New Technology Magazine September 2013

Page 1

SE PTE m B E R 2013

T h E F i R ST w o R D o n o i LPATc h i n n oVAT i o n | $10

New processes aim to

revolutionize oilsands production

23 Tailings Technologies Small independent companies vie with majors in a quest to end ponds’ proliferation

27 Refined Tastes Technology for proposed B.C. refinery has potential to significantly reduce the carbon footprint


Resettable frac isolation on coiled tubing + Grip/ShiftTM sleeves

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Frac ports

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.

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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.


S E PTE M B E R 2013


VOL.19 | NO.07



Necessity drives innovation



News. Trends. Innovators.



Numbers Game A revised well iD system will help the U.S. o&g industry—canada is next


13 IN SITU 2.0


New processes aim to revolutionize oilsands production

Small independent companies vie with majors in a quest to end ponds’ proliferation

Risk assessment system helps companies find least harmful additives




Frac With Care


Refined Tastes


Surfactant Solution


Operators Get A Welcome Lift


Accelerating Radio Frequency Technology

Technology for proposed B.c. refinery has potential to significantly reduce the carbon footprint

oilsands operators are hoping additives will help boost thermal in situ recovery rates

new “one-eyed” electronic sensor cracks north American plunger-lift market

innovative simulation software could lead to greener oilsands production

ADVE RTI S E R S Baker hughes canada company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .OBC

ihS Energy (canada) Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

dmg events . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

ncS oilfield Services canada inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IFC

Dragon Products Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Packers Plus Energy Services inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

DuPont Sustainable Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Schlumberger canada Limited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Entero corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Society of Petroleum Engineers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

geoLogic Systems Ltd.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IBC

women in Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38


n E w T E c h m Ag A z i n E . c o m


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glance at forecast crude oil output in Canada over the next couple of decades leaves little doubt where our future oil will come from—the oilsands and, in particular, in situ bitumen production. The latest figures from the Canadian Association of Petroleum Producers (CAPP) released in June show our already increasing reliance on in situ production will grow substantially as output more than triples from one million to 3.5 million barrels per day between 2012 and 2030. In percentage terms, in situ production—which today consists primarily of thermal production from steam assisted gravity drainage (SAGD) and cyclic steam stimulation methods—swells from 31 to 52 per cent of Canada’s total crude oil output by 2030. While oilsands mining will almost double in that period, from 800,000 to 1.7 million barrels per day, its percentage of overall production will remain largely unchanged, at about 25 per cent. While conventional oil output will rise somewhat due to application of horizontal drilling and multistage fracking technologies, from 1.2 million to 1.4 million barrels per day between 2012 and 2015 and stabilizing at 1.4 million thereafter, it will represent a dwindling proportion of oil production, falling from 38 to 21 per cent. Total Canadian oil production is predicted to grow from 3.2 million to 6.7 million barrels per day. The dramatic shift in production is all the more amazing when one considers that commercial in situ production technology isn’t much more than a decade old, having reached that stage after decades of research and development. And herein lies perhaps the technology’s greatest challenge and its greatest potential. For while in situ oilsands production is the most energy intensive, and therefore the most greenhouse gas (GHG) emissions intensive, it remains a relatively immature technology with great potential for improvement. While the decades-old oilsands mining operations have gone through stages of dramatic improvement over the years— consider the switch from draglines and


bucket-wheels to giant trucks and hydraulic shovels, and replacement of conveyor belts with hydro-transport to begin the separation process before the ore hits the processing facility—in situ production remains in the early stages of evolution and improvement, with several exciting ideas and concepts under consideration that could lead to dramatic improvements down the road. In this issue of New Technology Magazine, we look at a sampling of some of the most promising of those technologies, including some very different variations on the SAGD production method and some alternatives to steam assist, such as the use of radio frequency fields to heat bitumen. And there are, of course, many other technologies out there under consideration or in early testing, and it’s too early to say which ones will catch on and potentially lead to game-changing improvements to the process. But some companies, at least, are showing themselves willing to take the risks involved to seek better means of production. This is vital because as the easiest reservoirs become depleted, companies will need more efficient techniques to make more challenging deposits economic to produce. Also, it is essential because the downside to current technologies, high GHG emissions, is likely to be unsustainable in the long term. The oilsands already account for over seven per cent of Canada’s GHG emissions, and as production triples—with an even greater emphasis on higher-emission in situ production techniques—utilization of current technologies could see the oilsands creating over 20 per cent of Canada’s emissions in less than 20 years. That’s almost equivalent to the country’s entire transportation fleet, currently the largest emitting economic sector at 24 per cent of emissions, according to Environment Canada. Clearly, better, less polluting production technologies will be necessary to meet CAPP’s forecast oilsands production levels. And the sooner they are developed, the better. Maurice Smith

n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2013

EDITOR maurice Smith | STAFF WRITERS carter haydu, James mahony, Elsie Ross CONTRIBUTING WRITERS godfrey Budd, gordon cope EDITORIAL ASSISTANCE MANAGER marisa Sawchuk | EDITORIAL ASSISTANCE Laura Blackwood, Sarah Eisner

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nEwS. TREnDS. innoVAToRS.



British Columbia’s carbon tax shift is not only effective in reducing fuel use, but it does so with no apparent adverse impact on the economy, according to a Sustainable Prosperity study released in July. “British Columbia pretty much did what economists said it should do, and it is working,” Steward Elgie, lead author of BC’s Carbon Tax Shift After Five Years: Results, told the Daily Oil Bulletin. The province’s fuel consumption fell by 17.4 per cent (18.8 per cent more than in the rest of Canada), while its gross domestic product kept pace with the rest of the country, the report found.


MILLION Both AKITA Drilling Ltd. and Trinidad Drilling Ltd. announced plans in late July to build ultra-deep drilling rigs that will rank as Canada’s largest and most technically advanced onshore rigs. The rigs, to be constructed in Nisku, Alta., are intended to drill for natural gas in northeastern B.C.’s Liard Basin, an area that is being developed to supply gas for liquefied natural gas plants proposed for the West Coast. While costs were not disclosed, AKITA earlier estimated such units could cost as much as $35 million, roughly double the cost of its pad drilling rigs that cost $16 million to $19 million.

heavy oil—and “ Venezuelan Venezuela—would be the number one beneficiary of a negative decision on Keystone.


— Canadian Oil Sands Energy Dialogue, IHS CERA

The proposed Keystone XL Pipeline would have “no material impact” on U.S. greenhouse gas emissions, says an IHS CERA study, which found that in the absence of the pipeline, alternate transportation routes would result in oilsands production growth being more or less unchanged. The study, released in August, also found that any absence of oilsands on the U.S. Gulf Coast (the destination for Keystone XL) would most likely be replaced by imports of heavy crude oil from Venezuela, which has the same carbon footprint as oilsands.

“On average, new natural gas wells drilled in 2012 would need a higher natural gas price than current levels to be considered economic and would not recover their full costs over the producing lifetime of the well.” — Conventional Natural Gas Supply Costs in Western Canada, Canadian Energy Research Institute

According to the study, released in July, the average natural gas supply cost for new production was $4.79 per thousand cubic feet (mcf ) for vertical wells and $5.71 per mcf for horizontal wells. Assuming 2012 market conditions (AECO-C price averaged $2.07 per mcf while the Henry Hub price averaged US$2.64), average new gas wells in the Western Canadian Sedimentary Basin can’t recover costs at current prices.

$12 Billion

TransCanada Corporation’s proposed Energy East Pipeline project from Alberta to Saint John, N.B.—the single-largest capital project TransCanada has undertaken—will “soon become known as a model of environmental responsibility within the energy sector,” said Alex Pourbaix, president of energy and oil pipelines. That’s because 70 per cent of the pipeline is already in the ground and will not need to be dug up except for some digs to check its integrity, which greatly reduces the environmental footprint, he said. The $12-billion, 1.1-million-barrel-per-day project, to be in service by 2018, involves conversion of an existing natural gas pipeline to crude service.

n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2 013



Creative Solutions Sought Grade B oilsands reservoirs need new, improved methods to exploit


ith the best oilsands reservoirs in Alberta already under development by the majors, more than new technologies will be needed to profitably exploit the remaining second-tier reservoirs, attendees to an energy conference heard in July. “The Grade B reservoirs are going to take not only new technologies but new techniques and ways of doing things,” Byron Lutes, president and chief executive officer of Southern Pacific Resource Corp., said in response to a question at the TD Securities Calgary Energy Conference. “Smaller changes in technology will be important for operators

to be more effective in their business,” he said. While continued improvements in technology are important to the industry in general, “technical” technology such as solvents are likely to play a more prominent role in the future, said John Zahary, president and chief executive officer of Sunshine Oilsands Ltd. However, he said there also is a need to see improvements in commercial matters—bringing down capital and operating costs, he said. Sunshine, which has a number of Chinese investors, is looking at different ways of building equipment further afield and bringing it to the field location. It’s also examining different ways of operating facilities than have been done in the past. 10

n E w T E c h m Ag A z i n E . c o m

“This is a very large business; there is a lot of opportunity,” he said. “We are a price taker on the oil side, so we need to manage our costs in order to get the kind of profitability we need to make this business successful.” Southern Pacific has had to experiment with a number of techniques to get the ramp-up of its STP-McKay steam assisted gravity drainage (SAGD) project back on track because it is not getting even conformance as it is warming up the wellbores, said Lutes. “We are having certain areas breaking through first, and we are having some hot spots that we are having to manage the production to until we get to a more even conformance.” The process is taking longer than expected, which the company believes is due in part to the fact that it is operating at a slightly lower pressure than most SAGD projects, he said. “We are the second shallowest project out there and because of that we have a lower maximum operating pressure. So, we can’t use pressure as one of our tools to really push things through and really get the zone between the injector and producer opened up.” STP-McKay, 45 kilometres northwest of Fort McMurray, is also in a slightly younger-aged McMurray sand, and some of the grains are more angular than those in some larger projects such as Suncor Energy Inc.’s Firebag or Cenovus Energy Inc.’s Christina Lake, said Lutes. “We think some of the packing is more like rice kernels rather than marbles, so we have a little bit tighter packing that we need to dislodge or dilate and we need pressure to do that.” The most effective technique appears to be a high-pressure steam stimulation. In June, Southern Pacific completely shut in the injector well in one well pair and with the regulator’s approval pushed steam into the producer well at higher than its maximum operating pressure. “What we are really trying to do is fluff up the sand...and twist the grains of sand in between the producer and the injector so we can improve and accelerate the rate of conformance in the pair.” As a result of the procedure, one of the company’s poorest wells in terms of conformance is now a producing SAGD

