NTM Supplement - Horizontal Drilling and Multistage Fracking by JWN

nove m b e r 2013

SUPPL EMENT

HORIZONTAL DRILLING AND MULTISTAGE FRACKING

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spawn new tools and processes to squeeze more resources from tougher reservoirs

ClEaring THE HurDlES For rEliaBlE CEMEnTED SlEEvE CoMplETionS Horizontal Cemented Completions are our focus at i-TEC. To date, weâ&#x20AC;&#x2122;ve installed our systems in over 80 wells, using over 2,700 i-Frac CEM sleeves in 650 discrete frac stages. With installations of 90+ sleeves per well, our successful track record is growing by leaps and bounds!

The i-Frac Cemented Completion System i-Frac CEM sleeves Ball-activated with multiple sleeves per stage; up to 26 stages available.

Dissolv-A-Ball Dissolvable frac ball reduces risk and makes cleanout optional.

BPSâ&#x201E;˘ Port Sub Toe initiation sub with multiple redundancies. More cost-effective than perforating run.

i-Frac is part of a complete line of horizontal completion solutions offered by i-TEC, a Trican company.

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technologyprofile

Multizone Completions Taken To New Level With i-Frac System The concept behind the i-Frac system was to create a very simple way of maximizing the number of fracture initiation points in a wellbore using ball-drop sliding sleeve technology. The i-Frac completion system can either be deployed as an open hole or cemented completion, and allows up to 440 fractureinitiation sites in a wellbore, which is significantly higher than the industry standard of 50–60. “This is a game-changing technology, which is allowing companies that are doing plug-and-perf operations to gain significant operational efficiencies during the completion. The i-Frac system really is the best of both worlds: the efficiency of ball-drop operations with isolation accuracy, and the future ability to re-frac,” says Trican Director of Completion Systems and Downhole Tool Services Andrew Buzinsky. Now that the horizontal multistage completions market is becoming mature, customers are beginning to experience the limitations of the open hole technique, particularly when it comes to aging wells. Since starting its completion initiative, Trican has put together a formidable portfolio of solutions for its customers. “We have the ability to do a ball-drop style cemented completion with a large number of valves, or we can do similar interval density in an open hole completion—if that makes sense for the reservoir and customer—as well as coiled tubing fracturing with sleeves that allow for production management with the new i-Can sleeve,” Buzinsky says. The i-Can sleeve, which uses North Sea proven sealing technology, provides a

cost-effective solution in Canada and the U.S. for low-reservoir pressure wells that require fracturing down the annulus on coiled tubing. “The big advantage for customers is that you don’t need a coiled tubing packer to isolate between stages, which can be a source of non-productive time,” Buzinsky notes. “In addition, the sleeve can be opened and closed hundreds of times, which allows operators to manage their production over the life of the well.” When Trican’s completions group went looking for innovative technologies, “it was really important to us to not only find a technology that was in line with industry trends, but also a company that placed the same value on service quality, technology and customer service that Trican does,” says

Buzinsky. Trican found that fit with i-TEC Well Solutions, which had developed new sliding sleeve technologies for markets in the North Sea. Trican’s Completion and Downhole Tool service line is now active in Canada and in all major shale plays in the U.S., in Norway—which serves as a jumping off point for work in the Middle East and the Far East—and in Russia, where Trican is the country’s largest fracturing service provider. Although relatively new to the completions market, Trican has set the bar high in terms of establishing new industry records. Recent achievements include being the first to deploy dissolvable frac ball technology in a North Sea completion, as well as successfully completing a well with 97 sliding sleeves in the demanding Eagle Ford reservoir of the U.S.

Ball-activated multi-zone frac valves ready for cemented horizontal completion.

