recent experience of Halifax-based Corridor Resources Inc., a junior

marsh operating co. | petrohawk energy | gasfrac

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operating in a shale play in New Brunswick. In December 2009, Corridor announced that it had completed segregated testing of two intervals in the Frederick Brook Formation that had been fractured with propane at its vertical Green Road G-41 well.

The first test interval, a black shale at a depth range of 2,000–2,050 metres, was flowing at a rate of 430,000 cubic feet per day at the end of an 83-hour flow period. The second test interval, a silty, sandy shale at 1,850–1,900 metres, was very prolific. It produced a total of 42.4 million cubic feet (mmcf) of natural gas over a 185-hour period, with a final flowing rate of three mmcf per day. The well was shut in after testing.

A year later, in December 2010, the news from two other horizontal wells nearby, each completed with a slick-water frac, was not so good.

Gas flow from the two wells was “zero” for one and “negligible” for the other. Given the strong gas shows while drilling the horizontals of

both wells and, especially in light of the fact that a frac in a silty interval of one of the horizontals was less than a kilometre away from that of the previous year’s prolific vertical, it’s easy to see why a Dec. 6, 2010, Corridor press release described the horizontals’ performance as “both unexpected and perplexing.”

Propane fracs could be a better fit for some shale completions, suggests Eric Tudor, vice-president of engineer-ing at GasFrac Energy Services Inc., a company that provides its proprietary Vantage LPG fracturing process. “The properties of propane density, surface tension and viscosity are all superior [to] water, and allow for propane to be recovered from the formation. With hydraulic fracs in shale, often 20 per cent is recovered, and considered very good if you recover 50 per cent. The water left behind has the potential to block the flow of hydrocarbon,” says

Tudor. He adds that propane typi-cally mixes more easily with in-place hydrocarbons, often has frac fluid recovery rates in the 90 per cent range and can be recycled.

nano soluTionsNanotechnology is also being applied to improve downhole multi-phase liquid flows and boost production. CESI Chemical, a division of Flotek Industries Inc., has been providing industry with micro-emulsions of a range of complex nano fluids (CnF) to improve downhole flows—and production curves. The selection of the CnF additive is determined by specific downhole conditions, including percentage of clays, pres-sures, pumping rate, microbiological activity and potential for scale gen-eration, according to an SPE paper co-authored by Glenn Penny, director of technology at CESI.

“It reduces the differential pres-sure requirements for getting any fluid to flow out of the formations. It acts in ways that are comparable, although not exactly the same, as surfactants. It helps gas flow as there is less resistance on pore walls. It also helps the dewatering process because of reduced inter-facial tension. It’s a non-ionic product and has no charge,” says Richard Fox, director of marketing and sales at CESI.

Developed at CESI, there are more than a dozen CnF formulations tar-geting a range of applications and downhole conditions, including wet and dry gas, oil and wellbore clean-outs, says Fox.

Performance Sciences’ Crafton has done several studies comparing the performance of wells treated with CnF to wells not treated with CnF, one of which is on the Flotek web-site. One study included comparisons of the effective fracture half-length in feet of CnF and non-CnF wells in Wyoming’s Green River Basin. (Frac-ture half-length refers to the radial distance from a wellbore along a fracture that has conductivity.) Aver-aged out, the fracture half-length for the CnF wells after seven days was 177 feet, compared to 124 feet for non-CnF wells. After 90 days, the gap widened between the two groups, with CnF wells averaging 163 feet and non-CnF wells averaging 92 feet (see graph). “Wells with CnF were roughly 50 per cent better after one week,” says Crafton.

After 90 days, as the numbers indi-cate, the CnF wells performed almost 100 per cent better. “These numbers are based on interpretations of pro-duction figures,” says Crafton.

Nanotechnology could also soon have a role in downhole monitoring and observation of fractures. Most current sensor technology is not very effective as distance from the well-bore increases. “The more sensitive ones don’t go out far enough and large-scale surveying of a frac is too low resolution,” says David Potter, a professor in petro- and geophysics at the University of Alberta.

His research and development work has been involved with attaching nano-particles with high magnetic susceptibility to proppants. The idea is that the nano-particles, because of their magnetic properties, could enable a better signal from within the fracture to sensors in the wellbore. “A sensor could sit on a standard logging string,” says Potter, who adds that nano-sensor technology can be used to assess permeability.

new ToolsA range of tools and tactics seems to be emerging to address the technical challenges of shale development—and hold the line on declines. For example, Schlumberger Limited’s new SonicScope 475 tool can acquire wireline-quality sonic data while drilling. “Using SonicScope, you can characterize the rock mechan-ics along a lateral while drilling and save a wireline trip,” says Jean-Marie Degrange, Schlumberger’s product champion for SonicScope.

The use of traditional plunger-lift technologies combined with fine-tuned monitoring and control can help optimize production from horizontals, says David Cosby, an engineer at Harbison-Fischer Manufacturing Co. This, he says, is despite the fact that much of the water is inevitably behind, not in front of, the plunger-lift.

And for those already-completed wells that could produce better, a refrac that takes advantage of the latest completion methods and technologies could be the answer, says Gary Schein, vice-president of engineering and technology at Dale Resources LLC.

The key, perhaps, to the shale resource is that there is no single key. Instead, it seems, there are many. ■

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/Dperformance sciences | halliburton | cesi chemical

direcTorytech guide

70

Drilling

3D Drilling Tools Inc.8135 Wagner Rd. Edmonton AB T6E 4N6 780-440-1922 www.3Ddrillingtools.ca

Accudrill Inc.Bay 14, 702 - 18 Ave. Nisku AB T9E 7V8 780-955-9337 www.accudrill.com

Advance Drilling Ltd.400, 221 West Esplanade North Vancouver BC V7M 3J3 604-980-5973

Aero Drilling & Consulting Ltd.Box 263 Bentley AB T0C 0J0 403-748-3603

AKITA Drilling Ltd.900, 311 - 6 Ave. S.W. Calgary AB T2P 3H2 403-292-7979 www.akita-drilling.com

Alta. Can. Oil Tool Int. Ltd.Box 370 Avonlea SK S0H 0C0 306-868-2291

Arrival Oil Tools Inc.946 - 55 Avenue N.E. Calgary AB T2E 6Y4 403-730-6660 www.arrivaloiltools.com

B.W. Rig Supply609 - 21 Ave. Nisku AB T9E 7X9 780-955-8686 www.hyduke.com

Baker Hughes Canada Company1000, 401 - 9 Ave. S.W. Calgary AB T2P 3C5 403-537-3400 www.bakerhughes.com

BBJ Tools Inc.5430 - 30 St. S.E. Calgary AB T2C 1G2 403-236-8224 bbjtools.com

Beaver Drilling Ltd.910, 500 - 4 Ave. S.W. Calgary AB T2P 2V6 403-265-6472 www.beaverdrilling.com

Beck Drilling and Environmental Services Ltd.9919 Shepard Rd. S.E. Calgary AB T2C 3C5 403-297-1399 www.beckdrill.com

Bertram Drilling Corp.10 Main St., Box 100 Carbon AB T0M 0L0 403-572-3591 www.bertramdrilling.com

Bico-Faster Drilling Tools Inc.805, 505 - 6 St. S.W. Calgary AB T2P 1X5 403-262-5595 www.bicodrilling.com

Big Sky Drilling Inc.Box 659 Oxbow SK S0C 2B0 306-483-5132

Black Diamond Energy Services2000, 715 - 5 Ave. S.W. Calgary AB T2P 2X6 403-206-4747 www.blackdiamondlimited.com

B-Line Directional DrillingBox 1240 Elk Point AB T0A 1A0 780-210-2225

Boundary Equipment Co. Ltd.10740 - 181 St. Edmonton AB T5S 1K8 780-483-3133 www.boundaryequipment.com

Calmena Energy Services Inc.700, 333 - 7 Ave. S.W. Calgary AB T2P 2Z1 403-225-3879 www.calmena.com

Canadian Association of Oilwell Drilling Contractors800, 540 - 5 Ave. S.W. Calgary AB T2P 0M2 403-264-4311 www.caodc.ca

CanElson Drilling Inc.700, 808 - 4 Ave. S.W. Calgary AB T2P 3E8 403-266-3922

CARBIDE.CA55 Queens Dr. Toronto ON M9N 2H3 416-895-4769 www.carbide.ca

Cathedral Energy Services Ltd.1700, 715 - 5 Ave. S.W. Calgary AB T2P 2X6 403-265-2560 www.cathedralenergyservices.com

Champion Drilling Inc.Box 1090 Brooks AB T1R 1B9 403-362-4400 www.ensignenergy.com

Chinook Drilling2550, 300 - 5 Ave. S.W. Calgary AB T2P 3C4 403-269-2612 www.chinookdrilling.ca

Classic Oilfield Service Ltd5211 - 65 St. Lloydminster AB T9V 2E8 780-875-3276 www.classicoil.com

Columbia Oilfield Supply9280 - 25 Ave. Edmonton AB T6N 1E1 780-437-5110 www.precisiondrilling.com

Compass Directional Services Ltd.400, 525 - 11 Ave. S.W. Calgary AB T2R 0C9 403-237-8799 www.compassdirectional.com

ContainerWest11660 Mitchell Rd. Richmond BC V6V 1T7 800-561-9530 www.containerwest.com

Control Drilling Service (1987) Ltd.5921 - 87A St. Edmonton AB T6E 5W6 780-465-6006 www.controldrillingservice.com

Cougar Drilling Solutions7319 - 17 St. Edmonton AB T6P 1P1 780-440-2400 www.cougards.com

Cubex Limited12126 - 44 St. S.E. Calgary AB T2Z 4A2 403-258-1544 www.cubexltd.com

D & D Oilfield Rentals Corp.Box 1197 Redcliff AB T0J 2P0 403-548-2700 www.ddoil.net

Daily Oil Bulletin2 Fl., 816 - 55 Ave. N.E. Calgary AB T2E 6Y4 403-209-3500 www.dailyoilbulletin.com

Decarson Rentals1203 - 4 St. Nisku AB T9E 7L3 780-955-9420 www.essentialenergy.ca

Densak Pipe & Oilfield Trucking Service20 Strathcona Rd. S.W. Calgary AB T3H 1V5 403-246-5551

Drilformance ULC6051 - 47 St. Leduc AB T9E 7A5 780-980-5881 www.drilformance.com

Drilling Controls Canada Inc.607 - 22 Ave. Nisku AB T9E 7X7 780-955-2400

Drilling Fluids Treatment Systems Inc. (DFTS)7530 - 114 Ave. S.E. Calgary AB T2C 4T3 403-279-0123 www.dfts.com

Dril-x-Fluids Inc.480, 840 - 6 Ave. S.W. Calgary AB T2P 3E5 403-444-1517 www.dril-x.com

Encore Coring & Drilling Inc.1345 Highfield Cres. S.E. Calgary AB T2G 5N2 403-287-0123 www.ensignenergy.com

Enerflow Industries Inc.4800 - 27 St. S.E. Calgary AB T2B 3M4 403-279-9696 www.enerflow.com

Energy Drilling Services Inc.8921 - 50 St. Edmonton AB T6B 1E7 780-485-0999 www.energydrilling.ca

Ensign Energy Services Inc.1000, 400 - 5 Ave. S.W. Calgary AB T2P 0L6 403-262-1361 www.ensignenergy.com