well that has been operating steadily since June 4. Based on that, Southern Pacific has applied and received Alberta Energy Regulator approval to test five more wells and has already started its second steam test. It will continue to stimulate the wells over the summer and is hopeful that will accelerate conformance, said Lutes. “It’s not a silver bullet; there are other companies that are doing dilation and various techniques, but it is a way that we think will help us get that conformance so we can start to ramp up some of those well pairs and get them going.” BlackPearl Resources Inc. also has been “experimenting” with its 700metre single well pair at its Blackrod SAGD pilot project in the Athabasca oilsands, said John Festival, president and chief executive officer. The pilot is in the Lower Grand Rapids Formation at a depth of approximately 300 metres, and has 10–28 metres of continuous net pay. The Grand Rapids pilot has been underway for two years, and for the first 12 months had “very good results,” with production of 400 barrels per day and a steam to oil ratio of three, said Festival. BlackPearl’s results for the first year, in fact, were better than those of Canadian Natural Resources Limited’s Wolf Lake project, which the junior was watching as CNRL was learning with its process, he said. At that point, BlackPearl realized that it didn’t really have an optimized completion process, so it went back in and looked at its steam strategies. Earlier this year, the company tried removing the sand controls as it felt it had some fines migration and some clay. “We went and blew holes in the pipe to allow greater contact with the reservoir,” Festival said. “It worked very, very well; we know that more surface contact with the reservoir will allow better rates.” BlackPearl got the well up to 600 barrels per day with flush production and believes it will stabilize at between 400 and 500 barrels per day. In the first quarter of this year, the company drilled a second 900-metre well pair using a wire-wrapped screen that allows for more surface area contact with the reservoir, which should alleviate some inflow problems. While it is a better solution, it may not yet be the optimal solution, said Festival. “We have a commercial solution; we are just narrowing it down to what the optimized commercial solution will be.” Elsie Ross






Numbers Game A revised well ID system will help the U.S. O&G industry—Canada is next



or almost half a century, the American Petroleum Institute’s API well number (based on the API D12A Bulletin) has been a workhorse of the U.S. oil and gas industry. Operators use it to label, store and retrieve well information, including the geographic location, class of well (exploration, etc.), and well components such as sidetracks, logs, cores and completions. Regulatory bodies use it to track drilling permits, collect royalties from production and optimize field conservation. The API well number is based on a 10-digit system (see Table 1). The first two digits identify the state, the next three digits identify the county and the last five digits are unique numbers for each well in the county. In 1978, the API well number was expanded to 12 digits so that directional sidetracks could be identified. The rules for identifying sidetracks allowed considerable diversity in implementation, however, resulting in some fragmentation of usage between state agencies.

Over the last 10 years, drilling and completion technologies have expanded tremendously, with multiple wellbores, laterals and production reservoirs associated with a single well location. At a minimum, a 12-digit number is required to uniquely identify each sidetrack. Unfortunately, about half of the U.S. state regulatory agencies still only use a 10-digit API well number, and thus cannot identify all the drilled wellbores. Operators and vendors routinely add their own extensions to 12 or 14 digits, creating identifiers that unofficially emulate the API well number. This creates confusion when databases from different sources are merged together, resulting in errors that can cost money or create hazardous situations. Industry participants understood that the situation needed to be resolved. Early in 2010, the API transferred stewardship of the API well number to the Professional Petroleum Data Management (PPDM) Association. The PPDM Association is a global, not-for-profit

KEEPING TRACK In order to deal with the proliferation of multiple wellbores, laterals, and oil and gas reservoirs accessed from a single well, the Professional Petroleum Data Management Association is revamping the system used to track them through its Well Identification Project.

n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2 013


BYTES Table 1. API Well Number–1978 (based on the API Bulletin D12A)

Table 4. Structure of wellbore identifier













Unique well code

Directional sidetrack


Well ID

Component type

Component value










Table 2. API Number–2013 (based on industry revision in 2013)

Table 5. Structure of well completion identifier














Extension (optional)


Well ID











Component type Component value C


Note: Only digits are allowed in positions 1–12.






Well number




professional society that provides data management standards and best practices for the petroleum exploration and production industry. Petroleum companies, government agencies, software application providers, data vendors, service companies, standards bodies and individuals form the membership. In 2012, the PPDM Association formed the Well Identification Project (WIP). Industry participants included Anadarko Petroleum Corporation, BP p.l.c., Chevron Corporation, ConocoPhillips Company, Exxon Mobil Corporation, IHS CERA, Baker Hughes Incorporated, Devon Energy Corporation, TGS-NOPEC Geophysical Company, Llano Systems and Data Management Inc. and DrillingInfo, along with regulators. The goal was to create a new version that would honour existing standards but allow industry to identify and catalogue new well technologies in a consistent, universal manner. WIP polled industry experts to find out what capabilities the new well ID system needed and didn’t need. PPDM then turned to upgrading the U.S. well identification system. The API Number 2013 was formally launched in September. The standard can be downloaded for free by visiting The API Number 2013 now incorporates 12 digits (see Table 2). The first 10 digits are exactly the same as the old system, although the usage rules have 12

n E w T E c h m Ag A z i n E . c o m

been clarified. Digits 11 and 12, however, are reserved for identifying each wellbore in a consistent, standardized manner. The API Number 2013 has an optional extension to include more information. Positions 13+ allow for completions, plugbacks and drilling modifications within the stated wellbore. It is not meant to identify a wellbore or deepening; those functions are reserved for digits 11 and 12. The revised standard allows for improved financial, environmental, technical and safety performance, while still meeting contractual, social and regulatory obligations. Senior management benefits from reduced risk in decision making. Geoscientists will spend less time searching for and reconciling data. Engineers can make better workover and drilling decisions. Regulators benefit from standardized reporting methodology. Mergers and acquisitions activity encounters fewer errors. Data managers can improve the quality of databases and data exchange. The PPDM Association is now working with state and federal regulators to help them implement the system.

cAnADA’S wELL iD SYSTEm In the meantime, PPDM is also coordinating an upgrade of western Canada’s well ID system. The Canadian unique well identifier (UWI) was developed by the Canadian Petroleum Association (now the Canadian Association of Petroleum Producers) in the 1970s. The UWI contains a coded description of the general location of the well event. In western Canada this refers to the bottom of the wellbore; elsewhere, it refers to the well origin (surface). As industry has evolved over the years since, it became clear that the UWI

system had limitations. “It was difficult to uniquely identify all wells and components, especially in multilateral completions,” says Jeffrey Bonus, project manager at PPDM. “In addition, the UWI may be deleted and replaced by a new UWI for several reasons, chiefly because the bottomhole survey location changes over time.” In response to the industry’s need to overcome the limitations of the UWI, PPDM and the Energy Resources Conservation Board (now the Alberta Energy Regulator) initiated the Well Identification Revision Project - Western Canada, which kicked off in January. In addition to a wide selection of oil and service companies, participants included regulators from British Columbia, Saskatchewan and Alberta. The work group has proposed an entirely new well identification system (see Table 3). The first two positions identify the province and territory. Positions 3–9 establish a permanent, unique well identifier. Positions 10–13 (see tables 4 and 5) establish a component type identifier; B is for wellbore, C is for completion, etc. Up to 999 wellbores and 999 completion events can be identified for each well. In June, the working group submitted a position paper to regulators for review and comment. Since the new system requires comprehensive IT upgrades, participants expect it will be several years before formal implementation occurs. “The original UWI will still remain as an attribute because there is much valuable information embedded in it, but the new Well Identification System will be the standard that identifies each well, wellbore and well completion with a unique, permanent identifier,” says Bonus. Gordon Cope


Table 3. Structure of well identifier


EnViRonmEnTAL nEwS. TREnDS. TEchnoLogY innoVAToRS.

Water & Sand 99.5% Additives 0.5%

Acid Friction Reducer Surfactant Gelling Agent Scale Inhibitor pH Adjusting Agent Breaker Crosslinker Iron Control Corrosion Inhibitor Antibacterial Agent Clay Stabilizer


Frac With Care Risk assessment system helps companies find least harmful additives



eveloping hydraulic fracturing fluid additives posing the least environmental risks—and therefore attracting less scrutiny regarding the practice’s impacts on water quality—is a challenge that the Fracturing Fluid Additive Risk Assessment and Selection Tool helps companies address. “As well as the promise that comes with shale gas or shale oil development are a number of challenges, not the least of which are public concerns over hydraulic fracturing,” Donald Davies, senior vice-president at Intrinsik Environmental Sciences Inc., said during the recent Petroleum Technology Alliance Canada’s 2013 Water Forum. He told the forum that public concerns regarding hydraulic fracturing largely centre around the impact frac fluid additives might have on potable water. “[These additives] comprise a very, very small portion of the fluid system itself, generally in the order of 0.5 per cent, but nevertheless they have caught the attention of the

public, and a number of the concerns have been expressed by the public over the potential risks that these additives could present—particularly if they found their way into drinking water supplies.” According to Davies, his company developed the additive risk assessment and selection tool to tackle these concerns. The system uses pre-existing chemical test results posted in scientific literature or regulatory agency databases to separate frac fluid additives into different categories in order to help companies determine the ideal additives to use in their hydraulic fracturing programs. “We use information that already exists, and then basically depending on what the information is telling us with respect to the different properties in the chemical ingredients found in the hydraulic fracturing additives, it will determine the categories to which the additives will ultimately be assigned.” In category “A,” health or environmental impacts are not triggered by ingredients and the operator

DEMYSTIFYING THE PROCESS While additives make up a tiny proportion of fracture fluid volumes, they have attracted considerable public scrutiny as fracking has skyrocketed in recent years. Intrinsik’s additive risk assessment and selection tool helps companies choose the least risky additives and provide transparency about the additives they choose.

