MAY 2014
T H E F I R ST W O R D O N O I LPATC H I N N OVAT I O N
On the
Ball Canadian companies advancing alternatives to plug-and-perf fracturing
22 Optimizing SAGD New strategies and targeted tweaking are boosting efficiencies and production
26 From High Tech To The Oilpatch Wi-Fi pioneers invent technology for collecting wireless seismic data in real time
To clear up any confusion about frac sleeves:
GripShift Sleeves vs Ball-Drop Sleeves with cement
with packers
For a long time, the big frac debate was about whether plug-and-perf or ball-drop sleeves-and-packers are better for multistage completions—shots versus sleeves. Now there is a third choice that has quickly changed the debate: the Multistage Unlimited coiled tubing frac system. This system also uses sleeves, which has led to some confusion, even though Multistage Unlimited GripShift casing sleeves don’t even use balls. To help clear things up, here’s a quick comparison: TM
TM
GripShift casing sleeves
Ball-drop sleeves
Cemented annulus for stage isolation
Open-hole packers for stage isolation
Recorded pressure data verifies stage isolation
Unverifiable stage isolation, known failures
Each sleeve positively located for frac
No way to positively identify active sleeve
Sleeve shifting verified three ways
No verification of sleeve shift
Single-point injection, precise frac location
Unknown where fracs initiate
Verified frac spacing
No control over frac spacing
Verified propped volume in each frac
Unpredictable propped volume in each frac
Identical sleeves can be installed in any order
Sleeves must be installed in exact order
All sleeves have full-drift ID at all times
Ball seats restrict ID until drilled out or retrieved
Closable version is available
No closable option unless retrieved
Real-time frac-zone pressure data
No real-time frac-zone pressure data
Screenouts easily and quickly removed
Screenouts are costly
Sleeves easily located and isolated for restimulation
Well segments difficult to isolate for restimulation
The Multistage Unlimited GripShift casing sleeve is not a ball-drop sleeve.
ncsfrac.com +1 403.969.6474 info@ncsfrac.com Leave nothing behind. ©2014, NCS Energy Services, LLC. All rights reserved. Multistage Unlimited, GripShift, and “Leave nothing behind.” are trademarks of NCS Energy Services, LLC. Patents pending.
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CONTE NTS
MAY 2014
vol.20 | no.0 4
FEATU R E S
D E PARTM E NTS e d itor’s vi ew
6
Unexpected Game Changers
van g uar d
9
News. Trends. Innovators.
Bytes
13 16
ON THE BALL
Canadian companies advancing alternatives to plug-and-perf fracturing CoVER Photo: Packers Plus Energy Services Inc.
Making Waves Computer program simulates movement of water through oilsands operations
new te ch
31
Odour Eliminator
Oil-tank-cover technology offers quick solution to foul-smelling emissions problem
34
Slime Slayers
Advanced assay technology combats damaging buildup of microbial biofilms
37
Making Money With Mud
Environmental innovator touts drilling- fluids-recovery system
ADVE RTI S E R S
22
OPTIMIZING SAGD
New strategies and targeted tweaking are boosting efficiencies and production
Absolute Completion Technologies Ltd. . . . . . . . . . . . . . . 12 Baker Hughes Canada Company. . . . . . . . . . . . . . . . . OBC Calfrac Well Services Ltd .. . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Canadian Society for Unconventional Resources . . . . . 38 dmg events. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 Dragon Products Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 Enerflex Ltd . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Entero Corporation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 geoLOGIC Systems Ltd. . . . . . . . . . . . . . . . . . . . . . . . . . . IBC Gibson Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Momentive Specialty Chemicals Inc. . . . . . . . . . . . . . . . . . 20 NCS Oilfield Services Canada Inc . . . . . . . . . . . . . . . . . . IFC
26
FROM HIGH TECH TO THE OILPATCH
Wi-Fi pioneers invent technology for collecting wireless seismic data in real time
4 newtechmaga z ine.com
Packers Plus Energy Services Inc . . . . . . . . . . . . . . . . . . . . 5 STEP Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . 11 & 15 Society of Petroleum Engineers. . . . . . . . . . . . . . . . . . . . . . 28 TRTech. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 & 29 Tundra Process Solutions Ltd. . . . . . . . . . . . . . . . . . . . . . . . 21
MULTI-STAGE COMPLETIONS
Not all ball-drop systems are created equal. Our QA/QC process provides 100% traceability with 2D barcodes ensuring that every system is tracked from raw steel to on-site delivery. Contact us today and let us help you maximize your assets.
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E DITOR’S VI EW
www.newtechmagazine.com
editorial
Unexpected Game Changers
I
f there is one thing that two of the feature stories in this month’s issue exemplify, it is how quickly the unconventional can become the conventional. Both the technology developed to unlock shale gas and tight oil (horizontal drilling and multistage fracturing) and the technology created to access in situ oilsands (primarily steam assisted gravity drainage) have advanced from unproven and unconventional to enormously successful and more or less routine just this century. We have moved beyond proving commerciality to finetuning these new techniques. On the road to conventional, new techniques have transformed the North American energy industry landscape. Rapidly growing bitumen production has reversed Canada’s previously declining oil output, while shale gas and tight oil have put the United States on a path to energy self-sufficiency, something few would have dreamed possible at the turn of the century. They are great examples of how rapidly and dramatically the industry can be altered with the development of breakthrough technologies. Could the next transformation be just around the corner? In a speech to the Canadian Energy Research Institute’s 2014 Oil Conference in Calgary in April, respected oilpatch veteran James K. Gray suggested it could be, in the form of commercial production of natural gas hydrates. Gray, chair of the energy group at Brookfield Asset Management Inc., was the co-founder and former head of Canadian Hunter Exploration Ltd., which became one of Canada’s largest and most successful natural gas companies by the time it was purchased by Burlington Resources in 2001 for $3.4 billion. Along with partner John Masters, Gray led the company on a path of innovation in exploration and technology that led to the pi oneering development of Alberta’s prolific Deep Basin. Now, Gray suggests Canada may be on a path to missing out on the next technological breakthrough if and when the gas hydrates puzzle is solved. To understand the level of the risk in missing out on the potential offered by gas hydrates, one must consider the enormity of the gas hydrate resource. It dwarfs not only the oilsands, but all the world’s oil and gas deposits combined. Add in the planet’s entire stockpile of coal, and you approach the level of resources
6 newtechmaga z ine.com
contained in natural gas hydrates found primarily in the Arctic and offshore continental margins. Like shale gas before it, we have a pretty good idea where it is and how much could be there, but we haven’t mastered its production. Up until recently, Canada was a leader in technology development to unlock the resource. Working with other nations that provided most of the funding, the first ever successful production tests of gas hydrates occurred at Mallik in the Northwest Territories, using hot-water circulation in 2001 and depressurization in 2007-08. However, the federal government subsequently cut funding for further research, something Gray said was a mistake, reported the Daily Oil Bulletin. The Mallik project should have continued “not so much for the production, as for the technology, the knowledge and the pubic policy. I believe we Canadians are running the risk of taking our energy market opportunities for granted,” he said. “We have become complacent.” Relying too heavily on the energy superpower status “narrowly anchored” on the oilsands, he said Canada must continue to be a leader in the development of energy technology to ensure it isn’t left behind. “Recent history surrounding the emergence of shale gas and shale oil as unanticipated game changers in our industry teaches us not to discount the possibility of natural gas hydrate production emerging as another game changer at some time in the future,” he warned. “We’ve been blindsided once. We must make every effort not to let that happen a second time.” One added advantage of gas hydrates is their relatively low emissions profile compared to other hydrocarbons. Even the influential Intergovernmental Panel on Climate Change in its latest report acknowledged the role natural gas could play as a bridge to a low-emissions future, noting it is “quite clear” that in the case of shale gas, production is “very consistent with low-carbon development” on the road to reducing emissions. Given the increasingly rapid pace of technological change, it is becoming more difficult to predict where the next energy revolution may come from. All the more reason to cover our bases and maintain some level of research into a diversity of energy alternatives, particularly where they could reduce our emissions profile. Maurice Smith
Editor Maurice Smith | msmith@junewarren-nickles.com Staff writers Lynda Harrison, Carter Haydu, James Mahony, Pat Roche Contributing writers Jim Bentein, Godfrey Budd, Gordon Cope Editorial ASSISTANCE MANAGER Tracey Comeau | tcomeau@junewarren-nickles.com Editorial Assistance Shawna Blumenschein, Katy Jones, Sarah Maludzinski, Matthew Stepanic
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VANGUARD
News. Trends. Innovators.
Clean technology has the ability to solve some key economic and business problems that Canada faces today, including in the energy sector, says Michelle Rempel, minister of state for Western Economic Diversification Canada. “I think having that brand as a country is very important in terms of exporting our energy, and it is something with which we have a track record that we should be celebrating a bit more,” she said during the Economic Club of Canada and Analytica Advisors presentation of the 2014 Canadian Clean Technology Industry Report in Calgary. The report found the clean-tech sector could create a $50-billion domestic industry by 2022.
$50 billion
anadian LNG [liquefied natural gas] “ Cdefinitely is not as cheap as some of the
billion
American products for sure, but if you compare and your destination market is Asia with its $16 or $17 gas prices, it makes perfect economic sense. I expect Canada will not be immediately, but [will] sometime soon be, exporting natural gas to Asia.
Alberta oilsands capital expenditures are likely to top $25 billion this year as operators continue to ramp up production despite challenges of tight pipeline capacity. Based only on publicly available information, the Daily Oil Bulletin calculated $23.78 billion in planned spending. “We don’t see a major uptick or a major downtick either,” said Martyn Griggs, manager of oilsands, Canadian Association of Petroleum Producers. “In any other industry, they would be stunned [with that level of investment].”