Excalibur Drilling Ltd.700, 435 - 4 Ave. S.W. Calgary AB T2P 3A8 403-269-2041 www.excaliburdrilling.com

Excell Specialty Ltd.9516 - 62 Ave. Edmonton AB T6E 0C9 780-437-2776

Fiberbuilt Manufacturing Inc.3613 - 63 Ave. S.W. Calgary AB T3J 5K1 403-274-6366 www.fiberbuilt.com

Fill Movers Inc.300, 400 - 5 Ave. S.W. Calgary AB T2P 0L6 877-513-7455 www.fillmovers.com

Foremost Industries LP1225 - 64 Ave. N.E. Calgary AB T2E 8P9 403-295-5800 www.foremost.ca

FP Marangoni Inc.Hawkwood Box 62062 Calgary AB T3G 5S7 403-241-9180 www.fpmarangoni.com

Garritty & Baker Drilling Inc.5715 - 56 Ave. Edmonton AB T6B 3G3 780-433-8786 www.garrittyandbakerdrilling.com

H.M.F. Oil Co. Ltd.408 Mississippian Dr., Box 938 Estevan SK S4A 2A7 306-634-7688 www.hmfoil.ca

Halliburton Group Canada1600, 645 - 7 Ave. S.W. Calgary AB T2P 4G8 403-231-9300 www.halliburton.com

HiTech Fluid Systems Ltd.1800, 505 - 3 St. S.W. Calgary AB T2P 3E6 403-547-2906 www.hitechfluid.com

Horizon Drilling Inc.900, 606 - 4 St. S.W. Calgary AB T2P 1T1 403-290-0308 www.horizondrilling.ca

Hyduke Energy Services Inc.609 - 21 Ave. Nisku AB T9E 7X9 780-955-0355 www.hyduke.com

Hyduke Machining Solutions2915 - 15 St. N.E. Calgary AB T2E 7L8 403-250-5323 www.stratex-mco.com

Impact Rock BitsBox 6448 Peace River AB T8S 1S3 780-624-2640 www.impactrockbits.com

tech guidedirecTory

direcTorytech guide

71Ironhand Drilling Inc.405, 535 - 10 Ave. S.W. Calgary AB T2R 0A8 403-237-6789 www.ironhanddrilling.com

Jomax Drilling (1988) Ltd.2020, 355 - 4 Ave. S.W. Calgary AB T2P 0J1 403-265-5312 www.jomax.ca

K & D Pratt Ltd.210 John Savage Ave., Box 279 Dartmouth NS B3B 0C9 902-468-1955 www.kdpratt.com

K Tec Industries (2005) Inc.Box 1060 Grande Prairie AB T8V 4B5 780-538-1855

Komat DrillingBox 20126 Medicine Hat AB T1A 8M4 403-580-7476

Lory Oilfield Rentals Inc.1004 - 15 Ave. Nisku AB T9E 7S5 780-955-2626 www.oilfieldrentals.com

Lougheed Welding & Fabrication (2005) Ltd.405 - 18 Ave. Nisku AB T9E 7T5 780-955-3700 www.lougheedwelding.com

Marquis Alliance Energy Group Inc.1800, 800 - 6 Ave. S.W. Calgary AB T2P 3G3 403-264-1588 www.marquisalliance.com

Matco Manufacturing Ltd.Box 2, Site 2, R.R. 2 Sexsmith AB T0H 3C0 780-568-4484

MaxxiMat Inc.21074 - 5 St. Nisku AB T9E 7X4 780-979-6588 www.maxximat.com

McCaw’s Drilling & Blasting Ltd.4228 - 47 Ave., Box 2250 Rocky Mountain House AB T4T 1B6 403-845-3101 www.mccawsdrilling.com

Mi Casa Rentals Inc.200, 435 - 4 Ave. S.W. Calgary AB T2P 3A8 403-262-2288 www.micasa-rentals.com

N.O.V. Downhole2700, 144 - 4 Ave. S.W. Calgary AB T2P 3N4 403-234-9999 www.nov.com

Nabors Canada2800, 500 - 4 Ave. S.W. Calgary AB T2P 2V6 403-263-6777 www.nabors.com

Newsco Directional & Horizontal Drilling Services Inc.7000 Railway St. S.E. Box 8388 Calgary AB T2H 3A8 403-243-2331 www.newsco.ca

Noble Drilling (Canada) Ltd.4 Fl., 10 Fort William Pl. St. John’s NL A1C 1K4 709-758-4400 www.noblecorp.com

Norseman Inc.14545 - 115 Ave. Edmonton AB T5M 3B8 780-451-6828 www.norseman.ca

NorthBasin Energy Services Inc.150, 707 - 10 Ave. S.W. Calgary AB T2R 0B3 403-648-8600 www.northbasinenergy.com

Northwell Rentals Inc.9111 - 39 Ave. Edmonton AB T6E 5Y2 780-437-7469

OK Drilling Services L.P.Box 700 Red Deer AB T4N 5G6 403-343-8860 www.okdrilling.com

Parsons Oilfield Services & Supply Inc.88 Scandia Rise N.W. Calgary AB T3L 1V6 403-818-2005

Pason Systems Inc.6130 - 3 St. S.E. Calgary AB T2H 1K4 403-301-3400 www.pason.com

Patterson - UTI Drilling Canada Limited1450, 101 - 6 Ave. S.W. Calgary AB T2P 3P4 403-269-2858 www.patenergy.com

Peloton Computer Enterprises Ltd.450, 1000 - 7 Ave. S.W. Calgary AB T2P 5L5 403-263-2915 www.peloton.com

Petris Canada805, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-225-4954 www.petris.com

Precision Drilling Corporation4200, 150 - 6 Ave. S.W. Calgary AB T2P 3Y7 403-716-4500 www.precisiondrilling.com

Prinoth Ltd.6815A - 40 St. S.E. Calgary AB T2C 2W7 403-279-7271 www.prinoth.com

Prudential Energy Services Ltd.Box 887 Grande Prairie AB T8V 3Y1 780-539-1444 www.prudentialenergy.ca

Quintera Drilling LPBox 1408 Brooks AB T1R 1C3 403-501-3704

R & M Energy Systems Canada3703 - 98 St. Edmonton AB T6E 5N2 780-465-9500 www.rmenergy.com

RBI Canada 2000 Inc.5677 Burleigh Cres. S.E. Calgary AB T2H 1Z7 403-255-3730 www.rbi-canada.com

Richfield Equipment Ltd.337, 440 - 10816 Macleod Tr. S Calgary AB T2J 5N8 403-236-0056 www.richfieldequipment.ca

Rig Locator2 Fl., 816 - 55 Ave. N.E. Calgary AB T2E 6Y4 403-209-3500 www.nickles.com/rig

Rigworks Oilfield Solutions Inc.1606 - 13 St. Nisku AB T9E 0K4 780-955-3959 www.rigworks.ca

Rotary Sales & Service9516 - 62 Ave. Edmonton AB T6E 0C9 780-434-3621

Rowan Companies, Inc.1070, 99 Wyse Rd. Dartmouth NS B3A 1L9 902-469-1973 www.rowancompanies.com

Savanna Energy Services Corp.1800, 311 - 6 Ave. S.W. Calgary AB T2P 3H2 403-503-9990 www.savannaenergy.com

Saxon Energy Services Inc.1700, 700 - 4 Ave. S.W. Calgary AB T2P 3J4 403-716-4150 www.saxonservices.com

Schlumberger Canada Ltd.525 - 3 Ave. S.W. Calgary AB T2P 0G4 403-509-4000 www.slb.com

Sentry Pumping Units International450, 444 - 5 Ave. S.W. Calgary AB T2P 2T8 403-775-7077 www.sentryinternational.net

Sicotte Drilling Tools Inc.1101 - 77 Ave. Edmonton AB T6P 1M8 780-440-6700 www.sicottedrillingtools.com

Simmons Group Inc.800, 906 - 12 Ave. S.W. Calgary AB T2R 1K7 403-244-5340 www.simmonsenergy.com

Singletouch Canada Inc.300, 110 - 8 Ave. S.W. Calgary AB T2P 1B3 403-648-3930 www.singletouch.com

Smith Drilling & Remedial710, 396 - 11 Ave. S.W. Calgary AB T2R 0C5 403-264-6077 www.siismithservices.com

Smith International Canada, Ltd.710, 396 - 11 Ave. S.W. Calgary AB T2R 0C5 403-264-6077 www.smith.com

Southwest Distribution Ltd.9691 - 45 Ave. N.W. Edmonton AB T6E 5Z8 780-434-3473

Sphere Drilling Supplies3112 - 80 Ave. S.E. Calgary AB T2C 1J3 403-720-9333 www.spheredrilling.com

Stoneham Drilling Inc.1020, 850 - 2 St. S.W. Calgary AB T2P 0R8 403-264-7777 www.stonehamdrilling.com

Strip-O-Matic Rentals & Sales Ltd.Box 73037 Edmonton AB T5T 3X1 780-577-5112

T1 HDD Services Inc.2059 #3, 9899 - 112 Ave. Grande Prairie AB T8V 7T2 866-814-5254 www.t1hddservices.com

Tall Pine Drilling Ltd.Box 700 Bentley AB T0C 0J0 403-748-2955 www.tallpinedrilling.com

Technicoil Corporation, Drilling Division1700, 555 - 4 Ave. S.W. Calgary AB T2P 3E7 403-509-0700 www.technicoilcorp.com

Teledrift Canada Inc.7, 4275 - 78 Ave. S.E. Calgary AB T2C 2Y4 403-203-0840

Tempco Drilling Company Inc.Box 5543, Stn. A Calgary AB T2H 1X9 403-259-5533

Terracon Geotechnique Ltd.140, 2723 - 37 Ave. N.E. Calgary AB T1Y 5R8 403-266-1150 www.terracon.ca

Terracon McKay Ltd.140, 2723 - 37 Ave. N.E. Calgary AB T1Y 5R8 403-266-1150 www.terracon.ca

Terroco Drilling Ltd.4044, 39139 Hwy. 2A Red Deer County AB T4S 2A8 403-343-6236 www.terroco.com

The Crossing Company Inc.1807 - 8 St. Nisku AB T9E 7S8 780-955-5051 www.thecrossingcompany.com

The Motor Company5420 - 53 Ave. S.E. Calgary AB T2C 4R3 403-230-3055 www.themotorcompany.ca

Total Energy Services Inc.2550, 300 - 5 Ave. S.W. Calgary AB T2P 3C4 403-216-3939 www.totalenergy.ca

Tracer Supervision1110, 340 - 12 Ave. S.W. Calgary AB T2R 1L5 403-261-7097 www.barlon.ca

Tracker Sales & Rentals Ltd.Box 809 Bowden AB T0M 0K0 403-224-0000 www.trackersalesltd.com

Trendon Bit Service Ltd.Box 548 Redcliff AB T0J 2P0 403-548-7242 www.trendonbitservice.com

Treo Drilling Services L.P.R.R. 2 Ponoka AB T4J 1R2 403-783-5720 www.treodrilling.com

Trinidad Drilling Ltd.2500, 700 - 9 Ave. S.W. Calgary AB T2P 3V4 403-265-6525 www.trinidaddrilling.com

Tri-Service Oilfield Manufacturing Ltd.9545 - 58 Ave. N.W. Edmonton AB T6E 0B8 780-434-9596 www.tsm.ca