n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2 013


“THE SYSTEM IS CONTRIBUTING TO THE ‘GREENING’ OF ADDITIVES and greater awareness of potential hazards. We are certainly seeing that with companies moving away from the use of category ‘C’ compounds or products.” — Donald Davies, senior vice-president, Intrinsik Environmental Sciences Inc.

says, adding that information gleaned can do nothing. In category “B,” one or from the system is intended to be used as more ingredients trigger one or more part of a risk management program. impacts, and therefore the company is According to Davies, for over two expected to take proper actions to miniyears Intrinsik has developed its mize the hazard risk. In category “C,” the screening level assessment system impacts are more severe, and the company to classify hydraulic fracturing fluid is expected to determine the proper additives. He says it is a system that measures to take, as well as to reconsider will continue to evolve with growth its use of the particular additive. Once additives are categorized, Davies says the system also calculates the data availability index, which measures the extent to which ingredient information is available. He notes the system is based on the “parent compound,” and it doesn’t deal with “daughter products” or other by-products in the frac fluid DO NO HARM Intrinsik’s screening level fracture fluid additive assessment system additives. provides an evidence-based system that relies on empirical data to “It’s also minimize the risks posed by hydraulic fracking. dealing with the parent compounds as they are delivered downhole, so it doesn’t deal with flowback water issues. It deals with the additives at full strength, which is consistent with most systems of the type that operate on a hazard basis and at a screening level.” While the system does not address exposure opportunities nor can it substitute for a highly detailed site-specific risk assessment, Davies says a company could use it to determine the different types of additives in its hydraulic fracturing process. “The system focuses on public health, specifically, and the environment,” he 14

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in scientific knowledge and changing regulations. “We wanted an evidence-based system, so we’re relying on empirical data as opposed to conjecture or supposition,” he says, adding that the system is “nonjudgmental,” transparent and the reasoning behind categorization of certain chemicals is intended to be obvious. Originally developed through Encana Corporation, Canadian Association of Petroleum Producers (CAPP) eventually took over development of the system and offered support and advice to Intrinsik

through CAPP’s Shale Water Steering Committee. Davies says other experts, organizations and regulators have also aided the project. “The trend that CAPP is trying to encourage is the use of fracturing fluids that are the least likely to cause harm to human health or the environment. So this represents a very broad objective, but in terms of specifics around achieving that particular objective...there is a specific operating practice that relates to the assessment and management of the risk presented by these additives.” In order for companies to access the system, Davies says there is an online user manual available to CAPP members at, although many prefer Intrinsik to run the system on their behalf. “Some companies prefer to have the screening and categorization done by a third party, just because it provides a greater objectivity in their mind.” The purpose of the system is to increase awareness and understanding of those potential risks that could be associated with use of hydraulic fracturing additives, which Davies says would hopefully help guide decision making on the part of fluid suppliers, as well as operators, in terms of which additives to use and also what measures to take to ensure the use of a certain additive does not cause harm to human health or the environment. “Technical robustness” is critical to the system Intrinsik developed, as Davies says the tool must stand up to the scrutiny of industry, environmentalists and scientists. He adds that the system aims to identify additives with “the lowest risk profiles” in order to help industry develop the most benign frac fluid additives possible—and it works. “The system is contributing to the ‘greening’ of additives and greater awareness of potential hazards. We are certainly seeing that with companies moving away from the use of category ‘C’ compounds or products.” Carter Haydu



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umans have a long history with bitumen, from North American aboriginals using it to waterproof birch-bark boats to Mesopotamian empires using it as a construction material and ancient Egyptians using it in their mummification process. Contemporary use of bitumen as a highly valuable petroleum fuel source

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has encouraged development of an array of extraction techniques—the most well known commercial technologies being steam assisted gravity drainage (SAGD) and cyclic steam stimulation. But innovation doesn’t stop at commercialization. Several producers are working to advance in situ pro­ duction performance in very different

ways, including Nexen Inc. with its SAGDOX process; MEG Energy Corp. with its enhanced modified steam and gas push (eMSAGP) method; JR Technologies, LLC, developer of a radio frequency heating (RFH) technique; and GeoSierra LLC and Halliburton’s joint development of Azi-Frac, also known as X-Drain.


New processes aim to


revolutionize oilsands production By Carter Haydu

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At Nexen, a subsidiary of CNOOC Limited, SAGD is being taken to the next level with the addition of oxygen injection to horizontal wells—a process called SAGDOX. “Once the chamber is established, you can start injecting pure oxygen and reduce your steam volumes quite considerably for the same energy input into the reservoir,” says Hans Jonasson, project manager at Nexen. “As the steam chamber grows and expands, both laterally outward and then along the wellbore length, when you start injecting the oxygen you actually start creating more heat in the reservoir by burning the residual bitumen that is left behind by the SAGD process.” Invented by Nexen’s chief technology officer, Richard Kerr, SAGDOX currently has patents pending. The first phase of laboratory testing is complete, and researchers are now analyzing the results

From an environmental perspective, SAGDOX uses a lot less steam and therefore requires a lot less fuel. “There should be some reduction in [CO2] generation because you’re not burning as much natural gas to generate the steam. But the main environmental benefit we see is the reduced water use. You start out the SAGDOX pattern with steam, and then you switch to a steam-plusoxygen mixture, potentially reducing steam usage by 80–90 per cent.” Because there is no pressure limitation with oxygen like there is with steam, Jonasson says SAGDOX can achieve temperatures of approximately 450 degrees Celsius due to combustion, which is significantly higher than what steam alone can do. “Because bitumen’s ability to flow has a strong correlation to temperature, we think we’re going to see some viscosityreduction effects,” he says. Jonasson says another benefit is that SAGDOX can be applied to existing SAGD wells, simply by adding an oxygen-injection well close to the toe of the SAGD well pair, as well as gasvent wells to draw off the combustion gas.


OXYGEN ASSIST Nexen’s SAGDOX process uses oxygen injection over the SAGD well pair to create more heat in the reservoir via combustion of residual bitumen. Gas off-take wells limit combustion to the top of the formation, keeping high temperatures away from the producer and preventing gas from competing with liquids for flow space into the producer.

in order to create combustion-kinetic models for use in reservoir simulation. Jonasson says Nexen is also working on a larger-scale SAGDOX lab model. “We’ve been conducting some tests with Alberta Innovates-Technology Futures,” he says, adding that, although the process has never been field tested, analysis suggests recovery should be the same or better than conventional SAGD, and require a lot less energy input. “The way we envision it, even at the same recovery levels, the real benefits come from reduced operating costs... oxygen is about 10 times more effective on a [British thermal unit] basis than steam.” Transportation is another benefit of SAGDOX, Jonasson says, as Nexen has access to pure oxygen from its upgrader air-separation unit at the company’s Long Lake site and oxygen can be easily transported in its liquid state for hundreds of kilometres. “Steam is limited because of how far you can transport it due to heat loss and condensing of the steam—normally only 10–15 kilometres in a pipeline. With oxygen, there is no limitation in that way.”


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“You don’t have to start from scratch. You can use existing infrastructure,” he explains. However, because oxygen and moisture together create rust, Jonasson says developers must consider the corrosive potential SAGDOX could have on steel pipes and other infrastructure. “One of the main things we’re looking at is not injecting the oxygen and the steam within the same wellbore. We would have dedicated separate sites for oxygen injection and for steam injection,” he says. Another issue is the safety concern presented by handling pure oxygen in the presence of hydrocarbons, although complete oxidation should prevent explosions. Although SAGDOX is still in the very early stages of development and Jonasson does not expect to see a pilot any sooner than 2016, he says the process could be revolutionary for his company. “This could be a game-changing technology from the point of view that steam operating costs would come down dramatically. And because we do have a fairly cheap and reliable source of oxygen at the Long Lake site, we would be able to utilize that capacity for a number of phases of development.”

be stifled due to the condensation of steam, resulting in pressure loss. This is where the natural gas comes in—injection of a non-condensable gas will keep underground pressure constant. “If I were to think of it metaphorically, the non-condensable gas is really like an expanding balloon in the reservoir that keeps the pressure on the bitumen to keep it flowing to the wells, whereas with just steam, the balloon collapses over time,” Bellows explains. According to Bellows, the use of infill wells is proven to work fittingly with the eMSAGP process. “If you have a couple of pairs of the typical SAGD well, with the steam injector above and the producing well below, between those pairs there is a bit of a space, a bit of a sweet spot, where the bitumen has been mobilized by the heat but it doesn’t have a ready outlet. So, by putting a single well between two active well pairs, you’re

generation comes with a capital cost, so it helps on that front as well,” he says, adding that the company simply runs natural gas through the same wellbore as the steam with this process, so there is no additional underground infrastructure required for eMSAGP. “So far everything we’re seeing is win-win,” he says, adding the “trick” with eMSAGP is “hitting the right timing” for when gas should be injected into the well. “Typically, for instance, natural gas injection would usually be something producers would apply towards the end of a well life—maybe after six to eight years of operations when they’re really trying to re-pressurize the reservoir and get the last bit of recovery that is available. “But the thing we’re doing that is a little bit unusual is applying these technologies earlier in the well’s development to realize the efficiencies, as opposed to

“ I think there has been a little bit of resistance—no pun

intended—because of the unknowns associated with [radio frequency heating] technology, and frankly because there were a number of other technologies to meet the needs of the times. But times have changed.

FEEL THE PRESSURE Another company working on reducing steam usage while simultaneously increasing yields in SAGD operations is MEG. The company’s technology, eMSAGP, involves the addition of natural gas to maintain pressure underground. “I would characterize it as a very innovative evolution of some existing technology,” says Brad Bellows, director of external communications for MEG. The company introduced an eMSAGP pilot at the first phase of its Christina Lake oilsands project in January 2012, three years after the company started feeding the reservoir with steam. “We’re now expanding it this year to some other well patterns that are part of our Phase 2 project, and we are seeing results that are trending very similar to the very successful results we had on the Phase 1.” When a SAGD reservoir is at the stage of maturity where it has accumulated a lot of heat, production can

— John McTigue, co-founder and operations specialist, JR Technologies, LLC

able to use both the heat you’ve previously generated, as well as the pressure that comes with the non-condensable gas injection, to pull up more oil more quickly.” With eMSAGP, Bellows says, MEG is seeing production on par with, if not greater than, production from its SAGD wells, and with higher efficiency, reduced energy costs and fewer greenhouse gas emissions due to lower steam production requirements. An average SAGD operation uses three barrels of steam to recover one barrel of oil, Bellows says. However, with eMSAGP that payback ratio improves to just 1.5 barrels of injected steam to recover one barrel of oil. “So there is reduced energy requirement and there are also correspondingly lower requirements to make the steam generation from a facility and steam

just treating it as the means to get to the last possible remains of a resource.”