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N e w T ec h N o lo gy M ag a z i N e s u p p le m e n t | n ov e m b e r 2 013

EDITOR'S VIEW

www.newtechmagazine.com

EDITORIAL

Cusp Of A Renaissance

CONTRIBUTING WRITERS godfrey budd, gordon cope EDITORIAL ASSISTANCE MANAGER marisa sawchuk | msawchuk@junewarren-nickles.com

t’s amazing what a little bit of technological innovation can accomplish. The development of multistage fracturing combined with horizontal drilling to make accessible massive quantities of shale gas and tight oil continues to reverberate across North America, and is bound to spread elsewhere as the experts in the field unlock the resources found in the most promising areas. The impact on energy production alone is transformational, as the decades-long oil and gas deficit in the United States, and its resulting obsession over energy security, fades amid talk of it not only meeting its own needs, but also becoming an energy exporter. Consider that U.S. oil imports climbed to over 60 per cent of consumption by 2005 before tight oil production began to push back the tide, cutting imports to today’s level of 35 per cent—back to 1973 levels. But the shale gas/tight oil boom has done more than bolster production. It is starting to transform economies across the continent, creating new jobs and reawakening manufacturing, taming trade deficits and padding government revenues, and putting more money in consumers’ pockets. In a report released in September, IHS tallied some of the numbers. It estimates the “unconventional oil and gas revolution” had increased disposable income by an average $1,200 per U.S. household in 2012 due to savings from lower energy costs in the form of reduced energy bills and cheaper goods and services. Upstream, midstream and downstream energy and energy-related chemicals jobs supported by the revolution will climb to 3.3 million by 2020, IHS says, adding that the once bleak outlook for the petrochemical industry has undergone a complete turnaround due to the availability of low-cost feedstock, leading to new investment and capacity. Similarly big impacts are expected north of the border. Alberta leads the country in economic growth and employment, while British Columbia, blessed with massive shale gas reserves in its northeastern corner, is hoping to ride exports of liquefied natural gas to future debt-free prosperity. With as many as 10 proposed liquefied natural gas projects, including three that have secured

EDITOR maurice smith | msmith@junewarren-nickles.com

export licences, it hopes to be exporting gas by 2018—and building a “prosperity fund” that could reach $100 billion over 30 years by taxing those exports. To the east, prospects look bright if and when jurisdictions can sort out their regulatory regimes and allow application of the new extraction technologies to promising plays. Quebec, for example—under a current moratorium on extraction of its shale gas—has shown significant potential. Under two scenarios for developing the Utica Shale examined by the Canadian Energy Research Institute in March—one involving maintaining the province’s current production of 500 million cubic feet per day, and one lifting production to 1.5 billion cubic feet per day and exporting the balance—it found the cumulative addition to Canadian gross domestic product from 2012 to 2036 would amount to $37.3 billion and $112 billion, respectively. Though stagnating natural gas prices— due in large part to the surplus created by the very success of horizontal multistage fracking technology—have put a temporary lull on gas drilling, Kevin Heffernan, president of the Canadian Society for Unconventional Resources, said in a speech in June that the natural gas industry is on the “cusp of a renaissance,” having already undergone an evolution and a revolution in recent years. “There is, quite simply in western Canada, a staggering amount of gas that is technically recoverable today,” he said, though that shouldn’t imply it will be easy to access. “We’ve changed over time. We’ve moved down into more technically challenging, more expensive and larger reservoirs, and that really has an impact for all the stakeholders in the industry.” In this supplement to New Technology Magazine, we examine how the industry is dealing with those more technically challenging reservoirs, using new gadgets, techniques and innovations developed by a range of companies from the largest multinational service firms to the local junior start-up. The solutions they offer are evidence the industry is already meeting that challenge. Maurice Smith

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tec H n o lo gY advan c es

The latest and greatest Service companies roll out diverse range of new technologies to optimize horizontal multistage fracking

orizontal drilling and multistage hydraulic fracturing have revitalized western Canada’s non-oilsands oil and gas sector. According to recent figures, 55 per cent of wells drilled in Canada in 2012 were horizontal, with the horizontal length averaging 1,817 metres (5,960 feet), up 50 per cent from 2007. The targets include the Montney, Duvernay, Horn River, Cardium and a host of other unconventional reservoirs. The prizes are substantial. The Duvernay shale holds approximately 100 billion to 120 billion cubic feet per section of gas in place with liquids in the 100–160 barrels per million cubic feet (mmcf ) range, with expected average well recoveries of approximately one million barrels of oil equivalent. Earlier this year, Yoho Resources Inc. completed a Duvernay well in the Kaybob region with a horizontal wellbore of 1,536 metres and a plug and perf completion consisting of 15

