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NewTechnologyNovember 2009

• the first word on oilpatch innovation

For ReelUnique CT rig aims

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I G R O N R I S K M A N A G E MG E N E R A L L E D G E R E E M CO V I A R V E Q I S

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I N T E R N A T I O N A L W I S A R TN O E L I A I N T E R N E

R I S E A L L O C A T I O N S S MD O Y E A C P R I C E SA V A R Y D I D P O R D E R OT A V O F I S W O R K F L O WA L E L U T C A P T U

R U N S L S A A M A R K E T IA P A Y A B L E S P TT R H R E I P R O F

S H I P S H O T F I N O F EO O E H A P P L I C A T I O N C AL N E T B A C K P O E E P ED V U W I S E R E U N I Q U

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D E N M U L T I C U R R E N C Y DE B A A I K U

C O N S O L I D A T E D F I N A N C I A L S C LA E E A A E G D F IN R K X P R O D U C T I O N

G E P G A A L GR O Y A L T Y C A L C U L A T I O N S D R I L L

E N T WR E V E N U EA O E C

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B U S I N E S SU H DD C

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in this issue

advertisersBJ Services Company Canada 6Calfrac Well Services Ltd. 11Century Oilfield Services Inc. 8Enerflow Industries Inc. 31Entero Corporation 1Expro Group Canada 9geoLOGIC systems ltd. 3

November 2009 | vol.15 | no.9

editor’s viewWhen The Going Gets Tough 4

vanguardLaser’s Edge 7Saudi Aramco uses lasers to open way for oil to flow

Technology Play 8Horn River economics are promising; challenges remain

On Alert 9Rogers implements lone-worker solutions for the oilpatch

Combo Plan 10EnCana plans first commercial use of solvent in new oilsands project

Tech Briefs 10

Real-Time Communication 11Infosat provides new mobile and fixed satellite communications solutions

researchR&D In Recessionary Times 13During the downturn, becoming more efficient with funding is key

viewpointDoing More With Less 15How information and communications technologies can help companies reduce expenses and gain a competitive advantage

new techFor Reel 33Unique CT rig aims to shave drilling time

Candid Camera 36Video surveillance system can help protect assets

FeaTuRes

dEparTMENTS

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2 New Technology Magazine | November 2009

Halliburton 12, IBCHexion Specialty Chemicals 26JuneWarren-Nickle’s Energy Group 16, 35packers plus Energy Services Inc. 17Schlumberger Canada Limited IFC, 5TELUS 32Weatherford Canada partnership OBC

24 FracAdvances IceBreaker25 Inventorturnstonaturetofracturetightformations

FluidQuest27 Montneydemandsuniqueapproachtostimulation

DiscreteImprovement28 Fracturenetworkmodellingsystemhelpsshalegas

producersdeveloptheirgameplans

NumbersGame30 UsingaluminumhelpsGlobalHeatTransfer

developnewfracradiators

18 KnowThyReservoir Multi-disciplinaryshalegassolutionintegratescasedholeevaluation,interpretationandstimulation

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THANK YOU. Without you there, we wouldn’t be leading the way in superior customer service.

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editor’s viewwhen the going gets tough…

When times get tough and budget slashing becomes the order of the day, research and development spending may seem a logical place to economize. the technological advances it brings may not add to the bottom line for years, the eventual benefit may be hard to quantify, and thus to justify, and the entire exercise may be seen as an unnecessary luxury that a company can return to when times improve.

but as study after study has shown, the most competitive of companies, and economies, are those that are leaders in innovation. and innovation starts with r&d.

Fortunately, many of those who specialize in oil and gas r&d, such as ian Potter of the alberta research council and soheil asgarpour of Petroleum technology alliance canada, interviewed in this issue of new technology magazine, say r&d has not been severely impacted by the ongoing recession. the industry seems to be maintaining overall r&d investment in alberta, according to Potter, and spending more wisely where budgets have been trimmed, through increased collaboration, says asgarpour.

that is good news. but is that enough? digging a little deeper, it appears the oil and gas industry, even before the recession hit — at a time when companies were enjoying record revenues — was already scaling back on r&d.

it’s a decline that is not limited to the oilpatch. according to research infosource inc., r&d spending dropped among canada’s top 100 corporate r&d spenders in 2008 for the third year in a row, and for the fifth time over the past seven years. if that’s what occurred amid booming times, one wonders what the stats will look like when 2009 is tallied up.

Few oil and gas companies make the research infosource top 100, which is dominated by the communications and pharmaceutical sectors — fewer than 10. but among those that do, the trend has not looked good. While encana corporation, for example, did crack the elite $100 million (in r&d spending) list back in 2006, placing 16th overall, it slashed spending 49% the following year. though it ratcheted up spending 23% in 2008, to $88.5 million, that remained a far cry from the $140.5 million invested in 2006. still, with its 0.3% research intensity (r&d as a per cent of revenue), it was the top ranked energy company on the list at 24.

imperial oil limited, ranked 26, cut spending almost seven per cent, while syncrude canada ltd. trimmed five per cent. suncor energy inc. dropped off the list entirely in 2008 after posting a 32% drop in r&d spending on the 2007 list, when it spent $50 million and still ranked 46th. nexen inc. and Petro-canada, though, were the biggest oil and gas cutters on the list, slashing r&d spending 25% (to $30 million) and 23% (to $40 million), respectively.

but the news was not all bad. husky energy raised investment 122% to $30 million, Penn West energy trust increased spending 47% to $29 million and trican Well service ltd. lifted r&d investment 22% to $17.8 million. Penn West’s ascent is particularly notable, as it follows a 435% increase in r&d recorded the year before, and its 0.6 research intensity (while miniscule compared to intensities reported in other industries) ranked tops among producers.

as the economy begins to revive, we will increasingly look to, and reward, innovation that can help lift us out of recessionary times. those companies that have maintained a relatively strong balance sheet and that take a counter-cyclical approach to r&d stand to gain the most. costs to innovate, as with costs elsewhere, have declined, making r&d a better investment today. and by investing when times are bad, companies can benefit from the competitive advantage that can be gained when the economy does turn around, as it surely will.

in the coming months, new technology magazine will be featuring a series of articles and columns that fall under the banner “recession to recovery.” the r2r logo will help you identify the articles. stay tuned for stories examining ways companies are dealing with the recession, preparing for the rebound and even thriving in the downturn. • Maurice smith


Engineer Your Shale Gas Production

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Because Every Shale Gas Well Is Unique In the gas shale environment, a cookie-cutter approach doesn’t work.

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We’re involved in every major shale play in North America and have conducted proprietary shale gas evaluations for more than 1,100 wells and nearly 10,000 stimulation operations. Our extensive experience has enabled the development of proprietary technologies and processes for understanding the complexities of your reservoir to maximize your shale gas production.

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BJ Services’ patent-pending DirectStim™ system provides precise stimulation placement throughout a horizontal or vertical wellbore for broader pay zone coverage and greater access to reserves. The robust slimline design uses multiple activation balls with varying diameters to open frac sleeves and isolate zones to allow for faster, problem-free completion operations.

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COMPLETIONS

Laser’sEdgeSaudi aramco uses lasers to open way for oil to flow

in-situ laser PerForation is being touted as an innovative new technology that will avoid damage to formations, reduce costs and increase production.

saudi aramco’s research centre has achieved successful stages in developing a new perforation method using laser technology, making the com-pany the first to introduce in-situ laser perforation to the petroleum industry. the research and devel-opment of “in-situ lasing” is being undertaken in collaboration with halliburton.

the company said laboratory results have demonstrated laser perforation generates thermal stresses that fracture a well’s surrounding rock, thus increasing permeability around the perfora-tions, facilitating easier intake of hydrocarbons.

an immediate application of laser perforation

includes facilitating hydraulic fracturing in open-hole horizontal wells (oriented fracturing), which can greatly enhance the wells’ production capability.

laser technology has significant advantages over conventional perforation technology, in that there is no compaction. a high-energy laser beam can vaporize rock formation and create a perforation with a permeable wall surface, saudi aramco said.

“this successful lab laser perforation of casing and rock samples has brought us closer to deploy-ing laser energy in-situ for well perforation and fracture initiation,” said nabeel habib, Production technology team chief technologist. “this in-situ laser perforation will also set the groundwork for further research and applications in petroleum engineering, including laser drilling.” •

News. TreNds. INNovaTors.vanguard

New Technology Magazine | November 2009 7

LIGHT IdeaTop right: Fractures in rock resulting from the lasing perforation process.

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a trend toWards increasingly larger wells has brought the break-even price to drill in the horn river basin down by nearly $1 per mcf in the past year, to $5.05 per mcf, a recent oil and gas sympo-sium heard.

the economics of drilling in the horn river, in northeast british columbia, are beginning to stack up and will improve with more infrastructure, said michael mazar, an oil and gas services analyst for bmo capital markets, at the Pls, inc. Playmakers symposium in calgary.

drilling and completion technologies have made the play economic in the past few years, making it competitive with other north american shale gas plays, said mazar.