RADIO WAVES REPLACE STEAM Perhaps a bit analogous to placing a giant microwave oven in the ground, another burgeoning method of in situ production involves heating with frequencies along the electromagnetic spectrum. “It really targets the rotation of molecules, so the heating is on a molecular level,” explains John McTigue, co-founder and operations specialist for JR Technologies. A RFH field propagates through any medium—soil, liquid or gas—and tends to favour heating of organic molecular compounds, he says, and radio waves are preferable to microwaves, because they have broader wavelengths and can “reach out farther” within the targeted hydrocarbon-rich area—although it takes longer. n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2 013


TWEAKING THE PROCESS Richard Kerr, left, Nexen’s chief technology officer and inventor of its SAGDOX in situ production technique, and Hans Jonasson, Nexen project manager, use a project display to explain the inner workings and the benefits of the technology compared to the conventional SAGD process.

Ray Kasevich, co-founder and innovation specialist of electromagnetic technology for oil and gas recovery, explains, “Instead of heating up in a few hours, it might take a few days for a particular scenario, but the volume you’re heating with the radio frequency is so large as to make it economic.” He adds radio can cause temperatures as high as 400 degrees Celsius. According to Kasevich, there are very practical and environmentally friendly reasons for industry to embrace wireless transmission for in situ recovery: “No water is required. No chemical injections are required. No sand for proppant is required. You’re simply dealing with putting the radio wave into the ground through a borehole antenna system.” As for disadvantages, he says this hydrocarbon-heating process must be heavily engineered and controlled to 20

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prevent overheating. Further, the system requires on-site power and there is a natural inefficiency when it comes to power lost to producing electromagnetic waves. “When you’re using radio frequency, it takes some energy to convert from the utility frequency to the radio frequency. You might lose 30–40 per cent of your electric utility energy to make that conversion,” Kasevich says. The technology is currently used for environmental remediation, and there have been several pilot tests done in a variety of hydrocarbon scenarios. Currently, JR Technologies is working on a joint project with the Canadian government and several other companies as part of a carbon-reduction program. “The extraction of hydrocarbons from oilsands is very carbon intensive, so the Canadian government is looking for new technologies that will be more environmentally friendly to reduce the carbon footprint, and RFH is one of those under development right now,” Kasevich says, adding that the project has undergone preliminary testing and the pilot should begin in mid-2014.

“What they’re developing in Alberta is a horizontal system with a very long horizontal antenna—I think it’s an 80-metre antenna for the pilot. You generate an RFH field, which heats up the pay zone. In that particular application they’re looking at preconditioning the reservoir with radio frequency heating and facilitating extraction with a solvent.” According to McTigue, there are several other pilot projects planned to start within the next few months using shorter, vertical antennas for recovery of oil and gas from shale, as well as recovery of heavy oil from oilsands and other sources. “We really think that RFH has come of age, and [industry] will see it become a more conventionally used technology within the next couple of years,” he says. “I think there has been a little bit of resistance—no pun intended—because of the unknowns associated with the technology, and frankly because there were a number of other technologies to meet the needs of the times. But times have changed.”





producer well just as in conventional SAGD, followed with drilling the injector, creating vertical planes next to wellbore access, connecting the injector to the producer and going up to the pay thickness. “It will be about 2.5 to three centimetres wide, and be filled with a very permeable proppant, which is granite,” he says, adding the vertical planes are placed approximately every 50 metres along the SAGD well pair. According to Hocking, Azi-Frac could cut the SAGD steam to oil ratio in half and produce four to five times faster, assuming the planes are placed appropriately. However, he notes, the technology is not applicable for every formation. If there are strong rocks, for example, it will not work, as conditions must include weak cementation. Also, Hocking says, the process cannot occur near current steaming panels. “You’ve got to be some distance away, because the thermal stresses will upset what the process does,” he says. According to Cavender, X-Drain offers efficiencies over most other existing technologies and will provide access to uneconomical resources. Furthermore, he says, there are opportunities to increase recovery of heavy oil resources that have caprock limitations due to the higher steam pressure process in cyclic steam stimulation. EMSAGP VARIATION By injecting non-condensable gas along with steam, MEG’s eMSAGP process maintains constant pressure within the producing SAGD chamber. Infill wells, placed in between two active SAGD well pairs, speed up production by making use of both heat previously generated and the pressure provided by injection of non-condensable gas.


Low vertical permeability and interbedded mudstone layers aren’t the perfect situation for SAGD operations, but a system developed with funding from Halliburton through a joint collaboration agreement with GeoSierra will help companies produce through challenging geology. The technology, called Azi-Frac by GeoSierra and X-Drain by Halliburton, involves vertical, single-well SAGD with multiple producer wells. “Basically, by putting in these high-permeable planes we can virtually engineer around the geology,” explains Grant Hocking, president of GeoSierra. “So it can produce a lot faster, at a lower steam to oil ratio.” Hocking says Azi-Frac has not yet been employed in the oilsands, although he expects Halliburton to do so within the foreseeable future. Travis Cavender, project manager for the production enhancement business line at Halliburton, explains that the process involves a unique expandable casing system and placement of highly permeable vertical planes within weakly cemented formations. The current prototype system Halliburton is testing involves a vertical wellbore installation that targets shallow bitumen resources too deep to mine economically and too geometrically shallow for SAGD. “The placement process does not fracture the formation, but rather creates a planar inclusion which propagates a vertical fluidized plane, or series of planes, which

extends the wellbore radius for steam exposure and enhanced in situ recovery,” he says. Halliburton deployed the process in a vertical test well in 2012 and is ready for a steam pilot project to validate thermal reservoir modelling. “Once the proof-of-concept is validated, a commercial offering will be built which targets vertical installations in shallow bitumen, stranded and edge wells in conjunction with existing SAGD development assets as well as heavy oil resource plays, which have caprock pressure limitations using cyclic steam stimulation recovery,” Cavender says. “Commercialization will also include local specialty casing manufacturing and support to improve overall economics along with continued university optimization studies.” While the intent is for GeoSierra to eventually take its process to the Canadian oilsands as well, Hocking says for now his company will develop the technique in the United States—putting it in the field in Oklahoma in early 2014—as he waits for transportation bottlenecks and high prices associated with producing in northern Alberta to alleviate over the next couple of years. “The reason we’re going to Oklahoma is because it’s heavy oil and completely unconsolidated sand, and the market is right there to sell it,” he explains. If proven successful, Hocking believes the technology will become incredibly popular in a relatively short time frame, because there is “big upside potential” for oil companies. He says placing Azi-Frac technology in a horizontal well involves drilling the

n E w T E c h n o Lo gY m Ag A z i n E | S E P T E m B E R 2 013


Technology revolutionizes Canada’s oil & gas industry Each year, New Technology Magazine conducts a search for the most revolutionary technologies and the individuals who created them. Technology Stars is the only competition in Canada to recognize innovative technology in the oil and gas industry. The competition is open to any company that operates in Canada and deploys its technology here. Entering is easy. Simply fill out the submission form on New Technology Magazine’s website. All submissions will be reviewed and the winning Technology Stars will be featured in the November issue of New Technology Magazine. Technology Stars categories include: ★ ★ ★ ★

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Small independent companies vie with majors in a quest to end ponds’ proliferation By Godfrey Budd



eclamation and remediation of oilsands tailings ponds has begun receiving increased priority from industry and government alike. At the same time, the quest for an effective suite of technologies to address the issue has intensified. Growing concerns around potable water sustainability in Alberta as a whole, and declining flows of the Athabasca River, in particular, might assist in speeding things up. Reclamation budgets are on the rise, with Syncrude Canada Ltd., for example, upping its annual spending in this area from $15 million in 2003 to $150 million in 2010. In February 2009, Alberta’s Energy Resources Conservation Board (ERCB), which has now been replaced by the Alberta Energy Regulator (AER), issued Directive 074. The ERCB said its directive was issued in order to slow the growing volumes of tailings and the proliferation of tailings ponds.

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“The directive requires a fundamental shift in operators’ approach to tailings management: operators must commit resources to research, develop and implement fluid tailings reduction technologies, and tailings management and progressive reclamation must become operational priorities that are integrated with mine planning and bitumen production activities,” according to a June 2013 tailings management report from the ERCB. Under the directive, four of the existing six mining operations in the Fort McMurray region were supposed to meet performance targets for fines tailings capture. The requirements were based on the commitments that operators made as part of their tailings management plans. The first two periods covered by Directive 074, 2010-11 and 2011-12, applied to Suncor Energy Inc., Syncrude Mildred Lake, Shell Muskeg River and Shell Jackpine. (The Syncrude Aurora North and CNRL Horizon projects were not required to capture fines.) Although one operator, Syncrude, exceeded cumulative tailings capture requirements for the total time frame, 2010-12, for the reporting period 2011-12, the company had a lower-than-expected 24

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FEWER PONDS Suncor, which is sharing its TRO technology with industry partners, has said that its new approach has already allowed it to cancel plans for five additional tailings ponds. “In the years ahead, we expect it will help us reduce the number of tailings ponds at our current mine site from eight to one, allowing us to reclaim entire mine sites in about a third of the time it now takes,” said the company’s 2011 TRO update. The company cited problems with fluid tailings recovery equipment, problems with flocculant dosages and colder-than-expected weather among the factors that prevented the company from hitting its tailings capture targets in the period from 2010 to 2012 under the ERCB’s Directive 074. Before using TRO, Suncor used three main types of tailings technology: regular tailings (RT), densified tailings (DT) and consolidated tailings (CT), according to a paper by Suncor engineer and

reclamation specialist, Melinda Mamer, at the University of British Columbia’s cIRcle digital repository for research and teaching materials. “RT are simply the combination of sand, fines and water pumped to holding ponds called ‘tailings ponds.’ No additional treatment is used for RT, ” states the paper. In the DT process, the regular tailings are “cycloned,” which causes additional fines to be separated from the tailings. The overflow from the top of the cyclone consists of water and fines, while the underflow consists of sand, water and residual fines. CT technology involves the use of tailings sand, gypsum and mature fine tailings, or MFT, to form a non-segregating slurry, which is discharged into a tailings pond to form “a rapidly consolidating, soft, cappable deposit capable of meeting various land uses and landscape performance goals,” according to a 2010 review of available tailings remediation technologies. In a tailings pond, the water, sand, silts and fine clay particles and residual bitumen will settle into layers over time. Water is at the top, then thin fine tailings (TFT), which over about three years consolidate to MFT. Sand quickly sinks to the bottom to form a fourth layer. The TFT and MFT consist of particles of less than 44 microns in diameter and water—more than 30 per cent for TFT. MFT have a lower water content, around 30 per cent. Eventually, the MFT will consolidate to denser material, but experts say the process can take decades, so some efforts have focused on accelerating consolidation of MFT. The current state of knowledge includes a good number of technologies for tailings pond remediation. A 2010 report by BGC Engineering Inc. for the Oil Sands Research and Information Network reviewed 34 existing technologies, dividing them into five groups: physical/mechanical processes, natural processes, chemical/biological amendments, mixtures/co-disposal and permanent storage. The 144-page paper, Oil Sands Tailings Technology Review, concluded: “There is no single method of dewatering that works for all tailings. Similarly, experience has shown that there is unlikely to be one unique solution to the problem of tailings disposal.”