Tristar Resource Management Ltd.800, 815 - 8 Ave. S.W. Calgary AB T2P 3P2 403-262-8595 www.tstar.ca

Univar Canada Ltd.9800 Van Horne Way Richmond BC V6X 1W5 604-273-1441 www.univarcanada.com

Varel Rock Bits Canada Inc.9926 - 29 Ave. Edmonton AB T6N 1A2 780-435-5706 www.varelrockbits.com

Viper Rentals & Services Ltd.10709 - 95 St. High Level AB T0H 1Z0 780-926-3366 www.viperrentals.ca

Walters Oil Tool Machine Ltd.9924 - 29 Ave. Edmonton AB T6N 1A2 780-462-4744

Wenzel Downhole Tools Ltd.1000, 717 - 7 Ave. S.W. Calgary AB T2P 0Z3 403-262-3050 www.downhole.com

Westquip Diesel Sales (Alta.) Ltd.11720 - 181 St. Edmonton AB T5S 1M6 780-486-2645 www.westquip.ca

XI Technologies1700, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-517-0111 www.xitechnologies.com

XL Fluid Systems102, 2531 Hochwald Ave. S.W. Calgary AB T3E 7K3 403-265-4344 www.xlfluids.com

X-Treme Energy Group8014 Edgar Industrial Cr., Box 6239 Red Deer AB T4P 3R3 403-341-0067 www.xeg.ca

Production

4-Way Equipment Rentals8430 - 24 St. Edmonton AB T6P 1X8 780-464-4929 www.4-way.com

Access Waterwells Inc.Box 7297 Edson AB T7E 1V5 780-723-2242 www.accesswaterwells.com

Accu-Flo Meter Service Ltd.4028 - 7 St. S.E. Calgary AB T2G 2Y8 403-243-1425 www.accuflo.com

Accurata Inc.120 MacEwan Park Rise N.W. Calgary AB T3K 4A1 403-295-1637 www.accurata.ca

Advanced Flow Tech6135 - 10 St. S.E. Calgary AB T2H 2Z9 403-212-2382 www.afti.ca

Advantage Mud Systems Ltd.730, 777 - 8 Ave. S.W. Calgary AB T2P 3R5 403-262-1120 www.advantagemud.com

Advantage Products Inc. (API)Suite 273, 1919B 4th St. SW Calgary AB T2S 1W4 403-264-1647 www.advantageproductsinc.com

AERO Rental Services6525 - 67 St. Red Deer AB T4P 1A3 403-340-0800 www.iroccorp.com

ALCO Gas & Oil Production Equipment Ltd. 5203 - 75 St. Edmonton AB T6E 5S5 780-465-9061 www.alcogasoil.com

Alpha Controls & Instrumentation6, 361 Steelcase Rd. West Markham ON L3R 3V8 905-477-2133 www.alphacontrols.com

Amos & Co. Ltd708, 804 - 3 Ave. S.W. Calgary AB T2P 0G9 403-272-9981

Annugas Compression Consulting Ltd.3601 - 48 St. Wetaskiwin AB T9A 3N9 780-361-2350 www.annugas.com

Apex Distribution Inc.550, 407 - 2 St. S.W. Calgary AB T2P 2Y3 403-268-7333 www.apexdistribution.com

direcTorytech guide

72Apex Energy Consultants Inc.700, 815 - 8 Ave. S.W. Calgary AB T2P 3P2 403-269-9550 www.apexenergy.com

Apex Equipment Ltd.116, 5726 Burleigh Cres. S.E. Calgary AB T2H 1Z8 403-214-2049 www.apexequipmentltd.com

Apex Oilfield Services (2000) Inc.910, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-257-5152 www.apexoil.ca

API Oilfield Hauling Inc.R.R. 1 Red Deer AB T4N 5E1 403-309-7400

Aqua-Pure Ventures Inc.1, 135 Commercial Dr. Calgary AB T3Z 2A7 403-301-4123 www.fountainquail.com

Arbrux LimitedUnit 6, 33 Alliance Blvd. Barrie ON L4M 5K2 705-739-7878 www.arbrux.com

Ardy Rigging Ltd.Box 180 Valleyview AB T0H 3N0 780-524-3459 www.ardyrigging.com

ATECH Application Technology Limited242, 3359 - 27 St. N.E. Calgary AB T1Y 5E4 403-261-0005 www.atech.ca

B & H Tank Systems Inc.6012 - 62 St. Taber AB T1G 2J4 403-223-9198

Baker Hughes Canada Company1000, 401 - 9 Ave. S.W. Calgary AB T2P 3C5 403-537-3400 www.bakerhughes.com

Barber Engineering and Controls5728 - 1 St. S.E. Calgary AB T2H 0E2 403-252-7651 www.barbereng.com

Baron Oilfield Supply9515 - 108 St. Grande Prairie AB T8V 5R7 780-532-5661 www.baronoilfield.ca

Bell Industries5317 - 91 St. Edmonton AB T6E 6E2 780-434-4401 www.bellindustries.net

Big Bear Energy Rentals Ltd.Comp. 7, Site 5, R.R. 1 Sylvan Lake AB T4S 1X6 403-887-2839 www.bigbearenergy.com

Black Ink Oilfield Mechanical Inc.5 Wellhead St. Devon AB T9G 1Z6 780-987-4924 www.black-ink.ca

Bonnett’s Energy ServicesBox 1, Site 33, R.R. 2 Grande Prairie AB T8V 2Z9 780-513-3400 www.bonnettsenergy.com

Bouchard Well Service Ltd.459 Aquaduct Dr., Box 1955 Brooks AB T1R 1C7 403-362-4732

Boundary Equipment Co. Ltd10740 - 181 St. Edmonton AB T5S 1K8 780-483-3133 www.boundaryequipment.com

Bowie Pumps of Canada Ltd.9333 - 41 Ave. N.W. Edmonton AB T6E 6R5 780-465-7812 www.bowiepumps.com

Brost Well ServicingBox 25012 Red Deer AB T4R 2M2 403-314-0434

Brother’s Specialized Coating Systems Ltd.150 - 76 Ave. Edmonton AB T6B 0A6 780-440-2855 www.brotherscoating.com

C.B. Engineering Limited20, 1220 - 59 Ave. S.E. Calgary AB T2H 2M4 403-259-6220 www.cbeng.com

Cactus Gas & Oil Operators Ltd.26 Chinook Dr. S.W. Medicine Hat AB T1A 4B3 403-526-8910

Calfrac Well Services Ltd.411 - 8 Ave. S.W. Calgary AB T2P 1E3 403-266-6000 www.calfrac.com

Calmena Energy Services Inc.700, 333 - 7 Ave. S.W. Calgary AB T2P 2Z1 403-225-3879 www.calmena.com

Cameron Canada Corporation Measurement Systems Division7944 - 10 St. N.E. Calgary AB T2E 8W1 403-291-4814 www.c-a-m.com

Canadian Association of Oilwell Drilling Contractors800, 540 - 5 Ave. S.W. Calgary AB T2P 0M2 403-264-4311 www.caodc.ca

Canadian Nitrogen Services Ltd.610B McCool St., Box 1909 Crossfield AB T0M 0S0 403-946-0404 www.canadiannitrogen.com

Canadian Well Logging Society2200, 700 - 2 St. S.W. Calgary AB T2P 2W1 403-269-9366 www.cwls.org

Canadian Wellhead Isolation Corp.34 Industrial Dr. Sylvan Lake AB T4S 1P4 403-340-3356 www.wellheadisolation.com

Canamara - United Supply8750 - 53 Ave. Edmonton AB T6E 5G2 780-468-4064 www.canamara-united.com

Canyon Technical Services Ltd.2900, 255 - 5 Ave. S.W. Calgary AB T2P 3G6 403-355-2300 www.canyontech.ca

Carbon Controls Ltd.Bay 124, 11979 - 40 St. S.E. Calgary AB T2Z 4M3 403-238-9944 www.carboncontrolsltd.com

Carnwood Wireline Service Ltd.108, 3907 - 98 St. Edmonton AB T6E 6M3 780-434-1122 www.carnwood.com

Cartel Energy Services Inc.Box 155 Beiseker AB T0M 0G0 403-947-3334 www.cartelenergy.com

Cathedral Energy Services Ltd.1700, 715 - 5 Ave. S.W. Calgary AB T2P 2X6 403-265-2560 www.cathedralenergyservices.com

CCS Corporation24 Fl., 530 - 8 Ave. S.W. Calgary AB T2P 3S8 403-233-7565 www.ccscorporation.ca

CCW Inc.6137 - 80 St. N.W. Edmonton AB T6B 0J7 888-317-0891 www.ccwinc.net

CE Franklin Ltd.Box 6776, Stn. D. Calgary AB T2P 2E8 403-531-5600 www.cefranklin.com

Cementing Technology & Equipment Ltd.6704 - 59 St. N.W. Edmonton AB T6B 3N6 780-485-8799 www.cteltd.com

Central Alberta Well Services Corp.6763 - 76 St. Red Deer AB T4P 3R7 403-341-3933 www.cawsc.com

Central Wireline Services4513 - 51 St., Box 1969 Stettler AB T0C 2L0 403-742-5000

Chad Equipment Ltd.101 - 3 Ave. West, Box 445 Neilburg SK S0M 2C0 306-823-4561

Champion Technologies Limited1400, 815 - 8 Ave. S.W. Calgary AB T2P 3P2 403-234-7881 www.champ-tech.com

Chemline Plastics Limited55 Guardsman Rd. Thornhill ON L3T 6L2 905-889-7890 www.chemline.com

Clariant (Canada) Inc.950, 717 - 7 Ave. S.W. Calgary AB T2P 0Z3 403-262-7846 www.oil.clariant.com

Classic Oilfield Service Ltd5211 - 65 St. Lloydminster AB T9V 2E8 780-875-3276 www.classicoil.com

Codeco Energy Group Inc.3 Fl., 3333 - 8 St. S.E. Calgary AB T2G 3A4 403-237-7808 www.codecoenergygroup.com

Cofex Ltd.Box 179, 3428 - 99 St. Edmonton AB T6E 5X5 780-914-4010

Coltek Energy Services Ltd.210, 9823 - 116 Ave. Grande Prairie AB T8V 4B4 780-538-9878 www.coltekenergy.com

Computer Modelling Group Ltd.150, 3553 - 31 St. N.W. Calgary AB T2L 2K7 403-531-1300 www.cmgl.ca

Concord Well ServicingBox 1528 Valleyview AB T0H 3N0 780-524-2113 www.concordwell.com

Conn Pumps630, 1010 - 1 St. S.W. Calgary AB T2R 1K4 403-262-5151 www.connpumps.com

Cool Air A/C Service & RepairBox 370 Avonlea SK S0H 0C0 306-868-2291

Couturier Oilfield Anchors Ltd.6306 - 50 Ave., Box 5039 Drayton Valley AB T7A 1R3 780-542-6358 www.couturieranchors.com

C-TECH Oilwell Technologies Inc.3201 - 84 Ave. Edmonton AB T6P 1K1 780-464-3800 www.ctechenergy.com

D & D Oilfield Rentals Corp.Box 1197 Redcliff AB T0J 2P0 403-548-2700 www.ddoil.net

Danco Equipment (2009) Inc.9111 - 41 Ave. Edmonton AB T6E 6M5 780-468-5151 www.dancoequipment.com

Daniel Industries Canada Inc.4215 - 72 Ave. S.E. Calgary AB T2C 2G5 403-279-1879 www.daniel.com

