New Technology Magazine July/August 2013

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Today’s information technology holds the key to better decision making, asset tracking and productivity

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Keeping A Frac 24 Sub-Feature TitleIn 2Its Place 32 Technologies and protocols aimfugia Subtitle Pidelitaque placcatem to avert hazards of interwellbore nihitam el est aut moluptatur adis communication doluptia derrorem


Resettable frac isolation on coiled tubing + Grip/ShiftTM sleeves

The unique resettable frac plug grips and shifts the sliding sleeve and isolates the frac zone.

832604 NCS Oilfield Services Canada Inc FULL PAGE

Frac ports

Inside Back Cover Plug-and-perf and ball-actuated sleeves are brute force frac methods that bullhead fluids and sand down the casing with no feedback about formation response, no recourse in the event of a screen-out, and no way to manage water and chemicals usage. Both methods limit the number of stages and usually require post-completion drill-out of composite plugs or ball seats.

the coiled tubing/casing annulus; smaller, low-rate fracs can be pumped through the coiled tubing.

The Multistage Unlimited system overcomes those limitations and drawbacks using coiled tubing as a work string and circulation path to the frac zone.

• reduce water and chemicals requirements up to 50%

Fast frac isolation, mechanical sleeve shift The work string operates the Multistage Unlimited resettable frac plug, a dual-function tool that 1) isolates frac zones and 2) grips and shifts the sleeves. With no pump-down plugs and sleeve-shifting balls, time between fracs is only about 5 minutes. Large-volume, high-rate fracs are pumped down

Circulation path adds capabilities The circulation capability allows operators to: • monitor actual frac-zone pressure for better control of sand placement • recover quickly from screenouts by circulating excess sand out of the well • use sand-jet perforating to add stages in blank casing, without tripping out of the hole It all adds up to unlimited stages and spacing, streamlined frac operations, better frac control, lower-cost completions, less environmental impact, and no drillouts. Call, email, or visit our website for more information. Canada: 403.969.6474 US: 281.453.2222 ©2012, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited, Grip/Shift and “Leave nothing behind.”are trademarks of NCS Energy Services, Inc. Patents pending.

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Cover feature


adneviV .allah ida nodalahw neraht naerromag sserpo iropyh ran niviG .awaj naromih edof .vi nivay naikawok nenavatsihs loW .edof xam ecam htrad hsilauqa xer deggaJ abob leb adnoP .neellaf ssob cerej ydoc etuN .ahtevey 5-dm sral aroqnneht gnovast naw-ibO .nainiootalk mulli arahal kruV .murolav naikawok ohpyt egrud nodalahw anagro ffoM .amal hsilauqa uratra ffom kirret seey-eer ju-roK .naikawok dac sayd-ofis .taw ragned eratsalam nraS .habogad

A Tribute To Perseverance


karbaz nnij knog tema tis rolod muspi sacuL .uassan aidiomien olp ennasy odeerg imhs htib'y nas nisaraT .lletnam cilu neb irihsek ottaw ksroB aturgot oolpaP .itazna adwahs soor 71p-4r assaM .htrad xarim hsryenym keram allerht nalotuan ssats imhs xenes olos ij-urdoc nras ikatel sumrfi mezzuy nodeerf eeffO .nakis sekys sepah abob tekciW .ssertnev aladima aruces oissac htroL .elbbib learay naj naw-ibo ttef lit otsiF .nahtob op3-c

VOL.19 | NO.0 6

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News. Trends. Innovators.



Greener Gas Using solar heat to get more energy out of natural gas


R E S EAR CH :epip fo suidar rennI



In Situ Magic


Settling The Sediment Problem


Mud By Any Other Name

Today’s information technology Nanocatalysts could revolutionize :epip fo thgieH OILPATCH SOFTWARE holds the key to better bitumen decisionproduction Today’s information technology holds the key to better :tinU decision making, making, asset tracking and asset tracking and productivity :emuloV latoT productivity N EW TE CH A better polymer could crack the tailings ponds’ fine solids–settling challenge

Homegrown research on nanoparticles could change the future of drilling fluids




Tablets, smartphones and the wireless router are helping to revolutionize field-office communications

Abacus Datagraphics Ltd.


Baker Hughes Canada Company


(CCEMC) Corporation



Energy Navigator Inc.



................................................................. ........................................................

Globalstar Canada Satellite Co. Halliburton




N E W T E C H M AG A Z I N E . C O M



23, 28 & 29 10



Momentive Specialty Chemicals Inc.

Technologies and protocols aim to avert hazards of interwellbore communication



IHS Energy (Canada) Ltd. Maxxam Analytics


12 & 13

Dragon Products Ltd.

geoLOGIC Systems Ltd.



Climate Change and Emissions Management

Entero Corporation






NCS Oilfield Services Canada Inc.


Packers Plus Energy Services Inc.



Schlumberger Canada Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18 Wavefront Technology Solutions Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26


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STAFF WRITERS Lynda Harrison, Carter Haydu, Richard Macedo, James Mahony, Pat Roche, Elsie Ross CONTRIBUTING WRITERS Jim Bentein, Godfrey Budd, Gordon Cope

orty-four years ago, Phillips Petroleum Company, having drilled a succession of dry holes on the Norwegian continental shelf, had reached its limit. With just one exploration well left in its planned drilling program, it sought to exit its exploration obligation. But the Norwegian authorities wouldn’t have it. Drill the well, they declared, or pay the equivalent amount to get out of the commitment. There had been a few discoveries off the coasts of the Netherlands (the large Groningen gas field) and the United Kingdom, but Norway remained an exploration wasteland. Indeed, the Geological Survey of Norway had decided a decade earlier that there was no significant oil to be found. Phillips, the first to drill off the Norwegian coast, remained the last company still exploring after those that followed had given up hope. Rather than pay its way out, it drilled—and changed the history of the country when it hit the jackpot with the discovery of the massive Ekofisk oilfield in 1969. Still one of the world’s largest offshore discoveries, Ekofisk is not only scheduled to continue producing well into the 2020s at the least, but it unleashed an oil and gas rush that created one of the world’s largest oil and gas exporters. If the story sounds familiar to those in the Canadian oilpatch, it should. Twentytwo years prior, Imperial Oil Limited was similarly ready to throw in the towel in western Canada, having drilled a daunting string of 133 dry holes. Big discoveries north and south, in Texas and Norman Wells in the Northwest Territories, convinced some that there was more to the basin than the shallow natural gas earlier discovered at Turner Valley and other areas of southern Alberta. Others, however, speculated the sedimentary basin had been a desert millions of years ago, and thus not a good candidate for accumulations of oil. But, as the story that has become legend goes, Imperial’s board was convinced to drill one last wildcat well, spudded by none other than Vern “Dry Hole” Hunter, south of Edmonton near Leduc. As in Norway, it was a fateful decision, leading to the Leduc No. 1 crude oil discovery and many more that followed, ushering in a petroleum bonanza


EDITOR Maurice Smith |

that would transform the economy and the future of the province and the country. Other similarities followed. While their industries differ in composition, with Alberta dominated by a mix of junior companies and international supermajors and Norway led by its own state-controlled Statoil ASA, both countries have leveraged oil and gas to create some of the world’s most leading-edge technologies to exploit their resources (in part because Norway’s offshore oil and gas and Alberta’s oilsands are such technology-intensive resources to produce) and to export that technology to other oil and gas producing basins. Canada’s expertise in drilling and fracturing technology has made it the only country besides the United States to thus far capitalize on shale gas and tight oil production. The technologies have transformed the North American energy equation into one of potential self-sufficiency and, according to the U.S. Energy Information Administration, contributed to the setting of a new record global oil production of 75.6 million barrels per day in 2012. And Canada is benefiting from expertise developed by Statoil that it put to use offshore Newfoundland and Labrador. Statoil’s announced discovery of light, high-quality oil at its Harpoon prospect in the Flemish Pass Basin in June, which the company described as “very encouraging for the area,” bodes well for the region. Harpoon is near Statoil’s recent Mizzen discovery, estimated to hold between 100 million and 200 million barrels of oil, and Statoil plans three more exploration wells in 2013. (Additionally, Exxon Mobil Corporation said in January it would invest $14 billion developing its offshore Hebron oilfield, with estimated reserves of some 700 million barrels.) Clearly, much of the confidence and perseverance shown by the early wildcatters persists to the present day. All of which points to a promising future for the industry as explorers in western Canada and the East Coast continue to find and develop new sources of oil and gas, assisted by technologies that explorers from 50 years ago could not have dreamed of. Maurice Smith

N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2013



SALES SALES MANAGER—ADVERTISING Monte Sumner | SENIOR ACCOUNT EXECUTIVES Nick Drinkwater, Tony Poblete SALES Brian Friesen, Rhonda Helmeczi, Sammy Isawode, Mike Ivanik, Nicole Kiefuik, David Ng, Diana Signorile, Sheri Starko For advertising inquiries please contact AD TRAFFIC COORDINATOR—MAGAZINES Denise MacKay |


OFFICES CALGARY 2nd Flr-816 55 Avenue NE | Calgary, Alberta T2E 6Y4 Tel: 403.209.3500 | Fax: 403.245.8666 Toll-Free: 1.800.387.2446 EDMONTON 220-9303 34 Avenue NW | Edmonton, Alberta T6E 5WB Tel: 780.944.9333 | Fax: 780.944.9500 Toll-Free: 1.800.563.2946 SUBSCRIPTION INQUIRIES Tel: 1.866.543.7888 | Email: Online: GST Registration Number 826526554RT. © 2013 JuneWarren-Nickle’s Energy Group. All rights reserved. Reproduction in whole or in part is strictly prohibited. Publications mail agreement No. 40069240. Return undeliverable Canadian addresses to our circulation department, 2nd Flr-816 55 Ave NE, Calgary, AB T2E 6Y4. You may also send information on address changes by email to Please quote the code that begins with the prefix NTM. For members of the Society of Petroleum Engineers, please contact the SPE office directly with your address change. New Technology Magazine is owned by JuneWarren-Nickle’s Energy Group, a subsidiary of Glacier Media Inc., and is published 10 times per year. Printed in Canada by PrintWest. ISSN 1480-2147.