AND THEN THERE WERE 101 In August 2012, COSIA released an ambitious tailings technology road map. The multi-volume document identified 549 technologies for tailings remediation.


ENHANCED BITUMEN RECOVERY Targeting bitumen contained in waste streams, RJ Oilsands developed a technology that aerates the slurry stream with a gas that breaks into small bubbles that can attach to bitumen particles and cause them to float upwards.

fines capture. The other three operators fell short of their target requirements in both reporting periods. “The commercial implementation of tailings management technologies will take longer than expected and performance will be lower than expected until operational problems are resolved,” concluded the ERCB report. It noted, however, that the companies had made progress in fines capture technologies. Each operator has its preferred technologies for tailings reduction, but, as the report notes, most of them to date are based on the principle of mixing fluid tailings with chemicals, additives or flocculants to promote dewatering and deposition of the mixture in a way that allows it to consolidate and to form a solid. Suncor captures fines by combining fluid tailings with flocculants and depositing the mixture in thin lifts, or layers, to allow for dewatering and drying under ambient conditions. In the summer of 2010, Suncor ramped up implementation of its proprietary tailings reduction operations (TRO) technology to take advantage of the warmer peak drying months. “Suncor’s thin lift drying involves taking FFT [fluid fine tailings], adding flocculant and discharging [the mixture] onto drying beds. This allows for evaporation, but is only for the summer months,” says Alan Fair, executive director of Canada’s Oil Sands Innovation Alliance (COSIA).



“With refinement, these were reduced to 101 unique technologies,” says the executive summary of volume 2 of the road map. Some of the technologies in the road map are more experimental, or have yet to show their scalability for oilsands applications. But Fair believes that some technologies from third-party providers show promise. One technology, from Gradek Energy Inc., involves a patented (U.S. awarded, but pending in Canada) process using beads to recover hydrocarbons. The aim of the technology is to recover bitumen from tailings. “It was initially developed as a spill response technology and has been used for remediation since about 2000,” says Robert Andrews, senior vice-president for business development at Gradek. In its oilsands application, he says, the warm slurry of sand, fines and clays, small adhering bitumen particles and water, which remains after extraction, is mixed with cold MFT to form a further slurry that is fed into a mixer along with special oleophilic beads. “The bitumen in the slurry attaches to the beads. The fines typically settle very slowly as the bitumen that’s attached makes the fines ‘float.’ After the beads are separated from the mixer, they are dropped into a washing system that uses naphtha,” says Andrews. After raising funds from private sources to test its oilsands technology, Gradek ran a demonstration project near Montreal over the past year. Management at the firm expects to hear the results of an engineering audit of its technology any day. If things pan out, Gradek’s concept could be beneficial in a couple of ways. “Our project has a waste heat recovery component to it, as the water that’s returned is still quite warm. Also, 65 per cent of the water in the slurry is recycled. This results in emissions reduction because the operator will then need less energy to heat water,” Andrews says. Another technology also looks set to become an oilsands profit stream—if it gets used. The system, from Titanium Corporation, was rated by COSIA as one of the top 20 most promising technologies in its road map, says Jennifer Kaufield, the company’s chief financial officer and

“ [mature fine tailings] and water, and

We’ve taken a slurry stream of

with no heat, just tailings, can remove 95 per cent–plus of the bitumen consistently, under normal operating conditions.” — Wade Bozak, vice-president and technology lead, RJ Oilsands Inc.

vice-president of finance. The technology is designed to separate the sands and fines from the attached bitumen and valuable minerals. In the Titanium process, the waste slurry, soon to be tailings, is instead intercepted after froth treatment and divided into two streams—one with larger sand particles, over 44 microns in diameter, and the other composed of the smaller fines. “Because of size [differences], slightly different processes are needed,” says Kaufield. Titanium’s patented process uses highvolume technologies, including cyclone, flotation, counter-current decantation and steam stripping. The Alberta government provided $3.5 million for research and development and the federal government

contributed $6.3 million towards commercialization. A plant to operate Titanium’s system of mineral and bitumen extraction from the waste stream would cost between $350 million and $450 million to build and have operating costs of around $50 million per year. The company has estimated that revenues from a single mine site would be around $200 million per year. Payback would take about three years.

COST RECOVERY With technology that effectively removes oil from tailings—which contain a quarter-barrel of recoverable bitumen per cubic metre of mature fine tailings—RJ Oilsands says the sale of bitumen can offset the cost.

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WASTE STREAM RECOVERY A technology targeting mostly bitumen from waste streams was developed by a team at RJ Oilsands Inc. “The focus was to do enhanced oil recovery from waste streams, that is, EOR,” says Wade Bozak, vice-president and technology lead at RJ Oilsands.

that the sale of incremental bitumen could offset costs of bitumen recovery and naphtha stripping from tailings. “Every cubic metre of MFT in the tailings ponds has a recoverable quarter barrel of bitumen,” he says. That could mean a lot of extra oil. COSIA’s Fair says that there are about 900 million cubic metres of fluid fine tailings and MFT in the tailings ponds. Although Bozak still has his fingers crossed on prospects in the oilsands, RJ Oilsands has commercialized and is using its technology to augment a polymer flood and recover 8,000 barrels per year, “that was previously being lost,” Bozak says. Filtration is another proposed method of dewatering tailings. Draintube, from AFITEX-TEXEL Geosynthetics Inc., is “a drainage geocomposite consisting of two or three layers of geotextile layers comprised of short synthetic fibres of 100 per cent polypropylene (PP) or polyester, which are needle-punched together,” according to a company brochure. A series of special PP pipes, with corrugations and perforations, lie between the two textile layers. The system, used in Europe for over 25 years, can replace sand-based or gravel filtration—with the advantage of greater portability.

CATCH AND RELEASE When mixed with tailings slurry, Gradek’s oleophilic beads attract bitumen that attaches to their surface. They are then put through a washing system using naphtha to separate the bitumen from the beads, which can then be reused.

As waste slurry enters a separator, it is aerated with a gas, which, because of the pressure within the separator, breaks into small bubbles that can attach to bitumen particles and cause them to float upwards. “The gas bubbles in the stream only stick to the oil fraction, not the solids, not the water. We’ve taken a slurry stream of MFT and water, and with no heat, just tailings, can remove 95 per cent– plus of the bitumen consistently, under normal operating conditions,” Bozak says. A better oil and water separator is the key to the system, he says, noting that the company’s MFT remediation technology removes oil and strips naphthenic acids from the water and solids. Bozak believes 26

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Pascal Saunier, AFITEX business development director, North America, points to a couple of ways it could be used in tailings remediation: “You could use it at the base of the pond to collect water from the tailings, instead of sand or gravel. It could also be placed in layers within the pond. The geotextile with pipes could carry away the water faster than just at the bottom of the pond. The idea is to speed the drainage. There could be five or more layers [of Draintube

filration]. It could reduce the distance water has to travel to a drainage point.” The company is working with COSIA to develop a product that is tailored for the oilsands, and a three-year research and development project should be complete in 2015. “We’re doing a pilot with an operator. We’ve demonstrated good results. We’ll adjust the technology depending on the type of tailings,” Saunier says.

TANGENTIAL FILTRATION Another filter technology, cross-flow filtration (CFF), was advocated in a paper by two civil and environmental engineering professors at the University of Alberta, and presented at a conference in Edmonton in 2008. In CFF—tangential filtration, as it is also known— the feed is passed across, not through, the filter membrane. CFF technology has been used widely in industrial processes for small particles and has the potential advantage of a higher overall liquid removal rate in a continuous process, due to the absence of filter cake buildup and blockage. As in many other industrial processes, CFF, in its oilsands incarnation, would pass the slurry along a special pipe, which contains filtration and perforations around its circumference. “The idea is to create a non-segregating tailings, and eliminate future formation of MFT. This way, you take the water out before MFT forms,” says Dave Sego, one of the authors of the paper, and president and chief executive officer of Inline Dewatering Ltd. Like some of the other technologies proposed by third-party vendors, it holds out the promise of saving the operator money as well as solving a problem. “Its advantage is that water taken out is still hot and can be reused for the plant and reduce greenhouse gas,” Sego says. Inline Dewatering has received some $3 million in funding from government and industry to conduct more lab studies in 2013-14 and, in 2014-15, a field pilot at an oilsands mining site. “It will be followed by a larger demonstration at a later date but this is not presently funded,” Sego says. One technology that lacks the pennypinching attributes of some of the thirdparty vendor technologies involves centrifuges. They are expensive, says Fair, but they will definitely do the job. Syncrude has been running pilots since 2007 and launched a commercial-scale demonstration last year. A $1.9-billion, full-scale commercial plant is scheduled to start up in 2015.