Davis Controls Limited2200 Bristol Circle Oakville ON L6H 5R3 905-829-2000 www.daviscontrols.com

Demand Data Services Inc.520, 736 - 6 Ave. S.W. Calgary AB T2P 3T7 403-263-3023 www.demanddataservices.com

Dewitz EnterprisesBox 2014 Whitecourt AB T7S 1P7 780-778-6232

Diamond Energy Services1521 North Service Rd. WestSwift Current SK S9H 3S9 306-778-6682 www.diamondenergy.ca

DPS Microbial Solutions312 - 3 St., Box 116 Frobisher SK S0C 0Y0 306-486-2110 www.dpsmicrobial.com

Drive Systems GroupUnit 1 & 2, 7150 Torbram Rd. Mississauga ON L4T 3Z8 905-405-0310 www.drivesystemsgroup.com

DrSCADA Automation160, 32 Westwinds Cres. N.E. Calgary AB T3J 5L3 403-264-5937 www.drscada.com

Eagle Well Servicing8113 - 49 Ave. Close Red Deer AB T4P 2V5 403-346-7789 www.eaglerigs.com

Electric Motor Service Limited8835 - 60 Ave. Edmonton AB T6E 6L9 780-496-9300 www.emsl.ca

Elmridge Engineering Inc.15, 3625 Weston Rd. Weston ON M9L 1V9 416-749-7730 www.elmridge.org

Endeavor E-Line Services1100, 250 - 2 St. S.W. Calgary AB T2P 0C1 403-265-9423 www.endeavoreline.com

Endress + Hauser Canada Ltd.1075 Sutton Dr. Burlington ON L7L 5Z8 905-681-9292 www.ca.endress.com

Enerchem International Inc.450, 440 - 2 Ave. S.W. Calgary AB T2P 5E9 403-269-1500 www.enerchem.com

Enerflex Ltd.904, 1331 Macleod Trail S.E. Calgary AB T2G 0K3 403-387-6377 www.enerflex.com

Enerflow Industries Inc.4800 - 27 St. S.E. Calgary AB T2B 3M4 403-279-9696 www.enerflow.com

Entero Corporation500, 1040 - 7 Ave. S.W. Calgary AB T2P 3G9 403-261-1820 www.entero.com

Environmental Refuelling Systems Inc.208 - 10464 Mayfield Rd. Edmonton AB T5P 4P4 780-444-4104 www.envirofuel.ca

ESG Solutions20 Hyperion Court Kingston ON K7K 7K2 613-548-8287 www.esgsolutions.com

Essential Energy Services Ltd.1100, 250 - 2 St. S.W. Calgary AB T2P 0C1 403-263-6778 www.essentialenergy.ca

E-T Energy Ltd.4895 - 35 B St. S.E. Calgary AB T2B 3M9 403-569-5100 www.e-tenergy.com

Ex-Cel Well Servicing Ltd.420 Boscuruis Ave., Box 775 Oxbow SK S0C 2B0 306-483-2281

Expro Group Canada Inc1650, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-532-0873 www.exprogroup.com

Flexpipe Systems3501 - 54 Ave. S.E. Calgary AB T2C 0A9 403-503-0548 www.flexpipesystems.com

Flowstar Technologies Inc.8709 - 50 Ave. Edmonton AB T6E 5H4 780-485-6667 www.flowstardcr.com

FMC Technologies Company6703 - 68 Ave. N.W. Edmonton AB T6B 3E3 780-468-9231 www.fmctechnologies.com/SurfaceWellhead.aspx

Fourth Meridian Enterprises Ltd.Box 1908 Lloydminster SK S9V 1N4 306-825-3373

Frac Rite Environmental Ltd.2, 4416 - 5 St. N.E. Calgary AB T2E 7C3 403-265-5533 www.fracrite.ca

Frontier Power Products Ltd.7983 Progress Way Delta BC V4G 1A3 604-946-5531 www.frontierpower.com

Galvanic Applied Sciences, Inc.7000 Fisher Rd. S.E. Calgary AB T2H 0W3 403-252-8470 www.galvanic.com

General Well Servicing Ltd.Box 700 Carnduff SK S0C 0S0 306-482-3244

Global Well Servicing Ltd.Box 7745 Drayton Valley AB T7A 1S8 780-515-9885 www.globalwellservicing.com

GPM Sales & Service Inc.4216 - 76 Ave. Edmonton AB T6B 2H8 780-432-6957 www.gpmsales.ca

GrenCo Industries Ltd.3710 - 78 Ave. Edmonton AB T6B 3E5 780-468-2000 www.grenco.com

GS Hitech Controls Inc.6173 - 6 St. S.E. Calgary AB T2H 1L9 403-255-7884

direcTorytech guide

73Halliburton Group Canada1600, 645 - 7 Ave. S.W. Calgary AB T2P 4G8 403-231-9300 www.halliburton.com

Hertz Equipment Rental8660 - 61 Ave. Edmonton AB T6E 5P6 780-435-3711 www.hertzequip.com

High Arctic Energy Services Inc.8112 Edgar Industrial Drive Red Deer AB T4P 3R2 403-340-9825 www.haes.ca

HiTech Fluid Systems Ltd.1800, 505 - 3 St. S.W. Calgary AB T2P 3E6 403-547-2906 www.hitechfluid.com

Hi-Tech Seals Inc.9211 - 41 Ave. N.W. Edmonton AB T6E 6R5 780-438-6055 www.hitechseals.com

Honeywell5925 Centre St. S.W. Calgary AB T2H 0C2 403-509-1200 www.honeywell.com/acs/indsol

Horizontal Well Testing Ltd.10, 5915 - 40 St. S.E. Calgary AB T2C 2H6 403-880-4030 www.horizontalwelltesting.com

Hot Rods Oilfield Services Inc.Box 428 Carnduff SK S0C 0S0 306-928-2245 www.hotrodsoilfieldservices.com

Hotshot Fire Trucks Ltd.51532 Range Rd. 25 Box 2728 Stony Plain AB T7Z 1Y2 780-823-0063 www.hotshotfiretrucks.com

Husky Transport Ltd.12155 - 242 Rd., Box 6070 Fort St. John BC V1J 4H6 250-785-8335 www.huskytransport.com

Hyduke Mechanical & Machining2311 - 8 St. Nisku AB T9E 7Z3 780-955-9559 www.hyduke.com

ICI Artificial Lift6010 - 53 Ave. Lloydminster AB T9V 2T2 780-872-7470 www.icisolutions.ca

ICS Group Inc.250081 Mountain View Trail Calgary AB T3Z 3S3 403-247-4440 www.icsgroup.ca

Impact Rock BitsBox 6448 Peace River AB T8S 1S3 780-624-2640 www.impactrockbits.com

Import Tool Corporation Ltd.10340 - 71 Ave. Edmonton AB T6E 0W8 780-434-6406 www.importtool.com

Infinity Oilfield Services Inc.R.R. 2 Sundre AB T0M 1X0 403-230-6031 www.infinityoilfield.com

Integrated Production Services Ltd.1900, 840 - 7 Ave. S.W. Calgary AB T2P 3G2 403-266-0908 www.ipsadvantage.ca

International Frontier Resources Corporation100, 601 - 10 Ave. S.W. Calgary AB T2R 0B2 403-215-2780 www.internationalfrontier.com

International Oilfield Equipment Brokers Ltd.4, 4063 - 74 Ave. S.E. Calgary AB T2C 2H9 403-299-2244 www.oilfieldequipment.com

Isotopes Canada Ltd.3, 1216 - 34 Ave. N.E. Calgary AB T2E 6L9 403-250-3968 www.isotopescanada.com

ITT Water & Wastewater300 av. Labrosse Pointe-Claire QC H9R 4V5 514-695-0100 www.ittflygt.ca

Jet Rentals & Sales Ltd.B102, 400 - 5212 - 48 St. Red Deer AB T4N 7C3 403-352-8579

John Crane Canada Inc.423 Green Rd. Stoney Creek ON L8E 3A1 905-662-6191 www.johncrane.com

Kanex Energy Corp.41 Springland Way Calgary AB T3Z 3N6 403-240-1863

Kayden Instruments3368 - 114 Ave. S.E. Calgary AB T2Z 3V6 403-253-1423 www.kayden.com

Keddco Mfg. Ltd.645 Keddco St., Box 999 Sarnia ON N7T 7K6 519-336-2960 www.keddco.com

Ketek Group Inc.20204 - 110 Ave. N.W. Edmonton AB T5S 1X8 780-447-5050 www.ketek.ca

KSM Inc.1904 - 4 St. Nisku AB T9E 7T8 780-955-3456 www.ksmrig.com

Kudu Industries Inc.9112 - 40 St. S.E. Calgary AB T2C 2P3 403-279-5838 www.kudupump.com

Lamarre Equipment Inc.9419 - 27 Ave. Edmonton AB T6N 1C9 780-438-3493 www.lamarreequipment.com

Lanco Well Services Ltd.14630 - 119 Ave. N.W. Edmonton AB T5L 2P2 780-452-3744

Leader Energy Services Ltd.700, 706 - 7 Ave. S.W. Calgary AB T2P 0Z1 403-265-5400 www.leaderenergy.com

Lochterra Inc.Box 2096, Stn. M Calgary AB T2P 2M4 403-651-4090

Lockwell Servicing Ltd.Box 700 Kindersley SK S0L 1S0 306-838-2014

Logan Completion Systems210, 600 6 Ave. S.W. Calgary AB T2P 0S5 403-218-2041 www.loganinternationalinc.com

Lonkar Well Testing Ltd.8080 Edgar Industrial Cres. Red Deer AB T4P 3R3 403-347-9727 www.lonkar.com

Lufkin Industries Canada Ltd.1050, 808 - 4 Ave. S.W. Calgary AB T2P 3E8 403-234-7692 www.lufkin.com

M.W. Hagel Consulting Ltd.18 Golden Key Estates Calgary AB T3P 1A5 403-265-7800 www.optimus.ab.ca


Master Flo Valve Inc.4611 - 74 Ave. Edmonton AB T6B 2H5 780-468-4433 www.masterflo.com

Matrix Drilling Fluids Ltd.1240, 540 - 5 Ave. S.W. Calgary AB T2P 0M2 403-265-7660 www.matrixdrillingfluids.com

Maxquip Inc.6235A - 86 Ave. S.E. Calgary AB T2C 2S4 403-258-3685 www.maxquip.ca

Mayco Well Servicing Inc.Box 575 Oxbow SK S0C 2B0 306-483-2367 www.maycowell.com

McAdoo Flow-Systems Ltd.Bay 6, 6115 - 4 St. S.E. Calgary AB T2H 2H9 403-547-5002 www.mcadooflowsystems.com

M-I SWACO5 Fl., 700 - 2 St. S.W. Calgary AB T2P 2W2 403-290-5300 www.miswaco.com

MicroSeismic, Inc.1200, 815 - 8 Ave. S.W. Calgary AB T2P 3P2 403-262-5780 www.microseismic.com

Miller Well Servicing Ltd.Box 1341 Weyburn SK S4H 3J9 306-861-6154

Mow-Tech Ltd.17740 - 118 Ave. N.W. Edmonton AB T5S 2W3 780-484-6356 www.mowtech.com

Mud Master Drilling Fluid Services Ltd.530, 1015 - 4 St. S.W. Calgary AB T2R 1J4 403-237-8900 www.mudmaster.ca