CALL FOR EXPRESSION OF INTEREST The CCEMC is looking to invest up to CAD$50 Million in cleaner fossil fuel production and processing projects that have strong potential to make significant, verifiable, and sustainable reductions in Alberta’s greenhouse gas emissions. Projects must be innovative in nature, demonstrating new technology, unique application of existing technology or novel approaches to project development or technology advancement. Proposed projects may be at any stage of innovation – from the research and development stage to commercial-scale demonstration.

Applications are due September 27, 2013. For submission information or to apply, visit

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Solvent and polymer-based floods could increase Alberta conventional oil recovery by between 629 million and 1.89 billion barrels, as much as doubling the province’s conventional reserves, according to a study by Sproule Associates Limited for the Alberta Energy Resources Conservation Board. Titled Identification Of Enhanced Oil Recovery Potential In Alberta Phase 2, the study screened 11,000 oil pools and identified 3,000 pools that have solvent flood potential and 1,400 pools with alkaline surfactant polymer or polymer potential.


“We are not going to advertise our way out of this. We are not going to be able to say we are doing this, we are doing that, we are improving tailings ponds, we are reducing our emissions by this amount. We are not going to be able to do it by arguing that coal is worse. We don’t have to change overnight, but we’ve got to admit to it, and we’ve got to get on with it.” At the Enbridge Centre For Corporate Sustainability Research in

— Pat Daniel, retired president and chief executive officer, Enbridge Inc.

The U.S. Energy Information Administration

Action seminar series in May, Daniel said the oil and gas industry needs to change

estimates there are 345 billion barrels of

in response to the issue of climate change, gradually transitioning over the next

technically recoverable world shale oil

several decades to more sustainable forms of energy.

resources, in addition to 7,299 trillion cubic feet of shale gas resources. Its latest assessment released June 10, which looked at over 135 shale formations in 42 counties, estimated they represent 10 per cent of the world’s oil and 32 per cent of natural gas technically recoverable (can be produced using current technology without reference to profitability). Canada, the only country other than the United States producing shale gas and shale oil in commercial quantities, ranked fifth and ninth in those resources.

What we want to do is capture the value of the assets of the province in a way that will add value to the gross domestic product for the long haul—and that’s the life cycle of the project, including the environmental — Ken Hughes, minister of energy, Alberta impact as well. The Alberta government needs to continue to find ways to add value in the province, ensuring that it captures as much value as it can in an “economically sensible way,” Hughes said at a Canadian Energy Research Institute petrochemical conference in June, citing the actions of former premier Peter Lougheed to launch a petrochemical industry in Alberta.

N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013




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Recycling Oilsands Emissions CNRL to test technology to turn CO2 -eating algae into blend for heavy oil or jet fuel



anadian Natural Resources Limited (CNRL) and its partners have announced a pilot project for a technology it says has the potential to reduce greenhouse gas emissions by 15 to more than 30 per cent across its operations, and can be applied to other industries worldwide. CNRL says the project has the potential to revolutionize how industrial carbon emissions are managed and, if successful, it will share the technology with the oilsands industry. The partners, the National Research Council Canada, Pond Biofuels Incorporated and CNRL are constructing a $19-million facility at CNRL’s Primrose thermal in situ heavy oil project near Bonnyville, Alta. The three-year Algal Carbon Conversion Pilot Project will use algae to recycle industrial emissions by using CO2 to grow algal biomass, which will undergo further processing into products such as biofuels, livestock feed and products to improve soil. “Commercialization of this technology will mean that Canadian Natural’s oilsands CO2 emissions will be reduced at Horizon, our oilsands mining operation, by about 15 per cent,” Steve Laut, CNRL president, said during the pilot’s launch in Calgary in May. Success could lead to emissions reductions at Primrose of more than 30 per cent, says Laut. The company will also directly benefit from the produced biofuel in the process by blending it into a synthetic

light oil or heavy oil at Primrose, he adds. CNRL, which is paying $6.3 million toward the project’s costs, plans to share the results from the pilot, expected to be commercial in 2016, with the other 13 members of Canada’s Oil Sands Innovation Alliance. “By sharing this innovation, as an industry, we will accelerate the pace of environmental improvement at all oilsands,” he says. According to S. John Parr, vicepresident of thermal projects at CNRL, the concept is simple. “We will put carbon dioxide and waste heat from our oilsands facilities into large tanks with algae and treated waste water and create photosynthesis with LED lights. We will then press the algae to release the bio-oil that can be used for jet plane fuel or blended into our heavy oil or synthetic crude oil. The leftover biomass can then be used to feed livestock and for land reclamation.” Each tonne of algae can reduce CO2 emissions by 1.8 tonnes and will yield 0.3 tonnes of biofuel and 0.7 tonnes of biomass products that can be used as fertilizer, livestock feed and as an input into other premium products. The process will also release 1.3 tonnes of oxygen into the atmosphere. Joy Romero, CNRL’s vice-president of technology development, told reporters the source of the CO2 is the flue gas from burning natural gas. “We use a bunch of waste streams, which is what makes this work.”

RECYCLING CARBON Canadian Natural Resources Limited’s carbon conversion project will use CO2 emissions to grow algal biomass, which can be used to produce such products as biofuels, livestock feed and soil treatments.

Indicating a diagram of a photobioreactor that is full of waste water, Romero says the water must be warmed with waste heat because algae like to be kept warm. “The CO2 just bubbles through and the algae literally eat it, plus the nutrients in the waste water. When they grow they develop lipids or fat—the oil—and we then harvest the algae and take the oil.” The pilot will identify purposes for the oil, but CNRL believes the economics will work simply by using the products on site for synthetic crude oil production and biomass for fertilizer for reclamation. Coal, steel and cement plants—any facility that produces flue gas—will be able to use the technology, she says. The ultimate goal of the project is to test the viability and feasibility of such a facility. If proven successful, it can then be used as a model for recycling industrial emissions across industries in Canada and the world. Steven Martin, chief executive officer and chief scientist of Pond Biofuels, says the partnership, along with his company’s current work with the cement and steel industrial sectors to implement algae technology, is an enormous step forward and establishes Canada as the world leader in the field of carbon capture and recycling. Lynda Harrison N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013


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Greener Gas Using solar heat to get more energy out of natural gas



atural gas is increasingly the fuel of choice for power generators because it’s cheap, abundant and has much lower carbon emissions than coal. Technology that cracked open the vast stores of gas locked in North American shales created a glut that pundits predict will keep a lid on prices for many years. Everyone likes a bargain, so gas has never been more popular. North American gas consumption for power generation skyrocketed to 27 billion cubic feet per day last year from 21 billion cubic feet per day in 2010, according to figures provided by Calgary-based Ziff Energy Group. Would gas become even more popular if you could make it greener? Researchers at Pacific Northwest National Laboratory (PNNL) think that could happen if technology they’re developing is commercialized. PNNL recently received a total of $4.3 million in funding for a three-year project aimed at that objective. The funding is from two sources: a U.S. Department of Energy (DOE) program to advance U.S.-made solar technologies; and Santa Maria, Calif.–based SolarThermoChemical LLC, which would manufacture and sell the system if it is commercialized. (Based in Richland, Wash., PNNL is one of 10 U.S. national labs managed by the DOE’s Office of Science. PNNL has 4,700 employees and an annual budget of $1.1 billion.) While the technology, if successful, could have implications for natural gas producers, the idea began with

a potential application that is literally out of this world. Scientists at NASA would like to some day build an unmanned Mars vehicle that could not only collect rock samples, but also bring them back to Earth. Returning to Earth from Mars would mean carrying an enormous payload of fuel. But what if the spacecraft could make its own fuel from the CO2 and water that are naturally present on the red planet? About a dozen years ago, NASA asked whether technologies being developed at PNNL could be packed into a briefcase-sized, solar-powered chemical plant to capture CO2 from the Martian atmosphere, react it with water and produce propellant fuels. PNNL had been, and still is, working on ways to dramatically shrink the hardware used in chemical plants. The results are called microchannel processing technologies. For example, a microchannel heat exchanger can be one-hundredth the size of a conventional heat exchanger. “So the notion of a briefcase-size chemical plant really is possible for Mars. It’s possible based upon the microchannel processing technology,” says PNNL engineer Bob Wegeng. Whether NASA will use the technology remains to be seen—research for such projects begins long before the missions become reality. In the meantime, engineers at PNNL wondered how they could use the technology on Earth.

DOWN TO EARTH The Pacific Northwest National Laboratory is adapting microchannel processing technology, under development to one day ship a briefcasesized, solar-powered chemical plant to Mars, to augment the energy produced from methane here on Earth.

N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013


SOLAR BOOST Technology developed by the Pacific Northwest National Laboratory collects solar energy to produce synthesis gas containing 25 per cent more energy than methane.