Well costs have increased because larger wells are being drilled, he said. according to bmo, using a gas price assumption of $6 per mcf, the average well in the horn river costs $9 million and finding and development costs are 98 cents per mcf. after-tax net pres-ent value discounted at 10% is $2.71 million per well and the mean after-tax internal rate of return is 21%.

the increased number of frac stages — now numbering 14 to 16 — has increased well costs but they have improved the economics of the play and service costs have

fallen, he said. staged fracs, longer laterals and experimentation with different prop-pants has also helped to unlock the play, as have lessons learned from other shale plays, he added.

the main challenges to the future of this play are getting its gas to markets and the remote location, he said. “logistically it has been a very challenging area to develop because of how remote of an area it is. it’s a question of getting equipment up there, getting people, …[and] inputs such as water, proppant, etc. are all going to be challenges and are going to add to costs,” said mazar. it’s also a harsh environment that’s difficult to operate in, he noted.

enormous amounts of proppant — around three million pounds per frac — are required, and more could be needed as frac stages are added, said mazar. more than half the cost of proppant is transportation. there are also environmental issues such as the huge amount of water needed to fracture and these will need to be addressed, he said.

drilling pads could help shrink the environ-mental footprint and fit-for-purpose rigs may help to improve efficiencies, mazar added.

bmo estimates production from the horn river could exceed four bcf per day by 2015, assuming take-away capacity keeps pace. •

SHALEGAS

TechnologyPlayHorn River economics are promising; challenges remain

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COMMUNICATIONS

OnAlertRogers implements lone-worker solutions for the oilpatch

rogers has invested more than $55 million into the oilpatch over the past two years, extending its footprint into areas that didn’t have coverage previously, says steve roberts, vice-president for rogers Wireless in alberta. the rogers network has added 49 new global system for mobile communications (gsm) technology sites, expanding coverage into the Peace river and Fort mcmurray regions, grande cache and into southern alberta. “We’re bringing our technology into the oilpatch in a very big way and it’s going to enable oil and gas companies to do a lot of different things via our technology,” says roberts.

that expansion has helped rogers to provide three lone-worker solutions to the northern alberta oilpatch. “it gives workers working in northern alberta an alert switch if something happens to them, or a no-motion detector that, if they get knocked out, will automatically send their gPs location to a technical data centre that’s manned 24/7,” says roberts. “that’s brand new.” the various technologies can be on the worker’s black-berry, in the form of a tiny key fob that can be worn on the hip or put on a truck or atv.

rogers has been working on the solutions, all of them from “home-grown” alberta companies, for the past two years, and now, with the new lone-worker legislation in place, “we’re ready to go. People are putting them into operation as we speak,” says roberts.

a lot of the major producers are mandating that anybody working on their leases have these capabilities, he notes. shell canada limited, for instance, recently mandated that all service providers have gPs capability before going on its albian oilsands mine site so it can know where they are and when they leave the site, he says.

also, major manufacturers such as motorola and samsung are producing a line of handheld devices that have been made rugged, giving oilpatch workers tools they haven’t had before. they are shock-proof, water-resistant and dust-proof, roberts says. “it doesn’t matter what kind of fancy gizmo or gadget you have, if you don’t have the infrastructure and network in place, they won’t work. We’re confident now, that with our investment into northern alberta, we have a network; it’s just a matter of telling people about it.” • Lynda Harrison


OILSANDS

ComboPlanEnCana plans first commercial use of solvent in new oilsands project

a ProPosed in-situ oilsands Project Will see the first commercial use of a solvent such as butane to recover up to 120,000 barrels a day of bitumen with a steam-oil ratio of two, says encana corporation.

the narrows lake project, northwest of encana’s existing christina lake project in northeast alberta, will use a combination of solvent-aided process (saP) and steam-assisted gravity drainage (sagd), the company announced oct. 1 during a conference call to discuss its oil operations.

“We are very close to commercializing saP and that should be the first application commercially that you see for saP,” said harbir chhina, vice-president of upstream operations in the integrated oil division.

the steam-oil ratio at the new project is estimated to be two, however at higher rates it could reach 2.5, which chhina considers good. at christina lake, by comparison, the sor leading up to production of 200,000 barrels per day has consistently been about 1.7 to 1.9.

the sor refers to the amount of water that has to be converted to steam to produce one barrel of oil and is a measure of a project’s

success. an sor of two means two barrels of water have to be converted to steam and injected into the reservoir to extract one barrel of bitumen.

development will be in two or three phases of 40,000 barrels per day each. a regulatory application is scheduled to be filed in the second quarter of 2010.

saP involves injecting solvents with steam to improve recovery of deeper-lying bitumen deposits. it is expected to allow sagd developers to use wider well-spacing for a reduced environmental footprint. research suggests saP could also result in better-quality oil produced.

operating costs will depend on butane costs and the amount of its recovery, which will be better known from the single-well pilot project. “We believe we can recover 90% of the solvents we put down in our wells,” said chhina.

While there is a limited supply of butane within alberta, encana believes there is enough for narrows lake, which could use other solvents such as propane and ethane to replace it. •

vanguard

Baker Hughes has introduced its hughes christensen Quantec Force line of polycrystalline diamond compact (Pdc) bits, featuring newly engineered sta-bilization technology and next-generation cutters, to deliver appreciably higher penetration rates, increased footage and reduced costs in a wide range of drilling environments.

through the first 50 runs documented in fields across the united states, Quantec Force lowered costs by drilling 30% farther and 25% faster com-pared to offset bit performance, the company said. developed to reduce drilling costs through improved bit performance, baker hughes says Quantec Force has dem-onstrated excellent stability by employing updated design practices using a proprietary bit dynamics model to optimize the force distribution experienced while the bit is in service. this improvement has significantly reduced the occurrence of highly

destructive bit whirl, keeping the drilling process efficient and the cutting structure intact for faster and longer runs.

the new Pdc bit line also uses newly engineered and highly wear-resistant cutters, the company says. there are a variety of cutter choices, depending on the drilling application. one cutter type is specifically geared for abrasive formations, while another is engineered for drilling environ-ments where both abrasion and impact-resistance are required. •

Wavefront Technology Solu-tions Inc. announced in october that a calgary-based junior oil producer will deploy three Pow-erwave systems in its operations in the giant Pembina oilfield.

Pembina is the largest conventional onshore oilfield in canada with more than 11,500 wells covering more than 4,000 square kilometres. the field originally contained more than 7.8 billion barrels of oil, but

despite the fact that primary production started in 1953 and secondary (waterflood) recovery started in 1960, less than 20% of the oil has been recovered.

“unlocking the trapped reserves in the Pembina oilfield represents a significant oppor-tunity for Wavefront to demon-strate how effectively Powerwave can increase oil production,” said company president and ceo brett davidson. •

XACT Downhole Telemetry Inc. has announced the suc-cessful provision of its acoustic telemetry measurement while drilling (mWd) service in air drilled horizontal gas wells for equitable resources inc.

the Xact system is automated, solid state and incorporates a full throughbore design. the tool can easily be operated by rig crews without the need for full-time mWd operators on location. it is capable of transmitting data from downhole to surface at over 20 baud giving it the fastest commercially-available wireless update rate in the industry, the

company says.the system has advantages

over mud pulse systems as it does not rely on the presence of non-compressible fluid in the pipe or the use of mud pumps to generate the signals to the surface. Xact’s acoustic system is indifferent to formation type and can be used within close proximity to active coal mines or other nearby electromag-netic (em) telemetry systems, giving it distinct advantages over conventional em telem-etry systems.

in addition, sensor nodes can be installed along the drillstring, enabling the use of distributed measurements while drilling and tripping, as was demonstrated on the equitable wells.

Xact is a private canadian company with two shareholder groups, the majority holder being shell technology ventures Fund 1 b.v. the fund, managed by Kenda capital b.v., is a large-scale investment fund focused on reducing the cost of energy by accelerating the development and deployment of new technologies. •

TechBriefs


COMMUNICATIONS

Real-TimeCommunicationInfosat provides new mobile and fixed satellite communications solutions

vanguard

remote oPerations and a workforce on the move make the oilpatch a user of both mobile and fixed satellite com-munications solutions.

but mobile satellite com-munications products are often mistakenly thought of simply as the handheld satellite phone, says sarah crew, sales and mar-keting coordinator for infosat communications lP. the com-pany’s product lines and services include iridium, bgan, msat and connect.

currently, mobile satellite communication technologies such as small, car-mounted satel-lite dishes, voice and data termi-nals similar in size and weight to laptops, and hand-held satellite phones are commonly found in the oilpatch. these products cater to the mobile communica-tions needs in the industry as they are designed to be used in numerous locations, are typically small and lightweight compared to other solutions, offer users quick and simple set up, and are easy to use.

an example of a product launched in the past year is the iridium 9555 satellite phone, says crew. unique because of the reliability of service available with only a small and light hand-set, the iridium 9555 offers

global access to voice and data communications and can be used with a laptop for web browsing, e-mail and other applications. it will work anywhere in the world you happen to be, crew says.

she notes the exceptional cov-erage provided by the iridium network is a result of a meshed network of leo (low earth orbiting) satellites. typical uses for the iridium handheld in the oil and gas industry are for workers in remote locations or simply on the road but beyond the range of traditional commu-nications technologies. often irid-ium satellite phones are used as a first line of contact to the office. another typical use is as a primary safety back up when traditional communications are unavailable or unreliable, crew says.

Fixed satellite solutions, often referred to as vsat, differ from mobile satellite solutions in a number of ways. these products tend to be larger in scale, are able to perform reliably in much harsher environmental condi-tions, and are able to cope with a wide range of voice and data applications in the oil and gas industry. this type of solution is typically found where there is high demand for communica-tions and privacy in a remote location.

infosat’s vsat products include the connect line of products. “Within the connect line, the consumer will find both out-of-the-box solutions as well as more customizable vsat systems that infosat’s in-house engineering team will work to customize for your specific application in the oil and gas industry,” says crew.

new this year to the connect line of vsat products is infosat’s advanced guaranteed services (ags). developed in response to demand for a vsat solution offering a secure private network, ags offers industry professionals the ability to moni-tor and control their own network through an online bandwidth usage report via “Packeteer.” ags users have the

tools to prioritize iP traffic or applications using their own Qos, and choose the bandwidth required without upgrading their hardware or running into data allowance or limits.

a typical use for this would be setting up a virtual office at a remote drilling site, and accessing the company’s private network for the purposes of data sharing, transmitting faxes, e-mail, large files and making phone calls. “oilpatch profes-sional in the field and at the office need to communicate in real time. ags provides the oil and gas industry a fast, secure and economical tool to ensure critical voice and data communi-cations are as simple in the field as they are in the office,” says crew. • Lynda Harrison

MakInG conTacTLeft: Iridium 9555 sat phone. Right: Infosat’s ground station in Calgary where any VSAT data or voice is re-ceived from space and redistributed to the client’s networks.