Muis Controls Ltd.29 Riel Dr. St Albert AB T8N 3Z2 780-459-7080 www.muiscontrols.com

Nabors Production Services33 Schenk Industrial Rd. Sylvan Lake AB T4S 2J7 403-887-7400 www.nabors.com

National Coating Technologies Inc.1975 Logan Ave. Winnipeg MB R2R 0H8 204-632-5585 www.nationalcoating.com

National Process Equipment5049 - 74 Ave. S.E. Calgary AB T2C 3H2 403-219-0270 www.natpro.com

Navigator Resource Consulting Ltd.610, 7015 Macleod Trail S.W. Calgary AB T2H 2K6 403-233-7380 www.navigator-resource.com

NCS Oilfield Services Canada1170, 800 - 6 Ave. S.W. Calgary AB T2P 3G3 403-988-6342 www.ncsfrac.com

Nelgar Oilfield Services101, 7477 - 49 Ave. Red Deer AB T4P 1N1 403-309-2620 www.nelgarservices.com

Netzsch Canada, Inc.740 Huronia Rd. Barrie ON L4N 6C6 705-797-8426 www.netzsch.com

New West Drilling Fluids Inc.777, 700 - 8 Ave. S.W. Calgary AB T2P 3R5 403-263-7555 www.newwestdf.com

Newpark Canada Inc.300, 635 - 6 Ave. S.W. Calgary AB T2P 0T5 403-266-7383 www.newpark.ca

NGC Product Solutions Ltd.3160 - 118 Ave S.E. Calgary AB T2Z 3X1 403-295-3114 www.ngc-ps.com

Northern Pressure Systems Inc.1014A - 12 Ave. S.W. Calgary AB T2R 0J6 403-262-4698

Northstar Drillstem Testers Inc.201, 736 - 1 Ave. N.E. Calgary AB T2E 0B8 403-265-8987 www.northstardst.com

Oak Environmental Inc.103, 4712 - 13 St. N.E. Calgary AB T2E 6P1 403-250-9810 www.oakenviro.com

OD Well Servicing Ltd.Box 131 Cut Knife SK S0M 0N0 306-823-3771

Oil & Gas Instruments Inc.3, 265 Main St., Box 237 Glencoe ON N0L 1M0 519-287-3554

Oil Lift Technology Inc.Bay 3, 1820 - 30 Ave. N.E. Calgary AB T2E 7M5 403-291-5300 www.oillifttechnology.com

Opsco Energy Industries Ltd.285175 Kleysen Way Rocky View AB T1X 0K1 403-272-2206 www.opscoenergy.com

Optimus International Technologies Inc.18 Golden Key Estates Calgary AB T3P 1A5 403-265-7800 www.optimus.ab.ca

Oyo Geo Space Canada, Inc.2735 - 37 Ave. N.E. Calgary AB T1Y 5R8 403-250-9600 www.oyogeospace.com

Pacific Valve Services Inc.9750 - 62 Ave. Edmonton AB T6E 0E3 780-463-3972 www.pacificvalve.com

Packers Plus Energy Services Inc.2200, 205 - 5 Ave. S.W. Calgary AB T2P 2V7 403-263-7587 www.packersplus.com

Pajak Engineering Ltd.300, 707 - 7 Ave. S.W. Calgary AB T2P 3H6 403-264-1197 www.pajakeng.com

Parcels Trucking (2007) Ltd.4713 - 41 St. Stettler AB T0C 2L0 403-742-2781

ParVal Equipment Ltd.201, 14207 - 128A Ave. Edmonton AB T5L 4P5 780-437-2334 www.parval.ca

PCM Canada1014, 888 - 3 St. S.W. Calgary AB T2P 5C5 403-444-6951 www.pcm.eu

Peak Energy Services Trust900, 222 - 3 Ave. S.W. Calgary AB T2P 0B4 403-543-7325 www.peak-energy.com

Pembina Controls Inc.9611 - 42 Ave. Edmonton AB T6E 5R2 780-432-6821 www.pem-controls.com

Penetrators Canada Inc.8002 Edgar Industrial Ave. Red Deer AB T4P 3S2 403-346-7474 www.maxperf.ca

Penta Completions Supply & Services Ltd.9543 - 56 Ave. Edmonton AB T6E 0B2 780-436-6644 www.pentarods.com

Peterson Instruments123, 5655 - 10 St. N.E. Calgary AB T2E 8W7 403-291-9169 www.petersoninst.com

Petro Management Group Ltd.401, 100 - 4 Ave. S.W. Calgary AB T2P 3N2 403-216-5100 www.petromgt.com

Petroleum Technology Transfer Inc.5008 Nesbitt Rd. N.W. Calgary AB T2K 2N5 403-282-6183

PHH Petroleum Consultants Ltd.240, 1121 Centre St. N.W. Calgary AB T2E 7K6 403-232-6822 www.phhpc.com

Pimee Well Servicing Ltd.Box 39 Kehewin AB T0A 1C0 780-826-6392

Platinum Pumpjack Services Corp.Box 10207 Lloydminster AB T9V 3A3 780-875-7145 www.platinumenergy.net

Polycore Tubular Linings Corporation430, 736 - 8 Ave. S.W. Calgary AB T2P 1H4 403-444-5554 www.polycore.ca

Porteous Resources Limited5008 Nesbitt Rd. N.W. Calgary AB T2K 2N5 403-282-6183

Powerstroke Well Control Ltd.R.R. 2, Site 33, Comp. 4 Grande Prairie AB T8V 2Z9 780-539-0102 www.powerstroke.ca

Precision Drilling Corporation4200, 150 - 6 Ave. S.W. Calgary AB T2P 3Y7 403-716-4500 www.precisiondrilling.com

Premiere Energy Services Ltd.1700, 500 - 4 Ave. S.W. Calgary AB T2P 2V6 403-874-6666 www.premiereenergy.ca

Primary Flow Signal Canada, Inc.4003 - 97 St. Edmonton AB T6E 5Y5 780-440-0109 www.primaryflowsignal.com

Production Equipment Performance Reporting Inc.700, 521 - 3 Ave. S.W. Calgary AB T2P 3T3 403-561-7791 www.peprinc.com

direcTorytech guide

74Proficient Oil Tools Ltd.105, 616 - 71 Ave. S.E. Calgary AB T2H 2R1 403-255-4070 www.proficientoiltools.com

ProMinent Fluid Controls Ltd.490 Southgate Dr. Guelph ON N1G 4P5 519-836-5692 www.prominent.ca

Propak Systems Ltd.440 East Lake Rd. Airdrie AB T4A 2J8 403-912-7000 www.propaksystems.com

PRO-ROD3201 - 84 Ave. Edmonton AB T6P 1K1 780-449-7101 www.prorod.com

ProTechnics2100, 125 - 9 Ave. S.E. Calgary AB T2G 0P6 403-269-2055 www.protechnics.com

Proven Reserves Exploitation Ltd.1730, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-218-7000 www.proven-reserves.com

Pure Energy Services Ltd.10th Floor, 333 - 11 Ave. S.W. Calgary AB T2R 1L9 403-262-4000 www.pure-energy.ca

Q’Max Solutions Inc.1700, 407 - 2 St. S.W. Calgary AB T2P 2Y3 403-269-2242 www.qmaxsolutions.com

R & M Energy Systems Canada3703 - 98 St. Edmonton AB T6E 5N2 780-465-9500 www.rmenergy.com

Raider Well Servicing Ltd.6306 - 53 Ave. Lloydminster AB T9V 2E2 780-875-7373

Rebco Oil Tools Inc.4226 Ogden Rd. S.E. Calgary AB T2G 4V3 403-243-1380 www.rebcooiltools.com

Redmont International ULC3336 - 47 Ave. S.E. Calgary AB T2B 2W1 403-297-0910 www.redmont.com

Reliance Well Servicing (2002) Ltd.Box 7285 Drayton Valley AB T7A 1S5 780-542-5295 www.reliancewell.com

Rheotech Drilling Fluid Services Inc.610, 700 - 4 Ave. S.W. Calgary AB T2P 3J4 403-237-8870 www.rheotech.ca

Ringer Well Service Ltd.Box 506 Cochrane AB T4C 1A7 403-208-9733 www.ringerwell.com

Rockwell Servicing Partnership1000, 400 - 5 Ave. S.W. Calgary AB T2P 0L6 403-265-6361 www.ensigngroup.com

Rod Anderson Holdings Ltd.399 Whiteridge Cres. N.E. Calgary AB T1Y 2Y9 403-293-0583

Roll’n Oilfield Industries, Ltd.305, 5208 - 53 Ave. Red Deer AB T4N 5K2 403-343-1710 www.rolln.com

Ross Energy Services Ltd.66 Cranridge Heights S.E. Calgary AB T3M 0C1 403-236-0122

Rotation Power & Equipment Inc.Box 500 Neilburg SK S0M 2C0 306-823-4818 www.rotationpower.com

Royal Well Servicing Ltd.5214 - 62 St. Lloydminster AB T9V 2E4 780-808-2333

S.A. Armstrong Limited23 Bertrand Ave. Scarborough ON M1L 2P3 416-755-2291 www.armstrongpumps.com

Sabre Oilfield Equipment Ltd.2412 Cameron Ravine Dr. Edmonton AB T6M 0J2 780-446-6054 www.sabreoilfield.com

Safety Boss Inc.Bay 1, 2501 Alyth Rd. S.E. Calgary AB T2G 1P7 403-261-5075 www.safetyboss.com

Samsco Service (1990) Ltd.655 - 1 St. West, Box 987 Brooks AB T1R 1B8 403-362-4533

Sanjel Corporation200, 505 - 2 St. S.W. Calgary AB T2P 1N8 403-269-1420 www.sanjel.com

Savanna Energy Services Corp.1800, 311 - 6 Ave. S.W. Calgary AB T2P 3H2 403-503-9990 www.savannaenergy.com

Saxon Energy Services Inc.1700, 700 - 4 Ave. S.W. Calgary AB T2P 3J4 403-716-4150 www.saxonservices.com

Schlumberger Canada Ltd.525 - 3 Ave. S.W. Calgary AB T2P 0G4 403-509-4000 www.slb.com

Schneider Electric, Telemetry & Remote SCADA Solutions48Dr. Steacie Kanata ON K2K 2A9 613-591-1943 www.controlmicrosystems.com

SEI Industries Ltd.7400 Wilson Ave. Delta BC V4G 1H3 604-946-3131 www.sei-ind.com

Select Energy Systems Inc.4215 - 54 Ave. S.E. Calgary AB T2C 2A2 403-243-7542 www.selectesi.com

Sentry Pumping Units International450, 444 - 5 Ave. S.W. Calgary AB T2P 2T8 403-775-7077 www.sentryinternational.net

Servipetrol Inc.502, 903 - 19 Ave. S.W. Calgary AB T2T 0H8 403-266-2535 www.servipetrol.com

Sienna Contracting Ltd.683 - 18 St. S.W. Medicine Hat AB T1A 7Y1 403-527-9881 www.siennacomposite.com

SIGIT Group Inc.540, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-723-4256 www.sigitgroup.com

Simark Controls Ltd.10509 - 46 St. S.E. Calgary AB T2C 5C2 403-236-0580 www.simark.com

Sim-Con Oilfield Equipment Ltd.800 - 10 St. West, Box 246 Kindersley SK S0L 1S0 306-463-4938 www.simconoil.com