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stages and 51 perf clusters. After extensive testing, the well flowed 6.3 mmcf per day, with 106 barrels of field condensate per mmcf of gas. But there are substantial risks to unconventional plays. The drilling portion of Yoho’s well cost $4.5 million, and the plug and perf completion ran another $6.6 million, for a total of $11.1 million. Horizontal drilling and multistage fracking are complex technologies that can untrack a well when tools get stuck or procedures go awry. That’s why operators are always looking for improved technologies and safer procedures, as well as ways to balance costs and benefits. “Successfully operating in an unconventional resource play requires optimizing a complex mix of financing, risk, logistics and other factors,” says Sean Canning, global product champion for multistage stimulation at Halliburton. “The operator is looking for the optimal completion design; the fact that one

iMaGe: BaKer HUGHeS inCOrPOraTeD

By Gordon Cope

tec H n o lo gY advan c es

TAKING AIM Baker Hughes’ AutoTrak Curve rotary steerable system meets the challenges of drilling unconventional plays and extendedreach laterals. The Kymera hybrid drill bits combine PDC and rollercone bit technology for smoother drilling, improved torque management and precise steerability.

method may result in greater production has to be balanced with the other decision drivers.”

HORIZONTAL DRILLING Drillers and service companies are constantly innovating with new processes and kits in order to reduce costs and increase productivity. Rig builders are now incorporating many of the automated drilling rig technologies developed offshore into onshore rigs, including self-erecting hydraulic telescoping masts, hydraulic top drives, torque wrenches, automatic pipe handlers and hydraulic power tongs. In July, Trinidad Drilling Ltd. announced plans to build one of the most advanced rigs for a shale gas operator working in the Liard Basin, which takes in an area straddling the borders of the Northwest Territories, Yukon and British Columbia. Although the company declined to reveal the cost

of the rig or its customer, it noted the unit would have an automated rig-moving system, a 1.25-million-pound hook load, 3,000-horsepower alternating current power rating and a depth capacity of 8,000 metres. The rig is being assembled in the company’s Nisku, Alta., manufacturing facility and is expected to enter service in the second half of 2014. Baker Hughes Incorporated’s AutoTrak Curve rotary steerable system (RSS) has surpassed the two-million-foot milestone since its launch in 2012. The system can drill vertically, curve through up to 15 degrees per 100 feet, and continue on for the horizontal sections in one run, eliminating two trips. The direction of the steerable tool is measured while drilling (MWD) using a directional module that measures inclination and azimuth using triaxial magnetometers and gravity sensors. The system contains a transmitter/receiver to send data uphole through the mud system, and receive commands

N e w T ec h N o lo gy M ag a z i N e s u p p le m e n t | n ov e m b e r 2 013

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back downhole. The programmable system can make real-time adjustments to the steering target while drilling. Operators have reported reduced drilling time up to 60 per cent of the rig time per well. Logging while drilling, or LWD, enables the operator to keep the tool in the productive reservoir. This fall, Schlumberger launched the MicroScope HD high-definition imaging-whiledrilling service. The LWD system is based on resistivity, and offers a vertical resolution of 0.4 inches. The tight focus allows operators to determine fracture characterization and gain a strategic understanding of fracture networks. The system works equally well in carbonate, sandstone and shale reservoirs, and helps operators to identify potential mud-loss zones and develop more effective stimulation designs. Schlumberger also offers the TDDirect casing-whiledrilling service that combines casing and directional drilling in one run. The bottomhole assembly (BHA) consists of RSS, LWD and MWD modules attached to an underreamer. The BHA, in turn, is attached to the bottom of the casing shoe joint by a drill lock assembly that allows the casing to be rotated during drilling. Once total depth has been reached, the BHA is retrieved prior to cementing. By drilling and casing in one run, Schlumberger notes that drilling and casing running time can be reduced by more than 30 per cent. Drill bits are constantly evolving. Traditional roller cone bits are good for drilling through hard rock, but slow down in softer rocks like shale. Polycrystalline diamond compact (PDC) bits do well in shale, but break down in hard rock. Baker Hughes developed the Kymera hybrid line of bits to deal with both lithologies. The new line has roller cones and several PDC arms. Field experience showed drilling rates improved by up to 62 per cent, and single-bit run lengths were extended more than 200 per cent. In applications in inter-bedded formations in western Canada, the bit has performed 60–100 per cent faster than competing bits. Lance Chorney is head of drilling for Vesta Energy Ltd., a Calgary-based junior oil company. Vesta targets the Glauconite, a tight sandstone formation in central Alberta, with 800-metre laterals. The cost of drilling each well is $1 million, completions are $1 million, and tie-in and other surface expenses are $500,000, for a total of $2.5 million per well. “Bit stability is a big concern,” says Chorney. “We use a flat-head bit from the takeoff to the dogleg, but then switch to a pointed bit for better steerability in the horizontal leg.” During a recent horizontal drilling congress in Calgary, Chorney had an opportunity to learn more about combination bits. “They are a good idea because anything that saves a trip reduces rig costs, but renting the bits themselves adds