The Geosteering for the Digital Asset™ workflow does more than help ensure

precise wellbore placement. It lets you refine models and plans so you can adjust

well paths in real time—and maximize reservoir exposure.

Change the way you work: Increase the accuracy of your wellbore placement

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News FroM THe LaBresearchFUNDING

R&DInRecessionaryTimesduring the downturn, becoming more efficient with funding is key

desPite being hit by loWer commod-ity prices and clobbered by correspondingly weaker revenues, sending companies into cost-cutting mode, the importance of research and develop-ment and its implications on the industry’s future health and prosperity seem to still be resonating in oil and gas circles.

r&d budgets have been a fairly easy target for the budgetary hatchet in past downturns as compa-nies worked to keep costs in check during stormy times. unlike the past, though, the pressure on the oil and gas industry by government and the general public to improve its environmental record persists, even during this turbulent period.

ian Potter, vice-president of energy with the alberta research council, says the energy industry in alberta seems to be maintaining its overall investment in r&d.

“regardless of the current and historical economic challenges, it’s been evident in my time … at arc that if a research and develop-ment project can show a clear line of sight to commercial viability, the companies will normally invest in these projects,” he says. “in some cases, the research and development needs are addressing shorter developmental needs, but in other areas there’s an even greater emphasis on the game-changing, longer-developmental term, technology thrust.”

What’s changed is additional scrutiny that each project goes through for approval in terms of cost/benefit and return on investment and a higher authority sign-off level within companies.

“as for the focus for technology research and development, to be honest, over the last decade we’ve seen a move to adoption and adaptation of existing technology from other sectors and the larger-scale piloting and demonstration of

technology in the field,” Potter says. “in the case of level of investment, it’s been evident in previous downturns that companies that maintain the research and development investment are stronger in the longer-term.

“obviously, government-levered investment in innovation has been instrumental in helping these companies through these downturns.” an example is alberta’s large investment in technology to develop carbon capture and storage.

the path to lowering greenhouse gas emissions is going to be paved with technol-ogy development, a point that was made clear recently by eric newell, chair of alberta’s climate change and emissions management corporation. the arm’s-length provincial entity is charged with managing the province’s climate change fund, which to date has collected over $120 million. the first call for proposals closed on sept. 30 and generated tremendous interest.

now the organization will shuffle through the applications and dole out cash to help promising technologies that could lower ghgs, an issue which is now also prominent for investors. but while the economic crisis sparked widespread gloom, there is a silver lining for r&d, observers say.

The collaboration imperativesoheil asgarpour, president of Petroleum

technology alliance canada, says that while fewer


research

dollars are available for research because industry’s revenues are down, it’s forcing r&d cash to be used more efficiently by tackling the job collaboratively.

“clearly, when revenue drops, we see that r&d spending goes down,” he says. “there are clear connections between the two.”

based on historical experi-ence, companies will look at their revenue and from there decide how big the slice of pie will be for r&d. that’s mainly because research spending has no immediate payoff as companies are spending millions now with rewards not coming possibly for a decade hence.

“this has happened in the past,” asgarpour notes. “We have noticed that many r&d centres that companies had were shut down.

“in the 1980s, we had thou-sands and thousands [of people] working in research and devel-opment centres for big compa-nies. [since then] i think many of these companies have reduced the size of their research and development activities signifi-cantly.”

but by working jointly and combining research dollars and expertise, it gives the money more mileage and improves the quality of the work, he adds.

“collaboration usually occurs through formation of consortia consisting of industry and gov-ernment funders who manage projects through steering com-mittees. When you have a steer-ing committee of experts from different companies that look at the projects, the knowledge that they bring to the table would

be complementary,” asgarpour says. “not only do you get better financial leveraging, you get expertise leveraging and you reduce both the manpower that you would have required if 10 companies had gone and imple-mented a project [each on their own], reduce costs and [have better] results.”

he hopes that increased collaboration will spark a shift for companies to revisit their view on whether their technolo-gies are really competitive. “i’m hoping that we are getting to an environment where we are going to expand areas of non-competi-tive technologies and reduce the areas that … are competitive,” he says. “this collaborative approach makes perfect sense.”

robert Peterson, a houston-based consultant with charles river associates, says companies are increasingly partnering with firms from outside industry, such as general electric, siemens and duPont, for r&d oppor-tunities, including for chemical processes or using biological techniques for upgrading.

also, the oil and gas industry has generally favoured incre-mental technology development, he notes.

“if you look at a typical oilsands technology budget, a general characterization is that 80% to 90% of the spend is on short-term technology and tech-nology application,” Peterson says, adding the remaining is on fundamental breakthrough science.

but breakthrough technolo-gies are critical, notes asgarpour, pointing to horizontal drilling,

which helped to change the face of industry.

“those are still needed but i would say right now we’ve got to look at areas of focus,” he says. “to me, the major areas that we need to focus on are reducing costs, managing environmental impacts and improving recovery from our world-class resources,” he says. these must not be looked on in isolation during r&d, but examined as complementary. “to me it’s doable,” asgarpour adds. “What we have here in canada is no lack of innovative people and creative people.”

as an example, he says Ptac helped to facilitate the develop-ment of a detection system for fugitive emissions, which had the dual effect of saving natural gas and reducing environmental impacts.

research spending trendsearlier this year, Peterson

found that r&d spending had been flat in 2009 compared to the previous year, a trend that he says remains essentially unchanged.

“Firms weren’t immediately responding to the downturn with knee jerk, large reductions in research and development,” he says. “some of the bigger firms in canada, the u.s. and international that were scal-ing up their r&d [efforts] … weren’t able to staff up.

“lots of people … had empty positions. they decided not to fill those positions.”

the other trend is that inter-national operators with ambitious agendas around renewable energy development such as wind and

biofuels have deferred these pro-grams. since most of the cana-dian oilsands operators didn’t have renewable energy operations, the effect is virtually nil.

“[oil prices] have seemed to find a base … so companies have breathed a sigh of relief,” he says. “they’ve taken the view that there is a future.

“in general, supply costs for oilsands have come down and most operators are seeing their costs are now about $60 per barrel.”

the overarching point to technology development that hasn’t been a factor in previous downturns is a vigorous focus on environmental stewardship by the public, which is helping drive the political agenda.

“[companies] fully believe that technology is critical to the efficient, large-scale produc-tion of the oilsands,” Peterson says. “carbon will have to be managed. legislation will come in the u.s. around carbon management. [it’s] not clear whether it will be cap and trade or a tax.

“the expectation was there would be some definitive regulation this year but it’s likely to be next year.”

in the oilsands specifically, an area of focus is on improving in-situ production techniques such as steam-assisted grav-ity drainage (sagd). “they understand the immature nature of the process and are investing aggressively in technologies to optimize [sagd],” he says. “also being investigated are options for what might replace sagd in 10-plus years.” •

Richard Macedo

By The Numbersaccording to a recently-released survey of overall corporate r&d

expenditures in Canada by research Infosource, spending dropped amongst the country’s top 100 r&d spenders to $10.09 billion in 2008 from $10.10 billion the previous year.

EnCana Corporation was the top oil and gas performer on the list at 24th overall. The company spent $88.5 million in 2008, up from $71.9 million the previous year. In terms of research intensity, EnCana’s r&d spending as a percentage of revenue was 0.3%.

Husky Energy was a big mover, jumping to number 66 from 101 the

previous year by boosting r&d spending 122.2% to $30 million in 2008, a research intensity of 0.1%.

Other oil and gas companies cracking the list that had year-over-year increases were penn West Energy Trust, which upped its r&d expenditures 46.5% to $29 million, while service and supplier Trican Well Service hiked spending 21.5% to $17.8 million.

Those that recorded declines were Imperial Oil Limited, which spent $83 million, down 6.7%; Syncrude Canada Ltd. dropped 5.2% to $50.3 million; petro-Canada’s r&d expenditures fell 23.1% last year to $40 million, while Nexen had a 25% drop to $30 million. (The world economic crisis didn’t begin fully hitting the oil and gas sector until late last year).


CoNTrIBuTed arTICLeviewpoint

COMMUNICATIONS

DoingMoreWithLessHow information and communications technologies can help companies reduce expenses and gain a competitive advantage

the oil and gas sector in canada has more than 70% of its workers in the field. given the size of this remote workforce, companies are looking for ways to improve field productivity by the innovative use of information and communica-tions technologies. a 2008 idc study states: “as it budgets tighten, technology buyers will turn to those it suppliers that understand their business and can help them to do more with less. it solu-tions and services that can help the buyer reduce expenses, mitigate risk, and become more intimate with their customers will resonate well.”

a number of new information and communica-tions technologies are particularly suited to the demands of field work. a typical field worker carries a mobile device that is used primarily for conversation and email. but the potential is far greater. a large number of manual processes can be automated and mission-critical business applications can be extended into the field.

Field safety is one of those mission-critical applications. a common problem for most large

companies is having line of sight to regula-tory and safety deficiencies. all companies are required to address safety and environmental concerns and this is done in the field through inspections or checklists. technology is now available that allows field workers to access and complete these inspections electronically, wherever they may be. intrinsically safe devices allow this type of work to be performed even in hazardous areas. companies are finding that this technology not only increases productivity in the field, it also reduces business risk by creating an audit trail that shows they are meeting their corporate and regulatory obligations.

energy companies are also using information and communications technologies to monitor the safety of remote workers and respond to emer-gency situations. Work alone legislation requires employers to protect the safety of their workers by identifying potential safety risks, eliminating or controlling them, and refining communication among workers to notify them of these hazards.