“We started thinking, what if we brought in methane, which in the last few years we’ve been discovering is accessible at low cost in much greater abundance than anybody thought a dozen years ago,” recalls Wegeng. “With methane being very abundant, there was no reason to start only with carbon dioxide and water. We could start with methane and then use solar power to augment the feedstock. So we started thinking at that point: what if we wanted to use solar energy to help us make alternative fuels on the Earth?” What they ultimately settled on was augmenting methane with solar energy to produce synthesis gas (syngas). The prototype is about four feet long and two feet wide, and contains a chemical reactor and several heat exchangers. Water is reacted with methane through the steam-reforming process, and heat for the chemical reactor is provided by a mirrored parabolic dish with a device that 16

N E W T E C H M AG A Z I N E . C O M

concentrates the sun’s heat to 200 times its normal intensity. The process produces syngas that has 25 per cent more energy than methane, says Wegeng, who is leading the project. In other words, while the sun is shining, a power plant would need 20 per cent less natural gas, and emit 20 per cent less CO2, to produce the same amount of electricity. (On cloudy days, the power plants could bypass the solar-enhanced system and burn natural gas directly.) PNNL, which plans field tests at its Richland campus this summer, says the technology is best suited for power plants in sunny climates such as the southwestern United States. It says the system would be adaptable to a wide range of sizes of gas-fired power plants. For example, a 500-megawatt plant would need about 3,000 dishes equipped with PNNL’s device. While this may be just the ticket for Mars missions that are blissfully oblivious to turning a profit, could it ever make economic sense on Earth? Although the PNNL team doesn’t yet have capital and operating cost figures they’re confident enough to discuss publicly, they believe solar/gas hybrid

power generation could be competitive with conventional power plants burning coal or natural gas. The current project is intended to make the process more efficient and to develop mass-production methods to lower the cost of the reactors and heat exchangers. (For its part, the DOE says it wants to advance solar energy technologies to the point where they can produce electricity at costs that are no more than six cents per kilowatt hour by 2020.) But where would such a technology, if it achieves commercial success, leave natural gas producers? If solar power can get 25 per cent more electricity out of a cubic foot of methane, then gas-fired power plants would need 20 per cent less methane. Surely this can’t be good news for natural gas producers? Wegeng concedes the process wouldn’t need as much methane to produce the same amount of electricity, but says: “I don’t really know if that’s the same thing as reducing demand. Because it makes natural gas more attractive from an economic and environmental [standpoint], it might actually increase the demand for natural gas.” One independent analyst in western Canada isn’t convinced. “All things being equal, assuming this new process is commercially successful, then [it would create] extra energy that competes with natural gas supply, thus a downward driver on gas prices,” says Bill Gwozd, senior vice-president of gas services with Ziff Energy Group. “Essentially, this process is adding solar energy to displace natural gas.” However, Gwozd notes that what he dubbed “solar-powered natural gas” could have the potential to overcome a deficiency of wind and solar power. “One key challenge for solar and wind is the ability to store energy for later use. Thus the researchers here are focusing to address the storage challenge by identifying a unique mechanism to safely store the extra sunlight energy,” Gwozd notes. But the main question is how the cost of solar-enhanced gas will compare with other forms of energy—such as cheap naturally produced methane. “The key issue is: what is the full-cycle cost of solar-powered natural gas?... It may make better sense where natural gas prices are higher, like in Asia.” Pat Roche CONTACT FOR MORE INFORMATION Franny White, Pacific Northwest National Laboratory Tel: 509-375-6904 Email:






In Situ Magic Nanocatalysts could revolutionize bitumen production



etting bitumen out of the ground and into some form of useable crude has never been easy; operators in northern Alberta have been working for over half a century to find economic ways to extract and upgrade oilsands. Now, a world-renowned researcher and his colleagues at the University of Calgary may have perfected a way to make extraction easier by using nanocatalysts to upgrade the bitumen right in the ground. “You don’t need a lot of nanocatalysts—they work quite well at levels of few hundred ppms [parts per million],” says Pedro Pereira Almao, a professor for the Schulich School of Engineering and director of the Alberta Ingenuity Centre for In Situ Energy. “I really believe we have a breakthrough.”

Catalysts have been in widespread use in refineries for many years. When exposed to low quality crude, these metal compounds (commonly containing various mixes of nickel, cobalt, molybdenum and iron) reformate hydrocarbons into more complex molecules with higher octane values. Nanocatalysts are essentially the same compounds, ground from millimetre size down to nanometre size. Pereira has several decades of experience using catalysts to crack heavy oil in Venezuelan refineries and Canadian upgraders. He began researching in situ nanocatalysts in 2005. The first phase of the project (funded by the government and the industry for more than $10 million) ran until 2010. “We started with lab testing using bench-scale models,” says Pereira. “The reservoir matrix, bitumen,

CATALYTIC CONVERTER Pedro Pereira Almao, University of Calgary professor, and Alejandra Manrique, master of science research student at the university, are investigating nanocatalysts that can upgrade oilsands in a reservoir.

N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013



“In 2.5 years, we will have a lot of VALUABLE PRODUCTION INFORMATION FROM THE WELL DEMONSTRATIONS IN LATIN AMERICA AND CANADA, which will allow companies to assess the technology.” Are we compromising the integrity of the reservoir caprock during SAGD operations?

— Pedro Pereira Almao, professor, Schulich School of Engineering, University of Calgary

pressure and temperature conditions were the same as the actual reservoir. We introduced heat, nanocatalysts and a hydrogen source, then displaced the oil in order to follow the mechanics and catalyst performance.” The researchers discovered that the catalysts activated the hydrogen, which in turn cracked the dense bitumen into lighter molecules, converting the eight to 10 °API bitumen into 18–20 °API oil. “The process has many benefits,” says Pereira. “You don’t have the heaviest portion of bitumen being produced—it remains in the ground. You don’t have to use water for steam. It has a much smaller surface footprint than SAGD [steam assisted gravity drainage]. You use much less energy because the catalyst and hydroprocessing is exothermic, adding a lot of heat. The oil is capable of being shipped directly by pipeline to refineries without the need for upgraders or diluent.”


Source rock can produce only what caprock will contain. High-pressure steam injection can increase vertical permeability 6 times the reservoir’s original value, and the caprock must handle all associated pressure dynamics. Our comprehensive geomechanics technologies and expertise help you proactively avoid compromising the caprock by integrating, analyzing and visualizing all available data to increase production and decrease risk of caprock failure. Learn more about our comprehensive approach to caprock integrity.

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Pereira and his research partners were granted patents to the process and have created a spinoff company to control the technology. “We are now at the competitive stage, where we can formulate nanocatalysts for specific oil and reservoir conditions,” says Pereira. “We are going to launch demonstration projects. The first proto-field demonstration is a joint venture with a Latin American oil company that will run for 2.5 years. The demonstration will cost $26 million. We are also planning a project in Canada and in another Latin American country.” The researchers are waiting for the field tests to conclude before full commercialization. “In 2.5 years, we will have a lot of valuable production information from the well demonstrations in Latin America and Canada, which will allow companies to assess the technology,” says Pereira. “How many companies license the technology will depend on many factors, including the price of oil. Also, the technology is also not a panacea for everyone; reservoirs with high water content may not respond well.” In the meantime, the Alberta Ingenuity Centre for In Situ Energy is being funded to the amount of $1.3 million per year so that the six core researchers and 10 students can study methods to better anchor catalysts in the reservoir. “In the future, we will also develop better catalysts, and catalysts for water activation so that we no longer have to inject hydrogen into the reservoir, but can take it from the reservoir water,” says Pereira. Gordon Cope CONTACT FOR MORE INFORMATION Pedro Pereira Almao, University of Calgary Tel: 403-220-4799 Email:


Tablets, smartphones and the wireless router are helping to revolutionize field-office communications By Godfrey Budd


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and gas. But new entrants into the workforce in the 1980s felt they were not getting the robustness from products [that] they wanted. Then, in the early 1990s, they started wanting more connectivity. Now, this young workforce has become more influential and expects always-on connectivity,” Napier says. The trend to robustness of equipment and 24-7 connectivity go together, he says. An operator wants to know whether wellhead equipment is working properly or, as regulation tightens, if there is a leak or some other environmental issue. For this and other such queries to be answered whenever needed entails 24-7 connectivity supported by robust equipment for reliability. As bandwidth has grown in the wireless sector, the lower costs of wireless— compared to hardwired fibre optics—are helping to make private, secure wireless networks the preferred option for many companies, he says. But equipment must include certain features and attributes for the new wireless systems to function optimally. “Equipment must be able to handle sudden temperature changes. Also, say, a radio works to minus 20 [degrees] Celsius—it’s no good in Alberta. Rapid temperature changes can mean more maintenance. We’re now seeing a better

understanding of the robustness requirements to deal with this,” Napier says. Communications products, like all electronic equipment, generate heat. So designs must incorporate features to manage or dissipate the heat efficiently. Grooves known as heat fins are typically used to do this, and today’s designers are giving more thought to their configuration and location. The quest for reliability now involves not only field testing, but “standard statistical theory based on field data of the equipment used is being applied to design,” Napier says. The effects of solar flares and the pull of magnetic polar caps are also design considerations. “All these factors make the design more complex,” he says. TABLETS TAKING OVER In contrast to the systems of the 1950s, ’60s and ’70s, when communications systems in remote locations like the far north were radio-based, today, a consumer-driven concept like the home wireless router has moved to the field. And everything—phones, wireless infrastructure, devices—is converging to the tablet—“a screen where you put or obtain information,” Napier says. Tablets are being increasingly used in the field as they can eliminate swaths



f some mainstream media stories are anything to go by, consumers today often feel mistreated or even swindled by some product or service provider. The widespread grumbling about certain utilities, demands for an air passenger bill of rights and U.S. legislation passed in 2011 that allows for the imposition of hefty fines for airlines that inconvenience their customers suggest that consumers have been feeling that their interests and wishes are being ignored. All the probing and prodding of consumers by market researchers (to better understand customers and thus serve them better) seems somehow to have failed in its stated intent. Despite such perceptions of a demotion of consumer values, the chief technology officer at Westcan Advanced Communications Solutions, formerly Westcan Wireless, makes the case that it is the priorities that consumers have brought to the marketplace that are now in the driver’s seat when it comes to communications. Brian Napier takes the long view of this increasingly critical and sophisticated sector within the oil and gas industry, and looks back before the 1980s and the onset of the digital era. “The business side dominated the selection of products, including in oil