”
— Fatih Birol, chief economist and director, global energy economics, International Energy Agency
" With the oilpatch, any time you're talking about them having a problem with the general public, they're saying energy illiteracy of the petroleum industry is terrible, and so my rebuttal to that is that as far as I am concerned, the literacy rate of the oil industry on the environment is just as terrible, if not worse." — Ken Evans, faculty member, MacPhail School of Energy, SAIT Polytechnic
At the ConocoPhillips IRIS Public Seminar Series in April, Evans said the oil and gas industry is right to criticize environmentalists for often lacking “energy literacy,” though he said the problem goes both ways as he sees a lot of need for “environmental literacy” in the oil and gas sector.
Speaking during a University of Calgary Distinguished Speakers on Campus presentation in March, Birol said rising demand for energy in Asia will continue for decades, fuelling the likelihood that Canada’s LNG export sector is going to see growth in the future.
“ We need to find better ambassadors to critically assess these [statements from oil and gas industry opponents]. When you critically assess them, and you decide that it’s totally stupid, we need a reaction.” — Robert Mansell, academic director, School of Public Policy, University of Calgary (U of C) In a panel discussion sponsored by the Schulich School of Engineering alumni chapter and the U of C office of the vicepresident (research), Mansell said the industry needs to respond to the often illogical statements of its opponents and call them on those claims, arming the public with information to help support an informed discussion.
N ew T echnology M aga z ine | M AY 2 014
9
vanguard
EAST COAST
Exporting Offshore Expertise Newfoundland finds a niche in technology for Arctic oil and gas development
1 0 newtechmaga z ine.com
fishing, exploring and, most recently, developing the oil and gas industry, he said. “This leads to our keen interest and expertise in Arctic-related technologies.... The oil and gas operators that we have would not be there on the Grand Banks if they couldn’t contend with this ice and extreme ocean conditions.” According to Janes, Newfoundland and Labrador’s oil and gas sector is also adept at dealing with long distances from shore, which is where many northerly hydrocarbon assets are located. “Clearly there are challenges, but these challenges create an opportunity. It is an opportunity to once again deliver on our strengths as experienced harshenvironment operators, and it is also an opportunity for us to further improve our capabilities through focused R&D, so we can develop an industry that provides research and development services, along with technical solutions to this and other harsh environments.” Incorporated under the Research and Development Council Act in 2009, the RDC is an arm’s-length provincial corporation that provides leadership,
ARCTIC STAND-IN Though not technically an arctic region, the harsh weather environment found off the coast of Newfoundland and Labrador is an ideal proving ground for new technologies for arctic oil and gas development.
strategic focus and investments in order to strengthen and improve the research system throughout the province, driving innovation, creating wealth and increasing economic growth. “We’re looking to leverage our unique sub-Arctic environment, the knowledge we have, the knowledge we are building and the critical mass we want to obtain,” Janes said. One of those companies within the province possessing the expertise that could benefit developments throughout the Arctic is C-CORE, he noted. Established as the Centre for Cold Ocean Resources Engineering in 1975, C-CORE is a not-for-profit research and development corporation created to address the province’s challenges facing oil and gas development offshore in ice-prone
PHOTO: Svisio/THINKSTOCK
N
ewfoundland and Labrador is expanding not just as an exporter of oil and gas, but also as an exporter of the expertise it has developed in the extraction of hydrocarbons from harsh, offshore environments that could be employed throughout the Arctic. “Our goal is to live up to our name as a proving ground for the Arctic—a realworld and real-time laboratory,” said Glenn Janes, chief executive officer of the Newfoundland and Labrador Research and Development Corporation (RDC). Various northern regions around the globe are undoubtedly going to expand production into their frigid resource plays, and his province is blessed with a great deal of knowledge in this regard, Janes told the CI Energy Group Arctic Oil & Gas Symposium in Calgary in March. Although the province is not actually located in the Arctic, the conditions are the same. Throughout their history, Newfoundlanders have become adept at working in deep, cold waters with violent weather, as well as with icebergs and other seaborne ice anomalies while
vanguard
“ Countries like Norway and Canada can produce oil and gas for the long haul, but we need to be smarter with how we deal with it.” — Ole Anders Lindseth, director general, Ministry of Petroleum and Energy, Government of Norway
regions. Possessing world-leading capability in remote sensing, ice engineering and geotechnical engineering, it is now helping to put Newfoundland and Labrador on the world map as an expert for deepsea Arctic developments. “The successes we have had there have been led historically through organizations such as C-CORE. I would have to start drawing a map and putting flags all over the world to see where their reach has expanded. Our goal is to have more entities like the C-COREs of the world to be doing that type of work and that type of outreach.”
NORWAY STRESSES SUSTAINABILITY Norway is another jurisdiction familiar with offshore oil and gas developments in Arctic conditions. Ole Anders Lindseth, director general for the Ministry of Petroleum and Energy for the Government of Norway, told the symposium that his country’s second largest export sector is services for the petroleum sector elsewhere in the world. The country’s largest export is its own oil and gas. According to Lindseth, oil and gas development in the Arctic can be an important part of economic development, offering growth and employment to the approximately five million Arctic-dwelling people worldwide. However, he said, too often there is a public perception that sustainable development in the Arctic necessitates avoidance of the development of its natural resources—a perception he sees as false. “With too many discussions in the public domain, people deliberately or randomly confuse sustainable development with conservation and protection. This is to me very wrong because development actually requires activity. Sustainable development, as it was drafted...is that you need economic activity in order to safeguard the social dimension.” While Arctic development must occur in a way that both safeguards the people and brings economic opportunity to their communities, Lindseth said development must also preserve and protect the climate and environment. “Countries like Norway and Canada can produce oil and gas for the long haul, but we need to be smarter with how we deal with it.” For example, he said, in order to protect the climate and environment, Norway implemented CO2 taxes about 15 years ago, which have resulted in a barrel of Norwegian oil from the North Sea being produced with 50 per cent less emissions than oil produced elsewhere in the world. Norway has banned flaring of gas as well, he added, which has a tremendous positive impact on the environmental footprint of production. Carter Haydu
N ew T echnology M aga z ine | M AY 2 014
11
Oilpatch software
bytes
ENVIRONMENT
Making Waves Computer program simulates movement of water through oilsands operations
PHOTO: AQUANTY INC.
A
lberta’s oilsands mines need to be dewatered for extraction to take place, requiring a great deal of water diversion during operations and construction, and it is important to know how much water is involved, where the water is going and how it’s being managed. And there has been concern about seepage. “We need to know how much, when, where and what the quality of seepage might be,” says Chris Powter, executive director of the Oil Sands Research and Information Network in the School of Energy and the Environment at the University of Alberta. The Alberta government requires that oilsands mining companies submit closure plans that detail how they plan to integrate with their adjoining boundaries—not just between one mine and its neighbour, but between it and the environment. That’s because water flows downhill to the lowest point. “It’s absolutely critical that we have a proper
picture of how this water is going to move around,” says Powter. A new software tool, HydroGeoSphere (HGS), is designed to tackle these and other water-related issues. HGS, jointly developed by scientists at the University of Waterloo and the Laval University and provided by Waterloo, Ont.–based Aquanty Inc., simulates the entire terrestrial portion of the hydrologic cycle. It is a computer program that simulates the movement of water within the terrestrial portion of the hydrosphere. In addition to water flow, HGS is capable of simulating the transport of solutes such as salts, hydrocarbons and metals in both the surface and subsurface. The ability to accurately simulate the movement of water allows different scenarios to be posed to the model. For example, at the watershed scale, the impacts of climate change on water resources can be assessed, or
WATERWORKS Aquanty’s finite element discretization of the Athabasca River north of Fort McMurray, looking north, illustrates the way real-world topography and geology are represented in computer simulations. Each triangular element’s information on material properties is used to compute the movement of surface and subsurface water.
N ew T echnology M aga z ine | M AY 2 014
13
BYTES
Mean Annual Natural River Charges To Arctic Ocean 108,000,000 dam3
3,630,000 dam3
532,000 dam3
Petitot River
18,900,000 dam3 534,000 dam
3
Fort Chipewyan
High Level
Fort McMurray Clearwater River
Peace River
46,800,000 dam3
2,340,000 dam3
Grande Prairie 3,190,000 dam3 Beaver River
653,000 dam3
Grande Cache Edmonton
7,160,000 dam3
Lloydminister Jasper
275,000 dam3
Battle River Brazeau River
Red Deer Clearwater River
Banff
To Hudson Bay Drumheller Calgary
1,840,000 dam3 7,440,000 dam3
Total outflow: 129,697,000 dam3
Medicine Hat
Total inflow: 73,534,000 dam3
Lethbridge
Originating in Alberta: 56,163,000 dam
.
1 cubic decametre (dam3) = 1,000 cubic metres3 Inflow and outflow values represent the natural annual volume.