Roland Labuhn, vice-president, TELUS Energy Vertical


Wireless technologies such as Push to talk (Ptt) allow workers to instantly communi-cate safety concerns to a team member or the entire crew with a push of a button. rug-ged, intrinsically safe handsets with Ptt are now available for workers in the field. they are designed to have low electrical and thermal output, which eliminates the risk of producing sparks and therefore enhances worker safety. remote workers can also proactively signal an emergency by using either a dedicated device or a combination of a bluetooth-enabled pendant and an intrinsi-cally safe handset.

another alerting solution can be delivered through a technology called automated vehicle location (avl). class 1 div 1 no-motion sensors can be connected wirelessly to a modem in a vehicle equipped with avl. some of these devices are built specifically for the energy patch; they work in extreme conditions and can transmit over frequencies that will not interfere with wireless scada networks. another useful service is out-of-truck notification. these timer-based out-of-truck-notification systems utilize failsafe timers at the vehicle to notify drivers and responders of a potential incident.

avl combines global positioning system (gPs) with energy-specific mapping, sometimes Web-based. these maps, which provide details such as pipelines, well batteries and facilities, can prove critical in vehicle location, routing and worker safety.

avl not only enhances safety, it is also a field productivity tool. some systems allow companies to monitor speed, location, time and position of their fleet, resulting in more efficient routing and dispatch. companies are achieving cost savings through reduced service delivery time and increased unit hour utilization of assets. in addition, by monitoring vehicle usage and wear (through engine control modules), proactive maintenance schedules can be developed to further reduce fleet costs. some in-vehicle modems have ports so that workers can plug in laptops or tablets and use the secure connectivity in the truck. this mobile gateway can enable other productivity applications such as driver logs, compliance reporting and field ticketing.

the convergence of improved system capabilities, reduced costs and a growing demand for safety and field productivity has resulted in information and communications technologies becoming widely available. energy companies are using these technolo-gies to remain competitive and safe, even in challenging economic times. •

Roland Labuhn

viewpoint

We’re increasing our editorial content with stories and columns focusing on how companies are handling the downturn, preparing for the rebound, and, in some cases, even thriving. They’ll be easy to �nd. Just look for the special Recession to Recovery logo in each issue of New Technology Magazine.

While some economists have declaredthe recession over, the painful recoveryis expected to drag well into 2010.JuneWarren-Nickle’s Energy Group’s newRecession to Recovery initiative will helpyou navigate these uncertain times.

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kinds of conditions, for all kinds of clients.

..kinds of conditions, for all kinds of clients.




are trademarks owned by Packers Plus Energy Services Inc. Some or all of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936; 7,134,505; 7,108,067; 7,543,634; 7,431,091; 7,021,384; 7,353,878 or other patents pending.7,134,505; 7,108,067; 7,543,634; 7,431,091; 7,021,384; 7,353,878 or other patents pending.

are trademarks owned by Packers Plus Energy Services Inc. Some or all of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936; of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936;

are trademarks owned by Packers Plus Energy Services Inc. Some or all


worldwide – in all kinds of formations, in all worldwide – in all kinds of formations, in all


are trademarks owned by Packers Plus Energy Services Inc. Some or all of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936; 7,134,505; 7,108,067; 7,543,634; 7,431,091; 7,021,384; 7,353,878 or other patents pending.7,134,505; 7,108,067; 7,543,634; 7,431,091; 7,021,384; 7,353,878 or other patents pending.

are trademarks owned by Packers Plus Energy Services Inc. Some or all of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936; of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936; of the systems, methods or products discussed herein may be covered by US patent numbers 6,907,936;

are trademarks owned by Packers Plus Energy Services Inc. Some or all are trademarks owned by Packers Plus Energy Services Inc. Some or all are trademarks owned by Packers Plus Energy Services Inc. Some or all are trademarks owned by Packers Plus Energy Services Inc. Some or all

shalegas

a BeTTer PIcTUreNew tools, and new combinations of existing tools, are providing better-quality interpretations of downhole conditions in the long horizontal wells that have made shale gas plays a commercial success.


coverstory

know thy reservoir

Multi-disciplinary shale gas solution integrates cased hole evaluation, interpretation and stimulation

By Maurice Smith

What began as a steep learning curve to economically produce the massive quantities of shale gas in emerging plays around north america is becoming flatter by the day as the majors throw their considerable research expertise at the problem. as play after play is unraveled, creating vast new reserves of natu-ral gas and turning around what was just a few years ago considered a sunset industry, com-panies are finding increasingly novel ways to trim costs and squeeze out more molecules of gas from the ultra-low permeability rock.

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shalegas

one company that has made shale gas a priority has played to its greatest strengths, its size and multidisciplinary know-how, to create a range of new tools and techniques targeted at canada’s most promising shale gas play, northeast british columbia’s horn river basin. and schlumberger believes those innovations are on their way to not only unlocking the horn river, but spreading to other basins worldwide.

“With the recent focus in shale gas activity, primarily in northeast b.c., but not restricted to there, we are very focused on improv-ing our ability to understand the reservoir and improve completion practices,” says trevor gorchynski, unconventional gas business manager, canada. “geologically speaking, what we have in north-east b.c. is probably the potential, with the horn river basin, to be one of the best shale gas plays in north america.

“We have lots of examples of how we can complete these from our previous experience in plays such as the barnett shale [in texas] and others. but we can’t assume what works there is what is going to work for us here. We still need to really advance our understanding of the reservoir to allow us to have lots of knowledge to make informed decisions,” says gorchynski.

shale gas plays, which require maximum reservoir exposure to be economic, have been solved through the use of long horizontal wells that are fractured in multiple zones along their several-hundred-metres length. most producers, according to salman Khalid, a calgary-based schlumberger senior petrophysicist, have been work-ing under the assumption that the reservoir changed little along the length of the horizontal. each zone, therefore, was fractured identi-cally. but as detailed logging can reveal, the reservoir is not consis-tent, with qualities varying abruptly in vertical and lateral directions, and therefore each frac should be designed specific to each zone.

“What we are trying to do is to optimize fractures in horizontal wells. and the first thing to understand is the heterogeneity of the reservoir along the horizontal, which is contrary to what many people assume — which is that everything along that horizontal is homogeneous,” says Khalid.

the principle means to characterize the lateral has been openhole wireline logging — taking readings before the well has been cased and cemented. but openhole logging has its drawbacks. since it requires the presence of a drilling rig, it adds to day rate costs. and it can be risky, notes Khalid. “because you are in the open hole, you are subject to the possibility of getting stuck there or having other issues, which could delay the process or just increase the expense on the part of the operator.”

given those limitations, companies were forgoing logging of the lateral portion of the well altogether, says gorchynski, to the detriment of the completion strategy then employed. “the trend in the market has been to only conduct reservoir evaluation on the initial and vertical wells, and then apply this knowledge to the rest of the field,” he says. “We have seen lots of recent instances where we are not entirely sure of the stress environment that we are in when we are completing some of these wells, and this has led to us not effectively stimulating the well.” oftentimes, a refrac is then required, he notes, creating additional expense.

understanding reservoir properties beforehand and planning completions based on that knowledge is the key to production optimi-zation, he stresses. “Within these shale gas plays, horizontal comple-tions are one of the key things that has led to all of our successes. but the evaluation within that horizontal has really been left out and it’s extremely important to have this information. you need to understand changes laterally, the heterogeneity, how the properties are changing, and understanding this is really critical to optimizing these wells.”

new toolsschlumberger’s alternative to openhole logging in this environment,

aside from the option of using logging while drilling tools, was to devise a method to log the lateral after it has been cased, cemented, and the rig has been released. “if we move [the logging process] to the cased hole, after the rig has been released and the casing has been put in place, we take out a lot of risk factors from the situation. basically your hole is sealed, it’s safe, there is no rig costs being incurred,” says Khalid.

to accomplish this, the company marshalled the expertise of its in-house data & consulting services (dcs) group to produce solutions from cased hole tools that can provide the same reservoir answers, after completions, as openhole logging tools could before

InITIaTInG fLoWSchlumberger performs multiple stimulation treatments on a horizontal shale gas well in northeast British Columbia.


completions. the dcs group — “the interpretation experts in the company,” says Khalid — employs some of the industry’s leading experts in exploration and production data interpretation and consulting services. it employs over 2,200 technical experts, including geologists, geophysicists, petrophysicists, and reservoir and production engineers in more than 80 worldwide locations.

the new cased hole solution may take a different route to get there, but they are now capable of producing the same basic answers as openhole logging tools, at a lower cost and without the risks. “there are certain compromises, but the process has evolved to the point where we can take care of those compromises,” Khalid says.

“it is a different set of measurements compared to what we had in openhole. the challenge was to build an interpretation methodology

that would use those measurements and actually come up with a meaningful answer, for the same parameters that we were looking for. With the recent efforts of the dcs group here we have been able to achieve that, and that is a big plus for the industry. We are now able to make good assumptions about the added effect of cement and casing in the system.”

With such instruments as spectroscopy logging, epithermal neutron porosity logging and multidimensional shear sonic logging tools, schlumberger can now provide all the necessary measure-ments post-casing. tools available include the ecs elemental capture spectroscopy logging tool, which provides in-situ geo-chemical analysis; the Platform express platform which provides an integrated combination of neutron porosity, density, gross gamma

Photo courtesy of Schlumberger


shalegas

sPInner advanceSchlumberger’s Flow Scanner tool uses five spinners instead of one to more accurately measure flow in deviated and horizontal wells.

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coverstory

ray and electrical logs; and the sonic scanner used to measure anisotropy and mechanical properties with axial, azimuthal and radial information.

“some of the parameters that we look at are lithology, porosity, organic carbon, water saturation and mechanical properties of the rock, which includes stresses, and those kind of things,” Khalid says.

