New Technology Magazine February 2014

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REMOTE SENSE Arctic and oilsands data collection without physical contact

24 Keeping The Lid On Comprehensive advances have been made in offshore well containment systems—are they Arctic-ready?

30 Decoding Hydrocarbon Modern DNA sequencing could solve some of the petroleum industry’s biggest challenges

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VOL.20 | NO.01




Environmental Flare-Up



News. Trends. Innovators.


11 18


Arctic and oilsands data collection without physical contact

Managing Flaring And Venting New software could take some of the pain out of compliance and improve production



Green Hydrogen Power-to-gas technology enables utilityscale storage of renewable energy





Comprehensive advances have been made in offshore well containment systems—are they Arctic-ready?


Less Flaring, More Cash Flow Separator sends gas to sales pipeline instead of flaring after co2 fracture treatments

Defusing A Sour Situation Rise in h2S volumes from unconventional resources creates sweet opportunity

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Modern DNA sequencing could solve some of the petroleum industry’s biggest challenges


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eports that gas flaring from the proliferation of shale oil and gas wells in North Dakota can now be seen by Earth-orbiting astronauts echo another oil and gas industry–related environmental sore spot—the similarly recognizable-from-space tailings ponds. It seems that when an environmental problem becomes visible from orbit, it is perceived to have reached a scale where it can no longer be ignored. The rapid increase in output from shale and tight formations has certainly transformed the U.S. industry in recent years, creating a world-leading oil and gas producer. And in the rush to produce the crude—made economically accessible with advances in horizontal drilling and multistage fracturing technologies such as that in North Dakota’s Bakken Formation— producers have in many cases found it uneconomic to conserve the associated gas, which fetches far less value than oil these days. Flaring has become the most immediate solution, and it has skyrocketed. In North Dakota, which has seen oil output rise fortyfold from 2007 to 2013, almost one-third of associated gas, much of which contains valuable natural gas liquids, is flared, according to Ceres, a non-profit organization that works with investors on sustainability issues. In 2012 alone, widespread flaring resulted in the loss of approximately $1 billion in fuel, enough energy burned each day to heat half a million homes, creating greenhouse gas emissions equivalent to adding one million cars to the road, Ceres reported in July. “In addition, Ceres’ projections indicate that total flaring volumes will continue to rise above 2012 levels through 2020 unless the percentage of flaring is reduced from its current level to below 21 per cent,” it stated. Largely due to flaring in North Dakota and Wyoming, now making up more than half the United States’ total, the United States has seen flaring double since 2000, and the country has moved up the international rankings to fifth spot (behind Russia, Nigeria, Iran and Iraq— Canada is ranked 12th). Alberta, which was considered a world leader in flaring and venting reduction a decade ago, has also seen its long-term downward trend reverse in recent years due


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to a growth in both conventional and bitumen production. The Alberta Energy Regulator said it would look at tightening its regulations after reporting in October that flaring and venting has risen for the third year in a row in 2012. Industry flared and vented 34.71 billion cubic feet of gas in 2012, up 24.6 per cent from 27.86 billion cubic feet in 2011. The disturbing trend is partly the result of infrastructure lagging in new development and the current low value of natural gas, which can make it difficult to recoup the cost of getting the gas to market. While there are no technology barriers to conserving the gas per se, new advances in technology that could bring costs down would make more of it marketable. Potential solutions are many and varied, from better ways to measure and monitor it, to cheaper tie-in and transport options, to better ways to market the gas (such as small-scale gas-to-liquids technologies). In this issue of New Technology Magazine, we look at some of those new technologies, from the software in the office to the hardware in the field, meant to help bring the numbers back down. As the satellite photos of the tailings ponds have shown, such readily visible and striking imagery can go a long way toward eroding public confidence in—and allowing social licence for—large-scale oil and gas development. According to the World Bank, about 140 billion to 150 billion cubic metres of natural gas is flared to atmosphere annually—equivalent to three-quarters of Russia’s gas exports— representing a large-scale, and largely avoidable, financial and environmental loss. It also represents opportunity. Two years ago, General Electric Company issued a report on the subject, noting that the technology is available to put this wasted gas to more productive use and calling for the application of both “punitive and incentive-based approaches” to solve the problem. It concluded, “Gas flaring reduction has the potential to be one of the great energy and environmental success stories, and it has the potential to be achieved within the next five years.” The story is not over yet, but the clock is ticking.

Maurice Smith

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“No matter how optimistic one may be, it appears CCS is no longer considered by the government to be the dominant option for Albertans to reduce their greenhouse gas emissions.” — Michael Massicotte, partner, Borden Ladner Gervais LLP

Until costs, especially capture costs, associated with carbon capture and storage (CCS) can be reduced, or until the province dramatically increases the $15 per tonne penalty that is part of its Specified Gas Emitters Regulation, or until the province substantially subsidizes the costs, Massicotte says there is little incentive for the industry to engage in these projects. “Even where [enhanced oil recovery] is available, the economics of CCS are still grim.”



Not only must all current pipeline projects connecting the oilsands to new markets be approved and completed in a timely fashion, but new ones must quickly be added to the list as well, or the impact on Canada’s economy could be dire, said speakers at The Canadian Institute’s Oil Sands Symposium in Calgary in December. Nelson said oilsands exports must expand globally because while she does not foresee exports to the United States shrinking, there is not much room for growth in that market.

Through efficient energy practices, Alberta could reduce its greenhouse gas (GHG) emissions by close to nine per cent, saving billions of dollars per year, according to the Alberta Energy Efficiency Alliance report, Energy Efficiency Potential in Alberta. Even if the province were to prioritize only the most economic opportunities for efficiency, it could reduce its emissions by 27 megatonnes from businessas-usual by the end of the decade to 274 megatonnes, representing half of the province’s 2020 GHG emission reduction target. Net energy savings would amount to $1.5 billion per year.

“THE U.S. IS ANTICIPATED TO BENEFIT MORE THAN THE REST OF CANADA FROM OILSANDS EXPANSION.” Imperial Oil Resources Ventures Limited plans to develop its first in situ project in the Athabasca oilsands using steam assisted gravity drainage (SAGD) technology that it patented but has never employed commercially. The company has filed a regulatory application for its Aspen project northeast of Fort McMurray to use SAGD to access 1.1 billion barrels of recoverable bitumen with first production in 2020. The preliminary capital construction cost is estimated at $7 billion with future construction costs of $4 billion. Total estimated project operations costs (including natural gas) are $15 billion.

— Sarah Dobson, economist, The Pembina Institute While there are many potential benefits to a stronger Canadian currency based on growth in the country’s oil and gas sector, an Équiterre and Pembina Institute paper suggests that oilsands income is largely concentrated in Alberta, and the benefits of a high dollar are outweighed by its negative impacts, particularly those regarding the loss of export competitiveness. According to Dobson, sourcing outside of Canada, particularly for inputs to the oilsands process, is already occurring and likely to increase.

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VaN g UaR D


GTL Under Investigation Alberta seeks solution to rising venting and flaring volumes


he Alberta government is looking for producers to take part in a study of whether natural gas that is being flared and vented could be profitably converted into diesel and naphtha. The study of specific sites—expected to take roughly nine to 12 months—will be the second phase of a three-part look at the prospects for turning low-priced Alberta gas into high-value products such as liquid fuels and diluent. The first phase was an evaluation of emerging modular gas-to-liquids (GTL) technologies that cost less and could be used on a smaller scale than conventional commercial GTL technologies. If the second phase’s results are encouraging and a site can be selected, the final phase would be a field pilot. Since the gap between North American oil and gas prices dramatically widened a few years ago, there has been interest in GTL as a way to capitalize on

the low gas prices and high oil prices. South Africa’s Sasol Limited, the global GTL pioneer, has bought land for a potential GTL plant in the Edmonton area. Now the Alberta government is looking at whether producers can use smallscale GTL technologies that are not yet commercial to profitably convert some of the gas that is being flared or vented into high-value hydrocarbons. Following the release of its annual flaring and venting report last fall, the Alberta Energy Regulator said it will issue new rules for upstream flaring and venting. The report, which covered 2012 emissions, showed that flaring and venting rose and that solution gas conservation fell for the third year in a row, reflecting the growth in bitumen and conventional crude production and the collapse of gas prices. The rationale for GTL is that converting gas to diesel fuel and naphtha (which

can be used to dilute bitumen for pipelining)—both of which are in high demand in Alberta—would provide a better return than using gas to generate electricity, says Duke du Plessis, senior advisor of energy technologies at Alberta Innovates – Energy and Environment Solutions, the government’s research group for oil and gas technologies. “The other thing is that you produce high-quality diesel through the FischerTropsch [GTL] process—higher cetane number, lower sulphur,” he says. “So it’s a very valuable product.” He says technological advances have produced yet-to-be-commercialized modular GTL technologies that offer the prospect of lower capital costs. Also, modular technologies can be piloted at a small scale and then scaled up through replication, says du Plessis, a chemical engineer by training. The other factor driving the planned government/industry study is the rising volume of gas being flared and vented after several years of decline. However, there are hurdles. For example, the gas being flared and vented is from a number of locations, not just a few large emitters. Pat Roche

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Managing Flaring And Venting New software could take some of the pain out of compliance and improve production



ny tools, technologies, software or strategies to reduce venting and flaring would be welcome right now in the Western Canadian Sedimentary Basin (WCSB). Volumes for both have been on the rise across much of the region, as they have south of the border where flaring has become a big issue in the Bakken play in North Dakota. Production from the Bakken has skyrocketed in the last decade from a negligible 2,000 or so barrels of oil per day a decade ago to more than 900,000 barrels of oil per day in 2013. An update from the U.S. Energy Information Administration in November forecasted that combined production from the North Dakota and Montana Bakken would hit the million-barrels-per-day mark in December. Infrastructure to deal with increased volumes of solution gas has not kept pace with development. The upshot is that parts of the sparsely populated northern U.S. plains are emitting as much glare at night as a sprawling metropolis, thanks to all the flaring.

On a less dramatic scale, flaring and venting have been on an upswing in Alberta for the last three years. Volumes had bottomed out in 2009, following almost a decade of reductions. Flared volumes from gas plants are up slightly, but solution gas from crude oil and bitumen batteries accounts for most of the increase. The Alberta Energy Regulator (AER) explained the latest surge in the amount of flaring in a report last October: “The increase in solution gas flared in 2012 (25.9 per cent) from the previous year can be primarily attributed to an increase in new crude oil production and low gas prices, which makes the economic viability of conservation more challenging.” The industry in Alberta flared and vented 34.71 billion cubic feet (bcf ) of solution gas in 2012, up 24.6 per cent from 27.86 bcf in 2011. At some point, operators could be hit with more compliance regulation—perhaps on both sides of the border.