Milk RIver
1,664,000 dam3 106,000 dam3
167,000 dam3
To Gulf of Mexico SOURCE: Alberta Environmental Protection
the selection of mine closure materials can be tested with the computer simulation prior to construction, resulting in optimal closure design. “HGS is capable of simulating surface and subsurface flow and transport, which is of particular use for all aspects of mining involving movement of water in the environment, such as surface water flow—rivers, creeks, tailings ponds— groundwater flow, and surface-watergroundwater interactions like seepage and recharge,” says Steve Berg, Aquanty’s senior hydrogeologist. The technology is about 15 years old but has been available commercially 1 4 newtechmaga z ine.com
for only about two years and has been used by 10 companies on three oilsands mines, a pyrite mine in Australia and a gold mine in Africa, but also on a nuclear waste project in France. “It’s as close as possible to how physical processes actually work,” says Ranjeet Nagare, who has modelled oilsands mine reclamations and wetlands re-establishment projects with HGS. “Simulating natural processes using mathematics is a fairly difficult job, and these guys have done a very good job of it. It’s a fantastic technology, actually. It’s ahead of its time,” says Nagare, a
WATER IMBALANCE Oilsands development occurs in the northern half of Alberta, where water is abundant and use is relatively low. The north accounts for about 86 per cent of Alberta’s water supply (and the Athabasca River about 17 per cent), compared to just 13 per cent contained in the North and South Saskatchewan River basins, which support 88 per cent of water allocation demand, according to the Canadian Association of Petroleum Producers.
groundwater scientist with WorleyParsons Canada Services Ltd. in Edmonton. “It’s very helpful in solving complex problems and will save a lot of money.” Jon Paul Jones has used the tool in his work as a research assistant professor in the department of earth and environ mental sciences at the University of Waterloo and as a senior researcher in hydrogeology for Alberta Innovates – Technology Futures. Jones says the big advantage of HGS is that it integrates what happens to the surface water and groundwater, whereas in the industry, pretty much all the surface water and groundwater questions are addressed with separate studies and assumptions are made. For example, there is the danger that pumping too much water from the ground will affect surface water flows and result in the loss of fish habitat, he says. “[Most applications] treat groundwater and surface water in isolation, but really they’re just one big system,” says Jones. HGS is useful to the oilsands mining industry in particular because it can predict what will happen to a changing landscape—which an oilsands mine certainly creates—as water moves through it, he adds. HGS can also be applied to assess how a closure design will perform under different conditions. “When it comes to mine closure, the use of numerical simulations is very powerful as it allows the closure design engineers to test out their designs prior to actual construction,” says Berg. “When we work on mine closure problems, the process is usually iterative. Initially, we are provided with a closure design or a set of designs. “We simulate the designs under various climate scenarios—wet, dry and average conditions—and based on the results, the closure design engineers update their design to improve its performance. We then repeat the simulations with the updated design. This process is repeated until the design performance
BYTES
PHOTO: AQUANTY INC.
FLOW SIMULATION Three-dimensional view of a finite element model of the oilsands region built from publically available topography and subsurface geology. Such models can be used to simultaneously simulate the movement of water and solutes, like salt and napthenic acids, in the surface and subsurface.
criteria are met. It is not uncommon for this to result in dozens of design permutations to be simulated. This process helps the design engineers to understand how their design will perform and what design elements are most critical to that performance.” Given the detailed engineering design of where the liners are, how thick they are, what the material is and what the flow rates are, HGS can create a model to look at what the seepage is out of the base of a tailings pond, says Berg. “That’s actually kind of similar to looking at a closure design as well. We can incorporate on the closure side the detailed engineering design of where the tailing sand is going to be deposited, where the cap material is and look at how those designs will perform over the long term under different climate scenarios—look at what their seepage to nearby streams or water bodies might be, how those plumes could evolve with time.” The Cumulative Environmental Management Association, a multi-stakeholder group that makes recommendations about the cumulative impacts of oilsands development to provincial and federal regulators, cited HGS in its groundwater-monitoring guidelines report as a future option. University of Waterloo researchers have used HGS to model a proposed fen reclamation project for an oilsands mine, and it was used by University of Alberta researchers to look at water flow relative to aspen growth for oilsands reclamation. It can also be used for water-management issues associated with in situ operations such as steam assisted gravity drainage, say its developers. This may range from migration of subsurface contamination to the impact of water withdrawal from surface water. But so far, in the oilsands, HGS has primarily been used for projects focusing on operations and mine closure, as well as a basin-wide assessment of the impacts of climate change, says Dieter Hensler, Aquanty’s president and chief executive officer. Lynda Harrison CONTACT FOR MORE INFORMATION Dieter Hensler, Aquanty Inc. Tel: 519-279-1080 Email: dhensler@aquanty.com
N ew T echnology M aga z ine | M AY 2 014
15
F EATU R E
On the
Ball Canadian companies advancing alternatives to plug-and-perf fracturing
PHOTO: PACKERS PLUS ENERGY SERVICES INC.
By Carter Haydu
1 6 newtechmaga z ine.com
F EATU R E
t
he plug-and-perf method of cementing a liner—perforating and treating it before plugging the zone and moving up-hole to stimulate subsequent intervals—is a relative staple in the world of multistage hydraulic fracturing. But as the unconventional continues to become the conventional, the array of available systems is growing in tandem to help tap into these hydrocarbon resources. For example, Packers Plus Energy Services Inc. is probably best known for its StackFRAC HD system—a series of open-hole packers combined with ball-activated frac ports that the company developed in 2001 to access and economically produce low-permeability, tight-rock formations. “What the system does is it allows you to do multiple fracture stages, each done individually, on one segment, and then just by dropping a ball at surface and pumping it downhole, you can simultaneously shut off the lower section and open the next stage up the wellbore,” says president and chief executive officer Dan Themig. “If you look at the drilling rig count in western Canada, for example, or even in the U.S., now the vast majority of rigs are drilling horizontal wells. Not all of them use our completion methodology, but a lot of them do.” According to Themig, while northern Alberta’s Duvernay Formation would likely be the major contributor to recoverable hydrocarbons in Canada over the upcoming years, the formation is challenged with expensive, difficult-to-drill wells that are high-temperature and overpressured, making completions difficult. As far as open-hole systems go, Themig says, Packers Plus is really the only company with the equipment fit for the play. “What we utilize in there is our Titanium system, which is a super high-pressure, high-temperature series of packers and ports. They are rated to 15,000 psi [pounds per square inch], and I believe we have been, and currently are, the only company in the world that offers those temperature and pressure ratings.”
Another ball-drop alternative to plug-and-perf is Trican Well Services Ltd.’s i-Frac CEM system, which David Browne, vice-president of communications and marketing, says is unlike Packers Plus’ systems because Trican’s is cemented in place instead of being run and set in open-hole. “It is sliding-sleeve technology activated by dropping a ball. What is on the other side of the sleeve is a port, and when you slide the sleeve, it opens the port, so when you [apply] pressure up against it, you create your fracture at that point. Just like with the plug-and-perf, you are going downhole and perforating where the geologists think is best.... “We pump cement down, just like you would with the plug-andperf operation to cement the liner or casing into the horizontal part of the hole, but instead of going in with a perf gun and perforating, we are able to drop a ball and open one or many sleeves with the dropping of that one ball.” With an open-hole packer system, Browne says, every sleeve down the well requires a packer pressing against the rock to isolate sections, making that system a bit more expensive. “They generally just open one sleeve per ball drop, whereas we can open up to 20 per ball drop, and so we get a bit more efficiency there,” he says, adding that in an open-hole system with a sleeve opening up, for example, a 50-metre section of open-hole behind the casing cannot control where the frac is going to initiate. “You have the best of both worlds with our system. You can do many pinpointed zones like you do with the plug-and-perf, but you also have the speed of operation and the convenience of the ball-drop system.” Multistage fracture technologies at NCS Energy Services, Inc. started with the development of a downhole tool allowing operators to abrasively fracture a set of perforations before moving the tool up the hole and repeating the process, which was one of the first multistage systems of its kind. According to Eric Schmelzl, vice-president of strategic business, NCS perfected that tool’s design and refinement to function properly
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with 40 packers and 40 ports and several other components, reliability factors on equipment becomes extremely important,” Themig says, adding that ensuring quality control is of increasing importance for companies providing multistage fracture systems. “Technology is innovation, but it is also reliability.” According to Themig, another key Packers Plus technology is the SF Cementor stage collar, which enables open-hole, cemented-back completions and allows a fracturing system to run as a monobore. “Basically, instead of putting a whole series of casing strings in, you’ll typically just put in surface casing to protect the groundwater near the surface, and then you are able to run a single liner or a single piece of pipe all the way to total depth, and then you are able to effectively cement the build and vertical sections to protect other zones while keeping the horizontal section open-hole. “That really has been a key technology, and we now have additional-stage cementing technologies that are groundbreaking in that their reliability factor is much higher, and we have built in redundancies so that if there are any problems, we have a backup system to provide sealing. “So really, if you want to look at some of the key technologies, then that would be another one a lot of operators in western Canada would say has made tremendous strides towards cutting drilling time from 20 days to, in some cases, 13 or 14 days. These are the things that have had a really positive effect on the industry.” Themig says Packers Plus’ QuickFRAC system, now in its fifth generation, allows operators to not only pump a high stage number, but also allows pumping anywhere from three to five stages at a single time. “If you’re going to do 50 stages, instead of pumping BETTER DOWNHOLE DATA NCS, which specializes in coiled50 individual jobs, you might be able to pump 10 jobs tubing-deployed frac technology, at the surface and create 50 stages downhole by doing is a leader in collecting downhole five at a time, three at a time or whatever the number measurements during multistage might be,” he says, adding the company is also in fracking, helping ensure fracs are the process of releasing ScreenPORT sleeve technolcompleted as intended. ogy, which is ideal in areas where the rock is not very competent. in a horizontal wellbore—a precursor to developing “[ScreenPORT] allows us to perform stimulation work, the company’s Multistage Unlimited system where and when the well begins to flow, it actually flows back through a frac sleeve is run as part of the casing, and the same a screen that filters any sand that might be produced by a well if we bottom-hole assembly (BHA) is used to either open the installed didn’t have those components.” frac sleeves or to jet cut and isolate new perforations at any desired It is because of natural fractures and permeability—especially in location in the wellbore. unconventional reservoirs that do not produce uniformly out of the “The use of frac sleeves was a significant step forward in the speed matrix rock—that the Packers Plus open-hole system offers ultimate with which one can open up a set of ports and fracture them, rather recoveries in the range of 25–100 per cent higher than a cemented than abrasive jet cutting, which takes time and fluid. As operational system in certain environments, Themig says. speed went up, of course the number of stages one could do in a day Packers Plus recently completed a study in the Bakken comparing went up, and one of the drivers in the industry is to refine processes to production of cemented systems fractured with coiled tubing verses provide ever shorter times to place each stage.” open-hole systems. While cemented systems seemed to perform better at first, the data indicated that in the long term there were huge recovAUTOMATED ASSEMBLY KEY ery differences favouring open-hole, delivering additional revenue in Since StackFRAC’s inception, Themig says, the industry has moved to the range of $2.8 million in 30 months when compared with cement higher and higher stage counts, which is probably one of the biggest and coiled-tubing fracture completions. drivers leading to technological advancements. With a constant need to bring efficiency and cost-effectiveness to drilling projects of higher CEMENTED TECHNOLOGY PROVIDES EDGE stage counts, Packers Plus has invested heavily in robotics and autoBrowne says cementing Trican technology in place provides a greater mated assembly at its manufacturing plant in Edmonton. ability to work with a well as it matures, for example, if there is an area “When we had five packers in the well, it was not very hard to enthat is producing a lot of unwanted water. sure everything was built correctly, but now when we are doing wells
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PHOTO: NCS Energy Services, INC.