“When you have the knowledge of these variables, you go in and choose your completion strategy based on that. you can optimize parameters like pumping pressure, volume that you are going to pump in, the proppant that you are going to use. so basically what you are getting is the flexibility of intelligent design,” he says. “if you look at the cost of acquiring this data in a scenario where you have a cased hole well, and compare it to, for example, saving a single stage in your well to proper completion, these costs are easily offset.

“this technique has been optimized in canada and we have been using it successfully for about the past year or so,” Khalid adds. “most of the focus in canada has been in the horn river, but it’s

being applied in other places like the montney, and i’m sure as people get to know about it there will be a lot of application, [and] i’m expecting that people from the u.s. will pick it up as well.”

gorchynski notes the technology has led in other areas to increased levels of refracturing of completed wells. “that process has really led to some recent activity in some of the more mature shale basins on refracs,” he says. “When you hear about a refrac, you know that the well is underperforming, so some of these early concepts of what we call cookie-cutter [completions], putting stages so many metres, are definitely now being viewed as being under-stimulated and not optimizing the well. so that’s obviously what we want to avoid, is having to go in and reenter these wells and perform these refracs, and that’s an additional savings.”

along with the ability to take measurements through casing, schlumberger came up with a well tractor to convey tools through the length of the wellbore. the two-drive, modular tufftrac cased hole services tractor can run up to six drive sections as needed to push heavy loads, with each drive section capable of providing 300 pound force (1,330 newton) of push. the shortest tractor on the market, and the only one with reverse tractoring and traction control capability, it can reach a maximum speed of 3,200 feet per hour (975 metres per hour). “it can push the tools in and we can pull the tools back with wireline and be able to control the speed, and we are able to get the data as we like,” says Khalid.

the optimization process does not end with the well comple-tion. new tools are also available to improve output once gas production is underway. the question at that stage, Khalid says, is whether all the 10 or more fraced stages of the well are performing according to expectations.

“there is a post-stimulation evaluation that you can do which was very difficult to do earlier, that would allow you to determine the contribution from each section of your lateral,” he says. Previously, this was done with a conventional spinner tool with a single, central spinner, initially designed for vertical wells. the speed of the

spinner varies as it is moved from one zone to the next, providing readings for production from each. While that works well with vertical producers, once a well is on its side, conditions change. Fluids, for example, flow at bottom, while gas flows above, at a different velocity.

“the problem is, this well is sitting on its side, and what you will have is a bit of water production from these producing zones as well. because the well has two phases of fluid in it, you don’t necessarily know where the liquid phase is and where the gas phase is. and because it is along the length of the horizontal, what happens is that some sections might have liquid filling all the way to the top and very little gas coming out from the side, and other sections may have mostly gas.”

the result is that a conventional spinner measurement usually does not provide any meaningful results in horizontal wells because the phases are changing, and they are changing in an unpredictable way, he says. schlumberger’s answer was to produce a tool with five small spinners aligned vertically that can take readings from five “slices” of the wellbore from top to bottom.

“so now you can actually tell what the profile of the liquid is by looking at the various spinners along the height of the well. it allows you to look at the production profile while you have varying fluid phases in the reservoir.… if you have that data, that gives you the ability to go in and say, ‘oK, two of my 10 stages are not producing anything.’ and once you have that knowledge, the question then is, can you go back in and optimize those completions based on this information, and enhance production without having to drill a new well. you have the ability to take this data and to refrac some of the zones that have good potential but were not stimulated properly,” explains Khalid.

called Flow scanner horizontal and deviated well production logging, the tool also uses electrical and optical probes to distinguish water and hydrocarbon holdups, and to differentiate gas from liquid holdups, respectively, to enable the three-phase measurement. by combining the holdup profiles with the multiphase velocity profile calculated from the measured phase velocities, the tool can determine relative volumetric flow rates in real time.

use of the tool, among other things, “dispels the notion that everything is homogeneous along the lateral,” Khalid notes. “this technique is giving you the ability to judge the quality of the completion and rework the completion if you have to,” he says. “many of our clients are onboard and are working with it.”

taken together, such new tools and techniques have combined to bring down the cost of production from the potentially prolific horn river basin in a fraction of the time it took to make the barnett shale — the poster boy of shale gas production — the massive, highly profitable play it is today. and part of the reason for that is the valuable learnings taken from the barnett and applied to other shales, which provide an invaluable starting point for all shale plays that have followed.

“i think all that learning has helped us shorten the learning curve dramatically in the horn river, and the same could be said of the other opportunities that we are seeing in canada,” Khalid says. “there are other plays which are coming up as well — the montney is not a classic shale but it is considered as a shale reservoir, and there are the colorado shales which others are looking at, the bakken, the utica in Quebec, and then there are others that people are looking at which they are not talking about.” •

conTacTs for More InforMaTIon

Trevor Gorchynski, Schlumberger, Tel: (403) 509-4000

Salman Khalid, Schlumberger, Tel: (403) 509-4000

“I think all that learning has helped us shorten the learning curve dramatically in the Horn river, and the same could be said of the other opportunities that we are seeing in canada.”

fraca d v a n c e s

icebreaker


fracing

horizontal multi-fracture technology is revolutionizing oil and gas production across north america, opening up

new resource plays and boosting produc-tion by double-digit percentage points. but it comes at a cost as the fracture technology requires ever growing amounts of horse-power — and the surface infrastructure needed to produce it and force it into tight reservoirs far downhole.

the president of an edmonton-based startup thinks there is a better, simpler and cheaper way to produce the same results. and he uses a fluke of nature to do it.

darrell Kosakewich, founder, president and majority shareholder of triple d tech-nologies, wants to use the unique property of water to expand as it freezes — about nine per cent in volume — to move the process of creating the necessary frac pressures under-ground, to the reservoir itself.

similar to the freeze-thaw process that creates frost heaves that damage roads in winter, the technique Kosakewich has pat-ented would freeze formation water down-hole, causing it to expand and crack the rock, opening up new passageways for hydrocar-bons to flow back to the wellbore. “let face it, ice moves mountains, so why wouldn’t it move a little bit of formation,” he says.

the process uses concentric coiled tub-ing, or alternatively jointed pipe and coiled tubing, to circulate a refrigerant along the length of a horizontally drilled wellbore. the refrigerant, liquid co2, flows through the annulus between the two pipes, freezing the water-filled wellbore in the process. use of concentric tubing in the closed-loop system keeps the refrigerant from ever directly con-tacting the water or the reservoir. it also pro-vides a means of moving the freezing process along the length of the wellbore even while the outside tubular is frozen in place.

and, by relying only on the sheer might of water expansion as it turns to ice to create the necessary fracture pressure, the process does away with the surface equipment required in conventional fracturing to produce extremely high pressures needed and pump them downhole. it is thus inherently safer, less costly and creates a significantly smaller surface footprint compared to conventional fracturing techniques, Kosakewich says. additionally, the system uses produced water in volumes only enough to fill the wellbore and requires no fresh water, gels or other chemicals as is typical with traditional fracs.

“We can do a frac without the frac trucks and usual equipment and we get frac pressures in the neighbourhood of around 300 mpa [megapascal], which is two to three times greater than anything you can get on the surface,” he says. “the internal coil of the tubulars is moveable, similar to the retractable aerial on your car, so we can position it any place we like while the outer one is frozen in place. that is where the patent comes in.

“With ice we can then also put together some very interesting isolation packing situations. if we wanted to shut off a flowing water zone, we would just set up over it, freeze there first, and then move on. We have the only packer in the world that can go through a slotted liner and seal to the wellbore.”

Whereas conventional fracing tends to produce horizontal cracks, requiring the pumping of proppants as a buttress to counteract gravity’s tendency to close them, triple d’s technique offers a simpler solution, Kosakewich believes. “ice behaves in such a way that the forces go out radially from the freeze point, and so consequently you get a vertical frac, which doesn’t close once you take the freezing away. because it’s been vertically loaded, in our system, we don’t need to use proppants at all.”

Kosakewich envisions up to three freeze-thaw cycles being used, each taking about eight hours, to maximize the number of microfractures created and to clean up the wellbore. “We can clean up the skin effect on the wellbore, because when you freeze-thaw, the skin that is typically associated with drilling scales off.”

Inventor turns to nature to fracture tight formations


fracing

he says liquid co2 was chosen as the refrigerant because it has excellent heat transfer char-acteristics compared to liquid nitrogen and doesn’t have any special metallurgy issues. “When it goes into sublimation — by which i mean goes from liquid to gas phase — it really draws the heat very, very rapidly. there are two ways we can do this,” he adds. “one is with a vapour recovery system on the surface, and the other is by controlled venting through a flare stack.”

Germ of the ideathe idea came to Kosakewich, who has spent 15 years in various oilpatch research roles,

when he was investigating new ways to deal with settling tailings ponds created by oilsands mining operations. When he froze a piece of coal containing water he found the sample had broken to pieces in the freezer. “i thought, there’s your frac,” he says. From there, the challenge was to create a process whereby the mechanism to freeze the water could remain mobile rather than be frozen in place.

“you are limited on what you could freeze, because of the size of the jacket capacity of your tubulars, to only probably a maximum frozen section of about 50 metres at one time. so the only way we could accomplish more — say if you have a thousand-metre lateral — was to have a refrigeration system move, and that’s were i came in with the aerial idea.”

the freeze frac could be performed for a fraction of the cost of other methods, Kosake-wich says, estimating as a general average about $125,000 to $150,000 per frac. the initial market push will be for enhancing production from existing, low-production wells. “it will allow producers that have mature fields to take another look at their assets and give them the ability to get wells producing again. they can step up the value of their asset without [spending] too much money.”

triple d formed an alliance with calgary-based companies technicoil corporation and Petrojet canada inc. to bring the technology to market. technicoil will provide the delivery system while Petrojet will provide downhole services.