Values Rule? of paperwork, duplication and errors of transcription, and expedite fieldwork via their two-way exchanges of information. When a field operator spots a problem at a wellhead, for instance, he can take a picture, relay it to a supervisor or engineer, and then perhaps receive instructions by phone and tablet on how to deal with the problem. Or he can go to a field shop that’s already received a notification, pick up the equipment and scan it to verify that it includes the right parts. “When [the field operator] gets to the site, all the schematics, training, etc., show up on the [tablet] screen. You record what you’ve done at the site [to repair the problem]. Even the paperwork is done, so efficiency is way up. The capital cost is low, and a tablet comes with a shock-proof, submersible device,” Napier says. He adds, “All the complexity is on the back end.” The use of radio-frequency identification (RFID) technology can also help with the supply chain. RFID applies radio-frequency electromagnetic fields to transfer data, and can identify and track tagged parts and equipment on a non-contact basis. (People in secure office towers use RFID technology when they show their ID card to a device in an elevator.) Contents of a parts shelf or box can be scanned in seconds to ascertain what’s on hand and what has to be ordered in. The combination of versatility and portability in tablets—they weigh barely a quarter as much as a laptop—is a winner. “Applications for iPads and iPhones are driving much [of ] the progress in communications,” Napier says. Tablet applications can be used to augment data transmission and other communications from and to remote camps or other facilities that used to rely solely on two-way radio systems. Westcan mostly represents other manufacturers, but the recently renamed company does make what Napier describes as an interoperability

bridge in the form of a special communications trailer. It is called a mobile emergency response communicator— MERC for short. It allows groups—fire departments, for instance, from different towns who might be using different radio-based communications systems— to talk with each other. “It comes with certain radios, and lets you hook into a private radio system,” Napier says. ALL-IN-ONE SOLUTION A software program developed inhouse at DataDrill Communications Inc. would seem to perfectly embody a number of current trends in communications that Napier points to. “It’s a full internal company communications package. It has a system for tracking assets. It facilitates the full range of internal communications—safety, accounting, operations, reporting—and has a detailed, precise mapping system with directions, all rolled into a single software package,” says Nathan Olexa, sales and marketing at DataDrill. Portable digital devices like smartphones or tablets play a key role in the system. For the mapping component, which is on a Google platform and includes over 800,000 kilometres of private oil and gas roads, an operator would typically use a tablet or a larger smartphone. “Because of the Google architecture, the software provides searchable directions from one location to another,” says Ryan Cameron, the research and development manager at DataDrill. The computer device that is used for vehicle tracking, sometimes called an automatic vehicle locator (AVL) is connected to sensors in the truck and monitors a range of variables, including speed of travel, location, mileage, fuel level and so on. Also, the truck’s on-board monitoring unit can send data to any mobile device like a smartphone or tablet. The system’s two-way messaging means that when the software warns the base that a vehicle is speeding, the N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013


FIELD DATA CONNECTIVITY base can send out a message via tablet or something the size of a brick. New radios Digital technology and web-enabled phone that flags the driver that he has a rated at four or five watts—not one or devices like tablets and smartphones message waiting. The device on the truck two—and at around 24 kilometres have a are at the heart of a new software tool can talk on a two-way basis with the range of three times their predecessors. called FieldCap from VistaVu Solutions. driver’s smartphone or tablet. “So you don’t need as many towers. That’s The idea behind the software is to make The DataDrill software also includes been an issue for the oil and gas sector in it easier for service companies to collect stationary asset monitoring: tanks, com- the past,” Christiaanse says. and transmit operational data from the pressors and other field-based equipAustralian miner BHP Billiton Limited field. Field personnel can collect data ment. Unlike the AVL part of the system, is developing the world’s largest potash on the use of labour, equipment and this does not use real-time monitoring mine, estimated at a cost of $14 billion. materials and transmit the data back but, instead, can take readings at speciGLENTEL will be responsible for building to the office with any web-enabled fied intervals, like every 12 hours. the towers and installing a MOTOTRBO device. “It has five differentiators from Long-distance communications are solution, a digital Motorola two-way our competitors. It’s exclusively for done using cell or satellite, depending service companies. It’s fluid; our system on the coverage. The software design matches client processes for field tickets. automates the default to cellular It’s very simple. It’s web-based but can mode if it’s available. “This marks a work off-line. It’s the opposite to the offer new application of the indusof our competitors, as it’s easy to use and try term, least-cost routing,” teach. They have one system with many Olexa comments. (In voice options; we have a system with only the communications, least-cost fields that the clients need,” says Brad routing is the process of Peterson, co-owner of Core Creative selecting the path of Website Design and Development, outbound communidescribed as a sister company of cations traffic based VistaVu that helped develop FieldCap. on cost.) Both are based in Calgary. The use of geo-fencing Self-described global providers can let the base know when of communications equipment, like a specific truck leaves or SkyWave Mobile Communications, are enters a location, or it can let not letting the grass grow under their accounting know when to start feet either. Since last summer, the combilling on something. pany has had a couple of significant The system, which underwent product rollouts. One is IP testing over the SCADA. It takes data from a last year and SCADA (supervisory control is now being “New entrants into the workforce in the 1980s felt and data acquisition) serial released commerthey were not getting the robustness from products port and relays it over the cially, is designed [that] they wanted. Then, in the early 1990s, they Internet or satellite. “It’s very for flexibility. “If a started wanting more connectivity. Now, this young simple and provides a pipe,” customer does not workforce has become more influential and expects says Jeff Joslin, product manwant to use our ager at SkyWave. mapping software, always-on connectivity.” The other new product our system can — Brian Napier, chief technology officer, is called SCADAconnect, send out [only] Westcan Advanced Communications Solutions and it is the company’s most the data on their recent launch. Although it assets into their is described in the product literature mapping system,” Cameron says. radio voice and data communications as a connectivity solution between system. “It’s a digital technology that alfield and office, it is more than that. FASTER DATA TRANSFER lows for transmission of more data within “SCADAconnect provides intelligence. New standards like long-term evolution a wireless network and enables smaller It understands SCADA protocols (LTE), which allows for more data to run radios,” Christiaanse says. and can be programmed to enable through networks, are starting to make a MOTOTRBO uses intrinsically safe responses to a situation, e.g., open or difference, especially in the last year, says radios. This means, he says, that shut a valve, etc.,” Joslin says. Rick Christiaanse, the general manager “customers can now monitor through put He says advantages of the product are at GLENTEL Inc. The world’s first pubon a well, SAGD [steam assisted gravity a quick response and, by analyzing data licly available LTE service was launched drainage oilsands producing well pair] or on the spot, “You don’t send so much in Norway and Sweden in December mine, also flow-rates, systems problems data via a satellite link.” 2009. LTE is typically marketed as a 4G or issues. It doesn’t handle as much data As digital technologies mature, wireless service. as LTE, but has at least dial-up Internet creating a rapidly expanding range of Also, digital technology is accombandwidth and speed.” He adds that a products and systems, the question of modating smaller and more powerful MOTOTRBO network is now in place for how to get this or that is being replaced two-way radios. The result is a device trucking companies between Windsor, by: What do you want? you can put in your pocket, rather than Ont., and Ottawa. 22

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1 Stage

2 Stages

Stage 3 Underway

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BLOWOUT AVOIDANCE Companies such as Surface Solutions Inc. offer downhole pressure measurement technology to help companies avert potentially costly liability issues that can result from interwellbore communication during fracturing operations.

t was a heck of a mess. On Jan. 13, 2012, Midway Energy Ltd. was operating a frac job near Innisfail in central Alberta while Wild Stream Exploration Inc. was simultaneously producing from a nearby vertical well. At one point, enough frac pressure from the Midway operation passed into the other well to send hydraulic fracturing fluids, crude oil, produced water and natural gas spewing up from Wild Stream’s wellhead. Frozen ground prevented much of the 75 cubic metres of fluid from seeping into the ground, but clean-up crews still collected approximately 1,010 tonnes of contaminated snow and soil, and disposed of it at a nearby waste management facility. Following the Midway incident, the Energy Resource Conservation Board (ERCB) released Bulletin 2012-12 on Jan. 23, 2012, prompting licensees to manage proper well control at all times to ensure public safety and efficient resource recovery, as well as to prevent adverse impacts on offset wellbores and to avoid environmental consequences. In response to the ERCB’s bulletin, the Drilling and Completions Committee, with involvement from both the upstream petroleum industry and relevant regulators, developed the interim Industry Recommended Practices 24 (IRP 24). “The issue industry has faced is not the frequency, but moreover the consequences of an interwellbore-communication event resulting in a well-control event at an offset wellbore,” says Jeff Saponja, president and chief executive officer of TriAxon Oil Corp. “It is very important to point out that interwellbore communication is not a bad thing—it is only a bad thing if it causes a well-control event at an offset wellbore.” Until recently, Saponja led the charge on the first phase of IRP 24 development as co-chairman of the IRP 24 committee. As a relatively deeper-well operator, Saponja says, TriAxon has had numerous operators imposing risks to its wellbores when conducting proximal shallower zone fracture stimulation treatments. “In other words, they frac past our wellbores at pressures that could compromise our wellbores. of the fracs compromises a wellbore, we have serious concerns that a well-control event—surface or subsurface loss of containment—could result.” 24

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Included in IRP 24 is a recommendation to monitor at-risk identified offset wells (IOWs), either by remote device or on-site personnel, suggesting it is at the discretion of the subject well operator and/or the IOW operator to develop an appropriate monitoring method, as well as communication contingencies in case the monitoring method fails. Mike Beck, founder and chief executive officer of Surface Solutions Inc., says technologies offering immediate downhole pressure measurements are important public safety tools, which protect the environment, equipment and other assets, and avoid potentially costly and embarrassing liability issues resulting from interwellbore communication. “If you have offset frac monitoring on wells—yours or not—around your operations, you’re guaranteed because you’re watching those adjacent wells [to ensure] that you do not have an environmental disaster like Midway,” Beck says, adding that if a fracturing company detects pressure response on an adjacent well in real time, the company can make appropriate adjustments as necessary. “They can shut down their frac accordingly.”

PRESSURE MONITORING Adam Goehner, technical analyst with the Pembina Institute, says technologies that measure and monitor downhole pressure are key to reducing the chance of interwellbore communication. “They’re extremely important,” he says, adding that clear industrywide policies and procedures are also necessary tools for those individuals making decisions in the field. Goehner says it helps if policy-makers are mindful of current technologies when setting regulations. According to Bob Curran, spokesman for the ERCB (which is being replaced by the new Alberta Energy Regulator), managing interwellbore communication is among those well-control maintenance obligations incumbent upon operators. “The ERCB believes hydraulic fracturing can be utilized safely in Alberta—as it has been for more than 60 years—but [the ERCB] will continue to monitor this issue and will make regulatory changes if they are required,” he says, adding that the ERCB carefully monitors industry trends and reviews its regulatory framework to ensure regulations are appropriate and protective of public safety and the environment.