A FLARE FOR CONTROL As a means to better manage flaring and venting, Process Ecology’s FlareAdvisor can provide companies with immediate access to information on where it is occurring on various platforms.

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LIGHTING THE NIGHT SKY Visible from space, excessive flaring from North Dakota’s Bakken shale play has raised concerns about the incineration of over 250,000 million cubic feet of natural gas per day, valued at more than $100 million per month.

A software product from Process Ecology, a Calgary-based oil and gas consultancy, could soon be helping a growing number of companies in the upstream oil and gas sector estimate and manage much of their flaring and venting. The company’s FlareAdvisor is an Internet-based software package that can work with most browsers, including Internet Explorer, Firefox, Safari and Google Chrome, and is geared to help operators manage and estimate flared and vented volumes from operating facilities. Process Ecology has a track record of assisting operators with plant efficiency and compliance issues, and its new software product is primarily aimed at dealing with non-metered and nonroutine events. A flare calculator that used spreadsheets was introduced to the industry about 15 years ago but was regarded by some as cumbersome, says Alberto Alva-Argaez, senior project manager and founding director with Process Ecology. “One option is software you install in a PLC [programmable logic controller] that works on data from a single source, i.e. a single piece of equipment, to calculate the flare volumes of gas passed through that equipment item. The key drawback is that it’s a stand-alone without storage [capacity], so I typically would have to write the result of its calculation on a spreadsheet,” he says. FlareAdvisor, on the other hand, is designed to manage the whole field asset, Alva-Argaez says. “A company has 12

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immediate access to info on where flaring is happening. For instance, if I have a facility where frequent compressor blow-downs are needed, this [program] could help locate the source of the problem. The program could [have] an option so that head office is flagged when an item of equipment is showing signs of something wrong.” The software program has been designed with a process-engineering approach, and simulation calculations can factor in some of the field challenges. “In complex situations where fluids are changing phases, the program would improve accuracy,” Alva-Argaez says. Issues like this are par for the course at Process Ecology. The firm’s engineers have done the design work and troubleshooting on relief systems for several large operators in the upstream sector. Their studies have ranged from the calculation of tank venting at heavy oil facilities to the evaluation of complex flare networks. Besides providing simulations, FlareAdvisor captures and records data, creates events and generates reports. Process Ecology worked closely with the industry in developing the software. As the time for field testing drew near last summer, developers worked to ensure the product met some very specific field requirements. First, it was essential that it be easy to use, with minimal training needed. There were other criteria. As well as a friendly user interface, entering data

and other tasks should involve as few stages as possible, with minimal bandwidth requirements. That’s because Internet access in the hinterlands of northeastern British Columbia tends to be somewhat spottier than, say, in a Calgary office tower. “Even when it’s up, it’s almost equivalent to dial-up in some areas,” says Ryan Tulloch, field environmental advisor with Devon Canada Corporation. The company had backed away from another program partly because it involved a total of 14 screens for one event. FlareAdvisor now uses two. Besides an office desktop computer, the program can be run from a smartphone, tablet or laptop. Field operators with Devon started using FlareAdvisor last summer, with beta tests done in the Fort St. John area in the fall. “We expect to be using it district-wide across northeastern B.C. in the spring of 2014. We use it for compliance with regulations for greenhouse gases. We have to report greenhouse gas amounts stemming from production operations,” Tulloch says. He expects the program will also help the company reduce emissions and further optimize operations. “It will identify where we’re flaring, and by identifying that, help us improve operations.” Typical field events that FlareAdvisor has been designed for include compressor starts, blow-downs and line pigging, among others. Depending on the availability of facility and equipment data, the software can be set up relatively fast. Around the WCSB, Alva-Argaez sees long-term potential for FlareAdvisor in the oilsands and the Bakken. “If you’re an operator in the Bakken and you have hundreds of wells, the program would be useful for getting flaring and venting totals,” Alva-Argaez says. Recent numbers from the oilsands might also suggest a need for enhanced monitoring and management, even additional regulation, for flaring and venting. According to the AER, venting from crude bitumen batteries increased 25.2 per cent to 10.58 bcf in 2012 from 8.44 bcf in 2011. During the same period, flaring from crude bitumen batteries increased 50.6 per cent to 2.51 bcf from 1.66 bcf. Godfrey Budd CONTACT FOR MORE INFORMATION alberto alva-argaez, Process ecology Tel: 403-690-0550 email:

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Green Hydrogen Power-to-gas technology enables utility-scale storage of renewable energy



Mississauga, Ont.–based company that has grown to become one of the world’s largest producers of hydrogen for industrial, transportation, utility and other uses believes it has come up with a solution for storing renewable power, such as wind or solar, and converting it into fuel, power or heat. Hydrogenics Corporation’s power-to-gas technology can convert renewable energy to hydrogen, which is used worldwide in industrial applications and is growing in use as a clean alternative to fossil fuels. Hydrogenics specializes in the design and manufacture of hydrogen generators and fuel cells based on water electrolysis technology and proton exchange membrane (PEM) technology. The company, which employs approximately 150 people, is one of the few hydrogen and fuel cell companies that is profitable. It reported $31.8 million in revenue in 2012, an increase of $8 million over the previous year, while reporting a gross profit of $5.24 million.

Publicly listed since 1995 (on the TSX and the NASDAQ exchange in the United States), it has applied for or has been granted 145 different patents, and more than 2,000 of its products are in use in 100 different countries. It has some impressive investors, with Calgarybased pipeline industry giant Enbridge Inc., which has a large power division, holding a 13 per cent stake in the firm and working with it to develop a power-to-gas project in Canada. By combining Hydrogenics’ expertise in water electrolysis with Enbridge’s expertise in natural gas pipeline networks, they can establish “a bridge between the electricity and natural gas networks to bring seasonal storage capabilities to electricity networks,” Chuck Szmurlo, Enbridge’s vice-president of alternative and emerging technology, said in announcing the investment in Hydrogenics. Hydrogenics also signed a strategic agreement with CommScope Inc., a global leader in developing

STORING WIND ENERGY Hydrogenics’ power-to-gas energy storage facility in Falkenhagen, Germany, uses surplus wind energy to produce hydrogen for storage in the country’s existing natural gas pipeline network. Operated jointly with E.ON, the facility can store over 30 megawatt hours of renewable energy per day, providing electrical grid support.

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infrastructure for communications networks, to jointly build backup power systems. CommScope now owns about 25 per cent of Hydrogenics’ shares. The holy grail of the hydrogen economy, particularly the use of hydrogen as a transportation fuel, has long been viewed as a way to shift away from a world dominated by petroleum use for transportation. Hydrogen releases no pollutants, such as particulate matter and CO2. When consumed in combination with oxygen in a fuel cell, it produces electricity and emits only water. It is also more efficient than internal combustion engines, using about 60 per cent of the energy available compared to less than 20 per cent. However, as highlighted in a recent report by the U.S. Department of Energy, hydrogen-powered fuel cell vehicles are unlikely to reach critical scale in the near term, since it is costly to produce hydrogen and fuel cells, there is no fuelling infrastructure in place and large amounts of hydrogen would need to be stored on board a vehicle to use it as fuel. Nevertheless, it is gaining traction as a fuel for fleet vehicles, such as buses and delivery vans, which have the capacity to carry large volumes and return frequently to a base (although low-cost and widely available natural gas is a more likely alternative). It is also gaining momentum as a source of backup power, as a replacement for diesel-powered generators, as a source of district power for single buildings or clusters of buildings and as a portable power source for boats or RVs. Hydrogen has long been used for upgrading heavy oil and bitumen and as a feedstock in the petrochemical industry. Hydrogenics estimates the worldwide 16

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market for hydrogen is now worth $5 billion annually. Canada has long been the centre of global hydrogen and fuel cell development, with an estimated 2,000 Canadians employed in the sector, according to the Vancouver-based Canadian Hydrogen and Fuel Cell Association (CHFCA). The CHFCA points out that hydrogen’s greatest merit is its flexibility, since it can be produced from fossil fuels, from renewables, at centralized manufacturing plants (from which it is then distributed by pipeline or tanker) or through on-site production. Hydrogenics, which through its electrolyser business has been involved in the hydrogen sector for 60 years, is involved in several areas of the hydrogen market, including its OnSite Generation division—which is based in Oevel, Belgium, and generated $27.5 million in revenue in 2012—and its Power Systems division—which is based in Mississauga and Gladbeck, Germany, and generated $4.3 million in revenue in 2012. Its HySTAT on-site generating units use water electrolysis technology, which involves the decomposition of water into oxygen and hydrogen gas by passing an electric current through a liquid electrolyte. The resulting hydrogen gas is captured and used for industrial gas and hydrogen-fuelling applications and is used to store renewable and surplus energy in the form of hydrogen gas. Hydrogenics estimates the worldwide market for on-site generation equipment is worth as much as $200 million. It sells its technology now to merchant gas companies, such as Air Liquide and Linde Industrial Gases, and other end-users

ReNewaBle PoweR RePoSiToRy However, Hydrogenics believes much of its future growth will revolve around its power-to-gas technology, which it describes as a “three-step process of integrating renewable sources of generation, converting surplus electricity to hydrogen or renewable gas and leveraging the existing natural gas infrastructure for seasonal or longer-term storage.” The technology holds out the hope of overcoming one of the chief barriers in the use of more renewable power, such as wind or solar, which is the intermittent nature of those sources. Using existing natural gas storage infrastructure, which contains a vast amount of storage capacity, renewable power can be stored. It’s a market potentially worth billions of dollars, and the company says it is working with “leading utilities worldwide” on demonstration projects, setting the stage for commercial projects. Wido Westbroek, vice-president of sales and marketing, says the powerto-gas approach allows it to “convert multi-megawatts of renewable electricity to hydrogen and then use it in multiple applications.” Those applications include commingling the hydrogen with existing natural gas, with it flowing to end-users to generate electricity or heat; using the hydrogen as a transportation fuel; using it for large-scale industrial processes such as petroleum refining; or using biogas methanation, where hydrogen is combined with CO2 to create synthetic natural gas. “In a nutshell, Hydrogenics’ power-togas solution converts very large amounts


ELECTROLYSIS REACTION Hydrogenics’ proton exchange membrane (PEM) water electrolysis cell stack uses deionized water and electricity to produce hydrogen in an emission-free process. It consists of circular electrolytic cells, each containing two electrodes, the PEM membrane assembly and bipolar plates that separate the cells and provide flow channels for the water, hydrogen and oxygen.