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Trican Well Services Ltd.
NCS Energy Services, Inc.
i-Frac CEM system
Multistage Unlimited system
Multiple fracturing stages
Sliding-sleeve technology
Grip/shift sleeves
are done individually, on
activated by dropping a
are run as part of the
one segment, and then
ball downhole into a seat.
completion casing string,
by dropping a ball at
On the other side of the
inserted at planned
surface and pumping it
sleeve is a port. When
frac points. These
downhole, the system
pressure is applied, the
mechanically shifted
can simultaneously shut
sleeve slides open and
sliding sleeves can be
off the lower section and
the fracture is created at
cemented along with the
open the next stage up
that point.
rest of the casing string,
Packers Plus Energy Services Inc. StackFRAC HD system
the wellbore.
eliminating the need to use casing packers for zone isolation.
SOURCEs: PACKERS PLUS ENERGY SERVICES INC.; TRICAN WELL SERVICES LTD.; NCS ENERGY SERVICES, INC.
“You have the ability to seal off those ports that are causing the water—you could pump in a bit of cement. Future work-overs and future refracturing to get more recovery from the well is more likely with this system than with the open-hole system.” With an open-hole system, he says, there are limited options regarding scaling problems in a near wellbore area in the formation. “It would be hard to treat that in an open-hole situation, whereas in the cemented situation you could treat that—you put some acid down there and dissolve the scale. “Cemented technologies are relatively new to the Canadian marketplace, but we think that as the fields mature and [operators] want to improve their production, there will be a lot more opportunities for success and ways of doing things when you have a cemented-in system rather than an open-hole system.” Browne notes that while typically cemented, his company’s i-Frac system can also be employed with packers, which could come in handy in a formation with a lot of natural fractures and permeability contributing to production. According to Browne, many operators prefer plug-and-perf in a true shale gas play because such systems can pump down the casing at higher rates. Therefore, according to Browne, for very thick shale such as the Horn River, most operators are sticking with plug-and-perf rather than ball-drop systems that are offered by Trican. However, he says, if an operator is doing work in the Bakken or in the Cardium in Alberta, the oil-producing zones are not as thick, the size of the frac volume does not have to be as big and the whole height of the pay zone is easy to frac with normal rates. In that case, Trican’s system becomes very advantageous over plug-and-perf, as rates need not be as high. Trican’s record with i-Frac is 122 sleeves, over 23 stages, averaging about five sleeves in each stage, completed in the Eagleford play in Texas, according to Browne. “Theoretically, we could do up to 400 fracs. One ball could open 20 [sleeves], and with 20 stages, that is 400. We don’t think we will get there anytime soon; we don’t think there is a need to. However,
there is always a possibility that there is a formation out there somewhere that needs that many. I’m thinking, though, that we will likely push up to the 150-sleeve range, which is well within the capability of the technology.” NEXT-GEN SMART SLEEVES While the technology is still relatively new to the industry, Schmelzl says the next generation of sliding sleeves is already offering smart technology, which is what NCS, specializing in coiled-tubing-deployed frac technology and services for multistage completions, is currently bringing to its customers. “We are making downhole measurements during the completion of the well and using the downhole tools to facilitate that data collection. To date, the downhole data has not been recoverable in any other cost-effective manner, preventing detailed knowledge of fracture stage communications in many cases. “When you do ball drops [for example], you usually start with the sleeve closest to the toe of the well. You drop a ball that shifts it open, and then you frac it and drop a slightly larger ball that lands in the next sleeve up the hole. “In that kind of operating environment, you have zero indication as to whether the open-hole packer or cement job actually isolated the individual frac stages or not. You are literally blind to what is happening up-hole, so folks are just pumping balls and hoping that everything is going the way it ought to be going.” With his company’s system, Schmelzl says, the combination of coiled-tubing-deployed sleeves and bottom-hole pressure gauges located at the top and the bottom of the BHA, NCS can tell if there is a hydraulic communication path around either the open-hole packers or a cemented annulus. “We have seen some wellbores with over 80 per cent of the frac stages communicating. That is extremely valuable data if your purpose is to optimize the frac spacing, well spacing or any of the other key design parameters.”
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The principle difference between NCS offerings and many other systems is that with Multistage Unlimited, the fractures are placed one at a time, providing the knowledge of where they are and how big they are, and the peace of mind that the intervals have actually been fractured, Schmelzl says. Recently, NCS engineers developed a close-able option for the Multistage Unlimited frac sleeve. Schmelzl notes that his company also has a straddle-frac system that can isolate existing openings, either ports or perforations, in order to fracture them individually. “If a re-stimulation was needed, then a straddle BHA would be the appropriate technology for that,” he says, adding that a variant of the NCS Mongoose BHA was recently introduced to facilitate refracturing of previously completed wells. “While there are other multistage straddle tools that could be used in a pre-perforated casing, those systems do not typically allow operators to add perforations as they proceed, so they were not nearly flexible enough in all situations.” For that reason, NCS developed the new SpotFrac BHA, which allows both the re-stimulation of existing intervals and the addition and stimulation of new intervals. With this system, according to Schmelzl, switching between jet cutting and fracturing operations takes place in seconds, without the use of balls or seats, making the system fast and effective in targeting bypassed pay. “What a great many of the other systems do is they force operators to make lots of assumptions that at the end of the day prevent them from knowing what has been done to the reservoir. It can prevent them from knowing how many fractures have been placed, which in turn prevents them from managing the completion and ultimately the reservoir.
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“It’s not just the fact that they may be gambling with the well completion—it’s that they don’t even know how the gamble turned out in the end. That is the downside to many of the other systems,” he says, adding the only real limitation of NCS systems would be how far the coiled tubing can reach. “We have taken some steps to be able to pump the assembly down the hole, and we have done two-mile horizontal laterals with the existing Mongoose system successfully. “It is largely a function of well geometry more than anything else, and for those instances where coiled tubing can simply not reach the extreme end of a wellbore, the company has introduced a new BallShift cemented frac sleeve system that can place up to 24 frac stages at measured depths beyond the reach of the coiled tubing.” Schmelzl says the new cemented Ball-Shift frac sleeves will facilitate closely spaced frac stages in even the longest of horizontal wellbores. “In all of the formations that we reviewed in Canada, we haven’t really found any that would not be applicable to this system.” Kory Galbraith, vice-president of engineering at Elkhorn Resources Inc., says he started working with NCS back in 2011 to complete his company’s first multistage horizontal frac in the Midale Formation, which traditionally had not been fractured. As a small-cap private producer, Elkhorn could not afford to take too many chances in attaining production, Galbraith says, and so he found NCS initially attractive because its technology very rarely missed stages. He has worked with the service company ever since. “I’ve pumped over 1,400 stages with NCS, and I think I have only missed three stages out of those 1,400, and so their results speak for themselves. That was because the tool had backup ability in it so that we would never miss a stage.”
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SAGD New strategies and targeted tweaking are boosting efficiencies and production By Godfrey Budd
S
ome of the concluding remarks of a paper presented at the World Heavy Oil Congress in New Orleans in March offer a succinct summary of the in situ oilsands production challenge: “The McMurray Formation is not a clean sandbox. There are stratigraphic variations between wells at even the 25-metre distance which can affect SAGD [steam assisted gravity drainage] well production.” The paper—Connectivity between very closely spaced wells in mcMurray Formation oilsands by Russell Stancliffe, a staff geologist with the subsurface engineering and geoscience team at Suncor Energy Inc., and Gordon Stabb of Durando Resources Corporation, a consultancy—points to 1.845 trillion barrels of bitumen in place “of which 315 barrels can be recovered with present technology.” With around 80 per cent of this bitumen recoverable only via in situ methods, not mining, the pressure to improve efficiencies and production in oilsands SAGD projects is likely to increase. The thermal efficiencies, energy balances and emissions show a very wide range of field performance for many of the current SAGD projects, according to an analysis of publicly available data on 200 well pairs by professors at the University of Calgary. Earlier pilots had been more successful, they found. “The data suggests that, at the extreme, some operations are not net energy generating, with injected energy via steam exceeding recovered energy in recovered oil,” according to professors
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Ian D. Gates and Stephen R. Larter in an article recently published in Fuel, a journal focused on the science and technology of fuel and energy. Gates, Larter and other experts have pointed to a host of barriers to better fuel efficiency, as indicated by the steam to oil ratio, and increased production that could stand remediation from a few methodological tweaks or technical fixes. Some of the barriers are geological and include shales and silt stones in the reservoir that might impede steam rise or gravity drainage of the oil to the production well. Also, variations in oil viscosity along a lateral can prevent a uniform development of the steam chamber, resulting in inefficiencies and reduced production. Oilsands reservoirs are geologically variable, with a wide range of permeability and oil viscosities. The Suncor paper presented in March was based on research that included eight drilled wells with a view to a possible expansion of Suncor’s existing Firebag SAGD operation, which currently produces over 140,000 barrels per day and has a capacity of 180,000 barrels per day. Besides viscosity and stratigraphy, the Suncor research program looked at gas isotope and bacteria variations and other potentially critical variables. Aquathermolysis, which occurs in SAGD operations, is a set of physicochemical reactions between crude oil and steam, at temperatures between 200 and 300 degrees Celsius, that has been on the radar for decades. It has, perhaps,
been sometimes neglected in the face of more pressing operational issues. But now there is a growing interest in the chemistry, as well as the physics and geology, that might affect SAGD processes. Several experts interviewed for this story underlined the potential importance of understanding the chemistry in SAGD reservoirs. Such analysis might include, for example, looking at the impacts of hydrogen sulfide and other organic compounds, which are typically produced during SAGD aquathermolysis. The assumption now is that—besides knowing the stratigraphy, viscosity packages and other factors within the downhole en vironment of each specific SAGD pair—the more completely the diverse and complex web of physical and chemical processes are understood beforehand, the better, resulting in a more effective well design. The use of 4-D seismic is also being considered as a possible measure to help anticipate thermal conformance along horizontals. The data from this and other sources could help predict the likelihood of cold or hot spots along a wellbore and determine whether the probable cause is a viscosity variation or a mud plug. The cookie-cutter approach that has mostly characterized large-scale SAGD deployment needs to be replaced with designs that tailor individual well settings to the highly variable geological realities and other factors, according to Gates, Larter and other experts. In their Fuel article, Gates and Larter suggest that a well-design team might consider skipping the standard practice
PHOTO: COMPUTER MODELLING GROUP LTD.