Companies like Titanium that envisage generating revenues from waste streams belong in a different category from a mining operator like Suncor or Syncrude and should, accordingly, have a different royalty regime, it has been argued. “The Alberta government is working on a fiscal framework that would address resource recovery from waste bitumen mining streams,” Kaufield says.




Refined Tastes Technology for proposed B.C. refinery has potential to significantly reduce the carbon footprint



ne doesn’t have to look hard to find evidence that Canada’s oilsands are under pressure to reduce their carbon footprint—opponents of bitumen production are doing everything from protesting pipelines to chaining themselves to the White House fence. Critics note that high amounts of greenhouse gas (GHG) emissions and waste per unit of production make it “dirty oil.” Much of the criticism centres around how bitumen is processed. Traditionally, upgraders in the oilsands use coking technology to separate valuable hydrocarbons from unwanted heavy carbon molecules. Operators start by removing the higher-end hydrocarbons, then put the remaining bitumen into a large pressure cooker, or coker. They heat it to 900 degrees Celsius and drive off the rest of the recoverable material, leaving coke, a dark, coal-like substance. The process is energy intensive, producing large amounts of GHGs, and operators

are left with the coke residue, which represents approximately 15 per cent of the original bitumen. A Calgary-based firm has come up with a heavy oil and bitumen refining technology that has the potential to significantly increase production rates while at the same time reducing GHGs and coke residues. “The core to Expander’s technology is our Enhanced Fischer-Tropsch [EFT] process, which is the conversion of carbon sources into high-value synthetic fuels,” says Jim Ross, chief executive officer of Expander Energy Inc. “All our processes retain and convert carbon within the system, virtually eliminating low-value/waste products and significantly reducing GHG emissions by over 80 per cent.” Expander Energy was initially formed in 2001 to explore ways of turning waste heat into energy. The company expanded into turning biomass into energy through the gasification process so that forestry, municipal solid

UPGRADING THE UPGRADER Expander’s technology combines a synthetic gas generator, or gasifier, with its Enhanced Fischer-Tropsch process to upgrade bitumen to high-quality synthetic fuels.

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waste and other waste products could be recycled. The gasification process combines carbon-rich feedstock with oxygen under controlled conditions in order to create H2 and CO (syngas). The syngas in turn is converted to synthetic diesel using the Fischer-Tropsch (F-T) process, which uses catalysts to combine the syngas into linear paraffinic molecules, such as synthetic diesel. “Paraffinic diesel is the best type of diesel you can get,” says Ross. “Standard diesel has a Cetane rating [the quality of combustion under compression ignition] of around 40. Our synthetic diesel has a rating of up to 80, and there are no sulphur emissions or aromatics to cause soot.” Expander worked with a European technology firm to create systems that could operate at a biomass source, producing synthetic diesel in the 750-barrelper-day output range. “We found that we couldn’t make enough F-T liquids to make economic returns,” says Ross. “We needed to figure out a way to produce more diesel from the biomass.” One of the problems of the gasification of biomass is that it discharges large amounts of carbon as CO2. “The most efficient ratio of H2 to CO is 2:1,” says Steve Price, president of Expander. “But the biomass derived syngas had a ratio of about 1:1.” Operators can use a water/gas shift process, in which the CO is combined with steam in the presence of a catalyst to create more H2, but 30–40 per cent of carbon still ends up as CO2. “If you want to use all the carbon available, you have to either buy extra H2, or make your own.” 28

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Adding extra H2 into the F-T process was the first step toward Expander’s first patent—the EFT process. The second step was to recycle the uneconomic or small volumes of F-T liquids. “The F-T process produces an array of hydrocarbons, from waxes to light liquids other than diesel,” says Price. “When you have a large F-T plant like those that Sasol [Limited] or Shell [Canada Limited] operates, you end up with sufficient quantities to justify associated chemical manufacturing. But with our smaller-scale processes, these side products are uneconomical to deal with. Our idea was to use a steam methane reformer to turn natural gas into H2 and convert all the carbon-containing off-products to diesel through a recycle loop. With the original biomass process design, we were turning out 700–750 barrels per day of synthetic diesel. With the EFT process, we can increase output to 2,000–2,500 barrels per day.” “The increased output was a game changer,” says Ross, noting that a biomass facility costs around $300 million to build. “You could significantly more than recover your capital costs and operating expenses.” When the European technology provider went out of business in 2011, Expander shifted its focus to converting natural gas to liquid fuels in North America. “Natural gas was cheap, under $3 per thousand cubic feet, and it made sense to convert it to diesel,” says Ross. “We did the engineering work, and realized that the more carbon you converted, the better the economics became.” Their research led them to examine other sources of carbon. “When you refine crude oil, you end up with a certain amount of residue, either petroleum coke or asphalt. The heavier the crude, the greater the amount of residue,” says

Ross. Rather than viewing “the bottom of the barrel” as an unwanted by-product, Expander saw it as a significant source of carbon. “Heavy oil and bitumen were ideal for a feedstock.” Although Ross and Price have extensive experience in financing, designing and operating oil and gas facilities, they contracted with Colt Engineering (now WorleyParsons Canada) to do engineering and design work. In 2012, Steve Kresnyak joined Expander as chief technology officer and was instrumental in additional engineering/design work. Their combined research and development resulted in Expander’s second major patent: the FTCrude process for heavy oil and bitumen upgrading. FTCrude uses extra H2 to ensure that all the carbon products created in the F-T process are recycled into synthetic diesel. A traditional 100,000-barrel-per-day upgrader produces about 82,000 barrels per day of synthetic crude, while Expander’s FTCrude process produces 125,000 barrels per day of equivalent product, thanks to the extra H2. “And gasification and F-T are exothermic, so you can convert that heat to electrical power, enough to operate the facility and feed to the grid,” says Price.

KiTimAT cLEAn In 2012, David Black, chairman and founder of Black Press Group Ltd., announced his intention to build Kitimat Clean Ltd., a refinery in Kitimat, B.C., that would convert bitumen in the proposed Northern Gateway pipeline to fuel for export. A privately held community newspaper and printing company headquartered in British Columbia (80 per cent owned by the David Black family and 20 per cent by Torstar Corporation), Black Press publishes more than 150 daily and weekly newspapers. Expander contacted Black and presented their new technology. Black was


CARBON MANAGEMENT Expander’s FTCrude process enhances gasification and Fischer‐ Tropsch technology by managing and retaining carbon within the system, eliminating low-value by-products of petroleum coke and heavy oil residuals.


immediately intrigued. “We completed the preliminary design work for a standard coking heavy oil refinery,” he noted on the official Kitimat Clean website. “It was going to be the cleanest and greenest refinery in the world to meet Canada’s emission standards. We have now decided to change the configuration to make it even cleaner.” Black made the decision to adopt F-T over coking technology. “An innovative Calgary company, Expander Energy, has recently patented a new approach to processing heavy oil. We will be the first in the world to use it. Our consultants estimate Fischer-Tropsch will increase our capital costs by $3 billion. But it will decrease greenhouse gases per barrel by 50 per cent. Our refinery will now be much cleaner than any other heavy oil refinery in the world.” Black called in Glenn McGinnis, president of Pegasus Quality Consulting, a Calgary-based consultancy specializing in oil and gas refinery processing. The chemical engineer had already been working with Black on various aspects of his proposed refinery, including scope, preparations and processes, and was interested to see what Expander had to offer. “At first, I was a little skeptical, because it wasn’t a traditional refining process, but the more I looked at it, the more logical it became,” McGinnis recalls. “It’s not new technology, but a unique way of putting together licensed technologies to take maximum advantage of a heavy oil resource. You are combining high-carbon heavy oil with high H2


Production (million barrels per day)

“All our processes retain and convert carbon within the system, virtually ELIMINATING LOW-VALUE/WASTE PRODUCTS and significantly reducing [greenhouse gas] emissions by over 80 per cent.” — Jim Ross, chief executive officer, Expander Energy Inc.

natural gas so that there is no residual carbon content left. This synergy is especially attractive in western Canada, where you have a large supply of heavy oil and bitumen and low-priced natural gas. It really makes sense and has a lot of potential under these circumstances.” In addition, Expander is in discussion with refiners and upgrader operators throughout North America. “We’ve been talking to people in Alberta and eastern Canada and the U.S.,” says Ross. “There is a lot of interest.” Expander acknowledges the significant challenges to widespread adoption of the technology. “There’s the traditional point of view of ‘If it ain’t broke, don’t fix it,’” says Ross. But pressure is mounting to clean up Alberta’s oilsands. Since 2007, the province of Alberta has had legislation requiring large GHG emitters to reduce the intensity of their emissions per unit of production by 12 per cent, or pay $15 per tonne to a dedicated technology

fund for the amount they fall short of that requirement. In the last six years, the fund has collected $300 million, and there is speculation that the cost may rise to $30 or more in the near future. “New technologies such as ours can significantly reduce CO2 emissions,” says Price. While Alberta legislation won’t affect the proposed refinery in Kitimat (British Columbia has a carbon tax on fuel consumption, but not emissions), Kitimat Clean is still gung-ho. “The new design will be far better for the environment than what we had envisioned,” Black notes on his website. “As my daughter said, ‘Dad let’s keep this refinery in our backyard so we can build it right and help look after the planet.’ If we work together, we can do just that.” Gordon Cope CONTACT FOR MORE INFORMATION Jim Ross, Expander Energy inc. Tel: 403-475-4146 Email:

Bitumen production forecast/CO2 emission forecast

CO2 emissions (millions of tonnes per year)
























A GREENER PATH Expander Energy estimates its technology could trim CO2 emissions from upgrading Alberta’s oilsands by 80 per cent (indicated in green) while increasing production of synthetic crude by 20 per cent (shown in red).


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Surfactant Solution Oilsands operators are hoping additives will help boost thermal in situ recovery rates


here’s a new kid on the block as the operators of thermal oilsands projects look for new ways to wrest more bitumen out of their reservoirs. While solvent injection has been more commonly associated with steam assisted gravity drainage (SAGD) projects, at least two major producers have also been checking out surfactants—additives that operate much like familiar household products such as soaps and detergents. By injecting surfactants into the reservoir along with

River site since last year. Now, after nearly five years of research, Cenovus Energy Inc. is eyeing its first surfactant trial this fall at Christina Lake. “We see the use of surfactants as being a benefit to Suncor,” Cal Coulter, director, subservice technology and development, says in an email. “It’s a good example of a small technology that will make a big difference in our operations.” Using surfactants at in situ operations will immediately benefit the operation in terms of more efficient

some implementation at our in situ sites by 2014,” he says. While some surfactants are similar to existing household products, others are being developed specifically for the SAGD project. “We’re really working to find what’s going to work best with the resource and geology subsurface,” Coulter says. “Testing will help us narrow down which surfactant best works with our resource.” Suncor also believes that a combination of surfactants may be needed through the different stages of a development.