needing high-purity hydrogen for industrial purposes. The company is also targeting the backup power market, aiming mostly at telecom and data centre installations, a market worth an estimated $6 billion. Its HyPM fuel cell products rely on a technology that transforms chemical energy created during the electrochemical reaction of hydrogen and oxygen into electrical energy. The systems, which compete with diesel backup batteries and lead-acid batteries, offer more reliability and lower operational costs, according to Hydrogenics. The company also supplies hydrogenfuelling stations, having recently landed a large contract with Royal Dutch Shell plc’s hydrogen division. It supplies equipment for over 45 hydrogen-fuelling stations globally.


of renewable generation, when it is not needed, into renewable power, fuel or heat where and when it is needed,” says Westbroek. “Shifting power across seasons and vast geographic distances through existing pipelines at multimegawatt levels is something no other energy storage solution can do.” The company, like many hydrogenfocused firms, has not been without its problems. It faced being delisted from the NASDAQ in 2012 (the company has since complied with the requirements) and dealt with the departure of some senior executives. However, its powerto-gas technology is gaining traction, particularly in Europe. In 2012, Hydrogenics announced it had signed an agreement with a European consortium of utilities and technology firms to develop the INGRID project, a 39-megawatt, grid-connected, renewable energy storage project in the Puglia region of Italy, where there is now 3,500 megawatts of solar, wind and biomass energy in place. It has announced a number of other deals and has since started operating a series of projects that will convert renewable power into hydrogen. In August, Hydrogenics and partner E.ON SE, a large European utility, as well as a consortium of 100 local utilities, inaugurated commercial operations at what Hydrogenics calls the largest power-to-gas facility in the world in Falkenhagen, Germany. The plant uses surplus wind power and Hydrogenics’ equipment to transform water into hydrogen, which is injected into a gas pipeline. The facility has a capacity of two megawatts and produces up to 360 cubic metres of hydrogen per hour. In April, Hydrogenics announced a one-megawatt hydrogen energy storage system located near Hamburg, Germany, also with E.ON as project partner, using excess power generated from renewable energy, primarily wind. The system allows the produced hydrogen to be stored in large quantities over long periods of time within the country’s natural gas infrastructure. It incorporates PEM technology, featuring the world’s largest PEM electrolyzer stack. The company says the PEM technology “will serve as the building block for future multi-megawatt applications.” Rob Harvey, director of energy storage for Hydrogenics and a veteran of the renewable energy sector, says the scale of power-to-gas technology offered by Hydrogenics and others is what will lead to its adoption. “All the stars are in

place for the adoption of power-to-gas,” he says. It is most likely to be adopted first in countries like Germany, where over 20 per cent of the power being generated comes from renewable sources. Other countries in Europe, such as Spain and Denmark, have similar levels. Because there is so much renewable power in those countries, “you need large storage systems,” such as natural gas networks, Harvey says. In Europe, Hydrogenics has eight projects that are either in operation, being built or are planned. Overall, he says there are 30 power-to-gas projects being proposed for Europe, many of them in the North Sea area, where offshore wind farms are huge power producers, and the offshore natural gas infrastructure is in place. Hydrogenics is part of a consortium of nine companies proposing projects in the North Sea. In Ontario, which is rapidly ramping up its renewable power production, as well as in U.S. states like California, the approach also makes great sense, he says. That’s why Enbridge, already an owner of renewable-power facilities in Ontario, is interested in power-to-gas. He says Hydrogenics is also in talks with partners to develop systems in California. The company’s PEM technology, ideal for large-scale projects, is easily scalable, which allows for the future development of multi-megawatt systems, Harvey says. It is estimated that a 100-megawatt power-to-gas project could provide the same amount of renewable electricity as a new 55-megawatt wind farm, with a comparable capital investment of about $125 million. However, given hydrogen’s flexibility and the system’s ability to store renewable power, the company argues that power-to-gas is a much better investment since its technology would allow renewable power to be used when it is needed and in a variety of forms. Speaking recently to a business audience in Sarnia, Ont., where a handful of refineries are located, Harvey noted that the integration of its power-to-gas technology can help make fossil fuels more environmentally acceptable and sustainable. “What if we used surplus renewables in southwestern Ontario to produce green hydrogen for oilsands refining in Sarnia?” he asked. Jim Bentein


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CONTACT FOR MORE INFORMATION wido westbroek, hydrogenics corporation Tel: 905-361-3660 email: N e w T e c h N o lo gy M ag a z i N e | Ja N Ua Ry / F e B R Ua Ry 2 014


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REMOTE SENSE Arctic and oilsands data collection without physical contact

PhOtO: ClEaRPath ROBOtiCS inC.


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By Carter Haydu

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n what was undoubtedly an unbearably cold and miserable day in the late 1840s in the Canadian Arctic, the last British voyagers on the HMS Erebus and HMS Terror succumbed to pneumonia, hypothermia, lead poisoning or some other unpleasant end, as did the rest of the 128-man crew of Capt. Sir John Franklin’s ill-fated and final expedition to traverse the last unnavigated section of the Northwest Passage. The exploration of Canada’s northern, hostile wilderness has historically involved danger, hardship or, at the very least, a great deal of human effort. Fortunately, according to LOOKNorth executive director Bill Jefferies, contemporary exploration and monitoring of the Arctic and oilsands regions are supported by a rapidly evolving array of remote-sensing technology that augments on-site human presence, or reduces or removes the need for human presence altogether, to attain high-quality, valuable data. “Particularly over the past several years, there has just been a proliferation of new and better sensors,” says Jefferies, whose C-CORE-hosted centre for commercialization and research in St. John’s supports responsible, sustainable resource development in the northern regions of the country through its technology validation program. “Whether we’re talking about radar, whether we’re talking about optical, whether we’re talking about some of the geophysical systems and potential field measurements like magnetic, electromagnetic and gravity, those are all basic areas that Canadian technology has been very good at for a long time. “Now what is happening is you are getting more accurate sensors. You’re getting smaller, lighter and cheaper sensors, much better spatial resolution with the sensors, and much better accuracy and precision of the measurements they make. That has really expanded drastically in the last few years.” In a sun-synchronous orbit approximately 800 kilometres above the Earth, RADARSAT-2 is a synthetic aperture radar and C-band satellite system that works independent of both weather and light, sending a pulse to the planet’s surface that bounces back and provides a plethora of imagery for data analysis. Michael Nemirow, vice-president of energy and mining with MacDonald, Dettwiler & Associates Ltd. (MDA), says radar is very effective at identifying oil on water, among other things, and therefore MDA offers routine monitoring for all offshore operations to ensure companies take corrective action if there is ever any spillage. “If there is an incident, this information is used to identify the extent and area of the oil so [the company] can take the necessary actions to contain it,” he says. He adds that same capability allows MDA-owned RADARSAT-2 to provide valuable information during the exploration phase of offshore oil and gas operations by detecting naturally occurring hydrocarbon seepage coming up from formations below the sea floor.

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helping locate hydrocarbon deposits for the oil and gas industry. “It’s another layer of information, but it’s very important because it is a direct hydrocarbon indicator.” According to Duncan, Sky Hunter technology cannot determine the depth of hydrocarbons, but it can indicate the existence of hydrocarbons in a particular area two out of three times. With “minor tweaking,” he says, the remote-sensing technology is becoming increasingly more accurate as well. “We might put multi-sensors on the plane and get multi-layers of data,” he says, adding Sky Hunter is also looking at the possibility of placing its remote-sensing equipment onto unmanned aerial vehicles (UAVs), and companies exploring off the east coast have expressed interest in the availability of such an application. He expects to see microseep-detection technology on a UAV by the end of 2014. “What we need to do is probably lighten up some of the components, but that can be done. That’s just an engineering sort of thing. We’re pretty keen on doing that.” Sky Hunter just finished a survey for four EYES ABOVE companies in the oilsands, and Duncan says From Earth’s orbit, the RADARSAT-2 satellite, the result of collaboration between MacDonald, Dettwiler & remote sensing is increasingly important for the Associates Ltd. and the Canadian Space Agency, provides a wealth of information to the oil and gas industry, energy sector in northern Alberta. He says the such as Arctic sea ice observation and detection of offshore hydrocarbon seeps. use of remote sensing as opposed to physical land disturbance in the oilsands is preferable not just for economic reasons, but ecological ones as “It can help them identify where they want to take further explorwell. “Given the fact our maps show where not to go, there could be a lot ation action because of the cluster of seeps we identify from space.” of places left undisturbed from dry holes that do not help anybody.” Historically, remote sensing involved the application of some fairly expensive programs, but Jefferies says those costs have declined dramatically in recent years. REMOTE SENSING FOR “It used to be that if you wanted to do a job in the Arctic, you basically ENVIRONMENTAL IMPACTS had to pay the whole shot. Whether it was deployment of the airplane In December, the Alberta Biodiversity Monitoring Institute (ABMI) or deployment of the satellite, the cost was often borne by a few or often released the first ever report on the status of biodiversity in the Athabasca a single viewer. Now I think that is changing. Systems are becoming oilsands region. It measures the localized human footprint from indussmaller, they’re more transportable, and you have a broader customer trial operations, such as mining and in situ oilsands production, and base that is interested in it. correlates that with declining rates of species within specific areas. “There are a couple of really neat sensors that we are working with Jim Schieck, science co-director at ABMI, says satellite and airright now,” he says, noting Calgary-based Sky Hunter Corporation’s borne remote sensing played an integral part in determining characplane-mounted ion sensor. Jefferies says the technology is unique, and teristics of the landscape to accompany in-field data collection on 350 the fact that it detects oil and gas deposits offshore and onshore is likely species in the oilsands region for the biodiversity report. going to make it a highly sought-after technology for the industry. “That remote sensing information talks about the type of human “I think the potential is there because it is perceived as being a development and footprint in the area. This is compared with spemoney-maker.” cies information to look for relationships,” he says. “By comparing remote-sensing information to on-the-ground species information, we see how each species responds to different habitat types and to the “SNIFFING OUT” HYDROCARBON RESERVOIRS footprint in those habitats.” Russ Duncan, Sky Hunter director and co-founder, says his company According to Jefferies, remote-sensing technology is increasingly deploys sensory equipment on small airplanes that can detect negatively important for environmental monitoring and stewardship efforts in charged hydrocarbon particles that determine areas where companies the oilsands. He points to Edmonton-based Boreal Laser Inc., which is would want to search for possible oil and gas assets below the earth. developing laser systems that can detect a variety of greenhouse gases. “In a reservoir, it fills over geological time, but there is a small “I think that is quite exciting, obviously, because of the general degree that always comes through the caprock.... And when it public’s concern about the increasing presence of greenhouse gases in comes through the caprock it is like a refinery—[the molecules] the atmosphere. I think it is fair to say there is probably a lot of angst get cracked, and when the hydrocarbons get cracked, they pick up a and concern that is not well founded, so this not only provides a monitornegative charge.” ing capability, but also a transparency capability.” Duncan says the positively charged ionosphere pulls those Hamish Adam, Boreal Laser chief executive officer, says his comnegatively charged particles into the atmosphere, and his company’s pany’s technology consists of lasers that are sensitive to gases such remote-sensing technology uses three sensors to detect these microseeps, 20

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PhOtO: MaCDOnalD, DEttWilER & aSSOCiatES ltD. /thE CanaDian SPaCE agEnCY

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Robot Boat Could Revolutionize Tailings-Pond Monitoring, Say Developers


PhOtO: ClEaRPath ROBOtiCS inC.