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of placing the collector well two metres above the base of the oil column, “where the theoretically maximum oil recovery would be obtained in an ideal SAGD process.” Instead, they could opt for locating the collector higher up the column. “The lowest viscosity oils are typically in about the upper portion of the oil column and thus placing the wells higher in the formation [rather] than directly at the bottom will enhance production rates in real reservoirs, not only at start-up but also beyond,” says the article. It is a generally accepted axiom of SAGD that uniform steam chamber growth, often called conformance, promotes enhanced bitumen recovery, better economics and reduced environmental impact. Operators have been using a range of strategies to boost conformance. Some involve solvent additives for the steam injector, as in expanding solvent SAGD. “These can address concerns about pressure and allow you to lower the pressure and temperature, and in deeper pro jects, can reduce the amount of steam required,” says Joseph Kuhach, senior vice-president, upstream technology and integration, at Ivanhoe Energy Inc. Another solvent process, which uses heated solvent and no water, is currently being tested by N-Solv Corporation at a $70-million pilot facility. “In practice, we’ll have to see, as there may be more issues with the heterogeneity of reservoirs,” Kuhach says. He adds that steam can benefit the process in the steam chamber by shaking things up, including the sand, and thus increase permeability. Another option involves injecting a gas, like methane or CO2, at around one per cent, along with the steam. These can form an insulating layer above the steam chamber and reduce heat loss, Kuhach says. He warns, though, that CO2 has the disadvantage of being corrosive. Some issues that can crop up over the life of a SAGD operation can be just about impossible to build into the initial
IN SITU COMBUSTION TIME STEP A simulation of three stages of the flood front in an in situ combustion project, generated using Computer Modelling Group Ltd.’s STARS advanced processes and thermal reservoir simulator. STARS is used to simulate changes to the reservoir based on fluid behaviour, steam or air injection, electrical heating or chemical flooding.
design, however. Even the best design is unlikely to cover every contingency, especially when it comes to getting the steam to go where the operator wants— and keep it going there. For instance, as the steam chamber changes over time, channelling can occur, with steam sometimes breaking through to a nearby producer well. When this happens, production and overall efficiency can drop sharply. To deal with this, TAM International Inc. has developed swellable packers that handle the high temperatures (300 degrees Celsius) of the SAGD environment and help optimize the placement of steam. “The steam has a tendency to follow the path of least resistance, which could be to go down to the producer because of pressure differentials. Also, changes in rock permeability could be another factor,” says Tim Davis, senior technical adviser at TAM International. The packers are located at each end of the section of a collector where the steam breakthrough has occurred, with a closed scab liner (an extra section of casing for repairs or solving a problem)—not slotted collector pipe—installed along the wellbore between the packers. “The steam is sealed off the producer at the stretch between the two packers. Now that steam can do what it’s supposed to do,” Davis says. Besides Canada, TAM International has sold its high-temperature packers in Columbia and Russia, but the initial impetus to develop the devices arose in Canada’s SAGD sector, Davis says. “We’ve done packers for about 20 pairs in the Fort McMurray region in the last two or three years.”
Pilot Needed? SAGD plus in situ gasification looks promising In situ gasification (ISG), with accompanying in situ combustion (ISC), as a means of thermal bitumen production has its advocates, but such a large-scale project has yet to be launched in Alberta’s oilsands. “One of the problems with gasifying is that you burn some of the oil, which becomes mobile, and the oil might go where you don’t want,” says Eddy Isaacs, chief executive officer of Alberta Innovates – Energy and Environment Solutions. But could ISG of bitumen with some steam injection in a SAGD configuration not only unlock the potential of ISG/ISC, but also cut steam requirements in half? Punit Kapadia, a reservoir simulation engineer at Computer Modelling Group Ltd. (CMGL), thinks it could. While completing a PhD in reactive reservoir simulation at the University of Calgary, he was the principal author of a paper, Practical process design for in situ gasification of bitumen, that was published last year in the academic journal Applied Energy. Kapadia used data from an in situ combustion pilot done at Marguerite Lake in the 1980s to help design a new SAGDbased ISG process and compare it with conventional SAGD for water consumption, energy investment and emissions. Kapadia is quick to point out the research project’s focus on well productivity. “We wanted a better product mix, somewhat upgraded bitumen and some fuel gases.” Kapadia’s proposed ISG-SAGD concept would involve about three months of injecting air, or oxygen-enriched air, into the formation, after the typical three to six months of steam circulation, followed by three months of steam (Continued on page 24.) N ew T echnology M aga z ine | M AY 2 014
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Another approach to well optimization, which involves a recompletion, was presented in another paper called SAGD Producer Wellbore Optimization – Concept to Completion at the New Orleans conference in March. A seven-well-pair pad at Devon Canada Corporation’s Jackfish Phase 2 SAGD facility began operations in 2011. Early on, however, production from one of the pairs was markedly lower than that of the other six. It was found that one section of the collector, near the heel, was a lot hotter than the rest of the well. The trajectory of the producer was not even. “The inter-well spacing was tighter at the heel because of the higher elevation of the producer in that section,” says Devin Smith, a SAGD production engineer in the thermal heavy oil group at Devon and the main author of the paper. The collector (producer) well requires an even level of fluid, consisting mostly of softened bitumen and water, immediately above it. It should be out of reach of steam breakthrough. Industry has found that a five-metre spacing between injector and collector wells is the ideal compromise for most SAGD operations.
After trying some operational measures to fix the problem, Noetic Engineering 2008 Inc. was engaged to provide modelling support for various completion alternatives to evaluate their effectiveness in mitigating hot spots. The options included extending the heel string into the horizontal, increasing the diameter of the toe string and various scab liner configurations. Noetic modelling and simulation first developed a base case that showed the unstable fluid level distribution near the heel was due to the uneven trajectory of the producer well and the resulting close inter-well spacing. Further modelling and simulations indicated that the most promising option for fixing the problem was a scab liner with a large outer diameter. In August 2012, a recompletion was done with a 330-metre scab liner. Figures to the end of 2013 show that production of a well pair labelled BB6P increased by 120 per cent. The conference paper on the project states: “Vapour production for BB6P increased as expected with the increase in total fluid rate but remains comparable with other well pairs with similar production rates.”
(Continued from page 23.) injection to warm and mobilize the bitumen. Air injection would follow steam injection, and the dual cycle of steam then air injection would be repeated. A complex model was developed that aimed to include the full range of processes involved in SAGD for the simulation, which was done with the help of CMGL software. “We needed to simulate in a way that coupled both chemistry and the physics,” Kapadia says. The gasification that the Marguerite Lake data showed had occurred was incorporated into the comprehensive model. “We used the simulation results to forecast what would happen if bitumen gasification was done underground and predict gasification performance in a SAGD configuration. The results of the process look promising, with better product mix and better sweep,” Kapadia says. The simulation forecast an output of 7.4 gigajoules of energy per gigajoule input. The output was a mix of roughly 80 per cent partially upgraded bitumen and about 20 per cent hydrogen. Water consumption was halved. More data and a pilot could add confidence to the forecast, Kapadia says.
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OGI NEWTECH 4/14
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From High Tech to the
ilpatch Wi-Fi pioneers invent technology for collecting wireless seismic data in real time By Pat Roche
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I
n the Dark Ages of the early 1990s, before most people had even heard of the Internet, two Calgary inventors came up with a new technology for wireless communication. In 1994, Michel Fattouche and Hatim Zaghloul were granted a U.S. patent for something called wideband orthogonal frequency-division multiplexing (OFDM). “It took us about 10 years to make sure that this patent was established,” Fattouche recalls in an interview. “OFDM technology is now everywhere. It’s in Bluetooth. It’s in Wi-Fi. It’s in cellular.” But in the 90s, Fattouche and Zaghloul struggled to have their invention taken ser iously. The company they started in 1992, Wi-LAN Inc., rode the crest of the dot-com bubble, but almost went under when it burst. “It took us 10 years for people to start to accept the technology,” Fattouche says. “By that time, it was very hard to compete with the big companies that took over the technology without giving us any royalties.” So WiLAN converted from a product company to a patent-licensing firm, hired lawyers and demanded the tech giants pay up. In 2011, everyone settled except Apple Inc. (which still hasn’t licensed WiLAN’s technology for 3G), says Fattouche, who is still a WiLAN director and a major shareholder. Companies that agreed to pay licensing fees to WiLAN include Samsung Electronics Co., Ltd., Dell Inc., Hewlett-Packard Development Company, L.P., HTC Corporation, Cisco Systems, Inc., ASUSTeK Computer Inc. and BlackBerry Limited.