Slurry Cementers Ltd.9525 - 62 Ave. Edmonton AB T6E 0E1 780-435-3451

Smith International Canada, Ltd.710, 396 - 11 Ave. S.W. Calgary AB T2R 0C5 403-264-6077 www.smith.com

Sounder Technologies31 Norris Close Red Deer AB T4P 1R2 403-340-9750 www.meterdat.com

Spartan Controls Ltd.305 - 27 St. S.E.Calgary AB T2A 7V2 403-207-0700 www.spartancontrols.com

SPM Flow Control Ltd.Unit A, 8060 Edgar Industrial Red Deer AB T4P 3R3 403-341-3410 www.weiroilandgas.com

Stady Oil Tools Ltd.300, 1601 Westmount Rd. N.W. Calgary AB T2N 3M2 403-262-8022

Stewart & Stevenson, Canada3111 Shepard Rd. S.E. Calgary AB T2C 4P1 403-215-5300 www.stewartandstevenson.com

StimSol Canada Inc.900, 606 - 4 St. S.W. Calgary AB T2P 1T1 403-266-0667 www.stimsol.com

Stowell Pumps5415 - 99 St. Edmonton AB T6E 3N8 780-438-2485

Stream-Flo Industries Ltd.4505 - 74 Ave. Edmonton AB T6B 2H5 780-468-6789 www.streamflo.com

Sumitomo Canada Limited2800, 150 King St. West Toronto ON M5H 1J9 604-691-6000 www.sumitomocanada.com

Sure Flow Consulting Services (1992) Inc.Box 7400 Bonnyville AB T9N 2H7 780-826-6864 www.sureflowconsulting.com

Syndicated Ventures Inc.1500, 520 - 5 Ave. S.W. Calgary AB T2P 3R7 403-264-7474

Tank-Life Cradles Ltd.2032 Crocus Rd. N.W. Calgary AB T2L 0Z8 403-269-5525 www.tanklife.com

Tartan Controls Inc.4003 - 53 Ave. Edmonton AB T6B 3R5 780-463-3366 www.tartancontrols.com

Tax Back Ltd.710, 7015 Macleod Tr. South Calgary AB T2H 2K6 403-252-3128 www.taxback.ab.ca

TDH Fluid Systems Inc.112, 422 - 11 Ave. S.E. Calgary AB T2G 0Y4 403-228-7018

Techmation Electric & Controls Ltd.1, 43 East Lake Cres. N.E. Airdrie AB T4A 2H5 403-243-0990 www.techmationelectric.com

Technicoil Corporation, CT Service Division1510, 555 - 4 Ave. S.W. Calgary AB T2P 3E7 403-509-0700 www.technicoilcorp.com

The OPS Group International Inc.4119 - 55 St. N.E. Calgary AB T1Y 4B5 403-216-1216

Thuro Inc.4650 - 50 Ave. S.E. Calgary AB T2B 3R4 403-243-0276 www.thuro.ab.ca

Top-Co LP7720 - 17 St. Edmonton AB T6P 1S7 780-440-4440 www.top-co.ca

Total Enerflex9715 - 115 St. Grande Prairie AB T8V 5S4 780-532-8347 www.totalenerflex.com

Tracer Supervision1110, 340 - 12 Ave. S.W. Calgary AB T2R 1L5 403-261-7097 www.barlon.ca

TRC Hydraulics Inc.855 Champlain St. Dieppe NB E1A 1P6 506-853-1986 www.trchydraulics.com

Treeline Well Services Inc.750, 333 - 11 Ave. S.W. Calgary AB T2R 1L9 403-266-2868 www.treelinewell.com

Trendon Bit Service Ltd.Box 548 Redcliff AB T0J 2P0 403-548-7242 www.trendonbitservice.com

Tri 3 Well Servicing Ltd.1, 5316 - 43 St., Box 743 Provost AB T0B 3S0 780-753-2927

Trican Well Service2900, 645 - 7 Ave. S.W. Calgary AB T2P 4G8 403-266-0202 www.trican.ca

Trinidad Well Servicing2500, 700 - 9 Ave. S.W. Calgary AB T2P 3V4 403-265-6525 www.trinidaddrilling.com

Tryton Tool Services5107 - 62 St. Lloydminster AB T9V 2E3 780-875-0800 www.essentialenergy.ca

TS&M SupplyBox 28 Estevan SK S4A 2A2 306-634-6494 www.natoil.com

Tucker Wireline Services Canada Inc.900, 444 - 5 Ave. S.W. Calgary AB T2P 2T8 403-264-7040 www.tuckerenergy.com

Twylight Pressure Controls Ltd.10124 - 94 Ave. Fort St. John BC V1J 5J6 250-785-2178

Variperm (Canada) Limited10, 3424 - 26 St. N.E. Calgary AB T1Y 4T7 403-250-7263 www.variperm.com

Vetco Gray Canada ULC710, 530 - 8 Ave. S.W. Calgary AB T2P 3S8 403-264-4146 www.geoilandgas.com/vetcogray

Viking Pump of Canada, Inc.661 Grove Ave., Box 398 Windsor ON N9A 6M3 519-256-5438 www.vikingpumpcanada.com

Viking Surplus Oilfield Equipment Ltd. 36 Hwy. 39 East, Box 1460 Estevan SK S4A 2L7 866-634-6612 www.vikingsurplus.com

Volant Products Inc.4110 - 56 Ave. N.E. Edmonton AB T6B 3R8 780-490-5185 www.volantproducts.ca

Waterflood Service and Sales Ltd.Box 1490 Estevan SK S4A 2L7 306-634-7212 www.waterflood.com

WaterTech321, 11979 - 40 St. S.E. Calgary AB T2Z 4M3 403-252-9056 www.watertech.ca

West Rock Energy Consultants Ltd.1110, 910 - 7 Ave. S.W. Calgary AB T2P 3N8 403-663-4860 www.westrock-energy.com

Westcomm Pump & Equipment Ltd.Unit 2, 3424 - 26 St. N.E. Calgary AB T2E 7A4 403-215-7867 www.westcommpump.com

Westpower Equipment Ltd.4451 - 54 Ave. S.E. Calgary AB T2C 2A2 403-720-3300 www.westpower.ca

Wilco Wireline & Swabbing Services Inc.1, 4451 - 58 Ave. S.E. Calgary AB T2C 1Y3 403-279-8895 www.wilcowireline.com

Wildcat Well Servicing Inc.Box 2374 Kindersley SK S0L 1S0 306-463-1114

William Nichols Consulting4616 Brockington Rd. N.W. Calgary AB T2L 1R6 403-714-3330 www.williamnichols.com

Wizard Well Servicing Ltd.5211 - 65 St. Lloydminster AB T9V 2E8 780-875-6035

World Oil Tools Inc.6, 3504 - 72 Ave. S.E. Calgary AB T2C 1J9 403-720-5155 www.worldoiltools.com

Wrangler Well Servicing Ltd.6108 - 24 St. Lloydminster AB T9V 3J8 306-821-7292

direcTorytech guide

75XL Fluid Systems102, 2531 Hochwald Ave. S.W. Calgary AB T3E 7K3 403-265-4344 www.xlfluids.com

Zazula Process Equipment Ltd.1526 - 10 Ave. S.W. Calgary AB T3C 0J5 403-244-0751 www.zazula.com

Zedi500, 600 - 6 Ave. S.W. Calgary AB T2P 0S5 403-444-1100 www.zedi.ca

Ziff Energy Group1117 Macleod Tr. S.E. Calgary AB T2G 2M8 403-234-4299 www.ziffenergy.com

Data/Software/Communication

3esi200, 1601 Westmount Rd. N.W. Calgary AB T2N 3M2 403-270-3270 www.3esi.com

Alternate Solutions Inc.565 Arvin Ave. Stoney Creek ON L8E 5N7 905-643-8289 www.asifluid.com

Applied Electronics Limited5170-B Timberlea Blvd. Mississauga ON L4W 2S5 905-625-4321 www.appliedelectronics.com

AVEVA2600, 144 - 4 Ave. S.W. Calgary AB T2P 3N4 403-303-3335 www.aveva.com

B & G Systems Canada54, 850 Tapscott Rd. Scarborough ON M1X 1N4 416-646-2885 www.b-gsystemscanada.com

Barnett Engineering Ltd.215, 7710 - 5 St. S.E. Calgary AB T2H 2L9 403-255-9544 www.barnett-engg.com

Benchmark Data Solutions5, 4001 - 19 St. N.E. Calgary AB T2E 6X8 403-590-9101 www.benchmarkdata.ca

BH Electronics Ltd.23 Deermoss Pl. S.E. Calgary AB T2J 6P5 403-278-2084 www.www3.telus.net/hendersb

Brillium Corporation12 Hamptons Pl. N.W. Calgary AB T3A 6B8 403-614-3913 www.brillium.ca

Canadian Centre for Energy Information1600, 800 - 6 Ave. S.W. Calgary AB T2P 3G3 403-263-7722 www.centreforenergy.com

Canadian Discovery Ltd.300, 706 - 7 Ave. S.W. Calgary AB T2P 0Z1 403-269-3644 www.canadiandiscovery.com

Canadian Gas Association809, 350 Sparks St. Ottawa ON K1R 7S8 613-748-0057 www.cga.ca

Carbon Controls Ltd.Bay 124, 11979 - 40 St. S.E. Calgary AB T2Z 4M3 403-238-9944 www.carboncontrolsltd.com

Cartel Energy Services Inc. Box 155 Beiseker AB T0M 0G0 403-947-3334 www.cartelenergy.com

C-FER Technologies200 Karl Clark Rd. Edmonton AB T6N 1H2 780-450-3300 www.cfertech.com

CGI Information Systems and Management Consultants Inc.900, 800 - 5 Ave. S.W. Calgary AB T2P 3T6 403-218-8300 www.cgi.com

CL Consultants Limited3601A - 21 St. N.E. Calgary AB T2E 6T5 403-250-3982 www.clconsultants.ca

Computer Modelling Group Ltd.150, 3553 - 31 St. N.W. Calgary AB T2L 2K7 403-531-1300 www.cmgl.ca

Copyseis Ltd.6705 Fairmount Dr. S.E. Calgary AB T2H 0X6 403-253-3425 www.copyseis.com

Coraspec Systems1600, 521 - 3 Ave. S.W. Calgary AB T2P 3T3 403-262-8750 www.coraspec.com

CriticalControl Solutions Inc.1100, 840 - 7 Ave. S.W. Calgary AB T2P 3G2 403-705-7500 www.criticalcontrol.com

Datacon Core Imaging Inc.2410F - 2 Ave. S.E. Calgary AB T2E 6J9 403-270-9350 www.dataconimaging.com

DGL Software Services Ltd.200, 1040 - 7 Ave. S.W. Calgary AB T2P 3G9 403-234-9202

Energy Navigator2200, 101 - 6 Ave. S.W. Calgary AB T2P 3P4 403-233-9400 www.energynavigator.com

Energy Processing/Canada500, 900 - 6 Ave. S.W. Calgary AB T2P 3K2 403-263-6881 www.northernstar.ab.ca

Enersight Corp.204, 3320 - 17 Ave. S.W. Calgary AB T3E 0B4 403-246-7447 www.enersight.com

Entero Corporation500, 1040 - 7 Ave. S.W. Calgary AB T2P 3G9 403-261-1820 www.entero.com