REMOTE CONTROL Using a rugged mobile operator control station with a scalable outdoor network communication infrastructure, an operator can control one or several of Clearpath Robotics Inc.’s Kingfisher unmanned surface vessels from the safety of shore.

as CO2 and carbon monoxide. The instrument shines the laser beam through the air to a reflector and receives a signal proportional to the amount of gas along the measurement path. “We’re using a technique called infrared spectroscopy. The wavelength of the laser coincides with the wavelength at which the gas we’re interested in measuring absorbs light,” he says. “When we shine this laser beam through the air, and there is methane [CH4] in the air, then the methane absorbs some of the laser beam and reduces the amount of energy in the laser beam that makes the journey to the reflector and back to the instrument.” In regard to oil and gas operations, Adam says the main use of Boreal Laser technology to date has been providing CO2-monitoring equipment to Shell Canada Limited’s Quest carbon capture and storage (CCS) project near Redwater, Alta.—which will sequester CO2 from the nearby Scotford Upgrader—and detecting hydrogen sulphide leaks at several sour-gas-processing facilities in the province. “We’re working directly with Shell on their Quest project to do longterm, baseline monitoring of carbon dioxide levels at the [CCS] site before they start injecting CO2 into that subterranean facility in late 2014.” Adam says Boreal Laser’s technology is configured most commonly for ground-based measuring with a battery-powered instrument mounted on a tripod and paired with a distant reflector array. The technology is also available for airborne applications. “Using our equipment, owners and operators of natural gas pipelines and service companies that provide aerial service to pipeline companies fly our equipment on their helicopters as they fly along the pipelines, measuring the ambient concentration of CH4. When the ambient increases significantly over a short period of time, it is typically an indication of a plume of methane resulting from a leak in the pipeline.” According to Adam, Boreal Laser is currently working on miniaturizing its technology in order to place it on UAVs, which he says would be ready for demonstrations by mid-2014. Boreal Laser is also developing versions of its technology that measure toxic hydrocarbons, volatile organic hydrocarbons and polycyclic aromatic hydrocarbons, using quantum cascade lasers. “So what I see for the oilsands is Boreal Laser delivering instruments that can measure not just greenhouse gas emissions, but also

lthough small in size, the robotic Kingfisher bathymetry vessel could be the next big thing in monitoring and management of oilsands tailings ponds, says the company developing the machinery. Working with LOOKNorth’s technology validation program, Blyth Gill, Kingfisher’s commercialization manager at Clearpath Robotics Inc., based in Kitchener-Waterloo, Ont., says by summer 2014 his company’s unmanned survey vessel would be providing topographic information of the bottom of tailings ponds in northern Alberta. According to Gill, in a tailings pond application, Kingfisher “ties together” its GPS and sonar capabilities to provide readings of the exact position of the pond bottom, which is constantly changing as new materials are added from industrial mining operations. “In understanding the depths and the amount of volume within these ponds, you can calculate how much sediment has gone in there, how much water is in there, as well as calculating the lifespan left of these tailings ponds. Depending on the size and what those tailings ponds are used for, they may need to be increased.” Gill says Kingfisher is a lot more accurate than traditional methods of measuring the bottom of a tailings pond because the small robot boat can do more transect lines and collect more data than conventional survey crews riding in a larger boat. He adds that Kingfisher has sensors to measure pitch, heave and roll as it rides along, enabling triangulation of the exact bottom of the pond even if there are bumpy waters at the surface. The remote-controlled boat consists of two pontoons with embedded electric jet thrusters, which Gill says gives the device a shallow-draft profile. The watercraft connects wirelessly to a base station and relays collected information from GPS and sonar sensors to the operator. In a case study with Saskatoon-headquartered PotashCorporation of Saskatchewan Inc., the world’s largest fertilizer producer, Clearpath used the Kingfisher to map a tailings pond in Atlantic Canada. Tailings ponds are unique environments with specific safety requirements,

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the emissions of those toxic hydrocarbons. We would do that using ground-based instruments that can do permanent, fixed monitoring around tailings ponds or in the vicinity of tailings ponds. “Particularly for deploying in remote areas of the oilsands and the Arctic, the opportunity to fly our equipment on UAVs in order to do more extensive surveys is very attractive.”


Clearpath notes, and contain complex chemical compositions that make taking accurate bathymetric readings difficult. Density stratification at various depths can cause sonar waves to become distorted and impede quality data collection. In the case study, the company was able to safely collect 100 times more data in one-eighth the time and cut costs by 60 per cent. The full survey was completed in 12 hours with 89,000 usable data points collected, according to the study. By combining the data collected remotely with slime-depth measurements taken with physical probes, it was possible to determine the capacity of the tailings pond and create a bathymetric map. In the upcoming months, Gill says, Clearpath plans to launch an “autonomy package” for Kingfisher, so an operator can preplan the boat’s course and simply observe the incoming data, intervening only if necessary. “There is a location for a camera on board as well, so when it is beyond line-of-sight there will be that option too, in the future, to control it through a camera feed.” According to Gill, there is a definite health and safety advantage to sending Kingfisher out on a toxic tailings pond to take measurements, as opposed to sending out an actual person in a boat. “Anytime you send somebody out on a tailings facility, it is added risk. While there are ways of doing things properly, if you could simply remove that person from the hazardous situation entirely, then everybody benefits.” The versatility of the range of remote-sensing equipment the boat can accommodate should prove an attractive feature to companies as well, Gill suggests, as an operator could attach different sensors to the boat in order to attain whatever measurements are deemed necessary. “This system, apart from having on-board intelligence, is also unique in the fact that you can plug and play with multiple different GPS systems, as well as sonar packages,” he says, adding that without any monitoring and control equipment on board, Kingfisher costs less than $30,000. Carter Haydu


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KEEPING ICE TROUBLES AT BAY In the Arctic, Jefferies says, Canada is a world leader in ice mapping through remote sensing, with MDA’s RADARSAT program largely designed with Arctic ice in mind. “Really, RADARSAT is the default standard in the world for doing operational ice mapping. Whether that’s producing daily charting, determining the ice dynamics in a region or how to predict what is going on, all those are aspects that apply to the Far North.” Due to the broad area the system can cover, the fact it operates regardless of weather and because of the positioning of the satellite’s orbit, Nemirow says RADARSAT-2 is a reliable tool for monitoring ice and managing offshore oil and gas exploration and production.

PhOtO: ClEaRPath ROBOtiCS inC.

MAKING WAVES Clearpath Robotics Inc.’s 1.3-metre-long, 29-kilogram Kingfisher unmanned surface vessel is capable of collecting more data from waterways and tailings ponds, in a shorter time frame and at lower cost, than crewed vessels, without the risks associated with putting workers on the water.

Terra Remote Sensing Inc., of Sidney, B.C., uses an integrated airborne system of various sensors, including light detection and ranging (LiDAR, an optical remote sensing technology), digital imagery, hyperspectral and positioning systems for an ongoing project to collect imagery data on a large contiguous block of the Peace–Athabasca Delta located downstream from industrial developments. The hyperspectral camera is a passive sensor that measures visible-to-near infrared portions of the electromagnetic spectrum without going into a thermal range, splitting the spectrum into as many as 492 bands, says Taylor Davis, LiDAR applications specialist at Terra Remote. Combined with a spectral library of a certain condition attained through ground sampling, Davis says the hyperspectral sensor can measure deviations from what should be expected with conditions in a particular area. Much of the information provided on the Terra Remote system focuses on both form and function of the landscape, which applies to the landform surface as well as the vegetation that covers it. Davis says the benefit of this approach is that it maps path flows within the landscape and addresses changes to both the structure and health of vegetation along these paths. “The information is intended for those who are concerned with the broader impact of the extraction activities, particularly in downstream off-site areas where there could be potential convergence of contaminants.” According to Davis, the desired outcome of Terra Remote’s data collection is a greater understanding of the actual impact that oil and gas activities have in the downstream region, which could lead to more effective development of resources for monitoring and migration. Because wetlands are very sensitive gradient landforms, he suggests sensors can monitor environmental changes through changes in locally adapted vegetation. Davis says activities in the oilsands-impacted areas are uniquely suited to remote sensing, in part because licensees are required to return the landscape to a level that replicates ecological functioning once they have finished with extraction and reclamation. “The data that are collected with our system allows for the characterization of the vertical and horizontal landscape structure as well as species composition. These data can be used to develop a metric for post-mining reclamation. In addition, the affected wetland network can be mapped for future reconstruction.”

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“Particularly over the past several years, there has just been a proliferation of new and better sensors.” — Bill Jefferies, executive director, LOOKNorth

“We are able to provide oil companies and service companies with information about the ice edge or ice movement, icebergs or pressure areas that are occurring. That information is used to keep their operations safe.” Launched in 1995, RADARSAT-1 functioned for 17 years before finally going silent this past year. Fortunately, RADARSAT-2, which was launched in 2007, still provides a range of remote-sensing services. In 2013, the federal government announced a $706-million contract with MDA to build, launch and provide initial operations for a new RADARSAT Constellation mission before the end of the decade. “That will only serve to improve the high level of service that we offer our customers today,” Nemirow says, adding MDA, based out of Richmond, B.C., provides optimized imagery from RADARSAT for ships travelling though troubled waters, as well as nearly real-time

satellite information so companies can determine how they want to operate in a northern sea environment. “They can assess where the ice edge is or if there are any hazards that they need to consider in the operations that are occurring offshore.” One of the programs LOOKNorth currently funds investigates some of the extreme ice features in the North, which Jefferies says includes areas of high deformation that would be very difficult for a ship to navigate or for an offshore platform to withstand. Perhaps if modern remote-sensing technology had been around 170 years ago, the HMS Erebus and HMS Terror would not have become icebound in the Victoria Strait, and Franklin’s final expedition might have safely traversed the Northwest Passage. Of course, remote sensing possibly could have rendered such a dangerous voyage of discovery unnecessary in the first place.