In its year-end 2013 financial results, WiLAN, which is now based in Ottawa, says 279 companies have licensed its technologies. While the details of individual licences are confidential, WiLAN says royalties from these licences generated revenue of $82.21 million in 2013. Licensees include makers and sellers of products like 3G/4G/WiMAX base stations, 3G/4G/WiMAX handsets, laptops, routers, xDSL infrastructure, Bluetooth-enabled devices and digital television receivers. Meanwhile, Sayed-Amr “Sisso” El-Hamamsy, a former president of WiLAN, and Fattouche, now a professor in the electrical and computer engineering department at the University of Calgary, along with two other former WiLAN engineers—Ron Murias and Rashed Haydar— set out to solve another wireless challenge. (Zaghloul had left WiLAN by then to pursue other ventures.) SHOOTING BLIND Late last decade, El-Hamamsy and Fattouche were persuaded by a geophysicist friend to turn their wireless-technology talents to the real-time transmission of seismic data as it is being shot. The traditional way to view seismic data during acquisition has been via cables connecting geophones strung out over the survey area. But stringing out tonnes of cable is unwieldy, and the environmental footprint is huge. So in recent years, manufacturers produced cable-free receivers that can record seismic data. But the downside was that
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MESH NETWORKING A microseismic shoot in the muskeg in northeastern British Columbia. SRD uses a hybrid mesh network to enable the realtime transmission of seismic data while it is being shot.
geophysicists couldn’t see the data in real time. In industry parlance, they were shooting blind. Not being able to see the data during acquisition meant problems—such as noise— wouldn’t be detected until after the shoot. Then the only recourse would be to reshoot, adding significantly to the survey cost. So why can’t cable-free geophones transmit data in real time? El-Hamamsy and Fattouche quickly learned of three big obstacles:
1
Direction of data flow: In most net-
works, data flows mostly from the base station to the field units. For example, when you touch a link to a website on your wireless device, you are only sending a tiny bit of text—that web address— to the base station. Most of the traffic moves in your direction in the form of the photos, web pages, video and music that you are downloading. Although we may upload photos, for example, the proportion of data downloaded dwarfs the amount sent. But in a seismic survey, the data flow is reversed. The central location sends commands, but the multitude of geophones send back vast volumes of data.
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Data synchronization:
PHOTO: SRD INNOVATIONS INC.
Remember what happens in civic emergencies when everyone tries to phone at the same time? Not everyone gets through. That’s because networks are designed on the assumption that only a fraction of users will access the network simultaneously. In seismic surveys all the data gets generated at the same instant—for example, when a dynamite charge is detonated. So the network must be able to handle the maximum that can be produced. In some cases, this could be as much as 320 megabits per second. By comparison, a typical residential cable Internet connection can probably do up to 10 megabits per second if most of the resident’s neighbours aren’t also using it.
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Ease of Deployment: Cellular
networks take months of planning and construction. Base stations are designed to last for years. In contrast, seismic surveys need to be rolled out in days, mostly by unskilled crews and often over difficult terrain.
IDEAS MESH El-Hamamsy and Fattouche began working on the problem about six years ago. Their solution was to use what’s called a hybrid mesh network. Mesh networking is where each node, or point on a network, not only captures and disseminates its own data, but also relays data from other nodes. Mesh networks were in development in the late 1990s during the tech boom, but funding evaporated when the bust occurred so not many viable applications were created. One way to understand a mesh network is to look at what it isn’t. A cellular network is the opposite of a mesh network. If two people are phoning or texting each other, they can only connect through a base station—even if they are in the same room. But in a mesh network, if the nodes were close to each other, they would connect directly. If they weren’t close, the signal would hop to the closest node, then to the next closest and the next closest, until it found its destination. There is no base station. All the nodes talk to each other and use each other to move data from one point to the next on an ad hoc basis. If two nodes are too far from each other to connect directly, they can connect via nodes that are in between. On a cellphone network, if you lose your line of sight from the base station, you lose the signal. But on a mesh network, you can connect with whatever node is closest. CONCEPT TO REALITY Once they decided a mesh network could solve the problem of viewing data from
cable-free geophones in real time, the inventors formed Calgary-based SRD Innovations Inc. to develop the technology. El-Hamamsy is president and chief executive officer; Fattouche is chief technology officer. What SRD created is a software solution built on customized off-the-shelf Wi-Fi hardware. (The Wi-Fi radios are made in China and sold by a U.S. company.) “The work is all done on the software,” Fattouche says of the mesh protocol software that lets the Wi-Fi radios talk to each other. In July 2012, El-Hamamsy and co-inventor Ron Murias were granted a patent (U.S. Patent No. 8217803 B2) for part of the software; other patent applications have been filed. SRD's trademarked name for the mesh protocol software is hyMesh Wireless. This is what PhDs hired by SRD work on. The company is privately held, and its research is supported by federal and Alberta government funding. The hyMesh radios can be used for conventional seismic or microseismic. The latter is often used to monitor fracture stimulations because the operators need to know whether the fractures are being created in the target zones. IN THE FIELD SRD’s use of a wireless mesh network to relay data in real time “looks like a breakthrough,” says John Giles, president and chief executive officer of iSeis, a Ponca City, Okla., builder of seismic recorders. While there are other systems on the market, Giles says the ones he is aware of require someone to physically assign which box will
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F EATU R E
talk to which. The SRD boxes, on the other hand, “automatically detect the shortest route to the central unit,” Giles says, describing the hyMesh auto-routing capability. “So they automatically find their neighbours and actually determine what route to follow without any user intervention.” Perched on tripods to maximize signal reach, the hyMesh radios are deployed by the seismic crew when they lay out their geophones. SRD calls it a drop-and-go deployment. LEDs immediately indicate whether the device is connected to the network. If one can’t connect, a relay is used to provide the connectivity. However, crews shouldn’t take the dropand-go part too literally. “They still have to set up some antennas on the prospect and make sure everything is working,” Giles says. “It’s more than just hooking up a battery and a box.” If seismic contractors want the hyMesh technology, iSeis will sell it as a package with the seismic recorders it builds. Giles has had a few sales of the SRD radios but says adoption of new technology takes time. And there’s a trade-off. Without the radio and associated gear, the recorders are cheaper, lighter and require less battery power—but you don’t see any real-time data, he notes.
Giles is also president of Ponca City– based Seismic Source Company, which builds control electronics for sources such as dynamite or VibroSeis. He says he has been selling seismic equipment for more than a quarter century. “After you make your first sale, it takes about three years in this industry for it to really take off,” he says. “You usually make a few sales, then a year or so later a few more and then finally it starts getting written into specifications for some of the crews. That’s where it actually starts taking off.” One iSeis customer that bought 20 of the hyMesh units is Breckenridge Geophysical, Inc., a small contractor based in Breckenridge, Texas. Breckenridge’s other systems are cablefree units that record, but don’t send back, data in real time. “And so there’s no way for us to monitor noise or to QC [quality control] our data,” says JR Nelson, a technical support specialist with the company. “We’re very comfortable with it and confident in it, but some clients want to see something.” So far, Breckenridge has used SRD’s hyMesh units in conjunction with the recordonly boxes. If the portion of the data being displayed in real time is high quality, then the clients can have more confidence they are
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getting good data on the units that don’t have real-time capability. Also, the radios are used to check for noise—for example, in the wheat fields of Kansas where Breckenridge does a lot of work. “The clients up there are very particular about wind noise.... It seems like when the winds get up around 20–25 miles an hour, it generates about 60 or 70 Hertz noise on your geophones,” Nelson says. “With this signal system, we can put a line out right next to our regular receiver lines that the client can see. And we added a bar graph that’s calibrated in microvolts.” He hasn’t encountered any major downsides with the technology. One issue was getting the mesh radios a little higher off the ground, “but they’re working on that also as we speak,” he said in late March. Nelson is also impressed with SRD’s desire for feedback, its continuous improvements to the technology and its responsiveness to problems, even during off-hours. “For our purposes, it works really well,” he says. “We’re happy with it.” CONTACT FOR MORE INFORMATION Sayed-Amr El-Hamamsy, SRD Innovations Inc. Tel: 403-616-5441 Email: sisso@srdinnovations.com
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Tools and Techniques
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HEAVY OIL
Odour Eliminator Oil-tank-cover technology offers quick solution to foul-smelling emissions problem
PHOTO: GREATARIO COVERS INC.
W
ith controversy over odours from heavy oil operations in the Peace River area of northwestern Alberta having led to a provincial order to take action quickly, a vapour control technology developed by a company based in Innerkip, Ont., is likely to be viewed as at least part of the solution. In a ruling released on March 31, the Alberta Energy Regulator (AER) demanded that one of the operators in question install pollution-control equipment within a four-month period. Greatario Engineered Storage Systems, which since 1986 has designed and installed 400 tanks and 100 dome covers in eastern Canada (mostly overtop of water and waste-water storage systems), was mentioned at the hearings as a company that has the technology to control hydrocarbon emissions. Baytex Energy Corp., the target of most of the complaints from residents about odours from its heavy
oil production and storage operations, was ordered by the AER to take steps to reduce its emissions because of possible health concerns. The AER panel that issued the order held public hearings in the Peace River area in January, at which Baytex, one of the larger producers in the Peace River area, was singled out as the company responsible for most of the odour-causing emissions. “Odours caused by heavy oil operations in the Peace River area need to be eliminated to the extent possible as they have the potential to cause some of the health symptoms of area residents,” the AER panel said in its ruling. About seven families have moved away from the rural area in the last two or three years after complaining about dizziness, headaches, fatigue and cognitive impairment. Baytex spokesperson Andrew Loosley says the company promised at the January hearings to install vapour
COVER UP Greatario’s Hexa-Cover tankcapping solution uses hexagonal tiles made from recycled plastic designed to interlock and form a coherent cover.