Envirosoft Corporation10-B, 1235 - 64 Ave. S.W. Calgary AB T2H 2J7 403-225-8760 www.envirosoft.ca

Fekete Associates Inc.2000, 540 - 5 Ave. S.W. Calgary AB T2P 0M2 403-213-4200 www.fekete.com

Financial Services & Management Group Inc.66 Discovery Ridge Manor S.W. Calgary AB T3H 5L8 403-861-8299 www.fsmg.ca

Firemaster Oilfield Services Inc.4728 - 78A St. Close Red Deer AB T4P 2J2 403-342-7500 www.firemaster.ca

Fluid Life9321 - 48 St. Edmonton AB T6B 2R4 780-462-2400 www.fluidlife.com

Focal Technologies Corp.77 Frazee Ave. Dartmouth NS B3B 1Z4 902-468-2263 www.moog.com/marine

Forum Energy Services Ltd.300, 400 - 5 Ave. S.W. Calgary AB T2P 0L6 403-540-2429 www.forumenergy.ca

Fugro Data Solutions Canada Inc.4221 - 23B St. N.E. Calgary AB T2E 7V9 403-250-1119 www.fugro-data.ca

Gas & Oil Accounting (1988) Ltd.200, 1040 - 7 Ave. S.W. Calgary AB T2P 3G9 403-234-9202 www.dglsoftware.com

geoLOGIC systems ltd.900, 703 - 6 Ave. S.W. Calgary AB T2P 0T9 403-262-1992 www.geologic.com

Geomodeling Technology Corp.1100, 665 - 8 St. S.W. Calgary AB T2P 3K7 403-262-9172 www.geomodeling.com

Glenbriar Technologies Inc.301, 401 - 9 Ave. S.W. Calgary AB T2P 3C5 403-233-7300 www.glenbriar.com

Glentel Inc.8501 Commerce Crt. Burnaby BC V5A 4N3 604-415-6500 www.glentel.com

Global ThermoelectricBay 9, 3700 - 78 Ave. S.E. Calgary AB T2C 2L8 403-236-5556 www.globalte.com

GrahamChandler Writers Inc.311, 317 - 19 Ave. S.W. Calgary AB T2S 0E1 403-229-3309 www.grahamchandler.ca

Grantech Engineering International Ltd.600, 906 - 12 Ave. S.W. Calgary AB T2R 1K7 403-451-2211 www.grantecheng.com

Guardian Telecom Inc.7552 - 10 St. N.E. Calgary AB T2E 8W1 403-258-3100 www.guardiantelecom.com

GuildOne, Inc.901, 304 - 8 Ave. S.W. Calgary AB T2P 1C2 403-355-8900 www.guild1.com

Halliburton Landmark Software & Services1600, 645 - 7 Ave. S.W. Calgary AB T2P 4G8 403-231-9300

Hinz103, 801 Manning Rd. N.E. Calgary AB T2E 7M8 403-235-5305 www.hinz.com

IFP Technologies (Canada) Inc.810, 744 - 4 Ave. S.W. Calgary AB T2P 3T4 403-234-0342 www.ifp-canada.com

IHS200, 1331 Macleod Trail S.E. Calgary AB T2G 0K3 403-770-4646 www.ihs.com/energy

Independent Data Services (Canada) Inc.1700, 840 - 7 Ave. S.W. Calgary AB T2P 3G2 403-209-1528 www.idsdatanet.com

Infosat Communications, Inc.3130 - 114 Ave. S.E. Calgary AB T2Z 3V6 403-543-8188 www.infosat.com

Jedex Equipment Ltd.4, 4063 - 74 Ave. S.E. Calgary AB T2C 2H9 403-531-8670 www.jedex.ca

Junewarren-Nickle’s Energy Group2nd Floor, 816 - 55 Ave. N.E. Calgary AB T2E 6Y4 403-209-3500 www.junewarren-nickles.com

Kenwood Electronics Canada Inc.6070 Kestrel Road Mississauga ON L5T 1S8 905-670-7211 www.kenwood.ca

M.W. Hagel Consulting Ltd.18 Golden Key Estates Calgary AB T3P 1A5 403-265-7800 www.optimus.ab.ca

MacdonaldCole Inc.912 Lake Twintree Cr.S.E. Calgary AB T2J 2W3 403-271-6908 www.macdonaldcole.com

Merlin Edge Inc.100, 602 - 12 Ave. S.W. Calgary AB T2R 1J3 403-237-7684 www.merlinedge.com

Micotan Software Company Ltd.615, 1010 - 1 St. S.W. Calgary AB T2R 1K4 403-910-1010 www.micotan.com

Microhard Systems Inc.150 Country Hills Landing N.W. Calgary AB T3K 5P3 403-248-0028 www.microhardcorp.com

Mustagh Resources Ltd.134 Hubman Landing Canmore AB T1W 3L3 403-265-5255 www.mustagh.com

NEOTEC430, 910 - 7 Ave. S.W. Calgary AB T2P 3N8 403-277-6688 www.neotec.com

Network Innovations Inc.4424 Manilla Rd. S.E. Calgary AB T2G 4B7 403-287-5000 www.networkinv.com

Northern Transportation Company Limited42003 MacKenzie Hwy. Hay River NT X0E 0R9 867-874-5100 www.ntcl.com

Offshore/Onshore Technologies Association of Nova Scotia202, 305 Cambridge 1 Dartmouth NS B3B 1T5 902-425-4774 www.otans.com

Open Door Technology Inc.108, 7710 - 5 St. S.E. Calgary AB T2H 2L9 403-777-2410 www.opendoor.ca

P2 Energy Solutions2100, 639 - 5 Ave. S.W. Calgary AB T2P 0M9 403-774-1000 www.p2energysolutions.com

Pandell Technology Corp.215, Bldg. B8- 2526, Battleford. Ave. S.W. Calgary AB T3E 7J4 403-271-0701 www.pandell.com

Paradigm Geophysical (Canada) Ltd.2110, 125 - 9 Ave. S.E. Calgary AB T2G 0P6 403-571-1555 www.pdgm.com

Peloton Computer Enterprises Ltd.450, 1000 - 7 Ave. S.W. Calgary AB T2P 5L5 403-263-2915 www.peloton.com

Petris Canada805, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-225-4954 www.petris.com

Petro Management Group Ltd.401, 100 - 4 Ave. S.W. Calgary AB T2P 3N2 403-216-5100 www.petromgt.com

PHH Petroleum Consultants Ltd.240, 1121 Centre St. N.W. Calgary AB T2E 7K6 403-232-6822 www.phhpc.com

Platinum Communications Corporation280, 550 - 71 St. S.E. Calgary AB T2H 0S5 403-301-4590 www.platinum.ca

Priority Leasing Inc.200, 7909 Flint Rd. S.E. Calgary AB T2H 1G3 403-216-1930 www.priorityleasing.net

Process Ecology930, 105 - 150 Crowfoot Cr. Calgary AB T3G 3T2 403-313-8931 www.processecology.com


Propane Canada500, 900 - 6 Ave. S.W. Calgary AB T2P 3K2 403-263-6881 www.northernstar.ab.ca

Quest Computer Consultants145, 6815 - 8 St. N.E. Calgary AB T2E 7H7 403-275-2775 www.geometrix.ca

Resource Energy Solutions Inc.204 - 7A St. N.E. Calgary AB T2E 4E8 403-245-0220 www.resourceenergysolutions.com

Rigstar Communications Inc.3567 - 52 St. S.E. Calgary AB T2B 3R3 403-243-0600 www.rigstar.ca

Rinax Systems Ltd.5542 - 1A St. S.W. Calgary AB T2H 0E7 403-243-4074 www.rinax.com

RiskAdvisory, a division of SAS (Canada)970, 401 - 9 Ave. S.W. Calgary AB T2P 3C5 403-263-7475 www.riskadvisory.com

Rittal Systems Ltd.7320 Pacific Circle Mississauga ON L5T 1V1 905-795-0777 www.rittal.ca

Schlumberger Information Solutions (SIS)600, 322 - 11 Ave. S.W. Calgary AB T2R 0C5 403-294-4300 www.slb.com/sis

Schneider Electric, Telemetry & Remote SCADA Solutions 48 Steacie Dr. Kanata ON K2K 2A9 613-591-1943 www.controlmicrosystems.com

Health, Safety & Environment

direcTorytech guide

76SustaiNet Software International Inc.98, 887 Great Northern Way Vancouver BC V5T 4T5 604-717-4327 www.sustainet.com

T1 Services Group Corp.204, 4216 - 10 St. N.E. Calgary AB T2E 6K3 403-547-3125 www.t1servicesgroup.com

Teknica Overseas Ltd.2700, 350 - 7 Ave. S.W. Calgary AB T2P 3N9 403-269-4386 www.teknicaltd.ca

Terra Management Inc.611 - 71 Ave. S.E. Calgary AB T2H 0S7 403-269-6090 www.terramanagement.com

The Roughneck Buy & Sell500, 900 - 6 Ave. S.W. Calgary AB T2P 3K2 403-263-6881 www.northernstar.ab.ca

Traverse LandGroup Ltd.300, 1011 - 1 St. S.W. Calgary AB T2R 1J2 403-265-1050 www.traverselandgroup.com

Trinity Electronics Systems Ltd.10708 - 181 St. Edmonton AB T5S 1K8 780-489-3199 www.trinity-electronics.com

Trivision Geosystems Ltd.314, 602 - 11 Ave. S.W. Calgary AB T2R 1J8 403-777-9454 www.powerlogger.com

Western Midland Communications Ltd.8, 3601 - 19 St. N.E. Calgary AB T2E 6S8 403-250-9433

XI Technologies 1700, 734 - 7 Ave. S.W. Calgary AB T2P 3P8 403-517-0111 www.xitechnologies.com

Zedi500, 600 - 6 Ave. S.W. Calgary AB T2P 0S5 403-444-1100 www.zedi.ca

A.F.M. Resources Ltd.R.R. 2 Okotoks AB T1S 1A2 403-938-2158

Abandonrite2800, 500 - 4 Ave. S.W. Calgary AB T2P 2V6 403-263-6777 www.nabors.com

ABKO Holdings (1977) Ltd.2422, 246 Stewart Green S.W. Calgary AB T3H 3C8 403-262-3221

Accurata Inc.120 MacEwan Park Rise N.W. Calgary AB T3K 4A1 403-295-1637 www.accurata.ca

Altus Geomatics17327 - 106A Ave. Edmonton AB T5S 1M7 780-481-3399 www.altusgeomatics.com

Altus Geomatics Limited Partnership, Environmental & Forestry17327 - 106A Ave. Edmonton AB T5S 1M7 780-481-3399 www.altusgroup.com

AMEC Earth & Environmental140 Quarry Park Blvd. S.E. Calgary AB T2C 3G3 403-248-4331 www.amec.com

Aresco Ltd.108 Varsity Cres. N.W. Calgary AB T3B 2Z4 403-247-1449

Ark Envirotech Inc102, 1439 - 17 Ave. S.E. Calgary AB T2G 1J9 403-355-3655 www.arkenvirotech.ca

Ashbrooke Quality Assurance Ltd.78038, 3295 Coast Meridian Rd. Port Coquitlam BC V3B 7H5 604-552-0496 www.ashbrooke.com

Banner Consulting Services, Inc.269 Valley Springs Terrace NW Calgary AB T3B 5P8 403-510-5351