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

PHOTO: BaKer HUGHeS inCOrPOraTeD

SHADOW FRAC Baker Hughes’ new Shadow Series Plug has eliminated the requirement to drill out, which substantially reduces operators’ completion costs.

tec H n o lo gY advan c es

EASE OF ACCESS Baker Hughes’ Alpha Sleeve gives operators a reliable way to access the first stage of their cemented-in liner systems, saving the costs of coil tubing perforating or wireline tractoring.

about one-third to your bit costs, so you have to balance out the benefits,” he notes. “We’re not a large company, so we have to be conservative; I would want to wait and see some stats before making a decision.”

iMaGe: BaKer HUGHeS inCOrPOraTeD

MULTISTAGE FRACTURING RapidSuite is Halliburton’s line of multistage stimulation frac sleeves that provides specific solutions to a wide variety of reservoirs. “At Halliburton, we are continually refining and adding tools to our tool box to give the operator greater flexibility and choice,” says Canning. RapidStart Initiator CT is a specialty tool that allows an operator to test the casing prior to fracking in cemented and open-hole applications. “Regulations require the operator to test the integrity of the casing before fracking,” says Canning. “Prior to the development of the RapidStart Initiator CT, you had to run a plug, do the test, then retrieve the plug. It added to the completion cost and completion time, and there was the potential to get the plug stuck in the hole.” The RapidStart Initiator CT is run to the toe of the wellbore. “As the pressure increases to the test point, the toe sleeve meters open and this allows the operator to validate the integrity of the casing and meet regulatory requirements,” says Canning. “The tool reduces the time spent on pre-frac integrity testing by 40 per cent, which is significant. People who have used it since its introduction in July have said it’s been a long time coming.” Halliburton’s RapidShift sleeve is used in multistage frac completions and allows the operator to selectively isolate

portions of the reservoir. “Let’s say you’re getting water cut at the heel of the well; you can close the sleeve using a mechanical shifting tool and reduce the negative impact that water can have on production,” says Canning. Halliburton’s mechanical shift sleeve allows for alternate sequence fracking in coiled tubing operations. “You can go in and open sleeve one, frac zone one, close sleeve one, then repeat process for sleeve three, then go back and repeat process to sleeve two, then on to sleeve four,” says Canning. “It allows for greater fracture complexity. Right now, it is mostly being used in the Anadarko Basin in Oklahoma, but it has potential applications in Canada.” Baker Hughes has also added several multistage innovations. “The FracPoint NXT is a ball drop multistage sleeve, but it’s 45 per cent shorter than our previous model,” says Marc Carriere, product line manager, completions, for Baker Hughes. “It’s more compact and easier to insert at the rig site. It doesn’t need pup joints, so there are no costs related to that. It’s just as robust and reliable.” IN-Tallic is a drop ball that is designed to disintegrate after its job of opening and fracturing the interval is done. “It’s made of controlled electrolytic metallic nanostructured material that is stronger than some mild steels,” says Carriere. “When the well is put into production, brine fluids from the reservoir dissolve the ball.” Baker Hughes is also introducing alpha sleeves in Canada. “It’s the first sleeve in the hole, and it sits at the toe during a plug and perf operation,” says Carriere. “Normally, you need coiled tubing and wireline to gain access to the