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recovery units (VRUs) at its Reno field operation, and it will go ahead with those and other plans to contain emissions, although he says “it might be challenging” to meet the four-month deadline. Baytex, like other producers in the area, uses the cold heavy oil production with sand (CHOPS) process to extract the heavy oil. CHOPS is used widely in Alberta, but emissions with a higher sulphur content appear to be the source of the odour problem in the Peace River area.
because the majority of its 86 tanks at Reno are open-vented, with only 29 being connected to VRUs, the most commonly used technology in the industry. In a detailed description of steps that it and other CHOPS operators in the area have taken to contain emissions, which include the use of casing gas conservation and tank vapour management systems as well as VRUs, Baytex mentions it is considering the use of Greatario tank covers for “enhanced vapour management.”
LIMITING EMISSIONS A Greatario crew installs Hexa-Covers atop heavy oil tanks. The covers offer one solution to the problem of odours escaping from the heated tanks in northern Alberta.
In the CHOPS process, bitumen is heated on the surface in storage tanks, causing the hydrocarbon emissions that were being vented by Baytex and others. In the more widely used steam assisted gravity drainage (SAGD) and cyclic steam stimulation processes, steam is injected underground to liquefy the bitumen, allowing emissions to be better contained. The AER panel said operational changes must be implemented to eliminate venting and reduce flaring. It also ordered all excess gas from tank tops or gas co-produced with bitumen to be captured. It wants operators, either collectively or individually, to produce solutions to the odour problem by October. Although there are other operators in the area—including Shell Canada Limited, Penn West Petroleum Ltd. and Husky Energy Inc.—Baytex has been the target of much of the criticism, largely 3 2 newtechmaga z ine.com
If it does so, it would certainly not be the first heavy oil producer to do so. At the hearings, Terry Frank, vicepresident of sales and marketing for Greatario Covers Inc., a wholly owned division of the parent company, said the company had received orders for more than 1,300 of its tank covers since introducing the technology to Alberta and Saskatchewan producers in April 2013. He said 949 of those had already been installed. The genesis of the technology came from a distribution agreement the parent company signed with a Danish-based company for its Hexa-Cover technology. When Greatario announced the deal, it said the floating-tile system could be used on all kinds of liquids and would eliminate evaporation, organic growth, emissions and odours. It said it could be used on all forms of basins, lagoons, reservoirs, containers, ponds and water
tanks used in the industry by municipalities or in agriculture. Greatario went on to describe how the tiles—manufactured from recycled plastics and without the use of harmful materials—would work. “The tiles are hexagonal elements with symmetrical ribs on both sides,” it said in a press release. “The ribs make the floating elements distribute themselves naturally and uniformly on the liquid surface without overlapping. The unique design makes them interlock by wind pressure, ensuring that they mechanically constitute a coherent cover.” It went on to further describe how the Hexa-Covers could cover 99 per cent of a tank or lagoon’s total surface, eliminating 95 per cent of evaporation. “The floating tiles can simply be poured onto the surface and, under the effects of the wind and movement of the liquid, will form themselves into a cover,” the company continued in describing the technology. “They are so designed that the tile edges will key into each other.” It went on to say there would always be free access to the liquid in a tank for measuring, emptying or observing. In addition, the company said, once installed, there are no operational costs attached to the Hexa-Cover system. There would be a reduction in total costs, with energy savings and a reduction in water consumption. The covers have a life expectancy of 25 years. At the time the company, which had never worked in the oilpatch, didn’t realize the systems would play such a growing role in western Canada’s oil industry. The Hexa-Cover technology was first developed in Denmark to reduce odours from farmers’ manure tanks. Greatario first started testing the technology for a company with extensive heavy oil operations. (It will not identify the company.) That company has since ordered several hundred of the units. Frank, who testified at the Peace River hearings, tells New Technology Magazine that it costs about five per cent of the cost of a VRU to install. Most oil storage tanks hold about 1,000 barrels of crude. With VRUs costing several hundred thousand dollars each, he argues that wide use of the covers could “dramatically reduce” the need for VRUs and could be used on their own as an interim solution or in combination with VRUs. At the hearings, the “ultimate solution” identified by him and others was a combination of a Hexa-Cover installed
PHOTO: GREATARIO COVERS INC.
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over a floating roof, tanks with fixedroof systems, VRUs and a collection or destruction system for vapours. Frank said the use of Greatario’s technology could help suppress petroleumbased emissions such as benzyne, toluene, ethylbenzene and xylenes, and water vapours at the source. “We reduce overall emissions by two-thirds,” he said. The covers, installed by an experienced crew brought to western Canada from Ontario, can be in operation in less than 30 minutes. The units are installed through a “thief hatch” opening in the storage tanks, which is an opening created for observation and other purposes. Given the activity levels in the oilpatch and the sophistication of VRUs, it can take six months or more to have one installed. Meanwhile, a Greatario cover can be in place and can be substantially reducing emissions. At the hearings, Frank also said that once the covers are installed, they “dramatically reduce the amount of hydrocarbon and water-vapour emissions that need to be collected by the VRU,” meaning less VRU freezing or upset conditions will occur. This can reduce the need for flaring.
“Odours caused by heavy oil operations in the Peace River area need to be eliminated to the extent possible as they have the potential to cause some of the health symptoms of area residents.” — Alberta Energy Regulator
Frank, who noted that the company’s new petroleum division is growing so rapidly it has opened an office in downtown Calgary, said it is also working on a cover that might be applicable to the SAGD sector of the oilsands business. The cover would be installed overtop storage tanks used for condensates, which is used to dilute bitumen (prod ucing dilbit) for transport by pipeline, and would reduce vapour loss to the atmosphere. Since companies need to capture the vapours, it would reduce a cost for the industry.
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While SAGD is not as large a market as the CHOPS sector of the heavy oil industry, it would still represent a significant opportunity for the small company, which has 60 employees overall, five of whom work for the petroleum division. The company is awaiting the granting of patents in the United States and Canada for its covers. Jim Bentein CONTACT FOR MORE INFORMATION Terry Frank, Greatario Covers Inc. Tel: 519-469-8169 Email: tfrank@greatariocovers.com
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new tech
TINY TROUBLEMAKERS If allowed to take hold in a pipeline, corrosion-inducing bacteria form colonies that produce a protective slime layer, at which point they are very difficult to eradicate.
PRODUCTION
Slime Slayers
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very day throughout North America, pipelines carry millions of barrels of crude and billions of cubic feet of natural gas. They are considered the safest way of transporting large volumes of hydrocarbons, but when things go wrong, they tend to go wrong in a big way. In August 2000, a natural gas line exploded in southeastern New Mexico near the Pecos River. Eleven nearby campers were killed by the blast and fire. The ensuing fireball was large enough to be seen in Carlsbad, N.M., 20 miles to the north. In March 2006, a transit pipeline in the Prudhoe Bay oilfield on the Alaska North Slope developed a small hole and leaked 5,000 barrels of crude on the tundra. Subsequent inspections of other transit lines uncovered crude staining beneath the insulation, and operator BP p.l.c. had to shut down most of the field to undergo repairs.
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Recently, a 10-inch crude line serving an offshore platform burst after only three years in service. According to Braemar Adjusting, an oil and gas (O&G) sector insurance company, it cost the operator $75 million in remediation. In all three cases, the leading culprit was microbially induced corrosion (MIC). “Approximately 20 per cent of corrosion that occurs in pipelines and tanks is caused by microbes,” says Amin Omar, contract research manager of Edmontonbased Innovotech Inc., an anti-microbe laboratory. “According to Nature Reviews Microbiology magazine, the costs associated with MIC in the O&G sector amounts to $100 million per year in the U.S. alone—and don’t forget the uncalculated environmental damage.” Corrosion within pipelines and related equipment is a big concern in the O&G sector. There are two general types of corrosion: internal and external.
Most pipelines are buried beneath the ground, where various factors can cause the outside of a pipe to pit and corrode. Wet ground, for instance, is an ideal breeding medium for sulphur-reducing bacteria, which produces acidic water (that promotes corrosion) and hydrogen (that may promote cracking). Internal corrosion can occur when impurities are present within the natural gas, crude and refined products being transported. Water can chemically react with hydrogen sulphide and brine to form very corrosive liquids that collect in low-lying spots. Under such circumstances, corrosion rates, which normally average one to two mils per year (a mil is one-thousandth of an inch), can accelerate to several hundred mils per year. Bacteria can also cause significant internal corrosion. “Micro-organisms are introduced into pipelines and tanks through process water,” says Omar, a biofilm
PHOTO: INNOVOTECH INC.
Advanced assay technology combats damaging buildup of microbial biofilms
PHOTO: INNOVOTECH INC.
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expert who holds a PhD in molecular biology and microbial biofilm physiology from the University of Manchester. “Once there, they seek out areas of intermittent or low flow, where they can begin to attach to the surface. These initial micro-organisms are called primary colonizers and, at that stage, are reversible. If they take hold, however, they send out chemical signals to other micro-organisms, and a colony begins to grow. The colony exudes polysaccharides that form a protective biofilm coating, at which time the attachment is irreversible.” Once established, the microorganisms grow to the point where they form a slime layer. “Within the layer, they produce acids or reducing agents that cause pitting in the inner pipeline wall,” says Omar. “If left untreated, the pitting accelerates the corrosion of the steel to the point where a leak or rupture occurs, spilling hydrocarbons and making an expensive mess.” Periodic inspection and monitoring programs are designed to regularly check for corrosion. Lines are dug up and inspected with ultrasonic devices that emit sound waves; the time it takes to reach the inside wall and return to the receiver is directly proportional to the thickness. Internally, coupons (a strip of metal three inches long and one-eighth of an inch thick) are inserted for six months and then removed and examined for corrosion. Smart pigs can also be sent down a line to record the state of the pipe by using calipers, magnetic flux leakage devices and ultrasonic sensors. Unless a sensor comes in direct contact, however, biofilm is difficult to detect, and operators generally deal with it through periodic chemical injection. The most common method of removing biofilm is to put a slug of biocides into the system to break it up. But if operators miscalculate the chemistry or treatment process, they can end up peeling off the outer layer and exposing inner layers to further growth, exasperating the problem. Innovotech offers a process called minimum biofilm eradication concentration (MBEC) assay that helps to finetune biocide treatment. The company’s technology originated with the University of Calgary’s Biofilm Engineering Research Group (BERG), the largest biofilm research centre in Canada. The BERG developed the Calgary biofilm device, an assay tool that measures the effectiveness of various biocides against biofilms that formed in medical devices.