Bennett Jones LLP4500, 855 - 2 St. S.W. Calgary AB T2P 4K7 403-298-3100 www.bennettjones.com

Black Gold Projects - Inspection3809 South Island Hwy. Campbell River BC V9H 1M4 403-262-4653 www.black-gold.ca

Boundary Technical Group Inc.8, 421 East Lake Road N.E. Airdrie AB T4A 2J7 403-948-2198 www.btgi.ca

Calvin Consulting Group Ltd.1A, 3850 - 19 St. N.E. Calgary AB T2E 6V2 403-547-7557 www.calvinconsulting.ca

Canadian Institute of Resources Law3353 MFH, University of Calgary Calgary AB T2N 1N4 403-220-3200 www.cirl.ca

Clear Environmental Solutions440, 840 - 6 Ave. S.W. Calgary AB T2P 3E5 403-263-5953 www.clearenv.com

Cordy Oilfield Services Inc.1010, 2303 - 4 St. S.W. Calgary AB T2S 2S7 403-266-2067 www.cordy.ca

DANA Technical Services Ltd.104, 3016 - 19 St. N.E. Calgary AB T2E 6Y9 403-571-0390 www.danats.com

Diagnostic Engineering Inc.111, 616 - 71 Ave. S.E. Calgary AB T2H 2R1 403-253-4856 www.diagnosticgroup.ca

Energy Insurance Group1500, 727 - 7 Ave. S.W. Calgary AB T2P 0Z5 403-261-6061 www.cpix.com

Enviro-Guard Reclamation Inc.252 Sienna Hills Dr. S.W. Calgary AB T3H 2Y8 403-540-9312

Envirosoft Corporation10-B, 1235 - 64 Ave. S.W. Calgary AB T2H 2J7 403-225-8760 www.envirosoft.ca

Epic Environmental Technologies Inc.48 Carlton St. Box 700 Redvers SK S0C 2H0 306-452-3200 www.epicenvirotech.com

FDI Acoustics Inc.250, 600 Crowfoot Cres. N.W. Calgary AB T3B 0B4 403-547-9511 www.fdiacoustics.com

Frac Rite Environmental Ltd.2, 4416 - 5 St. N.E. Calgary AB T2E 7C3 403-265-5533 www.fracrite.ca

Geo Webworks Inc.2020, 801 - 6 Ave. S.W. Calgary AB T2P 3W2 403-301-4001 www.geowebworks.com

Geophysics GPR International Inc.100, 2545 rue de Lorimier Longueuil QC J4K 3P7 450-679-2400 www.geophysicsgpr.com

Ghostpine Environmental Services Ltd.111, 10699 - 46 St. S.E. Calgary AB T2C 5C2 403-291-9238 www.ghostpine.com

Golder Associates Ltd.2535 - 3 Ave. S.E. Calgary AB T2A 7W5 403-299-5600 www.golder.com

HFP Acoustical Consultants Corp.1140, 10201 Southport Rd. S.W. Calgary AB T2W 4X9 403-259-6600 www.hfpacoustical.com

HMA Land Services Ltd.100, 7710 - 5 St. S.E. Calgary AB T2H 2L9 403-692-0850 www.hmaland.com

Hunter and Associates/GISUnit 18, 2285 Dunwin Dr. Mississauga ON L5L 3S3 905-607-4120 www.hunter-gis.com

Hydrogeological Consultants Ltd.17740 - 118 Ave. N.W. Edmonton AB T5S 2W3 780-483-7240 www.hcl.ca

HydroQual Laboratories Ltd.4, 6125 - 12 St. S.E. Calgary AB T2H 2K1 403-253-7121

Integrity Land Inc.9940 - 99 Ave. Fort Saskatchewan AB T8L 4G8 780-992-1500 www.integrityland.com

J.K. Engineering Ltd.320, 7930 Bowness Rd. N.W. Calgary AB T3B 0H3 403-247-1777 www.jkeng.ca

Kanuka Thuringer LLP1400, 2500 Victoria Ave. Regina SK S4P 3X2 306-525-7200 www.kanukathuringer.com

KCM Engineering Ltd.84 Oakmount Way S.W. Calgary AB T2V 4Y1 403-807-6576

Keneco Environmental Services (2000) Inc. 3 Fl., 3333 - 8 St. S.E. Calgary AB T2G 3A4 403-237-8137 www.kenecoenviro.com

Lorrnel Consultants400 - 6 St. S.W. Calgary AB T2P 1X2 403-233-0900 www.lorrnel.com


McNally Land Services Ltd.215, 5718 - 1A St. S.W. Calgary AB T2H 0E8 403-503-5263

MediaLogic Inc.105, 620 - 8 Ave. S.W. Calgary AB T2P 3G2 403-261-5690 www.naturalresource.ca

Milepost Manufacturing55004, Range Rd. 251 Sturgeon County AB T8T 1R6 780-459-1030 www.milepostmfg.com

Millennium EMS Solutions Ltd.208, 4207 - 98 St. Edmonton AB T6E 5R7 780-496-9048 www.mems.ca

Morgan Construction & Environmental Ltd.702, 702 Acheson Rd. 53016, Highway 60 Acheson AB T7X 5A7 780-960-6966 www.mcel.ca

Naft Canada Resources Ltd.125, 315 - 24 Ave. S.W. Calgary AB T2S 3E7 403-239-3003

New Paradigm Engineering Ltd.10444 - 20 Ave. N.W. Edmonton AB T6J 5A2 780-448-9195 www.newparadigm.ab.ca

Nichols Environmental (Canada) Ltd.17331 - 107 Ave. N.W. Edmonton AB T5S 1E5 780-484-3377 www.nicholsenvironmental.com

Nickpoint Environmental Services Inc.110, 239 - 10 Ave. S.E. Calgary AB T2G 0V9 403-260-6702 www.nickpoint.ca

Nor-Alta Environmental Services Ltd.157, 9768 - 170 St. Edmonton AB T5T 5L4 780-486-4931 www.nor-alta.com

Normcan1800, 140 - 10 Ave. S.E.Calgary AB T2G 0R1 403-233-7565 www.normcan.com

North/South Consultants Inc.83 Scurfield Blvd. Winnipeg MB R3Y 1G4 204-284-3366 www.nscons.ca

Outcrop Communications Ltd.800, 4920 - 52 St. Yellowknife NT X1A 3T1 867-766-6700 www.outcrop.com

Pratum Resource Consulting Ltd.2320 - 41 Ave. N.E. Calgary AB T2E 6W8 403-717-0493 www.pratum.com


Remedx Remediation Services Inc.305, 1550 - 5 St. S.W. Calgary AB T2R 1K3 403-209-0004 www.remedx.net

Roy Northern Environmental Ltd.Box 847 Fairview AB T0H 1L0 780-835-2682 www.roynorthern.com

Scace Environmental Advisors Inc.2416 Sandhurst Ave. S.W. Calgary AB T3C 2M6 403-246-8303

Seaway Energy Services Inc.1250, 700 - 4 Ave. S.W. Calgary AB T2P 3J4 403-235-4486 www.seawayenergy.com

Seguin Construction (1979) Ltd.913 - 8 St. N.W. Bag 10 Slave Lake AB T0G 2A0 780-849-3091 www.seguinconstruction.ca

Skypics10420 Maplemont Rd. S.E. Calgary AB T2J 1W4 403-271-5094 www.skypics.ca

SLR Consulting200, 1620 West 8 Ave. Vancouver BC V6J 1V4 604-738-2500 www.slrconsulting.com

Tansley Associates Environmental SciencesBay 3, 1470 - 28 St. N.E. Calgary AB T2A 7W6 403-569-8566 www.tansleyaes.com

TERA Environmental Consultants1100, 815 - 8 Ave. S.W. Calgary AB T2P 3P2 403-265-2885 www.teraenv.com

The Association of Science and Engineering Technology Professionals of Alberta (ASET) 1630, 10020 - 101 A Ave. Edmonton AB T5J 3G2 780-425-0626 www.aset.ab.ca

Trek Construction & Environmental Services Ltd.63A Skyline Cres. N.E. Calgary AB T2K 5X7 403-274-1000 www.gettrekin.com

Visser Consulting Ltd.290, 6815 - 8 St. N.E. Calgary AB T2E 7H7 403-239-3797 www.visserconsulting.ca

Waterworks Technologies Inc.2024 - 12 Ave. N.W. Calgary AB T2N 1J7 403-289-3198 www.waterworks.ca

Whitland Consulting Inc.2320 McIntyre St. Regina SK S4P 2S2 306-757-8511

Wotherspoon Environmental Inc.104, 429 - 14 St. N.W. Calgary AB T2N 2A3 403-269-4351 www.wenv.com

we are the people of Baker Hughes.

and we have solutions for optimizing your heavy oil production.

www.bakerhughes.com

Baker Hughes artificial lift solutions offer an expanded line of progressing

cavity pumping and electrical submersible progressing cavity pumping

systems specifically designed to provide longer run time, lower

intervention costs, and increased production in heavy oil wells.

Our specialty chemical programs further enhance heavy oil production

by improving fluid lift efficiency and minimizing production disruptions

downhole and at surface processing facilities. We have a wide range of

chemicals and additives that eliminates emulsions, scale, and corrosion;

reduces fluid viscosity; lifts sand and fluids; and allows you to manage

your assets with confidence.

To learn how we deliver the right lift

mechanisms and chemical programs to

maximize production and extend the life

of your wells, contact your Baker Hughes

representative or visit us at

www.bakerhughes.com/canada

© 2011 Baker Hughes Incorporated. All Rights Reserved. 32532

IBC418451-853

Baker Hughes Canada Companyfull page

we are the people of Baker Hughes.

and we have solutions for optimizing your heavy oil production.

www.bakerhughes.com

Baker Hughes artificial lift solutions offer an expanded line of progressing

cavity pumping and electrical submersible progressing cavity pumping

systems specifically designed to provide longer run time, lower

intervention costs, and increased production in heavy oil wells.

Our specialty chemical programs further enhance heavy oil production

by improving fluid lift efficiency and minimizing production disruptions

downhole and at surface processing facilities. We have a wide range of

chemicals and additives that eliminates emulsions, scale, and corrosion;

reduces fluid viscosity; lifts sand and fluids; and allows you to manage

your assets with confidence.

To learn how we deliver the right lift

mechanisms and chemical programs to

maximize production and extend the life

of your wells, contact your Baker Hughes

representative or visit us at

www.bakerhughes.com/canada

© 2011 Baker Hughes Incorporated. All Rights Reserved. 32532

(OBC)429365-113

Calfrac Well Services Ltd.full page

Our recent performance in the Horn River Basin will be tough to beat. Extensive planning between the operator and Calfrac’s team resulted in an unprecedented average of 3.5 fracs/day – a significant advance over industry’s previous record. With just 1.5 hours between stages and zero screenouts, we completed the operation in 41 days – significantly exceeding expectations. All executed with a flawless safety record.

Calfrac. We’re breaking new ground... every day.

For more information, contact:

Gary Rokosh P.Eng. Vice-President, Sales, Marketing & Engineering 403-218-7483

Chad Leier P.Eng. Manager, Sales & Marketing 403-218-8180

www.calfrac.com

In the Horn River Basin, every hour counts. But shaving 23 days off the budgeted 64 day delivery is nothing short of amazing.

canadian oilpatch technology guidebook tech...

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