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Keeping the lid on

Comprehensive advances have been made in offshore well containment systems—are they Arctic-ready?

n the evening of April 20, 2010, the Transocean Ltd. Deepwater Horizon, a semi-submersible rig situated approximately 40 miles off the Louisiana coast, had just finished drilling an 18,000-foot well into BP p.l.c.’s Macondo Prospect in the Mississippi Canyon block 252. Most of the crew of 126 were relaxing as a specialist team ran casing and cement into the hole. Suddenly, a large volume of gas and oil raced uncontrollably up the riser, resulting in an immense explosion and fire. Eleven crew members were killed, and over a dozen injured. The stricken rig eventually sank, crashing to the ocean floor 5,000 feet below. 24

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The tragedy was just beginning. The blowout preventer (BOP), a massive 25-tonne, fivestorey device designed to prevent runaway wells, failed to close. Around 50,000 barrels per day (bbls/d) of thick crude began to spill out onto the sea floor and make its way to the surface, threatening wildlife, beaches and protected habitats. BP and state and federal authorities launched a massive cleanup campaign, attempting to corral the immense slick. Helix Energy Solutions Group, a Houston-based well intervention specialist, was brought in to try and kill the well. Debris and subsurface damage complicated their task. After several attempts, the well was finally sealed on July 15, 87 days after it first began to spew. U.S. government agencies estimate that over four million barrels of oil escaped.

PhOtOS: MaRinE WEll COntainMEnt COMPanY

By Gordon Cope

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CAP IN HAND The centrepiece of Marine Well Containment Company’s (MWCC’s) interim containment system, the single ram capping stack is about 30 feet tall, including the necessary lifting gear, 14 feet wide and weighs 100 tons. It can handle temperatures up to 350 degrees Fahrenheit and operate in water depths up to 10,000 feet.

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PhOtO: MaRinE WEll COntainMEnt COMPanY

WELL CONTAINED Ken Salazar, who served as U.S. interior secretary from 2009 to 2013, and Marty Massey, MWCC chief executive officer, view the company’s interim containment system capping stack with industry and government officials.


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THE AFTERMATH After the well had been capped, various investigations and committees were struck to find out who was responsible, how the potential for similar events could be reduced in the future and how to prepare for intervention in case of a repeat incident. “After the Macondo incident in 2010, operators realized the need to put in a system that could respond effectively,” says Marty Massey, chief executive officer of Marine Well Containment Company (MWCC). “They formed an independent company in July 2010, and by February of 2011, we had the interim containment system in place.” Guided by experts at Royal Dutch Shell plc, Exxon Mobil Corporation, Chevron Corporation and ConocoPhillips Company, MWCC developed a capping stack that could be quickly deployed on site, lowered into place and clamped on to a blowout well. The system was capable of handling 60,000 bbls/d of oil and 120 million cubic feet (mmcf ) of natural gas per day. It had a 10,000-foot depth capability for capping, and a cap-and-flow capability up to an 8,000-foot depth. Over the following years, capabilities were increased, and the current system can handle temperatures up to 350 degrees Fahrenheit, and cap and flow depths of 10,000 feet. “We now are building a new system that is called the expanded containment system,” says Massey. “It will be able to handle 100,000-bbls/d cap and flow at a depth of 10,000 feet. We will be rolling out the system all through 2014.” As various committees released their findings, new deepwater well legislation emerged. “You now have to have a dedicated response system available before the regulators will issue a drilling licence,” says Kevin Robison, Helix general manager, production facilities. The company provides its Helix Fast Response System (HFRS), which consists of several major components that are either deployed in the Gulf of Mexico or in quayside storage. The Helix Producer 1 is a floating production and off-loading vessel that works on platforms in the Gulf. The Q4000 semisubmersible platform can be used for well intervention, completions and decommissioning. Helix stores flexible pipe that connects from a well cap to vessels on the surface and between vessels. “We can deploy the system in well under a week,” says Robison. “The capping stack is sitting quayside and can be deployed in 24 hours. Once you get to site, you send down an ROV [remotely operated vehicle] to do a survey and see what is happening on the subsurface, then send the tools down and latch the capping stack, which is a converted BOP, to the wellhead.” In full-service mode, the HFRS can contain up to 55,000 bbls/d of

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ASSESSING THE UNDISCOVERED The U.S. Geological Survey’s Circum-Arctic Resources Appraisal estimated the occurrence of undiscovered oil and gas in 33 prospective geologic provinces. It found the sum of the mean estimates for each province indicates 90 billion barrels of oil, 1,669 trillion cubic feet of natural gas and 44 billion barrels of natural gas liquids may remain to be found in the Arctic.

crude and 95 mmcf per day of natural gas at depths of up to 10,000 feet. Other containment systems are also entering service. In December, Oil Spill Response Limited, a global oil spill response cooperative funded by more than 160 oil and energy companies, opened a new base in Saldanha Bay, South Africa, to enhance Africa’s oil-spillresponse abilities. The Saldanha base joins two other facilities in Stavanger, Norway, and Singapore. Oil Spill Response Limited now has four capping stacks and related equipment that can be deployed worldwide to intervene in blowout wells in depths up to 3,000 metres.

THE ARCTIC Most systems are designed for temperate oceans; however, much of the offshore potential now lies in colder waters. In a 2008 study, the U. S. Geological Survey (USGS) assessed all potential sedimentary basins north of the Arctic Circle and estimated that about 30 per cent of the world’s undiscovered gas (1,670 trillion cubic feet) and 13 per cent of the world’s undiscovered oil (90 billion barrels) could be found there. In addition, the area of the polar region subjected to permanent sea ice has begun to shrink, from an annual summer minimum of nine million square kilometres in the 1990s to as little as six million square kilometres in the last several years. Two major shipping lanes,

the Northwest Passage through the Canadian Arctic Archipelago and the Northern Sea Route along Siberia, are frequently ice-free for several summer months of the year. This doesn’t just benefit shipping; exploration companies can conduct seismic surveys for longer periods of time and take advantage of an extended summer offshore drilling season. Recently, several major oil companies announced plans to explore in various deepwater Arctic regions. Chevron and Statoil Canada Ltd. are conducting a 3-D seismic program on a 2,060-square-kilometre lease in the Canadian part of the Beaufort Sea. Imperial Oil Limited, its parent corporation ExxonMobil and BP have filed plans with Canadian regulators to drill two licences located in the Beaufort Sea approximately 175 kilometres north of Tuktoyaktuk, N.W.T., in waters reaching 1,500 metres in depth. The prospects, known as Ajurak and Pokak, mark a departure from the shallow, near-shore Beaufort wells drilled in the past, all in less than 70-metre water depths. Imperial noted that each well would take at least two years to drill, given the 120-day operating season. The National Energy Board has a sameseason relief well regulation for all offshore regions, in which operators must be able to drill a relief well in case of a blowout in one drilling season. It recently modified its regulation by announcing that an

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equivalency system (that would prevent a blowout well from leaking until a relief well could be drilled) was also allowable. “Offshore wells in the Arctic have the same requirements as the Gulf of Mexico,” says Massey. “They must be able to demonstrate they have a system that can control a well.” Shell is furthest down the line in terms of the Arctic offshore. Several years ago, the Dutchbased company invested over US$2 billion in drilling leases in the U.S. portion of the Chukchi Sea, a marginal marine area of the Arctic Ocean that extends north of the Bering Strait between Siberia and Alaska. It subsequently spent an additional US$3 billion on equipment and operating expenditures to explore the Burger prospect. Shell considers it to be a potential world-class, multi-billion barrel exploration target. In 2012, Shell positioned the Noble Discoverer, an Arctic-class drilling ship, over the Burger prospect. Because it had not been able to finish its specialized containment system and get it in place in time to obtain permits from the Department of the Interior (DOI), it spent the season drilling only a top hole (the portion of the well above hydrocarbon-bearing reservoirs). Shell’s plans for continuing exploration in 2013 were dashed when one of its specialized rigs, the Kulluk, was badly damaged when it ran aground during towing in late 2012. The Kulluk and the Noble Discoverer were 28

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subsequently sent to South Korea for repairs and upgrades.

DUAL CONTAINMENT SYSTEMS In December, Shell filed a detailed plan with the DOI stating that it intends to resume drilling with the upgraded Noble Discoverer, with Transocean’s Polar Pioneer semisubmersible vessel replacing the Kulluk on standby in case a relief well is needed. In addition, Shell has finished developing two subsea containment systems, a capping stack and an Arctic Containment System (ACS) that will be available for deployment during the drilling season. The capping stack, Shell’s first line of defence against a blowout well, is a modified BOP designed to cap and divert hydrocarbons to the surface. It is equipped with blind rams, spacer spools and mud crosses that allow weighted fluids to be pumped down the borehole to kill the well. The stack will be stored on an Arctic-class vessel and be ready for deployment at a moment’s notice. The ACS is Shell’s backup plan—a last resort measure to stopper an out-of-control well. The ACS is designed to drop down over the spewing borehole and bring to the surface up to 25,000 bbls/d. Over the last year, the device has been upgraded through the addition of a stiffening frame and reinforced tanks. It will be mounted on a reinforced barge and stored in harbour, ready for deployment during the drilling season.

Many of the technical specifications and regulations regarding Arctic drilling have yet to be finalized. The DOI is expected to release guidelines for comment in the first quarter of 2014. In the meantime, the industry and interested parties have been invited by the federal agency to submit their input. Marilyn Heiman is director of The Pew Charitable Trusts’ U.S. Arctic program. When the DOI solicited feedback, Heiman and technical experts prepared a study, Arctic Standards: Recommendations on Oil Spill Prevention, Response, and Safety in the U.S. Arctic Ocean. “We are not opposed to oil and gas development in the Arctic,” says Heiman, “but the Arctic is vulnerable and remote and challenging, and we want to see world-leading standards.” Most of Pew’s recommendations focused on the challenges the harsh climate presents. “There is floating ice all year-round in the region,” says Heiman. “We recommend that vessels be designed and built to operate in these conditions. If a blowout occurs in October, and it takes one or two months to drill a relief well, then capping and containments systems must also be built to operate in late fall conditions.” When a big storm blows up in the Arctic, nothing moves because it isn’t safe, adds Heiman. “We recommend that you need both capping and containment systems on site and operable within 24 hours.”