By Carter Haydu


Keeping A Frac In Its Place For example, the regulator’s Directive 083: Hydraulic Fracturing – Subsurface Integrity, which was released on May 21 and takes effect on August 21, states that a licensee must have a documented hydraulic fracturing program, with a copy maintained at the subject wellsite for the duration of operations. The program must include methods for detecting interwellbore communication. Goehner says rules set out in Directive 083 are “definitely a good step in the right direction,” although he believes concerns surrounding interwellbore communication are not resolved through that document alone. “[Directive 083] is not extremely specific, and it doesn’t get into the details needed in order to evaluate each individual hydraulic fracturing operation,” he says, adding that each well in each hydraulic fracturing situation is unique, and each requires a specific set of expert oversight. Saponja says the intent of documents such as Bulletin 2012-12, IRP 24 and Directive 083 is to make clear the subject well operator’s role to minimize risk of a well-control event at an offset well, as well as an IOW operator’s role to act reasonably with development of a mutually agreeable offset well–control plan. “As such, a well-control risk assessment for each of our wellbores within a defined risk area is required,” he says, adding that for an offset well–control plan, the operator may need to do more than just monitor surface pressures. He suggests a well-control plan should include procedures in case detection of interwellbore communication occurs at an offset well, complete with appropriate actions to prevent escalation of a well-control event. “The key is—and therefore [it is] imperative—that operators act reasonably, as collaborative development of an offset well’s well-control plan can effectively minimize the risk of a well-control event at an offset wellbore if interwellbore communication were to occur.” According to Goehner, overall industry standards and regulations are to the benefit of producers, as the impacts of one company’s frac job can impact public perception toward the entire industry. Saponja notes, “All the technologies are available today to minimize the risk of an offset well–control event.”

PREVENTATIVE MEASURES Independent Energy Solutions Corp.’s response to the issue of interwellbore communication is the Surefrac Safety System, which the company installs on existing wellheads in close proximity to fracturing operations to detect pressure changes and instantly inform the operators of those changes. “What our company does is we build a product that is all CSAapproved that monitors pressures, and we send the data onto the Internet so [customers] get real-time monitoring of their wells in case there was an inter-well communication—and it does happen,” says Brad Turner, president and director of the Rocky Mountain House, Alta.–based company. He adds that Surefrac systems are also approved by the Alberta Boilers Safety Association. According to Turner, his solar-powered technology gets a reading before a company conducts its frac job, and then Surefrac monitors baseline pressure, setting an alarm-trigger threshold at whatever level the producer requests, with sustained higher pressures on the device’s sensor indicating pressurized fluids entering the wellbore. “[Producers] tell us where they want the threshold put, and if it exceeds that threshold it alarm goes off and tells them they’ve exceeded where they’ve set as a set point, and it emails and text messages them.” While the device works at whatever pressure level the producer sets, Turner says he recommends companies set that threshold very low. “We always say, ‘Don’t set that pressure point too high, because you may have inter-well communication but you don’t know it because it’s below the threshold.’” Because Surface Solutions offers an Internet-based product, Beck says his customers can log in and monitor pressure at a wellsite almost instantaneously. “You can log in on smartphones, iPads, mobile devices—essentially, you could be logged in at your house at 2 a.m. and, heck, if you want, the frac company could be logged in at their office in Calgary,” Beck says. He adds that the company’s streaming pressure data is accessible via a 128-bit transport-layer security-encrypted website, which makes measurements Surface Solutions collects from wellsites both immediately and privately accessible to customers. N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013



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Also, Beck says his devices measuring the wells feature high-accuracy, high-resolution pressure and temperature recorders that prevent unwanted false alarms due to other forms of instability in the wells. “So when they see pressure response on an offset well, it’s communicated to their computer screen in two seconds. So, if you’re pumping on well A and you see a very large, out-of-character pressure increase on subject wells C and know it has been stimulated from the operation fracturing down the road.” If the interwellbore communication can be caught right away, Beck says, preventative actions can be taken to greatly reduce the amount of damage caused by the unintended frac pressure in those other wells. Failing to catch the problem early, he adds, can result in rather unpleasant outcomes. “You could overpressure the producing wellheads, because they’re not rated as high as the fracturing wellhead, and you could actually blow a wellhead apart.” According to Beck, interwellbore communication is also a worry if sandy frac fluid is allowed to move into unintended downstream infrastructure such as pipelines, as it could cause a lot of damage. “You don’t want to frac a pipeline. Frac sand is abrasive, and if it gets pushed down one well and sucked up the other well and sent down a pipeline, there’s a heck of a cost to equipment there that you would need to get fixed.” Beck’s 13-year-old surface data acquisition company has offered the sort of high-pressure monitoring services necessary to detect interwellbore communication for the past six years. “With all of the horizontal wells that have come into play in about the last five to six years, wellbore spacing is getting to be an issue. With wellbore spacing becoming increasingly tight, more and more offset wells are being affected by fracturing.” While he refers to it as niche, Beck says the need for companies such as his is nonetheless growing in western Canada. His company is currently monitoring 30 offset wells for customers. With demands for Surface Solutions services throughout Alberta, and into Saskatchewan and British Columbia, Beck says monitoring equipment is “the cheapest insurance clause” an oil company could ever have when fracturing. For this reason, his business is booming. “I’m bursting at the seams. I’ve ordered double the equipment that I have—it’s being built currently. It’s tough to keep up with the demand once people understand what Surface Solutions is trying to do, and that is it is trying to reduce liability.” Turner says Independent Energy Solutions carries a variety of Surefrac devices, as the company has been tinkering with and expanding upon its technology since it was first introduced at the request of a customer three years ago. Surefrac systems can do multiple sensors at one time as well, which Turner says enables the technology to service large multi– well pad operations. “We have portable ones that can fit into a [quad-runner] if you want to take them in by ATV or UTV—we’ve done that before. Or we have larger ones. Sometimes we go farther north and we’ll do these great big pad wells, and they’ll look a little bit different—we’ll add more solar to them.” According to Goehner, while the chance of interwellbore communication causing a nearby wellbore to “blow out” is quite rare, when it does happen, the environmental consequences can be dire, which makes it an issue of importance to the oil and gas industry and to the regulators. “From an environmental perspective, there are a number of chemicals and fluids, and even saline water that gets distributed around the well,” he says, adding that it is particularly concerning if a frac job impacts nearby water wells. “Interwellbore communication is not the only issue that is arising right now in light of all this additional activity with the application of hydraulic fracturing, but it is one of the many issues that seem to be arising.”

2.0 The Evolution of Energy Industry Mapping

AbaData on the Move For almost 10 years thousands of AbaData subscribers have relied on our Internet mapping program for trusted data and an intuitive interface. Now with AbaData 2.0, one of the energy industry’s favourite mapping tools goes fully mobile. Whether accessed from a phone or tablet, or from a Mac or PC computer, AbaData 2.0 travels seamlessly from the office to the field. You can use your device’s GPS capabilities to show your current location on AbaData 2.0 relative to pipelines, wells and survey boundaries, overlay aerial or topographical imagery and pull reports from anywhere you have web access.

Halliburton Technology Spotlight Advanced Perforating Solutions

Take Charge of Your Reservoir

Do you know which perforations your treatment is pumped through? MaxForce®-FRAC shaped charges are engineered to enhance the success of any stimulation treatment. MaxForce®-FRAC shaped charges provide a consistent hole size regardless of the gun-to-casing clearance. Documented tests have demonstrated that casing hole size after perforating can vary up to 75% with other industry-available shaped charges. Proprietary charge technology and manufacturing processes allow the MaxForce®-FRAC shaped charge to create a casing hole size that varies, in some cases, less than 9%, which has shown during extensive field trials to reduce treating pressures and prevent early screen outs.


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Variation in hole sizes create less consistancy in treatment flow outside the casing.

The Section IV Halliburton Advanced Perforating Flow Laboratory located at the Jet Research Center is used to predict a well’s inflow performance.

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Today’s information technology holds the key to better decision making, asset tracking and productivity

:epip fo suidar rennI :epip fo thgieH :tinU :emuloV latoT

CERTIFIED GRADE A Plans to certify data managers will profoundly enhance how the sector handles geoscience, engineering and production data


otal E&P Canada Ltd. has invested billions of dollars in the oilsands, including the Joslyn lease. The region northwest of Fort McMurray covers over 221 square kilometres, and is expected to yield 874 million barrels of bitumen over a 20-year period, starting in 2018. “We are in the process of defining our oilsands leases, delineating the extent of bitumen, water and gas,” says Marc Nolte, geoinformation manager for Total E&P Canada. “We drill and core thousands of wells and capture the data. We do this to build our geological model to show the ratio of bitumen to total volume. Characterizing the resource is a huge task; if we make a mistake with the data, it has the potential to reduce the economics and make the project non-viable.” The task of keeping over 13 terabytes of data on the straight-and-true falls to the data management team. “We have a staff of eight, including myself, that handles all subsurface data,” says Nolte. “You need a mix of skills; ideally, you want someone who is knowledgeable in GIS [geographic information systems], someone familiar with well data and someone who is comfortable with seismic data. In addition to the above, we have an archivist