Joe Harrison, assistant professor and Canada Research Chair in Biofilm Microbiology and Genomics at the University of Calgary department of biological sciences, is a researcher at the BERG and one of the developers of the Calgary biofilm device. “Some bacteria are temperature-sensing organisms,” he notes. “When they encounter human body temperatures, their thermo-sensors send out a signal that tells the bacteria to start forming a biofilm community.”
tool. The device consists of a plastic lid with 96 pegs, where the identical biofilms are formed, and one of two fitted bases (one contains 96 corresponding wells and one contains a trough base). “Once the biofilm is fully grown on the pegs, the pegs are exposed to biocides at different dilutions in 96 wells,” says Omar. “This challenge step can be set up for minutes or hours, depending on your study layout. Once the challenge step is over, we recover whatever is left
BIOFILM SCREENING Containing a plastic lid with 96 pegs onto which biofilms can be grown, Innovotech’s MBEC assay allows for the simultaneous testing of multiple biocides at multiple concentrations.
The BERG is largely focused on investigating chemicals (such as nanoparticles of silver) and enzymes that break up biofilms that form in humans. “Children who suffer from cystic fibrosis often have lung infections that are difficult to cure because the pathogens form biofilms,” says Harrison. “Sometimes the lung tissue is so damaged that they have to have lung transplants. We are looking for ways of breaking up or interfering with the biofilms. Clearly, the chemicals or enzymes have to be non-toxic to humans but still effective. To that end, we use MBEC quite a lot. It’s a very good device for investigating anti-microbial susceptibility.” The BERG wanted to find more uses for its technology. In 2004, it spun its inventions into Innovotech. The Calgary biofilm device evolved into the MBEC assay, which is at the heart of the company’s service of identifying bacterial biofilms, evaluating the effectiveness of biocides against bacteria in biofilms and identifying the most efficient ways of eradicating the bacteria and biofilm. The MBEC assay design allows for the simultaneous testing of multiple biocides at multiple concentrations with replicate samples, creating an efficient screening
on the pegs to calculate the log reduction compared to untreated controls.” Innovotech has assayed sulphatereducing bacteria such as Desulfovibrio salexigens, acid-producing bacteria like Clostridium formicaceticum, general heterotrophic bacteria such as Clostridium oceanicum and a wide array of mixed micro-organisms. “We have tested all kinds of biocides, and we either can use oil-based challenge media or water-based challenge media,” says Omar. “The assay can be easily manipulated to simulate the real environment, such as the presence of heavy crude oil, sediments, dynamic environment rather than static, single and multi-species of biofilm, et cetera.” Innovotech’s technology is slowly gaining traction in the O&G sector. NALCO Champion, a Houston-based service company, supplies specialty chemicals that operators use for drilling, stimulation, production, transport and storage. “The industry now recognizes that there is a significant MIC issue and that biocide treatment is not highly effective in certain applications,” says Vic Keasler, NALCO Champion’s research development and engineering manager, microbiology N ew T echnology M aga z ine | M AY 2 014
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and industrial biotechnology anchor. “You can’t simply run a higher dose as many of these biocides become economically unfeasible at higher doses or become incompatible with other chemicals that are in use.” In order to find a more effective treatment protocol, NALCO Champion has been conducting extensive research. “We have been using Innovotech’s MBEC assay as an analytical tool to screen a large array of biocides and treatments,” says Keasler, who holds a PhD in molecular virology and microbiology from Baylor College of Medicine and has numerous publications in the areas of microbial pathogenesis and petroleum microbiology. “We narrowed hundreds of combinations down to the best performing products, and we have then been able to focus our research on how they will perform in an oilfield system. We need to look at their effectiveness under different turbulence and flow conditions. Once we have ascertained their effectiveness in real-world conditions, the next step is to deploy them for testing in the field. The end goal is to find a chemistry and process that is faster, more effective and more cost-efficient,” Keasler says. Innovotech, which currently employs 13 staff and has annual sales in the $1-million range, is looking to expand. “O&G has traditionally accounted for five to 10 per cent of our business,” says Omar. “I recently saw a report that a pipeline company had purchased $10 million’s worth of chemicals from a biocide supplier. Clearly, the need for biocides is huge, but so is the need to be able to target your biocide usage. When it comes to conventional treatments, many companies are shooting in the dark. We can test 300 cocktails for $10[000]–$15,000; you can spend $100,000 per year and know exactly what you are aiming for and use that $10-million biocide budget wisely and effectively.” And the technology has applications in areas that go far beyond the energy sector. “Its use in the O&G industry sounds like a logical extension of the technology,” says Harrison. “But there is no aspect of our lives that biofilms don’t touch; there are lots of other sectors that it can benefit.” Gordon Cope CONTACT FOR MORE INFORMATION Amin Omar, Innovotech Inc. Tel: 780-448-0585 Email: amin.omar@innovotech.ca
new tech
DRILLING
Making Money With Mud Environmental innovator touts drilling-fluids-recovery system
ENHANCED SEPARATION Fuse Enviro’s RecoverTank technology uses a centrifuge for enhanced separation of drilling mud’s solid and liquid constituents.
PHOTO: FUSE ENVIRO LTD.
T
he messiest part of drilling oil and gas wells may just be the most profitable, at least for companies that make drilling-fluids recovery their business. In the oil industry’s early days, drilling waste was more easily disposed of than it is today, with little thought given to the life cycle of wastes or their longterm environmental effects. Increasing vigilance from regulators and environmentalists means producers and drilling contractors can’t run the risks they once did in handling drilling muds and wastes. Today’s rules are a world away from the regulatory landscape that prevailed in the 1970s and 1980s when relatively lax environmental rules—at least by today’s standards— governed much of the industry, including the drilling sector. Across the board, tighter rules mean drilling contractors and operators need
to pay more attention, both to what’s going into and what’s coming out of the well, since much of the drilling fluid being used will have to be recovered and disposed of. For the waste-recovery team at Fuse Enviro Ltd., job number one is collecting drilling waste on the lease, then treating it so the least amount possible will have to be transported for disposal at the end of the day, while much will be recovered and recycled. While the company’s work is largely about the environment, it’s also about the bottom line. Today, recovering drilling fluid means cost savings for most well operators. In the end, they can reuse drilling mud and spend less time, effort and money disposing of solid drilling waste, since the amounts involved will be sharply reduced, according to Fuse Enviro. Key to the company’s solution is the mobile RecoverTank that the Fuse team
designs and manufactures. In a nutshell, the system takes drilling waste after it goes over the shale shaker and passes it through a cone-shaped, spinning centrifuge, which separates the mud’s liquid and solid components. The solids that remain are disposed of in the same way other drilling wastes are: typically by being trucked away. Thanks to the RecoverTank’s screening and centrifuging, far less solid waste remains than would be the case without the system, which means there’s less to move away and discard. From an operator’s point of view, the main appeal of the RecoverTank system is economics. While not cheap to rent, the system allows producers using oil-based muds to recover drilling mud and 80 per cent of the other reusable ingredients in the mud. Reusing drilling mud means having to buy less in the future, and the recovered mud is N ew T echnology M aga z ine | M AY 2 014
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BETTER RECYCLING By recovering more drilling mud and other reusable components, the RecoverTank system both produces valuable products and reduces disposal costs.
valuable too, according to Brian Millett, business development manager with Fuse Enviro. “From the drill cuttings, we recover quite a large volume of drilling fluid, and it’s typically worth $1,000–$1,500 per cubic metre,” says Millett. “On a typical 2,500 to 3,000–metre invert section of a well, we can recover between 40 and 60 cubic metres. It doesn’t take long for the value to add up.” Conservatively, Millett estimates that much drilling mud is worth $40,000– $60,000—that’s money that would put a dent in most producers’ drilling-mud
budgets. The economics of the system depend on more than well parameters, however. Fuse Enviro’s customers have a choice when it comes to billing. With performance-based billing, they pay per cubic metre of mud recovered from the drilling waste. The more that’s recovered, the more they pay. On the other hand, with day-rate billing, customers pay a flat, per diem rate for the RecoverTank, regardless of how much oil they recover. For customers who recover plenty, there’s an obvious benefit to day-rate billing, and Millett says most customers figure out the
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relative advantages of the two billing options fairly quickly. Due to the rising cost of disposing of oil-based drilling muds, including trucking costs, Millett says horizontal wells—where oil-based muds are popular—usually make more economic sense for drilling-fluids recovery. While the RecoverTank also works on water-based muds, the ease of conventionally disposing of these fluids makes the economics relatively less attractive. Even when weighing the economics of using the system on horizontal wells that use oil-based mud, there’s a sweet spot, Millett says. That’s the well’s build section. Typically, after drilling the surface hole, an operator sets the surface casing and switches over to oil-based mud. At that point, from where the well trajectory changes angle and begins turning, until it reaches horizontal, lies the region where the RecoverTank typically recovers the most fluid, thanks both to high penetration rates and the often larger cuttings being generated, Millett says. Once the well is horizontal, things change again, and the cuttings typically become smaller and more ground up, resulting in even smallersized cuttings that are more difficult to recover fluid from. Currently, Fuse Enviro operates five RecoverTank systems, two in Canada and three in the United States. The company could not, however, locate a customer willing to discuss his or her experience with the system on the record. James Mahony CONTACT FOR MORE INFORMATION Brian Millett, Fuse Enviro Ltd. Tel: 403-451-0133 Email: bmillett@fuseenviro.com
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