PhOtO: MaRinE WEll COntainMEnt COMPanY

PUT TO THE TEST A Shell crew prepares the MWCC capping stack to be lowered to a simulated wellhead at Walker Ridge 536 in the U.S. Gulf of Mexico. Shell, ExxonMobil, Chevron and ConocoPhillips founded MWCC in 2010 to develop a better deepwater well containment system.

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Finally, Pew recommends that the capping stack and containment equipment be physically tested in Arctic conditions. “The testing should also be subject to third party review, and the devices inspected by BSEE [federal Bureau of Safety and Environmental Enforcement] officials,” says Heiman. A final caution involving well blowouts: not all ruptures occur on the sea floor. The underground well casing near the surface can be broached, resulting in leaks that can flow up the outer side of the well or through adjacent unconsolidated sediments. Such leaks are known to have occurred in the 1969 Santa Barbara oil spill, the 1974 and 1979 Brunei Champion Field releases and the 2008 North Sea Tordis incident. When the Macondo well blew, BP and government officials were concerned that their initial inability to top kill the well using mud was due to the possibility that there was a broach in the 16-inch well liner, allowing the mud to flow into surrounding sediments. If, as was their intention, a capping stack was installed and closed without due diligence, the oil would simply flow laterally out of the well and wreak further havoc. A multidisciplinary task force known as the Well Integrity Team (WIT) was organized. Stephen H. Hickman, a USGS geophysicist and lead author of the WIT’s report, Scientific basis for safely shutting in the Macondo Well after the April 20, 2010 Deepwater Horizon blowout, summarized their task. “We had to determine if we could ensure the safety of the well when we shut it in.” WIT scientists conducted a series of seismic surveys, sea-floor samplings and theoretical analysis. They were able to determine that no leakage of hydrocarbons was emanating from adjacent sediments and that the well casing was sufficiently cohesive to withstand a short shut-in of the capping stack. However, the testing to ensure that the capping-stack technology would not create a lateral blowout added almost a month to the containment process. In all, it took nearly five months to safely and securely deploy the containment system, more than the length of most Arctic drilling seasons. Thankfully, both offshore well blowouts and subsea broaches are extremely rare; of the 92 wells drilled in the Canadian part of the Beaufort Sea, for instance, none have experienced blowouts. That doesn’t mean that containment developers can be complacent. “There is ongoing advancement of technology,” says Massey. “As operators reach farther and farther out into the Gulf, they do R&D [research and development] into operating at temperatures greater than 350 [degrees Fahrenheit] and 15,000 psi [pounds per square inch]. We tag along.”

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Microbiology Modern DNA sequencing could solve some of the petroleum industry’s biggest challenges


ntil very recently, the industry’s interest in the role of microbes in oil and gas has mostly focused on two main areas—corrosion mitigation and microbial enhanced oil recovery (MEOR). In the case of the former, it has long been known that sulphate-reducing bacteria are culprits in microbially influenced corrosion (MIC) of oilfield infrastructure. MIC mitigation has worked for years, although scientists continue to work on identifying some of the related processes involved, but MEOR has often been marred by uncertainty and mixed results. Significantly, though, recent developments in MEOR have been encouraging, with more than just promising lab results. A growing number of field trials, large pilots and commercial projects have been showing consistent MEOR-based incremental production. (An article in the November 2012 issue of New Technology Magazine, “Microbe Stampede?,” described the recent progress in MEOR.)


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Not only MEOR’s problems, but many of the barriers to a better understanding of microbial activities in hydrocarbon environments might soon be a thing of the past. Just as genetic information from the Human Genome Project is beginning to revolutionize modern medicine, today’s tools of genomics, microbiology and metagenomics (the study of genetic material recovered from environmental samples) are now being applied to unlock some of the secrets of microbial life in hydrocarbon environments. The $11.5-million Hydrocarbon Metagenomics Project is developing a metagenomic database with stored information that should help scientists investigate in situ organisms and potential bioprocesses to improve production and reduce the environmental impacts of extraction in the oilsands and elsewhere. When the Human Genome Project was planned more than two decades ago, many considered it to be biology’s equivalent to the moon shot. Although viewed as a technologically risky international scientific

PhOtO: illUStRatiOn: ?????????? tEagan ZWiERinK

By Godfrey Budd


As the technology improves, the cost of sequencing is less. At the time of the Human Genome Project, sequencing costs were in the millions. Now, it’s in the thousands.

— Sean Caffrey, manager, Genome Alberta

enterprise, with a timeline of 15 years beginning in 1990, it was completed ahead of schedule in 2003 and below its projected $3-billion cost. “Already, doctors can better categorize some cancers by examining the constellation of genomic changes in an individual tumour rather than simply establishing the anatomic origins of that tumour. This refined categorization will often lead to more appropriate treatment,” according to the National Human Genome Research Institute (NHGRI), part of the U.S. National Institutes of Health (NIH). The NIH and the U.S. Department of Energy (DOE) provided funding for the Human Genome Project. Such advances in health care, along with spurring investment of additional billions of dollars in biotechnology research and development (R&D) for medicine, are only part of the story. The economic spinoffs have also been impressive, according to a study by Battelle’s Technology Partnership Practice released in 2011. “Among its findings was that for every $1 invested by the [U.S.] federal government, the Human Genome Project’s impact has resulted in the return of $141 to the U.S. economy,” NHGRI says. Compared to biotechnology R&D for medical and pharmaceutical purposes, current spending on oil-and-gas-focused microbiology and biotechnology R&D is relatively slight, perhaps around $100 million globally, according to one estimate. This makes the Hydrocarbon Metagenomics Project a big fish in a small pond—for now. “It is by far the largest such project in Canada, perhaps anywhere,” says Steve Larter, Canada Research Chair in petroleum geology at the University of Calgary and a senior member of the project team. The project has benefited from continued advances in genomics and sequencing technologies and has chalked up some success of its own. The Hydrocarbon Metagenomics Project was set up to run from October 2009 to October 2013 and came in under budget. “It received a no-cost extension to June 2014 using funding not spent. As the technology improves, the cost of sequencing is less. At the time of the Human Genome Project, sequencing costs were in the millions.

Now, it’s in the thousands,” says Sean Caffrey, with Genome Alberta, manager of the project. “Our project was very cutting edge. It’s among the first applications [of genomics] for the environment,” Caffrey says, noting the main funding came from Genome Canada, with support from some provinces and the industry. Using modern genomics tools and technologies, the project has been developing a database that includes detailed information on the genetic potential of micro-organisms found in a range of hydrocarbon environments, including bitumen deposits, oilsands tailings ponds, conventional oil and gas reservoirs, and coal beds. The expanding database and continuing research are helping scientists involved in the project to identify microbial processes and the conditions under which they occur in these environments. “In the same way that genetic information generated by the Human Genome Project is revolutionizing medicine and allowing doctors to target genes to improve the body’s health, information in the meta­ genomic database will allow scientists to develop techniques to harness naturally occurring organisms and bioprocesses to decrease the environmental impact of hydrocarbon extraction. Recent advances in high-throughput sequencing and decreased costs have only now made the creation of an extensive metagenomics database feasible,” the Hydrocarbon Metagenomics website says. Possible environmental benefits stemming from the research project include reductions in greenhouse gas (GHG) emissions; bio­ remediation of tailings ponds; biodegradation of pond toxins, including some napthenic acids; faster consolidation of fine tailings; and safe, controlled transitions to end-pit lakes for some ponds. The work will also improve understanding of how methane, oil and oilsands are formed and how to optimize recovery from aging reservoirs, oilsands deposits and coal beds. Mitigating methane gas efflux from tailings ponds is one area of focus for the metagenomics project, as the government and the

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~0.5 vol% diluent 85% water


~5 vol% bitumen

H 2S CO2

8-10% clays pH ~8


Process-affected water ~25% solids ~12ºC


35-60% solids ~20ºC

BIOLOGICAL SOLUTION Oilsands tailings ponds are breeding grounds for methane, a powerful greenhouse gas. Advances in genomics in recent years hold the potential to reduce these emissions with the use of methane-consuming bacteria.

industry are looking at ways to reduce the oilsands’ environmental footprint. According to Alberta Energy, of GHG emissions by industrial sectors in 2010, oilsands mining, upgrading and in situ extraction accounted for 38.2 per cent, compared to 37.4 per cent from electric power transmission and 6.9 per cent from conventional oil and gas production. Combined oilsands production was about 1.75 million barrels of oil per day, while the province’s conventional sector accounted for about 465,000 barrels of oil per day and 11 billion cubic feet of natural gas per day.

TAILINGS EMISSIONS Methane emissions from the oilsands’ many tailings ponds are no small matter. The largest tailings pond, measuring about 10 square kilo­metres, “effluxes an estimated 100 million litres per day of methane to the atmosphere, equivalent to about 500,000 head of cattle,” states the paper Methanotrophic bacteria in oilsands tailings ponds of northern Alberta. Published last year in The ISME Journal, the paper discusses bacteria that consume methane in tailings ponds and conditions in which they do this. (They require oxygen and are found in the surface water of the ponds.) It concluded that conditions were such that methanotrophs (methane-eating bacteria) might be pushed to higher rates of consumption. “Engineering a deeper, less turbid surface water cap might allow better O2 [oxygen] penetration and foster the growth of the aerobic community, including methanotrophs.” The paper added that this would cut methane emissions and increase degradation rates of harmful chemicals in the ponds. Biotechnology for the oil and gas sector has some way to go before it provides techniques for scaled-up programs for cleaning up tailings ponds. But as Peter Dunfield, an associate professor at the University of Calgary and a co-author of the paper, points out, biotech has had successes elsewhere in the energy sector, for example, in producing bio-ethanol from cane sugar in Brazil. “We can use methanotrophs to get rid of methane where it’s venting or leaking or can’t be recovered as fuel—it’s either too sour or there’s no infrastructure,” he says. 3 2 n e w t e c h m ag a z i n e . c o m