“We are supplying a conventional service rig and a coiled tubing unit that will work in conjunction with that rig,” says marvin clifton, technicoil president and ceo. “now it’s just a matter of finding a prospect, lining it up, buying some coil and basically taking the mast off one of our rigs and then backing it up to the service rig.”

While he thinks the process still requires some fine-tuning, noting, “it’s simple in con-cept, it might be a little harder to execute,” clifton says it certainly has promise.

“What’s happening right now [with con-ventional fracing] is an excessive amount of force is being applied with a great amount of horsepower at the surface, and this takes away from that. you don’t need all of that horse-power at the surface because [with the freeze frac] it’s all being done downhole. if you can get away from the high-horsepower fracs and all that entails, and increase production, then yes, we think there is potential.”

the next step, he says, is to carefully select the right prospective wells to prove out the technology before launching it in a big way. “We should walk before we can run, because what happens in the oilpatch so often is, if you introduce something and it doesn’t work as promised right away, it takes a long, long time for people to overcome that negativity.”

in one field trial of the freeze frac last February in a nexen inc. coalbed methane well, the technology itself worked flawlessly, says senior staff engineer john anderson. but he says the end result was less encouraging.

“in terms of the operation of the freezing, there were no issues whatsoever — it worked perfectly,” he says. “but as far as the effectiveness of the treatment, the jury is out on that. there was really no effect either positive or negative on the production of that well. i was hoping that we would get some cracking of the coals, some fracturing, perhaps two metres out into the coal, to increase the near wellbore permeability. but we have not seen that happen.”

anderson cautions, however, that the lack of production response may be due more to the reservoir chosen than the technology. “i don’t think coal was the best candidate. being such a soft rock, the fractures we created may have resealed themselves. shale gas plays, tight gas sands, something of that nature, might be a better candidate.

“i am convinced that the freezing down-hole does take place. depending on rock type, the fractures created by the freezing may increase the producibility, or possibly help in hydraulic frac initiation or other stimulation techniques.” he says nexen would be willing to try the technology again, though it will await other results first. •

Maurice smith

conTacT for More InforMaTIon

Darrell Kosakewich, Triple D Technologies,

Tel: (780) 440-3348,

E-mail: [email protected]


fracing

fluidquest

as an emerging tight natural gas play in northeast british columbia and northwest alberta, the mont-ney formation offers considerable

potential. but its heterogeneous character presents unique stimulation challenges.

“the whole world is not a barnett shale; there is a real tendency for people to think that everything is the same as the barnett shale and that everything should be done the same way and that’s definitely not true,” says halliburton’s robert taylor, who has spent the last year on core studies of the upper montney from two different wells and two different producers.

“What we are seeing in areas that we have studied is that there are definitely some issues with water sensitivity and to just go in and copy what is done in the barnett shale [which displays little water sensitivity] would definitely be a mistake,” he says. “it could be done but there are better ways to do this, better ways to get good economic value out of the reservoir.”

the upper montney that was studied exhibits reduced “regained methane permeability” as a function of both frac fluid water content and exposure time, says taylor, a senior technical professional manager. a key challenge for the operator is to maximize the effective fracture flowing half-length to get better production from the wells and to maximize the fluid clean up. “the faster you can clean up the fracturing fluid, the faster you are going to get it on production and that can be very important as the production you get in the first two or three months can be a large part of the economics of the well,” he says.

a paper presented at the canadian

Montney demands unique approach to stimulation

international Petroleum conference in june discussed work in which a large number of fracturing fluids were studied for regained methane permeability with montney core. of the fluids studied, four were identified which outperformed the others — two water-based and two hydrocarbon-based.

although there are issues with water retention and slick water was not the best choice, it certainly wasn’t the worst choice as damage to the reservoir also is a key issue, says taylor. (slick water fracs combine water with a friction-reducing chemical additive that allows the water to be pumped faster into the formation.) “We don’t want to have any more water content in the fluids than we have to; we want to get it out of the reservoir as quickly as we can.”

the study observed that the highest regained methane permeabilities as a function of drawdown pressure used energized fracturing fluids that minimize the total water injected into the reservoir. specifically, it found the most effective systems were water-based ultra-high quality (90% quality or higher and 10% or less water) foams and hydrocarbon-based systems.

on the water-based side, the omegaFrac system combined three different components, each of which had previously been used separately, resulting in improved performance over a traditional guar-based fluid.

in order to facilitate the higher quality foam, a different type of proppant needed to be incorporated, in this case a new patented lightweight monolayer proppant that forms a partial monolayer providing improved fracture conductivity. as lower concentrations are required, the monoproppant enables the use of high quality foams while still injecting the required amount of proppant into the fluids. a potential issue with a normal proppant is that with the use of a high quality foam (90% quality or better) there are limits as to how much proppant can be put into the fluid. the monoproppant has been tested for high closure structures to 10,000 pounds per square inch.

the third component of the system is a new base gel polymer that provides both improved fracture conductivity and low shear viscosity for improved proppant transport.

as operators work to understand the montney and other tight reservoirs, among the key questions they are trying to answer is how many fracs there should be, their spacing and the spacing of the laterals with the objective of effectively draining the reservoir while not completing more fracs than are necessary. “that really gets into the need to do proper computer modelling and design, which is part of what we are offering here,” says taylor. “the overall goal is to deliver higher asset value so at the end of the day by applying these technologies the operators are actually seeing better overall economics.”

the overall cost of specialized fracture treatments includes not only the cost of the treatment but the effect on flush and longer-term production, he says. “if we are achieving clean up on the fluid, there is money saved on the swabbing costs or service rigs or any other additional cost.”

With the monoproppant, considerably less product — as a rule of thumb 10 times less — is required so it is faster to work with, which saves both time and money. “as you get into more remote locations, that in itself can be a factor.”

in the end, though, operators can best fully realize the potential of the montney with a thorough understanding of the reservoir in which they are working, taylor emphasizes. “that usually means taking your time on the first few wells and doing a lot more testing … to really delineate what you’ve got,” he says. “then you can go ahead in more of a production mode.” •

elsie Ross


Robert Taylor, Halliburton, Tel: (403) 231-9361, E-mail: [email protected]


fracing

the ability to accurately predict and optimize drainage volumes in natural gas shales is no simple feat. the movement of hydrocarbons and other fluids in naturally fractured reservoirs or in conventional reservoirs with significant fracture permeability often is not as expected or predicted. irregular fracture

network geometries yield scale dependent and anisotropic behaviour which is not observable in conventional reservoirs. hydraulic response of a reservoir is further complicated by hydraulic interaction between fractures and the surrounding porous matrix.

however, recent advancements in understanding one the most important geological parameters in shale gas reservoirs — the natural fracture system — are aiding exploration and production companies in their quest to optimize drilling programs and ultimately recovery.

evidence from microseismic monitoring of hydraulically induced fracture growth shows that hydraulic fractures sometimes propagate away from the present-day maximum horizon-tal stress direction, negatively affecting well performance. one likely cause is that natural opening-mode fractures, which are present in most shales, act as weak planes that reactivate during hydraulic fracturing.

that’s why knowledge of the geometry and intensity of the natural fracture system is important for effective hydraulic fracture treatment design, as production is often dominated by large fractures and the ability of wells to connect to them, says doug bearinger, geology advisor for nexen inc.

“as far as advancement goes, historically hydraulic fracturing models have been fairly simplistic. they essentially use a poroelastic model that assumes the rock is not fractured to begin with, which gets you into trouble if you keep making that assumption in a reservoir that is already quite fractured,” explains bearinger, who is involved in advancing the com-pany’s horn river shale gas play in northeastern british columbia.

“i think people are coming to appreciate that hydraulic fracture geometries are not typically simple bi-wing planar fractures and that they may also intersect open natural fractures.”

so, the characterization of naturally fractured reservoirs is increasingly becoming a key element in the game plans of shale gas players. and for good reason, bearinger says, noting

discreteimprovement

Fracture network modelling system helps shale gas producers develop their game plans

that fractured reservoirs are particularly challenging because production is dominated by the reservoir scale of the fracture fabric.

“it’s important to have awareness in understanding fracture systems, the sort of things you should look at. For instance, there’s the whole problem of scale. it’s not like a conventional reservoir where you take a piece of core and say, ‘yeah, this represents the permeability and porosity of this sandstone.’ the scale at which the fabric repeats itself is much, much larger than a core,” bearinger says.

“so a core could be extremely conservative and make you think something is no good at all or be way too optimistic because fractures often cluster.”

bearinger says there have been some recent measurements that can go a long way in helping companies understand which fractures might be more productive than others. For instance, outcrop exposures can help with understanding fracture fabrics provided that the importance of scale and fracture size are observed, and with images of suitably oriented boreholes, fracture sets can be identified and quantified. Fracture properties are also determined through core examination, fluid loss measurement and


fracing

production logging.“however, in terms of the natural fracture

fabric, probably the best tool we have to model and work with — or at least play with what the possibilities could be based on the data we have — is the discrete fracture network [dFn] model,” bearinger says.

dfn modellingPaul la Pointe, manager of Petroleum

services for the Fracman technology group at golder associates inc., says dFn modelling technology developed by his company — called Fracman — has been suc-cessful in helping clients plan their shale gas drilling programs.

“as an industry we do a good job at figuring out where the gas is in place and we know a lot about the engineering, but one of the big unknowns is the natural fracture systems and how best to connect the well to it via hydraulic fracturing. that’s where our technology comes in,” la Pointe says.

“if you really want to optimize drainage you’ve got to tap into a natural fracture system that’s an efficient collector of the gas, the natural ‘plumbing’ of the reservoir. What we do is we make models of the natural fracture plumbing system, and then we can also simulate the microseismic response as well as flow in the fracture network.”

not only does this help validate the “plumbing model” of the natural fracture system, it also enables producers to get a feel for the drainage system as the microseismic-ity occurs because microseismicity implies slippage along the fractures and that can enhance permeability.