EARLY STAGES Suncor, at its MacKay River oilsands project, above, and Cenovus have recently begun testing surfactants as a new way to improve in situ oilsands production.

steam, producers could help lower interfacial tension and create a more efficient method of separating bitumen and water. The companies emphasize that it’s still early days, but, if successful, the payoffs could include improved project economics along with a smaller environmental footprint. Suncor Energy Inc. has been testing the use of surfactants at its MacKay


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oil recovery, but it will also decrease energy and water use with minimal associated cost and environmental footprint, he says. Suncor also hopes to reuse the surfactants, which will provide an additional environmental benefit. “It will be produced back in the steam once it has come back to the surface, where there is a potential to strip it out and use it again,” Coulter says. Currently, the company is testing multiple products for use as surfactants in order to determine what will work best with what’s going on subsurface. “Tests are going well, and we can expect to see


TRiAL RUn “Surfactant use is still in the very earliest stages in SAGD,” says Khalil Zeidani, staff reservoir engineer at Cenovus. And while surfactants have been used in conventional oilfields for many years, “it is very different in SAGD,” he adds. The company, which has a patent pending on its surfactant steam process (SSP), conducted simulations using an in-house built simulator. The laboratory work was done at a thirdparty lab at Cenovus’s request, and now the company is ready to take it to the field, according to Zeidani. His group has proposed an SSP trial for one of the 12-well SAGD pads at Christina Lake, and he hopes to begin this fall. In the trial, surfactant would be co-injected into two wells with all or some of the remaining wells serving as controls. “Selection of the surfactant is key in this process,” he says. “It is very, very important.” In doing so, the operator needs to be able to answer questions such as whether the surfactant can be vaporized at reservoir (steam) conditions and not degrade when exposed to steam at high pressure. “Within the reservoir, there are a lot of issues such as salinity, and you have to have a surfactant that is compatible with the reservoir water and also the rock,” Zeidani says. He highlights two key qualities in a surfactant: obviously, it should have lower costs than others, but it


should also ensure oil and water can be separated in a hassle-free manner once they come to the surface. Some surfactants could be emulsifiers, and, if not designed properly when injected into the reservoir, could be “a nightmare for people to have to deal with,” Zeidani says. Cenovus anticipates that when the surfactant that it has selected for the test comes back to surface, it would help the facility by reducing the need for demulsifier to separate the oil and water. The ultimate solution would be to have a demulsifier that could be injected into the reservoir. “Let it help your oil drain faster, cleaner, and when it comes back to the surface it is already in the process and is helping you separate the oil and water,” he says. “There’s no need for surface separation of surfactants.” While solvents get into the oil and clean it out, surfactants act quite differently, according to Zeidani. They have two parts, like a head and a tail. One loves oil and the other loves water, so they try to interact like a medium

“What we have now is that STEAM COMING UP AGAINST ‘TAR,’ and it melts one molecule at a time because it can’t penetrate. If there is a surfactant, it can grab in and get a little bit deeper into that boundary.” — Laureen Little, principal, Vantage Energy Consultants Ltd.

between them right at the surface between oil and water. “The surfactant is dissolving the oil, it slips through the interface between oil and water, and it makes the oil slide easier down towards the producer,” he says. Although caution is still needed, Zeidani sees surfactants having the same potential as solvents in thermal projects. “If you are using the right kind of surfactant for the right conditions for the right reservoir, then overall I think

it will improve the project economics quite a bit through different methods,” he says. “For example, it accelerates your oil rate, which improves your net present value of the project. You are producing the oil faster. It washes the reservoir to a greater extent and ultimately produces more oil, the ultimate oil recovery factor—more oil from the same reservoir.” In a paper co-authored with Subodh Gupta, chief of technology development

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PUT TO THE TEST Suncor is testing multiple surfactants at its MacKay River steam assisted gravity drainage facility, located 60 kilometres northwest of Fort McMurray, to determine which works best for that project’s subsurface conditions.

at Cenovus, Zeidani reported on a lab test where four surfactants were used on typical Canadian oilsands sand packs. The results showed an improved incremental oil recovery factor in the range of six to 16 per cent compared to a SAGD base case. In SSP simulations, he used one of the mid-point surfactants from the test and the results were very close to those achieved in the lab. The simulation results indicate that this particular surfactant accelerated the oil rate by 15 per cent on average in the first 30 months of SSP operation, increased the ultimate oil recovery factor by 10 per cent and reduced the cumulative steam to oil ratio by nearly 11 per cent relative to a SAGD base case.

mAKing conTAcT Calgary engineer and consultant Laureen Little agrees that thermal in situ operators will be looking for new ways to get their bitumen to surface as Alberta’s “easier” reservoirs are


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drained. She has also been studying the possibilities of surfactants. “There are certain reservoirs that are just extremely’s really hard to get contact between steam heat and the oil,” says Little, the principal of Vantage Energy Consultants Ltd. “You need some flow path for it to get in there so those tighter, harder reservoirs are likely where we will start playing with surfactants again.” A paper co-authored by Little and presented at GeoConvention 2013 suggests a better alternative to solvent addition. Why not use biodiesel (fatty acid methyl esters) with steam as a surfactant additive? “What we have now is that steam coming up against ‘tar,’ and it melts one molecule at a time because it can’t penetrate,” she says. “If there is a surfactant, it can grab in and get a little bit deeper into that boundary.” Baki Ozum, owner of Edmontonbased Apex Engineering, Inc. and coauthor of the paper with Little, says his company has been researching for a decade whether SAGD process efficiency could be improved by reducing the bitumen-water interfacial tension. His research team has speculated that bitumen recovery is the

result not only of gravity drainage, but also the mobility of bitumen in a relatively narrow zone at the edge of the steam chamber where bitumen, water and steam flow together. In this zone—predicted at 10 and 40 centimetres based on conductive heat transfer calculations—reduction of the interfacial tension should promote bitumen mobility, he says. Steam-assisted bitumen recovery tests at the Apex laboratory were performed at typical reservoir pressure conditions of 200 degrees Celsius and 1.4 megapascals of pressure to evaluate the performance of biodiesel and solvent (pentane) as steam additives in bitumen recovery efficiency. The produced and residual bitumen were determined and used to calculate recovery efficiencies. “The results suggest that surfactants may be superior to solvents as additives in SAGD,” the authors conclude. The addition of less than two grams of biodiesel per kilogram of bitumen resulted in a significant increase in bitumen recovery in the lab. Experiments also showed that the higher the percentage of pentane in the steam, the lower the recovery rate. Elsie Ross





Operators Get A Welcome Lift New “one-eyed” electronic sensor cracks North American plunger-lift market



lthough fairly low profile in Canada’s oilpatch, plunger-lift systems are nonetheless key to keeping many of western Canada’s producing natural gas wells running smoothly. At their most basic, plunger-lift systems remove the liquids that build up in producing gas wells. Especially in older wells, water in particular can build up and slow gas production. As wells age, water output often rises, underscoring the importance of controlling it as gas production tapers off. In most plunger-lift systems, the plunger drops like a rock to the bottom of the well early in the lift cycle. As gas is produced downhole, however, it generates pressure, enough eventually to push the plunger and the column of water above it to the surface, where gas and water are separated. The cycle is

then repeated, allowing gas production to continue. Plunger-lift works because the pressure created by incoming gas downhole is sufficient to clear the well of produced water. Key to the successful working of plunger-lift systems is a device called the plunger-arrival sensor. Located at the surface, it tells the lift system’s “brain” when the plunger has returned from downhole. For most purposes, the plunger is what the arrival sensor was designed to recognize. While just a part of the plunger-lift system, the arrival sensor’s proper functioning is critical to the whole system. If the sensor can’t see the plunger, the system fails, and if the sensor misreads what it sees, the system also fails, often shutting down the well—and gas production—at least for the time being.

SELECTIVE SENSOR Incorporating a modern magnetic sensor chip rather than a traditional coil, Extreme Telematics’ Cyclops plunger-arrival sensor is sensitive enough to avoid false or missed plunger arrivals.

According to Extreme Telematics Corp. (ETC), a Calgary company marketing a new plunger-arrival sensor of its own, many sensors now on the North American market either fail to see the plungers they’re designed to detect, or see them when they’re not actually there, in either case causing needless production interruptions and delays. Industry insiders have terms for what occurs when plunger-arrival sensors fail. Operators talk, for example, of false arrivals and missed arrivals, something that, to many Canadians, might sound like the talk at an airline ticket counter. Instead, it’s a way of saying the

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BUILT-IN FLEXIBILITY The Cyclops’s magnetic sensing eye is capable of detecting a plunger-lift system’s plunger even when it does not fully travel past the sensor, allowing for a wider range of mounting locations.

plunger-arrival sensor has malfunctioned, either not seeing or misreading the plunger’s movements. A false arrival is plunger lingo for what doctors would call a false positive, meaning the sensor signals the plunger’s arrival when it’s not actually there, much the way a medical test might indicate that a patient is sick, when he’s not. A missed arrival, on the other hand, means the sensor did not see the plunger, when in fact it passed right by. For well operators, the fallout of such sensor misfires adds up over time and can be costly, since gas production is often interrupted or delayed. (Typically, the well is shut in.) In addition, sensor misfires often mean an operator must drive out to 34