Anaerobic fluid fine tailings (FFT) and microbes

SOURCE: Julia Foght, Peter Dunfield/PTAC

Dunfield’s group—he is a part of the metagenomic project—now has genomic sequences of many different bacteria. A big area of research today, he says, involves finding out whether it might be possible to harness these bacteria in order to deal with some of the challenges in tailings ponds and elsewhere in the oil and gas sector, and if so, how successfully. He also asks, “Can we use methanotrophs to convert CH4 [methane] into more valuable products?” Only a few years ago, this kind of thinking would probably have been dismissed as fantasy. But now, thanks to advances in genomics, it is within the sphere of possibility because analysis of biological ma­ terial has simply become so much faster, more comprehensive and less hit-and-miss than it was in the past. “We used to have to isolate the organisms first, then culture them, to understand who they were and what they were doing. Using meta­ genomics, we can figure them out in one fell swoop relatively quickly without cultivation, with the use of high-throughput sequencing. In one run, we can identify all the organisms in a sample to be identified at a time. This was not possible 15 years ago when the Human Genome Project was being done,” says Lisa Gieg, an assistant professor at the University of Calgary and a researcher on the metagenomics project. Depending on the organism, she says, “DNA sequencing can now be done for around $50–$100 on a sample that might contain hundreds of organisms. Ten years ago, this was not possible. For between $50 and $100, you get a list of ‘who’ is there.” Furthermore, “For less than $3,000, you can identify all the genes those microbes will have, which in turn tells you about their application potential. That is how we can use them for biotech development.” Gieg and Dunfield were part of a small group of scientists who gave talks last fall in a three-part series hosted by Genome Alberta and Petroleum Technology Alliance Canada (PTAC). The series, held in Calgary, was a progress report for the industry about the metagenomics project’s research and findings. Gieg’s talk, titled “Bioconversion of Crude Oil to Methane: Beneficial Applications for Remediation, EOR, and Corrosion,” was a wide-ranging discussion on the various impacts—both beneficial


and detrimental—of hydrocarbon methanogenesis on the oil and gas industry. Like other talks in the series, it also looked ahead and considered how the new knowledge of microbial communities and their processes might be applied to solve industry challenges.

OPENING NEW POSSIBILITIES “Geochemists and microbiologists have known for a long time that the subsurface was anaerobic. The surprise was the amount of aerobic microbes that were present in the anaerobic environment,” Gieg says. This discovery opens up some possibilities, in part because aerobic microbes are easier to work with. “Perhaps we can use our knowledge of biosurfactants and some of the new aerobes and novel organisms to improve [conventional] oil recovery, but more likely from bitumen,” she says. Although methanotrophs could lead to better methane control in tailings ponds and elsewhere, methanogens (methane-producing microbes) in tailings ponds also have a beneficial side. Methanogenesis (microbial production of methane) has been found to be involved in metabolizing toxins like benzene and toluene into methane, accelerating the consolidation of fine clay particles and helping with the recovery of pore water from mature fine tailings for reuse in ore processing. “Only certain hydrocarbons degrade quickly into CO2 or CH4. Some hydrocarbons degrade only slowly or not at all. We want to identify the categories and some rules that govern the processes,” says Julia Foght, project co-leader of the Hydrocarbon Metagenomics Project and a professor at the University of Alberta. She also gave a presentation at the PTAC series last fall. Methanogens might also be used to extract incremental hydrocarbons from mature oil wells in the form of methane once natural gas

prices rebound. Foght and others on the Hydrocarbon Metagenomics Project see a range of possibilities. For instance, the use of nutrients for microbes can dramatically augment some processes. In one experiment, initial coal cuttings from the Scollard Formation produced little methane. But when tryptone, which provides a source of amino acids for the growing of bacteria, was added, a lot more methane was produced. “There have been huge advances and lots of discoveries, but not game changers [yet] in technology,” says Larter, pointing to progress made by the Hydrocarbon Metagenomics Project. He says the oilsands constitute a vast bacteriological resource and that more money needs to be spent on R&D to understand it. “Otherwise, it makes out-of-thebox ideas difficult to develop,” he says. Larter, who early in his career was a visiting professor of petroleum geochemistry at the University of Oslo in Norway, points to a range of possibilities that require further research, including methanogens as a possible green route to the production of hydrogen, conversion of oil to methane at an accelerated pace, new ways to use natural gas for oil recovery, better ways to deal with corrosion, exploration of possible microbial processes to remove sulphur from oil and development of microbial-based methods for reducing viscosity. Larter says that the 20th century was the great age of physics— when discoveries by Einstein, Bohr and others in the early 1900s bore fruit 40, 50, 60 or 70 years later and made possible everything from transistors and modern computers to laser and nuclear technologies, global positioning systems and magnetic resonance imaging—and the discovery of DNA and the double helix 60 years ago, along with recent advances in genomics, are about to usher in a host of inventions, new products, technologies and practical applications. “This is the century of biology,” he says.

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Less Flaring, More Cash Flow Separator sends gas to sales pipeline instead of flaring after CO2 fracture treatments

DiagRaM: FERUS inC.


ompanies want quicker cash flow. Governments want less natural gas flaring. A new technology promises to achieve both goals by enabling wells fractured with CO2 to be put on production, instead of being flared, during fracture flowback operations. In 2013, Ferus Inc., which supplies liquid CO2 and nitrogen to the oil and gas industry, did the first Canadian test of its separator, which removes enough CO2 to allow post-fracture production to meet sales pipeline specifications. That way producers don’t need to flare the initial production after a well has been fracture stimulated with CO2. Ferus believes that eliminating flaring—and the social, environmental and regulatory headaches that go with it—will encourage producers to do more CO2-based fracture treatments. While water-based fracture stimulations are in the spotlight for opening up today’s big shale plays, CO2based fracture treatments are still widely used. “Typically 40 per cent of all fracture treatments in western Canada

use nitrogen or CO2 in some format. We’ve got records back at least two or three years, and that percentage has not changed significantly,” says Murray Reynolds, director of technical services at Ferus. In the Deep Basin region of Alberta and British Columbia, for example, water may damage the formations, so operators tend to use so-called energized frac fluids—those based on CO2 or nitrogen. However, one of the drawbacks of CO2 fracturing has been the need to flare. Depending on treatment facilities, the maximum concentration of CO2 allowed in sales pipelines can range between two per cent and 10 per cent. That means the initial production following a CO2-based fracture treatment can’t be put into a sales pipeline because the CO2 content is far too high. As a result, the initial flowback after a CO2 fracture is typically flared until the CO2 content becomes low enough to meet pipeline specifications.

WELLSITE OVERVIEW Ferus Inc.’s CO2 separation system enhances the economics of wells fractured with CO2 by reducing the CO2 content of post-fracture production to a level that meets pipeline specifications, thereby allowing sales gas to be tied in earlier and reducing flaring.

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“In the case of a large CO2-based fracture treatment in the Montney Formation, for example, it could be 10–14 days before the CO2 concentration drops below 10 per cent,” Reynolds says. And depending on the pipeline specifications, 10 per cent may not be low enough. In the meantime, natural gas and natural gas liquids are being flared. Flaring means gas that could be generating cash flow is being wasted. Neighbours regard gas flares as noisy, polluting eyesores. Governments anxious to reduce oil and gas flaring aren’t likely to encourage it. After declining for several years, the volume of gas flared in Alberta rose in 2012 for the third year in a row, and the Alberta Energy Regulator’s 2012 report indicates well testing contributed to this increase. And what happens if the volume of gas flared reaches the maximum allowed on the flaring permit before the CO2 level falls enough to be acceptable for the sales pipeline? A producer can keep reapplying for flaring permits, but if the regulator is trying to reduce flaring, this isn’t the best solution.

caNaDiaN DeBUT Devon Canada Corporation faced exactly this dilemma roughly one year ago. The company had drilled a horizontal gas well near Grande Prairie in northwestern Alberta. The well was to be tied into a third-party pipeline with a five per cent CO2 limit. But following the fracture treatment, the well flowed back on cleanup until its government-mandated flaring limit was reached, but the CO2 content was still too high to meet the pipeline specification. So the well was shut in for several months. When Devon Canada decided to test Ferus’s CO2 separator on this well, 36

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it wasn’t flying blind. Devon Canada’s parent company, Oklahoma City–based Devon Energy Corporation, did the first worldwide test of the concept on a well near Hammon, Okla., in the winter of 2005. The portable CO2 separator’s history, rationale and operation are described in a paper Reynolds presented at the Society of Petroleum Engineers’ (SPE) Unconventional Resources Conference–Canada in Calgary in November. Many wells in western Oklahoma and the Texas Panhandle area were being fracture stimulated with CO 2-based fracture fluids, and the CO 2 content couldn’t exceed four per cent under the sales pipeline specification. This resulted in significant flaring during the flowback operation. The captured CO2 is currently vented to atmosphere, but Ferus plans to eventually recover the CO2, so the operator, who has already purchased the gas, can reuse it for other fracture treatments. Since the concept was first tested in 2005, the unit has operated throughout Oklahoma, northern Texas and Wyoming on more than 100 wells, says Rodney Ku, Ferus’s manager of business development. While Devon Energy had a positive experience with the separator, the model used in the United States was a simpler version of the Canadian unit, which has been winterized and modified to comply with Canadian regulations, says Warren MacPhail, Devon Canada’s head of drilling and completions technology development. According to the SPE paper, the initial CO2 content was about 50 per cent, but it fell to about 30 per cent within the first

why USe co2? In some formations, such as the Bakken in southeastern Saskatchewan, waterbased fracture fluids can be used with no ill effects. But in the Deep Basin formations of Alberta and British Columbia, nitrogen-based and CO2-based fracture fluids are often used. The primary reason is that the Deep Basin formations tend to be very “under-saturated,” or contain minimal water. If these formations are fractured with water-based fluids, the water is imbibed into the near-fracture area and impairs the rock’s permeability to hydrocarbons. Hence, all Deep Basin formations are a target market for CO2based fracture fluids, says Reynolds.


EARLY ADOPTER Devon, the first company to test the concept of using a portable CO2 separation unit after a CO2 fracture operation at an Oklahoma wellsite in 2005, was also the first to apply it in Canada when it used a Ferus CO2 separator system on a CO2-fractured gas well near Grande Prairie in northwestern Alberta last year.