“the microseismic response in our models tells us the kind of scale and volume of the fracture system connected to the well, which in turn gives us a better understanding for the potential drainage volumes in a particu-lar situation,” la Pointe notes. “so we can go in after we’ve calibrated or validated one of these models and look at different designs, different orientations of wells, different loca-tions for wells, different hydrofracing, and see how that impacts the drainage.”

la Pointe explains that dFn models

provide the means for quantifying hydraulic properties from measured fracture data obtained by the exploration geologist. depending on the scale of fracturing, fracture network models can be used to estimate hydraulic parameters for reservoir simulation, well test data analyses or reservoir performance estimates.

“We really focus on the fracture component, not so much the matrix. We work with a number of different companies down in the barnett [shale in texas], for example, and help them figure out where to focus their resources or maybe how to redesign what they’re doing,” la Pointe says.

“one of the things we try to do is figure out why some wells are good and why some of these wells are bad and try to determine to what extent the natural fracture system and the way it’s being accessed through hydraulic fracturing may be playing a role.”

la Pointe says the network realizations are stochastic so they can be used to quantify uncertainty in the results. the models can incorporate flow within the porous matrix, although with the microdarcy permeability of most shales this is rarely done.

dFn models can help in the determination of average well production and expected variance. la Pointe notes that well production within fractured reservoirs is generally highly variable since effective connectivity of the well with the existing fracture system is uncertain. “since the fracture network models use a stochastic approach, the probability distribution of well production can be determined. Quantification of uncertainties in reservoir development cannot be provided by standard reservoir models with the same geological realism,” he says.

optimization of well spacing within fractured reservoirs can be greatly enhanced using fracture network models. specifically, the fractured reservoir models can be used to assess the compartmentalization of the fracture network, the effective drainage radius and effect of fracture anisotropy on the shape of the drainage patterns.

according to la Pointe, fracture network models can also predict the effectiveness of well stimulation techniques. he says the models provide the means of determining how success-fully the created hydraulic fractures, or multiple fracture stimulations, link up with existing fracture systems.

“the permeability and anisotropy scale effects of fractured reservoirs are particularly important here and cannot be assessed with standard porous media or dual porosity models,” la Pointe explains.

evaluation of secondary recovery performance can also be greatly enhanced through the use of dFn models. “secondary recovery within fractured reservoirs is often problematic, particularly when the injection fluid surrounds and isolates matrix blocks prior to their complete de-saturation,” la Pointe explains, adding that it is possible to improve the effectiveness of oil recovery using discrete fracture network models as this approach more accurately models injection fluid fronts, early water breakthroughs, the effectiveness of gel treatments and the effects of thermal stimulation than conventional reservoir models.

la Pointe says another advantage of dFn modelling is that it makes consistent use of a wide variety of disparate geological, geophysical and production data to reduce uncertainty, which conventional dual-porosity models cannot incorporate to the same extent.

data which can be used for constructing dFn models can be derived from lineament maps, outcrops, two-dimensional and three-dimensional seismic, well logs of various types, core, single-well and multi-well production tests, flow logs, injectivity profiles, as well as structural or depositional conceptual models. as well, la Pointe adds, specialized tools have been developed to derive the necessary input data for dFn models from these sources. •

Paul Wells


Paul La Pointe, Golder Associates, Tel: (425) 883-0777, E-mail: [email protected]


fracing

much like the surging use of aluminum for automobile compo-nents, with the weight savings leading to reduced fuel consumption

and carbon emissions, the lightweight metal is also seen as a beneficial new option for the construction of frac radiators.

as a result, the tableau of a typical frac job — with dozens of pumper trucks and associated crew crowding onto a site — could soon be in for a scene change.

“We have been extremely busy working with industry to come up with a road-legal, 3,000-horsepower (hp) frac package,” says randy vanberg, general manager with edmonton-based global heat transfer ltd. “it’s something that has never been done before in canada to our knowledge.”

engines have been getting heavier and heavier, as manufacturers boost horsepower from 2,250 to 2,500 to 3,000. the higher horsepower has resulted in a concomitant increase in the weight of the engine and associated radiator and transmission, which puts the transport of frac packages at risk during road bans. (in Western canada, road bans and weight restrictions are placed on secondary roads during periods when excess moisture — typically a combina-tion of snowmelt and frost leaving the earth — generates soft ground.)

at the request of some stimulation companies and producers, which wanted to increase the level of horsepower, keep the same overall size and also keep the frac units moving all-year long, global heat transfer (ght) set to work on a solution. the company zeroed in on the weight of the frac package’s radiator, knowing that the design of engines, pumps and transmissions were already set and couldn’t be changed. the result of their work is jumbotron, an all-aluminum frac radiator that can achieve 3,000 hp, but with less weight than a typical 2,250 hp package.

“With our 3,000 hp radiators, we’re actually up to 2,500 pounds lighter than most companies’ 2,250 hp radiators. of course, the final weight savings depends on the customers’ existing cooling system design as there are many different models and configurations out there,” says vanberg, who adds the reason to get to 3,000 hp is simple.

“it’s a numbers game,” he explains. “if a well requires 50,000 hp to frac [as vanberg says is required, for instance, in the shale gas plays of northeast british columbia] and you’re running 2,250 hp pumpers, you require at least 23 pumpers.

“if you run 2,500 hp pumps you require 20 or 21. if you run 3,000 hp pumps you only need 17 pumpers.” the potential for six fewer pumpers onsite — 23 versus 17 — also means there are six

using aluminum helps Global Heat Transfer develop new frac radiators

less crews, as well as the potential for smaller lease sites and a lower capital investment for a stimulation company’s fleet, which all add up to substantial savings.

the genesis of the idea occurred while vanberg was attending minexpo in las vegas. Fellow exhibitor caterpillar, which ght has consulted with, had incorporated an aluminum air-to-air aftercooler with the engine of its newest-generation of 797 haul trucks.

“sometimes, as it usually is, you sit down and get hit with that thunderbolt when you least expect it,” says vanberg. “We saw the air-to-air on their new 797s. can you imagine an aluminum air-to-air on some-thing that big? it’s the same size as a radiator, and we thought, ‘Why couldn’t we do that for a frac application?’ so we gave it a try.”

ght unveiled the new jumbotron design at this year’s go-expo show in calgary. “at the show, a lot of packagers showed a tremendous

amount of interest. reps from all the engine companies came by, too,” notes vanberg, who says ght is the “family business.”

in 1978, randy’s father, ged, started a radiator repair company in Fort mcmur-ray. he opened in edmonton in 1987, and soon after began building radiators. ged is still active in the business at the corporate level, focused on emerging markets, while randy’s brother runs ght’s chile operations.

today, ght focuses on the oil and gas and mining sectors and has over 500 employees worldwide in 15 locations. (the company has three facilities in alberta, at edmonton, grande Prairie and Fort mcmurray. it has four more in the u.s., at casper and gillette in Wyoming, as well as in Pittsburg and a newly-opened facility in the marcellus shale play in blairsville, Pennsylvania. ght has one facility in turkey, one also in each of australia and india, two facilities in chile and three in china.)

the aluminum parts for the jumbotron frac radiator are produced at one of ght’s china facilities and brought to canada for final assembly.

“We’ve been looking at the frac industry for a few years, but we didn’t want to go into the industry just being like everybody else,” says vanberg. “We wanted to come up with new ideas, have a new concept … and just say, ‘hey, what do our customers want and how can we do it better?’” •

stephen Marsters


Randy Vanberg, Global Heat Transfer,

Tel: (780) 448-3600, E-mail: [email protected]

Jumbotron

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COILEDTUBING

ForReelUnique CT rig aims to shave drilling time

TooLs aNd TeCHNIQuesnew tech


the PeoPle behind a neXt-genera-tion coiled tubing drilling rig taking shape south of the border say their invention will change the shape of drilling.

sometime in the next few months, the revolver coiled tubing drilling rig will roll out of a fabricator’s yard in odessa, texas, and into the real world. although “99% complete,” according to the company behind the rig, it’s getting a few last-minute touches before commissioning.

the prototype has been a long time coming. in mid-2007, austin, texas-based reel revolution ltd., the company behind the rig, said it would roll out in late 2008. that didn’t happen, but the current schedule should see the rig road-ready by january 2010.

if it lives up to billing, the revolver should save operators 30% in drilling time, since its coiled tubing drill string needs no connections on most wells. revolver’s set-up time is about three hours, according to terry borst, the british ex-pat who is reel

revolution’s founder, chairman and chief executive.apart from its innovative new rig, reel

revolution is launching another revolution downhole as it has designed a new coiled tubing connector that will allow one string of coiled tubing to be joined to another in the field, further extending the revolver’s coiled tubing reach. the connector will also allow smaller reels of coiled tubing to be transported over roads as well as onto offshore platforms.

although initially designed to handle 3 1⁄2-inch diameter tubing, borst says the new rig will be able to drill with different tubing sizes, ranging from 2 7⁄8 inches to 4 1⁄2 inches and possibly 5 1⁄2-inch tubing. he notes that coiled tubing manufacturers need to produce bigger and stronger tubing as the connector will allow multiple reels of coiled tubing to be used instead of being restricted to what can be accommodated on one reel.

While the connector is still a work in progress, according to steve tipton, an advisor to the

reeL WITH a TWIsTThe Revolver coiled tubing drilling rig can rotate coiled tubing from surface at up to 20 r.p.m.

new tech


company, a plastic model has been built, and design work will continue during the testing program that reel revolution has planned for the tool.

“i’ve done some preliminary layouts of the connector, and it will be designed with a very high-strength alloy,” says tipton, a university of tulsa professor of mechanical engineering. While it may include sections where the interior is narrower, it will never have to be coiled on a reel and will thus not have to bear the strains of coiled tubing. instead, when the connection is made at surface, the connector will go straight downhole.