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that deals with indexing, storage and retrieval of the paper, as well as project data administrators who assist in initial study project setup and preparation of data for loading.” Incredibly, none of Total’s data management team has any official sanction to do their job. In fact, none of the thousands of people around the world who manage hundreds of billions of dollars worth of oil and gas data have any formalized training in the field. Susan Hopkin is manager of database services, Atlantic region, for Petrosys Canada Inc., a provider of subsurface mapping solutions. She has a computer science background and has worked in the oil and gas sector for 14 years. “People from IT backgrounds go to O&G [oil and gas] and they have no idea what they’re getting into,” says Hopkin. “There are no guidelines about what’s important. Companies realize that they can’t have people who have just fallen into DM [data management], they need qualified people.” Data managers and oil companies around the world have been working to rectify the situation. The Professional Petroleum Data Management (PPDM) Association is a global, not-for-profit society, based in Calgary, that

provides data management standards for the petroleum exploration and production industry. International petroleum companies, government agencies, software application providers, vendors, service companies, data managers and students form the membership. Over the last two decades, industry professionals working as volunteers within PPDM have created a comprehensive, vendor-neutral data model that benefits all the business functions in the upstream petroleum industry, including seismic and well activities, production and reserves, equipment and facilities management, and surface and mineral rights management. Recently, they have been working on creating standard definitions and standardized business rules that govern well information. “Data management jobs are done differently from company to company, and that’s because they have different software and server systems and management policy and procedures,” says Trudy Curtis, chief executive officer of PPDM. “This is good, because it differentiates one company from another in terms of their strengths. But there are some elements of data management that need consistency. As an example, let’s look at a directional survey. Every survey is referenced to a cartographic system so that you can locate the borehole in the subsurface. But a survey might be referenced to either grid north or true north. If you don’t tell the user which one you used and he has to guess, then you can be wrong by a substantial amount. A standardized business rule allows you to eliminate guesswork.” Sufficient progress has been made on definitions and business rules to allow PPDM to move on to the development of educational


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courses. Recently, PPDM and members from the industry struck the Petroleum Education Task Force to create a system where data managers could formally acquire the knowledge and the skills necessary to oversee oil and gas databases. “PPDM has some courses, but training will be available on a wider basis from colleges and universities and private training providers,” says Curtis. “It will take students about six months to finish the entry-level courses, and up to two years to complete the mid-level and senior courses. There will be standardized testing to show that successful professional data manager candidates have the knowledge, skill and attitudes to effectively discharge their duties.” PPDM and industry partners are now working on the ultimate step for professionalizing data management: a formal certification process. “An important part of a certification program is psychometrics, which is the science of figuring out how to write an exam that is objective and legally defensible,” says Curtis. “When you create a professional designation, some people will get a job because they are certified, and some may not because they aren’t. We are therefore working with a psychometrics specialist in order to create an exam process that is robust and legally defensible.” Within a year, PPDM expects to have the first certification process for entry-level data

analysts—those with three to five years of experience. “The tests will be delivered online by service providers in testing centres where someone will verify a person’s identification, then proctor the test,” says Curtis. “PPDM will be custodians of a registry where successful candidates will be enrolled. You need a registry because HR [human resources] departments need an environment where they can go and confirm the certification actually happened.” Data managers look forward to the numerous benefits that certification will deliver. “I am a team leader, and when I go looking for someone to hire, I need some certificate that says to me that they have a base knowledge of the sector,” says Hopkin. “That way, I don’t have to spend six months teaching them the basics like what a geologist or geophysicist does.” “You can never guarantee that your staff will be around forever; the job market is very fluid, and some people retire and others are transferred to different teams,” says Nolte. “Data has to be properly indexed so that it can be found 20 years from now. Certification provides standardization of how data is stored and retrieved, no matter who is doing it.” Certification will also allow for the evolution of skills. “We recently calculated how much training it would take for someone at my skill level, and it came to 230 days,” says Nolte. “If you think in terms of two weeks a year of training, that comes to a 15-year cycle.”

POWER TO THE CLOUD Network computing facilitates mapping of decades-old pipelines to modern standards


he Lambton County area of southern Ontario has been industrialized for more than 150 years, a consequence of the fact “Crazy” Hugh Nixon Shaw launched Canada’s oil and gas industry by striking oil near Petrolia in 1862, which led to an oil boom, the birth of Imperial Oil Limited and the launch of Canada’s refining and petrochemical industry. That also led to the area around Sarnia, the largest city in Lambton County, which hugs Lake Huron as well as the surrounding countryside, hosting a maze of pipelines that span hundreds of kilometres and date back many decades. For Marty Raaymakers, an engineering technologist who has spent 41 years maintaining

and repairing some of those pipelines and designing new ones, managing that underground oil and gas transportation highway had become almost overwhelming, with the basement of his company’s headquarters being filled with file folders and boxes of maps and data detailing those pipelines. But that is no longer the case, thanks to his friendship with another Sarnia-area businessman who knows a thing or two about computer software and this thing called cloud computing. Raaymakers, president and general manager of Sarnia-based MIG Engineering (2011) Ltd., which has 25 employees and annual revenue of about $3 million, dominates the pipeline maintenance and design business

“People are starting to look toward data management as a career path,” says Hopkin. “But there’s no way for a company to recognize seniority and compensate a data manager accordingly. With certification, the HR department will have proof points to do that.” Once certification for entry-level data managers has been established, PPDM and industry participants will work to establish designations for higher skill levels and, eventually, the professionalization of the entire data management realm. “I believe that it will be impossible for upstream data management to progress to the next level of efficiency and effectiveness before the end of the ‘great crew change’ [the anticipated 50 per cent turnover in managerial personnel over the next decade as the baby boom generation reaches retirement age] without professionalization,” says Mark Priest, manager, Subsurface Systems Development and Enhancement at RasGas Company Limited. “I believe it is essential to the success of the E&P [exploration and production] industry.” Gordon Cope CONTACT FOR MORE INFORMATION Trudy Curtis, Professional Petroleum Data Management Association Tel: 403-668-9454 Email:

in the area. “We do about 90 per cent of the pipeline work in this part of the province,” he says of the 54-year-old company. That dominance, which represents the bulk of its work (it also designs bridges, buildings, sewer lines and other municipal infrastructure), allowed it to weather what has been anything but boom times for the region’s economy. The Dow Chemical Company closed a plant in the area and other petrochemical plants downsized, leading to the loss of more than 6,000 jobs in the last 20 years. But there are new signs of life, as NOVA Chemicals Corporation prepares to expand its area plant, thanks to the shift to the use of liquid natural gas from nearby shale gas fields in the United States as a feedstock, and as the area’s refineries look to gain access to lower-cost western Canadian crude, which will replace offshore oil. As a result, MIG has been busy recently, designing and building part of a Canadian and U.S. pipeline that crosses the St. Clair River and will deliver Marcellus shale gas to NOVA as well as working on new gathering lines for Pembina Pipeline Corporation and Plains Midstream Canada, Imperial and Enbridge Gas Storage.

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or tablets, was the answer to MIG’s dilemma. “We’ve been kicking around different ideas about this for a decade, but it looked like the database and servers required would require very deep pockets [to finance],” says Grant. With the emergence of cloud computing, which requires far less base computing power, developing asset management software that allows PIPELINE TRACKER MIG Engineering’s Marty Raaymakers, left, and David Grant of CanWeb Internet Services for remote access combined their talents to produce a unique pipeline location software solution. became possible. The pair kicked in a total of $100,000, teamed up with In addition, its pipeline business was Lambton College, and applied for matchgiven a big shot in the arm when the Ontario ing funding from the Federal Economic government passed Bill 8, which requires Development Agency for Southern Ontario, companies with pipelines near public land to a $1-billion fund established by Ottawa register with a centralized Ontario One Call in 2009 to help the recession-plagued monitoring system. economy of the region. “We work with companies on locates [of “This was a one-year project,” says Grant. pipelines] all the time,” says Raaymakers. “We “It exists [and was able to be developed that used to get two or three calls a week from quickly] because CanWeb had already worked companies looking for help. Now we get two on developing these types of systems. We or three per day.” took what we knew about GIS [geographic Add to that the greying of the workforce information systems, which capture, store population in the area, which has one of the and manage geographical data] and turned it oldest demographics in Ontario, as retireinto a web-based system.” ments mean knowledge of a company’s Companies can buy Pipeintel software pipeline network “walks out the door,” and have their pipeline data loaded onto it. creating a knowledge transfer gap. Workers in the field can type in a pipeline And that’s where Pipeintel Inc. and David Grant, president of computer services number and gain access to information that has never been remotely accessible in such a company CanWeb Internet Services Ltd., compact form, including pipe property data, enter the picture. maps, aerial photography, legal and survey Grant and Raaymakers, both of whom details, government regulations and past have been executives of the local chamwork orders on the pipeline. ber of commerce and are members of the It can also be used for locates, for emerSarnia Lambton Industrial Alliance, a local gency response, for maintenance inspections organization that promotes business deand by legal departments. velopment in the region, wrestled with the Raaymakers says it can take hours to find dilemma of what to do with the basement that information from varied sources, but now full of maps and information—and with workers in other departments or in the field other basements full of valuable informawill have it instantly at their fingertips. tion gathering dust. He pointed out that there is a great deal Grant, an electronics technologist who of information sharing between pipeline launched his five-employee company operators and even some use of other comin 1995 and now manages the corporate panies’ pipelines by firms. Pipeintel will allow networks of mid-sized companies throughcompanies to share as much information as out Canada, was convinced that software they want. using cloud computing, which allows users “These companies want different levels to share information on a network that can of access...some wouldn’t want everyone to include mobile devices like smartphones 32

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know everything about their pipeline. They will be able to control the amount of information available to others.” Each operator has data on their pipelines that “will tie into one system and help them make what they’re doing better,” he says. Grant adds that Pipeintel “can become a one-stop shop” for pipeline owners. In addition to the pipeline sector, they say the software can be used by those operating fibre optic networks, rail lines and municipal services. “Anything with lines on a map,” says Grant. They have done an extensive search to discover if there is a similar product available and have found none. (A check in researching this article with pipeline sector participants produced the same result). The partners were able to tap the academic and computer resources of the local community college in developing the product. Mike Nesdoly, faculty member at Lambton College, which offers two-year and three-year diploma programs mostly in various technological fields and has 3,500 full-time students, says Pipeintel is one of the most promising technologies in which staff at the college have been involved. Lambton College, like community colleges throughout Ontario, has been given a mandate by the provincial government to work on practical, applied projects, along with local industries. So far, he says Pipeintel has been the most promising culmination of that initiative for the college. “They [Raaymakers and Grant] had a great idea, and we were able to come up with ideas that advanced the project.” He says another project that appears as if it has commercial application involves an effort to convert wind, solar and other renewable energy into hydrogen, which could then be stored and used to generate energy. That five-year project, which recently received $2.3 million in government funding, is aimed at helping to address one of the largest challenges faced by renewable energy producers, which is that much of the energy they use can’t be stored for future use. Pipeintel hasn’t settled on a method of payment yet for the software, although it will likely use a subscription model. Grant calls it “demonstration ready” at this point, although it is a ready-to-use product. Jim Bentein CONTACTS FOR MORE INFORMATION Marty Raaymakers, MIG Engineering (2011) Ltd. Tel: 519-337-8000 Email: David Grant, CanWeb Internet Services Ltd. Tel: 519-332-6900 Email:




RUNNING THE MODEL Fluids-flow simulation software facilitates the solving of oil and gas flow problems



you to model multiple s computer softfluids which don’t ware gets more completely mix. You sophisticated, it might have oil and becomes more useful for water, for example, or professionals in the oil an oil layer and a water and gas sector, includlayer, droplets of oil, ing engineers. By now, or an emulsion. That computer-aided design requires another layer systems are standard of capability in the at most engineering software, and ANSYS firms, but other kinds of has very capable multisoftware also allow enSINGLING OUT phase models in our gineers to do more with Multiphase simulation within a horizontal threecomputational fluid desktop computers. dynamics package.” Computer-simulated phase separator with inlet piping, a vanetype inlet device and full-diameter perforated Lockley describes models, for example, baffles. The lower layer of fluid is water; above the company’s CFD allow designers to test that is the oil phase with the inlet device in the software as a “generaldrive such new products gas phase of the vessel. The pink area at the purpose, fluids-flow as pressure vessels and bottom of the vessel shows where sand software module.” separators before a entrained in the water phase will initially settle. ANSYS models are prototype is ever built. physics-based, incorporating mathematical Mistakes made during design are easily—and models based on the physics of the process cheaply—fixed, but those that need to be being modelled, he says. The software uses fixed during manufacturing are more costly. complex math, such as Navier-Stokes equaThus, modelling software is a costtions, to resolve fluid-flow behaviour. saving tool for those designing oilfield hard“We’re solving physics-based equations ware and other equipment. to isolate how the fluid will flow,” he says. In the field of fluid dynamics, new types of “We use those equations to solve general CFD software—short for computational fluid fluids-flow problems. There are variations, dynamics—are also allowing engineers to with different levels of complexity, but those craft new solutions, especially in multi-phase are the fundamental governing equations flow scenarios. In designing a separator, for we’re using.” example, the engineer wants to model both At the same time, the software user doesn’t liquid and gas flows, but potentially other need to understand all of the physics to use the phases, such as solids, as well (see photo). program, he says. In cases where the problem At its most basic, CFD software simulates being tackled doesn’t fit the ANSYS model, fluid flow in a model that accounts for most “they can contact us and through a dialogue, relevant variables in a real-world problem. we can establish whether or not we have a Other CFD applications arise in designing solution to that problem.” valves, pipelines and refinery vessels, where Apart from its CFD module, ANSYS makes fluids gas and solids often interact. two other general-purpose software modules: A company that’s giving competitors a run one geared to modelling and solving strucfor their money is ANSYS, Inc., a maker of CFD tural mechanics problems; the other tailored software. While the company offers other kinds to solving electromagnetic problems, both of engineering software, Ian Lockley, ANSYS areas familiar to many engineers. regional technical lead for northwestern North For large, well-funded engineering firms, America, says separator modelling is a “sweet ANSYS CFD software is economical in part spot” for the company’s CFD software. In parbecause the demands made on a large firm’s ticular, he cites the example of an engineer who resources mean it’s more likely to reap posiis tasked with designing a three-phase separator. tive returns after paying for the software and “That [job] requires multi-phase modelupdates that come with the package. ling,” he says. “[Our CFD software] allows

For small engineering firms, with more limited staff and tight budgets, the cost may be harder to justify, according to a Calgary-based engineer who has used several kinds of CFD software. “[ANSYS CFD] software is expensive for a small firm to justify,” says Derek Lastiwka, whose firm, Gray Matter Engineering Inc., works in the field of mechanical and fluids engineering, largely for the oil and gas sector. “The upfront cost of the software is one thing, but then you have to pay maintenance,” he says, adding that the software cost is substantial. Then there’s the increased computer “horsepower” many desktop computers need to run the ANSYS CFD application, which may require parallel processing. An engineer might have to upgrade his workstation or tap additional processing power elsewhere. In the applications he has used, Lastiwka says using six or eight microprocessor cores is typical. For engineers working individually and with small firms, Lastiwka says other, lesscostly options would include software that uses open-source code, something many engineers are familiar with, although it’s often a different experience than using commercial software, which typically does not use open- source code. When using open-source code CFD software—one type is known as OpenFOAM—an engineer would typically hire a software consultant to write a program that would, in effect, customize the software to the task or problem the engineer is solving. While doing so means incurring extra expense—one not needed with ANSYS CFD software—it would be an expense most engineers could easily handle, he adds. “It’s more cost-effective,” he says. “I think that’s the way a lot of it is going nowadays. With the open-source [software], there are a lot of people with packaged graphical user interfaces for it, which is more affordable. You can pay for them as you need them.” At the same time, there can be disadvantages to going the open-source code route, Lastiwka says. “[Open-source code software] usually doesn’t have as many features, and it’s not guaranteed. You need to run it against something you know to make sure it works, whereas the software you buy—commercial software—the manufacturer has usually run lots of benchmark cases to make sure [it] works.” As well, Lastiwka notes that commercial makers of software will often provide the user with fixes if the user finds something about the program that is not working or needs adjustment. “There’s more customer service there, whereas, with the open-source stuff, you’re on your own.” James Mahony CONTACT FOR MORE INFORMATION Ian Lockley, ANSYS, Inc. Tel: 510-219-9425 Email:

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Software allows for better collaboration


The company based its software on Microsoft n large, dynamic and complex oil and gas SharePoint. It allows everyone in an organorganizations, information silos can often ization to view all of the documents build up and create many challenges for the associated with a well, for example, which management of projects. A central problem then integrates with all of the data systems: is the fact that the oil and gas business is not well data management, land and financials. a static, ossified one; complex organizations “We also then bring all of the asset team must juggle multiple projects simultaneously, members—the geologist, the landman, drillwhich often includes hundreds of workers ing engineer—we list them on the site and performing different tasks. Without effective we provide a place where they can also have information management and collaboration, threaded discussions,” Halliday says. “Where handling these projects effectively and efyou might otherwise put Post-it notes onto ficiently is difficult. a well file, you can have a talk about the well According to market research and it keeps that history.” firm International Data Corporation, $14,000 is lost per worker per year due to their time and inability to find the information they require to do their jobs. Employees spend between 20 and 40 per cent of their time searching for information. Calgary-based NeoStream Technologies Inc. says it has the software solutions to help oil and gas companies slay the silos and help to foster more effective information COLLABORATIVE SOFTWARE management. A screen shot of NeoStream’s 4 Wells modular collaboration product, part NeoStream’s Platform 4 of its Platform 4 Energy modular software platform. The company’s Energy (P4E) is a modular software is designed to increase information management, communication software platform upon and collaboration. which NeoStream’s collabEssentially, everything that is happening oration software products are built. Intranet 4 with a particular well, for example, is located Energy (I4E) provides a portal through which in a central place. all information assets can be accessed; 4 Wells, “And then you have security-trimmed 4 Facilities and 4 Land are modular collaboraaccess to it,” Halliday says. “If you open it up tion products based on the same architecture and start letting some of your suppliers and and user experience. Energyplaza is the compartners [come] onto this page, you might pany’s optional cloud hosting service. restrict that they can’t see certain documents At the core of P4E is a base of software or certain sections. For example, maybe they code and associated best practices that enable can’t see the land system data. We can control energy industry clients to deploy cost-effective what’s viewed.” collaboration programs. While this can be done for wells, the “We’ve centred our solutions on helping company can also provide this service for manage documents within oil and gas comfacilities—as small as the equipping and panies,” says Sean Halliday, NeoStream’s chief tie-in process—all the way through to major executive officer. The company boasts clients gas plants and in situ oilsands producing fasuch as Crescent Point Energy Corp., AltaGas cilities. NeoStream can also offer this service Ltd. and Apache Corporation, among others. for land assets. “We bring the activities, data and documents “The point is to increase information manassociated with a well or other project to a agement, communication and collaboration,” single web page.”


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Halliday says. “The engineering companies, the contractors, the field workers, the head office—everyone can get at it.” Crescent Point has the 4 Facilities solution running for many projects. According to a report, the company’s asset portfolio has been growing along with reserves and production and the facilities team was finding it difficult to maintain effective oversight of costs and the status of each project. The legacy software that Crescent Point was using, in conjunction with manually maintained spreadsheets, resulted in cost reports that were difficult to assemble and were unreliable. The options were either to hire more administrative staff to manage the business or invest in a technological solution that would yield greater returns than adding staff. Crescent Point chose the latter. The technology resulted in cost and time savings, along with other benefits that are more difficult to quantify. “There’s a 4 Facilities site page and it’s [password protected] so that each engineering company and supplier can get onto the projects that they’re working on, and that’s their central point for managing the construction, operation and maintenance of a facility,” Halliday says. “Most of these companies are looking for the same sorts of things. “We literally built a model—a template— that we can roll out very quickly and you don’t spend any of your time on the technical risk side of the implementation—you’re spending your time on the communication strategy, the branding and the cultural side of what it looks like.” Jack Scown, Bonavista Energy Corporation’s director of information technology, says the company uses NeoStream’s I4E. “When evaluating candidates to provide our intranet, we were attracted to NeoStream’s template-based approach with the I4E solution,” he says. “We liked being able to match our requirements to the list of available features in the product. “We appreciated being able to easily tie our brand and culture to this tool, without the need to reinvent the wheel. We saw an economical and efficient way to implement a solution with minimal technical risk. This created good value for Bonavista.” In most cases, companies seek to improve the connectivity of information to its employees. “This is information management, but it’s really about alignment and connecting the organization,” Halliday notes. Richard Macedo CONTACT FOR MORE INFORMATION Scott Mitchell, NeoStream Technlogies Inc. Tel: 587-794-4865 Email:






Settling The Sediment Problem Using solar heat to get more out ofponds’ natural gassolids–settling challenge A better polymer could crackenergy the tailings fine



hile the massive oilsands tailings ponds in the Athabasca oilsands appear to have become a lightning rod for the opposition to oilsands development, the industry, armed with new technologies, is working to change that. For 40 years, Syncrude Canada Ltd. has used the ponds as a containment area where tailings can be segregated prior to further dewatering for use in reclamation activities. However, a major challenge is the length of time it takes for some solid components to settle. While the sand settles rapidly, clay and fine solids can take decades to settle on their own. In response to public concerns and an Energy Resources Conservation Board directive to speed up reclamation, the Oil Sands Tailings Consortium (OSTC), a group of oilsands mining companies, will be testing a range of tailings remediation technologies. In March 2012, the OSTC became part of Canada’s Oil Sands Innovation Alliance. The first out of the box is accelerated dewatering. An existing process, it has been refined with what Verve Energy Solutions Inc. hopes is a better polymer to separate

tailings into recyclable water and stackable soils and clays. The polymer’s large molecular mass, compared to small molecule compounds, produces unique properties. Verve’s high molecular weight polymer creates a nonsegregating deposit that is stable under shear loads. The resulting aggregate structure is porous, which improves dewatering and consolidation rates. “This is all based on lab testing, and that’s why the government is interested in seeing this explored closer to commercial levels,” says Verve director Ted Sortwell. “The test results show that it will [work], and the only way we’ll know for sure is to spend $19 million [on a field test].” The federal government is contributing $3 million through Sustainable Development Technology Canada’s SD Tech Fund and the consortium, supported by the major oilsands operators, will be putting up the rest of the money for this summer’s test at Mildred Lake settling basin, the oilsands’ largest and oldest tailings pond, covering 17 square kilometres. Syncrude will be the operator, and its partners will include Canadian Natural Resources Limited, Imperial Oil Limited, Shell Canada Limited and Teck Resources Limited.

TACKLING THE TAILINGS Verve Energy Solutions’ accelerated dewatering technology is the first chosen by Canada’s Oil Sands Innovation Alliance for field testing, at Syncrude’s mining operations near Fort McMurray, as a potential solution to the continued accumulation of tailings ponds.

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“What will happen is that THE SOLIDS DROP AND THE WATER IS PRESSED OUT AND UP TO THE TOP OF THE DEPOSIT. It’s allowed to compact over time and express more water to the top, and more water is pulled away.” — Ted Sortwell, director, Verve Energy Solutions Inc.

The field test will see existing fluid fine tailings pumped up from the tailings ponds to shore and into a large holding tank to ensure as much uniformity as possible. The tailings are then metered out of the tank and Verve injects the special polymers through different mixing systems into the line before it goes into a test pit or surface storage area. “What will happen is that the solids drop and the water is pressed out and up to the top of the deposit,” says Sortwell. “It’s allowed to compact over time and express more water to the top, and more water is pulled away.” The process could take anywhere from two to five years to provide final consolidation of the solids, he says. If a

pit is used, then it would be filled in over that period. A specially built $2-million machine produces the polymer solution that is metered in proportion to the flow rate, which may vary from 1,000 to 1,200 cubic metres per hour. “We are constantly testing because it’s not only the flow and the solids level in the flow, but it’s the particle size of the fluid fine tailings,” says Sortwell. “You are never sure what’s going to come up, so you have to check what is coming up and adjust the polymer feed to both the flow and the character of the solids.” Verve’s technology involves both the chemicals and the machine required to put them in solution, which produces

a very high volume of polymer solution almost instantly. The machine resembles a large trailer because it needs to be portable. The 750-kilogram super sacks of dry polymers are lifted up and inserted into the top of the unit. The dry polymer flows out the bottom of the bag into units that meter the polymer into special cutting heads, which slice the polymer to waferthin slices in the presence of water. The pressure at the point of slicing is between 18,000 and 20,000 pounds per square inch, which drives the water into that “wafer” from both sides. After the testing phase over the summer, the consortium should have all the data it requires from all the changes and adjustment that will be made during the test. That information will then be assessed before determining the next steps in potentially commercializing the technology. Elsie Ross CONTACT FOR MORE INFORMATION Ted Sortwell, Verve Energy Solutions Inc. Tel: 912-638-3579 Email:

774217 Momentive Specialty Chemicals Inc 1/2 HORIZONTAL General


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Mud By Any Other Name Homegrown research on nanoparticles could change the future of drilling fluids



• Small atomic clusters (one to 100 nanometres) with size-dependent properties


1m 100mm

Top of a nail


• Small particles, huge effects

Red blood cells

1mm 100µm

Wavelength of visible light


The scale of things


n western Canada’s oilpatch, when people hear the term “advanced technology,” they often think of downhole telemetry, wireless communications, engineering instruments or global positioning systems. Few people normally associate advanced technology with drilling mud, but it’s a link more people are making as drilling mud attracts interest from scientists, while North American drilling contractors push the limits of currently available drilling fluids by boring longer, deeper wells under increasingly hostile downhole conditions. At its most basic, a drilling fluid is an emulsion: water containing suspended clays, fluids or both. Water-based drilling fluid, usually a mix of clays and additives suspended in water, might be the simplest drilling fluid. More complex emulsions are invert drilling fluids, in which water is suspended, often in diesel or oil, along with clays or other additives. In the University of Calgary’s (U of C’s) department of chemical and petroleum engineering, two seasoned professors, Geir Hareland and Maen Husein, are conducting research on drilling fluids, with a view to developing products for commercial use in the oil and gas sector. They lead a larger team that’s developing the fluids. Unlike some drilling fluids, those being developed by the U of C researchers contain nanoparticles: microscopic bits of compounds, such as iron oxide, that are suspended in the drilling fluid. By any scale, nanoparticles are small, measuring from one to 100 nanometres in diameter. To put that in perspective, a nanometre is about one millionth of a millimetre, underscoring the tiny scale involved. By comparison, a human hair is about one micrometre—or one millionth of a metre—in diameter. In most respects, it’s the tiny size that gives nanoparticles their unusual physical and chemical properties when added to drilling fluids, says Husein. Those properties, which often enhance the performance of drilling fluids, are of great interest to the oil and gas sector as it pushes the limits of existing drilling fluids. According to Husein, the nanoparticlebased drilling fluids his team is developing



100nm 10nm

DNA molecule Atoms

1nm 1Å

offer several advantages. One is low cost. The nanoparticles used by Husein and colleagues are tailor-made in the lab. On the other hand, other researchers—and some drilling mud-makers—buy their nanoparticles ready-made on the open market, but incur higher costs in doing so. For its part, the U of C group makes its nanoparticles using a proprietary in-house technique, giving them a cost-advantage over other researchers and drilling fluid makers. As a practical

NO SMALL MATTER Drilling fluids incorporating nanoparticles—measuring just one to 100 nanometres in diameter—can benefit from the unusual physical and chemical properties found only in particles of that size.

matter, that advantage makes it easier to develop a commercially viable drilling fluid, Husein says, going on to explain other key advantages of his approach. “We form our nanoparticles, starting from their [chemical] precursors, in the drilling fluid, and that’s why we are able N E W T E C H N O LO GY M AG A Z I N E | J U LY / AU G U ST 2 013



Thermal Water Chemistry The Lifeline of your SAGD Operation

“We have applied our scientific expertise to help solve a well-known production problem in the Oil Sands: corrosion, deposits and scale. With Maxxam’s new, purpose-built Thermal Water Analysis Program, customers can now take appropriate corrective actions to optimize production and profitability.” Phil Heaton, P.Chem. General Manager, Oil Sands and Upgrading.

Contact Maxxam to design your site-specific Thermal Water Analysis Program: 780 378 8500

Procrastinating? submit your technology before August 30 The deadline for New Technology Magazine’s technology stars is fast approaching. Drop everything and enter your technology now. It’s easy. Just use that computer-Internet-thingy on your desk. Visit to submit your technology for review. technology stArs cAtegories this yeAr:

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to apply them on a large scale because it’s not as expensive,” he says, describing the process as a bottom-up approach. Because the nanoparticles are formed in the drilling fluid, they stabilize easily and are very well dispersed in either invert emulsion or drilling fluid, he says. The alternative, which involves mixing ready-made nanoparticles, is very difficult, he says. Other benefits also arise from making their own nanoparticles, he explains. For one thing, “you have more control over the particle size. At the end of the day, you can screen smaller from larger particles, but if you make the particles [from scratch], as we do, chances are that you have better control over particle size.” In designing a drilling fluid, he says scientists need to be careful that the benefits represented by such technology as nanoparticles do not impair the desirable properties of a particular drilling fluid. “We make sure that the presence of these particles does not ruin the properties that are favoured by industry, which they still want to see. You can use all kinds of particles, of whatever concentration, but at the end of the day, you may ruin the properties that industry prefers. So, it’s a balance that we want to maintain.” To a large degree, the research done by Hareland and Husein is a product of lab science, but further testing is planned. Asked if there is sometimes a gap between the early promise shown by some products in the lab and the later results seen in field testing, Husein is candid. When looking at new drilling fluids, he says the oil industry often relies on standard tests which they consider benchmarks. These address such goals as minimizing lost circulation, while others make lubricity and lubrication their aim, while still others look at properties that can strengthen the surrounding formation. “They have certain tests they believe in,” he says. “They trust the results. If you show them [the results] of these tests, they are more willing to buy in.” Currently, the U of C team is looking forward to the next step. “We’re in that process, and are collecting results to show [the] industry. They indicated they’re interested enough to take it to the next level, which is field testing.” James Mahony CONTACT FOR MORE INFORMATION Maen Husein, University of Calgary Tel: 403-220-6691 Email:

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