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the wellsite to fix the problem. Avoiding it is another matter altogether. Until recently, most plunger-lift systems in western Canada relied on coil-based sensors to detect the plunger as it returns to the surface. Yet those sensors have their issues, according to Mark Scantlebury, the electronic systems engineer who is also ETC’s president and chief executive officer. “There’s a lot of variance in [coilbased] sensors,” he says. “You can have different coil winding and the wire can vary in resistance or thickness. You’re really dependent on things like plunger speed.... If the plunger comes up and stops before it gets there, or goes by too quickly, it won’t cause current in the sensor’s coil [and will go undetected].” If the plunger is not detected when it arrives, the system’s controller will put the well into recovery mode, which will hurt production. If a well has missed or false arrivals, it will adversely affect the

well’s production, he adds. Scantlebury says ETC’s new plunger-arrival sensor, Cyclops, is a better solution. On the market for just under a year, the device is not coil-based, and more accurately senses plunger arrivals, he says. “Ours is a magnetic field sensor, and we don’t have a coil at all. We have an integrated circuit, a microchip that looks at the magnetic field of the earth. As an [iron-bearing] object moves in front of [our] sensor, it warps the magnetic field of the earth, and we look at that warping,” he says. With Cyclops, the user can adjust how the plunger is read by the sensor, allowing for variables that effectively make Cyclops more sensitive and flexible than coil-based sensors, he adds. For example, simply adjusting a dial can change the unit’s sensitivity. In this way, the user can adjust for the iron-content of the plunger, or for the use of nonferrous plungers. “There are many more options now,” he says. Since mid-2012, some Canadian oil and gas producers have used Cyclops on plunger-lift systems on wells in western Canada. The group includes ConocoPhillips Canada, which installed it on some gas wells in southeastern Alberta, east of Drumheller, in July 2012. Some of the wells were drilled on a ridge above the Red Deer River Valley,


EXTREME DESIGN Cyclops sensors are protected by a rugged watertight aluminum enclosure filled with hardened epoxy, allowing them to operate reliably in extreme conditions.


relatively high up in terms of elevation. As a result, the wells, which previously relied on plunger-lift systems using coil-based sensors, were right in the line of fire when summer electrical storms rolled in, as they often did, according to an employee of ConocoPhillips’s optimization group. “I’ve stood on that ridge and watched the storms come in, then watched the wells go down,” says Kelly Mason, an optimization technician who handled three long-life gas wells producing one to three barrels per day of water. Recalling the lightning strikes, he notes that, to knock a well offline, there didn’t have to be a direct strike on or even near a well. “The lightning could be within a half-mile or mile,” he says. “There wasn’t a lot of rhyme nor reason.” In tackling the problem, the company tried several things, including electrically isolating the coil sensors from everything around them. “We also tried adding diodes to the plunger-arrival sensor’s circuit [and] changing our software to work around it,” he says, noting none of these fixes worked and the problem continued.

“We have an integrated circuit, a microchip that looks at the magnetic field of the earth. As an [iron-bearing] object moves in front of [our] sensor, it WARPS THE MAGNETIC FIELD OF THE EARTH, and we look at that warping.” — Mark Scantlebury, president and chief executive officer, Extreme Telematics Corp.

Apart from causing lost or delayed production, the frequent well shutdowns consumed the time of operators called out to check the wells and get them producing again. Later, at an oil and gas trade show, Mason heard ETC would be rolling out a new plunger-arrival sensor, and asked the company to call him when it had Canadian Standards Association certification, which it did. In July 2012, the new product was installed on three of the wells Mason was responsible for. Since then, “we’ve had zero lightning-driven early arrival [shutdowns] on

those wells,” he says. The response from colleagues in the company’s optimization group was also positive. “The feedback was the same: [the sensors] have eliminated the problem and they’re working great.” Today, Mason estimates Cyclops sensors are installed on roughly 40 ConocoPhillips gas wells in western Canada. James Mahony CONTACT FOR MORE INFORMATION mark Scantlebury, Extreme Telematics corp. Tel: 403-290-6320 Email:

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Accelerating Radio Frequency Technology Innovative simulation software could lead to greener oilsands production


t takes a lot of energy to separate bitumen from the oilsands. In the case of in situ projects, where steam is injected into the reservoir in order to heat up the crude so that it can flow more easily to surface, approximately one thousand cubic feet of natural gas is used for every barrel recovered. Currently, one million barrels per day are recovered by in situ techniques. According to the Canadian Association of Petroleum Producers, in situ production is forecast to more than triple, to 3.5 million barrels per day by 2030. In addition to significant energy consumption, in situ production also consumes large quantities of water. It takes about three barrels of water (in the form of steam) to produce one barrel of bitumen. Although two barrels are recovered and recycled, about 0.5 barrels remain in the reservoir and must be replaced. Efforts are being made to use non-potable water, but when the amounts of energy and water usage are combined, it is not only expensive, but it makes ready fodder for oilsands critics. Small wonder, then, that efforts are underway to find more efficient, economical means of production that have a smaller environmental footprint. One of the most intriguing methods being


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investigated is radio frequency (RF) heating. “It works a bit like a microwave,” says Rob Miller, chief marketing and sales officer for Acceleware Ltd. “You insert an antenna into the ground and supply it with energy. The radio waves then excite the water molecules in the reservoir and heat the surrounding rock.” Acceleware is a software firm based in Calgary. The company was formed nine years ago when several professors and grad students investigating electromagnetic (EM) high-performance computing set out to help cell phone companies better simulate antenna design. The publicly traded company now has 30 staff and consultants, is on track to achieve $4 million in revenues in 2013 and is growing at 25 per cent annually. In 2008, Acceleware branched out of antenna design and entered the oil and gas sector. It designed seismic imaging software and technology in order to provide processors with greater computing capability using a smaller footprint by relying on graphics processing units. They also became intrigued with the potential of RF heating in heavy oil and bitumen. “Researchers tried the technology in the U.S. in the 1990s, but at the time there wasn’t sufficiently sophisticated simulator software to come up with the right processes, and they essentially melted their


POWER TO PRODUCE Acceleware’s radio frequency (RF) antenna heating system would produce bitumen in situ using less energy than current technologies and without the need for water. Its power matching network, at top, matches generator to loaded transmission line. Conjugate matching is used for maximum power transfer.


equipment,” says Miller. “The main challenge with RF heating is that it requires a technological approach.” Using their unique talents, Acceleware was able to bridge the two worlds between reservoir simulation and EM design. “Reservoir simulation software analyzes variables to seek out the best way to produce a reservoir,” says Miller. “EM design looks at antenna performance in an attempt to broadcast as much energy as widely as possible.” Acceleware devised the AxREMS software program. “It determines what’s happening in both the reservoir space and the EM space,” says Miller. “It has a loop where you can change dozens of variables and run iterations hundreds of times to see what’s happening. The advanced

“Reservoir simulation software analyzes variables to seek

Are we compromising the integrity of the reservoir caprock during SAGD operations?

out the best way to produce a reservoir. EM design looks at antenna performance in an attempt to broadcast AS MUCH ENERGY AS WIDELY AS POSSIBLE.” — Rob Miller, chief marketing and sales officer, Acceleware Ltd.

software allows you to perform an iteration in an hour, as opposed to several days. There is a huge compression ratio.” Their analysis indicates that RF heating uses 30–50 per cent less energy than steam. “You don’t have a steam plant at surface, so there are a lot less capital costs,” says Miller. “And you don’t need water. You can easily turn the system on and off, and you can even negotiate with energy providers to take lower-cost electricity at night or turn off in brown outs.” The company is working in partnership with a U.S. field operator to install its first antenna this fall. “There is a region where heavy oil has been produced for many years, but there is still a lot of stranded oil because it is too shallow for steam injection because there is insufficient caprock to prevent the steam from potentially coming to surface,” says Miller. “The idea is to use the antenna to apply the heat.” Acceleware has several clients and partners using their RF technology, but confidentiality agreements prohibit third-party discussion of the value of the company’s technology. One sector participant did note that RF heating has tremendous potential to reduce in situ bitumen’s footprint, “but it’s at least 10 years out.” For their part, Acceleware predicts a much shorter timeline. “We see RF heating being commercially viable in three to five years,” says Miller. “It will be especially valuable for shallow reserves, thin reserves and complex reservoir situations like bitumen carbonate. It’s early days, but at Acceleware we see RF heating as a large part of our future.” Gordon Cope CONTACT FOR MORE INFORMATION Rob miller, Acceleware Ltd. Tel: 403-705-2415 Email:

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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Resource-Intensive Growth

Water, natural gas consumption set to escalate alongside oilsands expansion The consumption of natural gas and water to extract bitumen in situ is set to rise rapidly along with oilsands output over the next two decades. As of 2012, the province had already approved over five million barrels of oilsands production per day using current technologies, while industry has announced or disclosed plans to produce more than nine million barrels of bitumen per day. According to the Canadian Association of Petroleum Producers’ (CAPP) 2013 Crude Oil Forecast, Markets and Transportation report, oilsands production will almost triple from 1.8 million barrels per day in 2012 to 5.2 million barrels per day by 2030. CAPP’s projection sees an ever-growing reliance on in situ production compared to oilsands mining. Of the 1.8 million barrels per day produced in 2012, one million barrels per day were from in situ operations. By 2030, in situ production is forecast at 3.5 million barrels per day, compared to 1.7 million barrels per day from mining. While less freshwater-intensive than mining, in situ production’s water consumption is expected to grow from 452,000 barrels per day in 2012 to one million per day in 2022 and 1.27 million per day for all projects approved as of November 2012, according to the Pembina Institute. Brackish water use will swell from 391,000 to 868,000 and 1.1 million, respectively.

The single highest operating cost for in situ thermal projects is the cost of natural gas, according to the Canadian Energy Research Institute (CERI). For steam assisted gravity drainage projects, dry steam to oil ratios typically range from 2.0 to 2.5, while for cyclic steam stimulation, wet steam to oil ratios are between 3.0 to 3.5, it states. If in situ production technology remains largely as it is today, by 2045 natural gas requirements will multiply by two to three times current levels to between 2,749 and 3,586 million cubic feet per day in CERI’s high and low case scenarios. However, in a March 2012 report, Canadian Oil Sands Supply Costs and Development Projects (2011-2045), CERI estimates that due to aggressive shale gas production growth in the United States, and anticipated in Canada, meeting the oilsands industry’s future demand for natural gas should not be a concern. “It would be expected that Canada and the U.S. could be engaged in an energy exchange—Canadian oil for U.S. natural gas—that further enhances the trade relationship between the two countries,” it states. “Also, the prospects for technology switching and efficiency improvements are substantial and will likely put downward pressure on the industry’s natural gas requirements.”

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