18 hours and about seven per cent at the end of the test. Initially the gas stream was flared until the separator was able to achieve the desired CO2 reduction. After 24 hours of operation, the CO2 content stabilized below the five per cent limit, meeting pipeline specs. The initial inlet flow rate was about 1.5 million cubic feet per day with a sales gas rate of about 800 thousand cubic feet per day. Total sales gas shipped was 15.5 million cubic feet, but there were several periods of downtime during the 21 days it took to complete the test. These were required to de-wax the tubulars as wax tended to build up, inhibiting gas flow. Small volumes of hydrocarbon liquids and water were produced with the gas. During the test there was no downtime associated with the operation of CO2 separation equipment, the SPE paper says. “We’re satisfied that we proved the technology, and we’re happy with how it worked,” MacPhail says of the first test of the Canadian unit. As this article went to press, Devon Canada had not used the separator again. While Devon Canada has used CO2-based fracture treatments fairly consistently over the years, the choice of fracture fluid is based on the target formations. Because of the areas where Devon Canada is now operating, its current program doesn’t include many CO2-based fracture treatments, MacPhail says. Like most producers in western Canada, the company is currently focused on formations rich in oil and natural gas liquids. “If and when we apply CO2 again, then [the CO2 separator is] something we can consider using. We’re that comfortable, at least,” says MacPhail. “So it gives us an option. And that was sort of the goal—to make sure we had an option to reduce our flaring if and when we have the opportunity.”


While there’s much gnashing of teeth in the media about carbon capture being prohibitively expensive, privately held Ferus routinely captures CO2 as part of its commercial operations. The CO2 Ferus sells to oil and gas producers in Canada is captured from major Alberta emitters such as the fertilizer industry in the Fort Saskatchewan area and gas-processing facilities such as the Rimbey and Elmworth gas plants. Because the Canadian CO2 sources are all anthropogenic, using the gas as a fracture fluid doesn’t put any new CO2 into the atmosphere. In the United States, a significant amount of the CO2 used in oil and gas operations comes from wells drilled specifically to produce CO2. In Canada, using CO2 as a fracture fluid actually reduces the amount that ends up in the atmosphere. “Roughly 30 per cent of the CO2 pumped during fracture treatments is sequestered in the formation and never recovered,” Reynolds says. One of the biggest advantages of CO2based fracture fluids, he adds, is avoiding the environmental issues associated with consuming finite freshwater resources. “We can displace 80 per cent of that fresh water,” he says. By using fracture fluids that are 80 per cent nitrogen and/or CO2, only 20 per cent needs to be liquid, which is typically water or methanol. Because CO2 has only onethird the viscosity of water, it has limited proppant-carrying characteristics. So CO2 fracture fluids are typically pumped

with a polymer-based gel; hence, water use is never reduced to zero. In February, Ferus plans to release a new study that Reynolds says will show CO2 and nitrogen-based fracture treatments in the Montney tight gas formation use 80 per cent less water and get better production and economic results. Meanwhile, there are situations where the CO2 separator could be used even if the fracture fluid isn’t CO2-based. For example, the gas in the Horn River Shale play contains up to 20 per cent CO2. So the separator could be used to remove that naturally occurring CO2 during flowback operations.

iS waTeR Really FRee? One of the downsides of CO2 is that you have to buy it, but water is free, right? “Careful on that,” Reynolds says, arguing the competitiveness of CO2 with water can depend on the fracture designs. He says Ferus’s Montney study, to be published in February, found CO2 foam fracture treatments were 20 per cent cheaper than the slickwater designs. “Part of that is they can be smaller [fracture treatments] and be more effective,” he says. As for the perception that water is free, Ferus estimates the real cost of water in central Alberta is roughly $90 per cubic metre. That takes into account the cost of sourcing, trucking, heating and storing, as well as the processing, trucking and disposal of flowback water. Reynolds acknowledges that water is cheaper in the Montney play, depending

on the sources. He says one senior producer spent $35 million on a watersupply system that takes water out of the W.A.C. Bennett Dam in northeastern British Columbia to feed its Montney operation. “So they’ll be able to supply water cheaper on a per-unit basis, but that $35 million has to go into the cost of the water somewhere.” Also, Reynolds notes the cost of waterbased fracture treatments may be underestimated if the calculation is confined to the completions budgets. Slickwater wells that consume 7,000–12,000 cubic metres of water may continue to produce water for six or eight months, but the cost of trucking and disposing of that water comes out of a producer’s production budget, not the completions budget. Reynolds acknowledges freshwater demand is reduced by recycling some of the fracture flowback water, but he notes recycling also has a cost. “If you truly include all of the costs related to water, it’s not incredibly cheap. And that’s why our energized fracture fluid systems can compete based upon price and, in some cases, be even cheaper,” he says. But the main benefit, he adds, is in the reservoir. “You get less damage in the [fracture treatment] and better production.” Pat Roche CONTACT FOR MORE INFORMATION Murray Reynolds, Ferus inc. Tel: 403-695-3893 email:


Defusing A Sour Situation Rise in H2S volumes from unconventional resources creates sweet opportunity


f you do a search for “workers killed by hydrogen sulphide,” you’ll see headline after headline from newspapers throughout North America reporting on deaths as a result of exposure to the colourless, poisonous gas with the characteristic foul odour of rotten eggs. In fact, hydrogen sulphide (H2S) is so toxic it was used as a chemical weapon by the British army during the First World War. H2S—which is considered a broadspectrum poison, meaning it can poison different bodily functions—has been

responsible for the deaths of thousands of people, mostly in confined working spaces such as sewers or slurry tanks. Being heavier than air, it tends to accumulate in low-ventilated spaces. As recently as late October, an oilfield worker died after being exposed to the deadly gas while working at an oil pumping location in Dunn County, N.D. H2S occurs in both the upstream and downstream areas of the oil and gas industry, with some sour natural gas containing as much as a 90 per cent

concentration. H2S also occurs in crude oil and is a result of the use of hydrogen in the refining sector (the hydrogen releases H2S from petroleum). But beyond the potential danger to workers in the oil and gas industry, there are also negative environmental impacts as a result of the venting of H2S, which can lead to the creation of sulphur dioxide and have harmful corrosive effects on pipelines and other equipment. Calgary-based AMGAS Services Inc. specializes in the treatment of H2S and

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other noxious emissions, which is a growth industry. “Hydrogen sulphide is becoming more of a problem,” says Sheldon McKee, director of business and product development with AMGAS. “There are more wells being drilled in North America, and they produce more natural gas and sour crude oil than ever. In addition, the transportation of sour blends is becoming an issue.”

which creates more worker-safety and environmental risks. “H2S is dangerous and must be handled and treated properly throughout all stages of drilling and production,” says McKee. “Our aim is to proactively treat all H2S instances in the field and during transport in order to give our client the very best solutions on the market.” Despite more natural gas and oil being produced in North America than

“H2S is dangerous and must be handled and treated properly THROUGHOUT ALL STAGES OF DRILLING AND PRODUCTION.” — Sheldon McKee, director of business and product development, AMGAS Services Inc.

The privately owned company, which was launched as a family business in 1989 by Dave and Kelly Meston, now employs more than 50 people. Dave Meston died in 2004, but his wife Kelly remains active with the company. The company is active in most of the conventional and unconventional active oil-and-gas-producing areas of North America, including northwestern Alberta, the Bakken area of North Dakota, Texas and, through an affiliation with Singapore-based Rutledge H2S, northern Iraq, Saudi Arabia and Oman. While there are competitors in the sector, McKee says most specialize in developing the chemicals or equipment needed for treatment or in providing service. “We’re the complete solutions provider, offering service 24 hours, 365 days a year,” he says. “It’s the philosophy that was used when the company was started. We want to be available whenever customers call.” In September, the company announced it was opening an office in San Antonio, Texas to respond to the needs of producers in the sour shale Eagle Ford area of the state, one of four H2S-prone areas in Texas. Historically a state where sour oil and gas production is prevalent, Texas is one of 20 states that encompass 14 major H2S-prone regions in the United States, according to AMGAS. In addition to the need to deal with the high concentrations of H2S in over 12,000 gas wells and 190,000 oil wells in the state, much of the production needs to be transported by truck and rail, 38

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ever before—much of it in H2S-prone unconventional reservoirs—the move to production in more populous areas calls for more diligence in the treatment of H2S and other noxious gases, he says. In addition, the oil and gas industry has become more conscious of its need to deal with all traces of noxious gases, something government regulations also require. H2S emissions are associated with drilling, completions, well testing, underbalanced drilling, transportation and production operations. Some of the newer techniques being deployed lead to increased levels of H2S. Waterflooding and steam flooding, for instance, can raise H2S levels in oilproducing areas, due to the introduction of sulphur-reducing bacteria. Parts of Alberta have long been sour-gasand sour-crude-prone areas as well. Costs for treatment vary depending on the H2S content, production volumes and geographic location. AMGAS designs and manufactures the chemicals and equipment it uses. It recently announced the launch of its Absorbital 320 MAX chemical, which offers customers extremely high H2Sremoval capacity while decreasing the disposal requirement of the chemical. The chemical is extremely fast-reacting and can be used in both low- and highpressure gas-sweetening applications. “It has environmental benefits because it decreases our chemical disposal by half,” says McKee. The company’s H2S-scrubbing technology can sweeten sour production with the use of three different types of

H2S scavengers. The scrubber technology works by reacting with H2S to form nonreversible water-soluble by-products, preventing the release of H2S into the atmosphere. For storage and fluid-loading operations, the company’s ScrubberMax series scrubbers remove H2S being vented from the storage tank. The scrubber is piped into the vent line and operates at lower pressure than the tank, allowing the vent gas to pass through the scrubber, leading to the removal of the H2S. During truck-loading operations, the tank truck vent line can be connected to the same scrubber that is controlling the vent gas coming off the storage tank. AMGAS also offers H2S-removal technologies for the loading of sour oil into railcars or tankers, utilizing an auxiliary pumping system and loading arm. In addition to its aggressive move into Texas, the company expanded its services in Saskatchewan last April to offer expanded services to Bakken producers who are facing tightened regulations for the flaring, incinerating and venting of gases. Through its relationship with Rutledge, AMGAS is expanding its offerings in the Middle East, where there has been a surge in sour crude production. The company has also expanded its presence in the oilsands sector, where H2S is a concern in fluid handling and transportation. Earlier this year, AMGAS announced the launch of its Ready Service product, which is a mobile, self-contained treatment unit that requires no external power source. The patented mobile unit is seen as being ideal for the “shutdown and turnaround” oilsands and refining sectors and for continuous plant maintenance. McKee says a key to the company’s success has been its disciplined approach to staff training. “We have three levels of training for our field technology employees,” he says. “It’s like an apprenticeship aimed at keeping our trained employees working for us for the long term. It’s a three-year process to get to level three.” The company also utilizes a shadowing program, which sees experienced field workers mentor newer trainees. Jim Bentein CONTACT FOR MORE INFORMATION Sheldon McKee, aMgaS Services inc. Tel: 403-507-5499 email:

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