“From a strength point of view, the connector won’t be a weak link,” he says. “it may have a slightly tighter inner diameter, and that might be a constriction, but it would be localized,” he says.

other advocates of drilling with coiled tubing acknowledge the technology has its failings, principally a tendency to build up friction downhole, thereby limiting its reach. difficulty in getting enough weight on bit, hole cleaning and the inability to drill a tangent section have also been major issues for coiled tubing rigs.

according to borst, another major hurdle for coiled tubing drilling to overcome, particu-

larly in the united states market, relates to s-curve drilling. coiled tubing requires different applications because, in the slide sections, standard coil cannot rotate. in many situations, directional drilling tools cause a “tacking” situation when drilling a straight hole after drilling a tangent using a mechanical orienter. reel revolution units can rotate the coiled tubing from surface, allowing the units to drill identical tangents compared to a conventional rotary rig using jointed pipe. as a conventional rotary rig,

the reel revolution rigs use “off the shelf” directional bottomhole assemblies instead of ones specially designed at extra cost.

as for wellbore friction, the revolver will eliminate 80% of it simply by rotating the drill string from surface, borst says. that’s something other ct drilling rigs don’t do.

When it comes to underbal-anced drilling, the revolver, unlike conventional rotary rigs, can maintain a constant under-balanced state, without the risk of going overbalanced. For drill-ers using conventional rotary rigs and drill pipe, however, the risk of going overbalanced dur-ing connections still exists.

While the revolver’s string of coiled tubing is rotated from surface at up to 20 revolutions per minute, it is not this rotation that turns the bit. thus, the revolver’s drill string does not need to be rotating continuously to be able to drill effectively, according to tipton. instead, the coiled tubing drill string uses a mud motor to rotate the bit. another application that will be new is that the reel revolution unit is able to use an air hammer.

the revolver is also designed to allow the driller to rotate the drill string clockwise or counter-clockwise, something not possible with conventional

drill pipe, since reversing rota-tion runs the risk of unscrewing the threaded pipe connections. Where threaded connections exist in the revolver’s bottom-hole assembly, they are locked, tipton says.

despite a feeling among crit-ics that coiled tubing is a weak substitute for old-fashioned drill pipe, tipton says it can withstand considerable torque and strain, including the kind encountered in drilling, and still remain stable.

among possible applications for the new revolver rig, tipton suggests that horizontal wells on alaska’s north slope would be a likely choice. “all of the drilling on the north slope is done with coiled tubing now. it’s all side-tracked out of existing [verti-cal] wells.” he says using the revolver, though, would allow the driller to get better reach in horizontal wells.

For his part, terry borst says coalbed methane, shale gas and geothermal drilling would also be a natural for the revolver. •

James Mahony

conTacTs for More InforMaTIon

Terry Borst, Reel Revolution,

Tel: (512) 858-9520,


Steve Tipton, University of Tulsa,

Tel: (918) 631-2521,


Model 52For top-hole sections, retrieving tubulars and running casings and production strings, reel revolution has designed Model 52, which, integrated with the revolver, comprises an 11-trailer mobile drilling rig that has its own integral power system. The power pack is equipped with a 475-horse-power Series 60 detroit diesel engine. The hydraulic package is coupled to the pump drive to provide the required hydraulic circuit. pneumatic pressure is supplied by the engine driven compressor. all circuits are remotely controlled.

On its own, Model 52 will comprise a total of six trailer loads. The rig has a self-erecting

telescopic mast with a hook load of 375 tons (750,000 pds/340 metric tonne) that also has a built-in 24,000 foot-pounds (32,544 Newton-metres) top drive system. The mast has a clear working height of 52 feet (15.24 metres) and has an integral “pull-down” capability from zero through to 20,000 pounds (9,071 kilograms). The rig is mounted on a heavy duty trailer and comes with a variable height work floor (12 to 30 feet, or 3.65 to 9.14 metres).

Model 52 can be rigged-up and ready to operate within one hour of arriving on-site. It requires no cranes or extra machinery to assist with the rig-up/rig-down and is designed to work independently or in tandem with reel revolution’s revolver coiled tubing drilling unit.

The driller has full control of all operations

from the climate-controlled operator’s cabin. The rig has an integral pLC-controlled hydraulic pipe lay-down/pick-up system, automatic power tong and automatic slips, all of which, plus the drilling parameters, can be fully controlled by a single operator.

Model 52 also comes with one trailer on which are mounted two 1,000 horsepower Quintuplex pumps with two independent mechanical power drives. The pumps are able to pump drilling mud, acid and cement. The fast hookup mud-treatment system is trailer mounted and designed to minimize drilled cuttings going back into the circulating system. The whole mud treat-ment system is mounted on two trailers. If required by the client, trailerized extra-capacity self-circulating mud storage tanks can be included. •

UnderBaLance advanTaGeThe nature of coil tubing allows continuous bottomhole pressure conditions to be maintained without potentially going overbalanced during a connection.

For further information about participating in STARS Legacy Publication,

contact: Phil Enarson Ph: 1.780.439.8788 | Toll Free: 1.800.390.1235

email: [email protected] | Westbrier Communications Inc.

Presenting Partners

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Partners in CeLeBratiOn: stars siLver anniversary LegaCy PuBLiCatiOn

As a leader in the community, you have helped make STARS what it is today and on behalf of the STARS family, I want to thank you for being a ‘Partner in our Silver Anniversary Publication’.You make a difference.

~ D. Gregory Powell, O.C., MD FRCPC, President & Chief Executive Officer, STARS & STARS Foundation”

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“JuneWarren-Nickle’s Energy Group is honoured to be publisher of the official STARS Silver Anniversary publication, STARS: 25 Years of Care in the Air. I want to invite you to join me in congratulating STARS and wishing stars the best for the next 25 years.

~ Bill Whitelaw, President & Chief Executive Officer, JuneWarren-Nickle’s Energy Group

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new tech

a calgary-based tech-nology company has developed video surveillance with real-time field intelligence, by combining closed-circuit cameras with sophisticated video analytics to create video sensors for use in remote areas.

intelliview technologies inc.’s explosion-proof video surveil-lance system can help the oil and gas sector monitor its assets.

the threat of eco-activism has increased the need for better com-munications technologies in the oilpatch. encana corporation experienced six unsolved bomb-ings between october 2008 and july 2009 at three pipeline loca-tions, a wellsite and two well-heads. more recently, this fall

two oilsands mining companies’ sites — owned by royal dutch shell Plc and suncor energy inc. — were infiltrated by doz-ens of environmental activists wishing to disrupt operations and air their anti-climate change views, putting themselves and mining processes at risk.

“it’s all about protecting your assets, everything from people to equipment, ensuring that things are operating as they’re supposed to,” says intelliview’s shelly brimble.

among other benefits, intelliview’s technology reduces the need for on-site security and operating personnel.

Where it’s really unique is the analytics in a patented product

COMMUNICATIONS

CandidCameraVideo surveillance system can help protect assets

known as the smrtdvr, where the camera’s images are stored, says brimble, the company’s communications and marketing consultant. the smrtdvr contains software intelliview has programmed to recognize specific events such as when somebody crosses a fence line, someone loiters around a well site, a man goes down, an object is left behind or a pipeline leaks. “there are endless applications for this product,” she says.

it can operate in temperatures as cold as minus 50 c and as high as plus 50 c, and monitor meters, pumpjacks, oil leaks and flare quality. For example, it can trigger an alarm if the gauge on a flow-valve meter exceeds a pre-defined limit. it can also remotely monitor production and report meter readings.

the product went commer-cial in 2006 when it was used by nexen inc. to date that is the only oil and gas company employing the system, though there are pilots underway, including at a site where vandal-ism was a recurring problem.

nexen recognizes that security analytics can assist in increasing the safety and security of its assets, says brent Fulmek, nexen’s manager of divisional information technology services. the company is piloting three of intelliview’s security analytics systems and has found the graphical user interface allows the user to easily select pre-defined security rules that, in the event of a breach, can record the event and send an alert to a handheld device, says Fulmek. the project is still in the testing phase but initial results are encouraging, he says.

using analog surveillance cameras, intelliview can detect, identify and track objects. two-way audio communication combined with video and digital data enables interaction with authorized and unauthorized individuals at remote sites. “it’s really good for sour gas applica-tions, for any kind of sensitive infrastructure like collection

pipelines coming into a grouped area,” says brimble. it would also benefit emergency response planning, refineries, upgraders, compressor sites and oilsands construction sites, she adds.

each smrtdvr box can be equipped with four to 16 cameras and each camera can have 10 video as well as 10 audio event notifications, such as an intrusion, assigned to it. companies can choose the events and change them at any time. When a selected event occurs the system sends out a notification in a low-resolution jpeg photo video and the video can then be reviewed remotely. “the beauty of it is you don’t need huge streaming video or huge infrastructure for commu-nication,” says brimble.

the alert can be sent by cellular phone, satellite and electrical power lines. it can send notifications to handhelds including blackberrys and iPhones, or if a client prefers, it can have a built-in third-party monitoring company option or tie it into its existing monitoring solution, she says.

False alarms set off by natural occurrences such as rain, snow, glare and shadows were a huge problem with analytics in the past but that’s been solved for intelliview by a team of Phds from the university of calgary.

“We’re one of 10 companies in the world that can open up the box because we have our own source code, and re-pro-gram the code,” brimble says.

the system uses its own localized power — battery, gas or diesel generators — and communication infrastructure. it has also been paired up with wind and solar power and intelliview is exploring the use of fuel cells, using methanol, so it can be left in remote locations for up to three months without maintenance. • Lynda Harrison


Shelly Brimble, IntelliView Technologies,

Tel: (403) 338-0001,


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