N e w T ec h N o lo gy M ag a z i N e s u p p le m e n t | n ov e m b e r 2 013

"In the end, it's essential to do A LOT OF SCIENCE and run the technologies in order to understand your reservoir and OPTIMIZE PRODUCTION." — Lance Chorney, head of drilling, Vesta Energy Ltd.

first interval, but the Alpha Sleeve is pressure activated, so you use pump pressure to open it, eliminating coiled tubing and wireless costs.” Schlumberger has also developed a wide array of hydraulic fracturing technologies. “Micro-seismic surveys are very useful for collecting data in regards to how a rock is cracking during a hydraulic fracture,” says Rick Klem, marketing and communications manager for Schlumberger Well Services. “A geophone array is placed downhole, as close to the fracture as possible. The data is then recorded and analyzed with our StimMAP service to tell you the location, geometry and dimensions of the hydraulic fracture system. This is especially valuable in newer plays like the Duvernay where you are trying to determine if the stimulation is going where you want it.” Schlumberger has launched HiWAY, a channel proppant technology. “We pulse a fluid/fibre mix into the fracture system in a manner that creates open channels in the proppant,” says Klem. “We have done 20,000 stages using the technology, and our research shows that production can increase by as much as 20 per cent. You also use 40 per cent less fluid and 60 per cent less proppant, which gives you savings in materials, time and other costs.” Schlumberger’s Mangrove is the first software package that is specifically designed to simulate fracturing in unconventional

SEARCH Get Connected! CSUR Members are connected to each other, to new technologies and to the pulse of our Unconventional industry. Membership includes access to exclusive technical luncheons, discount rates at CSUR events, daily media monitoring and much more. Visit

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iMaGe: BaKer HUGHeS inCOrPOraTeD

tec H n o lo gY advan c es

TEC H N O LO GY ADVAN C ES

plays. “It allows you to determine if you are using the right number of fracs, and whether they are too short or too long,” says Klem. “It allows you to plan how to surgically fracture your reservoir.”

THE FUTURE Industry participants note a trend to customize technology to specific formations, rather than a one-size-fits-all approach. “For the Horn River formation [in northeastern British Columbia], you need high pump rates to deliver lots of fluids fast,” says Carriere. “Ball drop and coiled tubing cause restrictions in the wellbore, so it’s more difficult to deliver high pump rates. The fracturing technology that best fits on the Horn River is plug and perf, which imposes no restrictions on the borehole.” Service companies are also seeing a trend toward more cement wellbore completions, as opposed to open-hole. “Part of this is due to operators being concerned with wellbore integrity issues, and part of it is due to regulatory preferences driven by environmental concerns,” says Canning. “The RRC [Railroad Commission, a regulatory agency] in Texas, for instance, is more partial to cement completions.” Operators are concerned with how well a stimulation works; does perf and plug outperform multistage frac sleeve

or multistage coiled tubing operations? Are they getting the optimum spacing? “The best way to quantify all that is through measurement during a stimulation,” says Canning. “I think in the future we will see fibre optic cable introduced into the well during stimulation so that you can monitor the frac in real time and see where the stimulation is going.” “A big driver right now in the Canadian market is increasing the efficiency of the newer plays by finding the technologies that work best,” says Peter Rottler, pressure pumping services technical manager for Schlumberger Canada. “Another big driver is increasing the success rate of fracturing. In the longer term, we are going to see more incentive to understand what we’re doing downhole in order to determine if we are optimizing our hydraulic fracturing.” “Many of the targets for horizontal wells in Canada are new plays in new areas, so there isn’t a lot of information to go on,” says Chorney. “With technology, you have to exercise caution, and you have to balance the advantages with affordability.” That said, however, drillers appreciate the efforts of service companies to deliver the kit that makes their work that much easier and more effective. “In the end, it’s essential to do a lot of science and run the technologies in order to understand your reservoir and optimize production,” he says.

Get the Complete Picture • NEW video camera/production logging combination tool • Full motion, high definition, color or black and white video • Robust camera design for horizontal deployment • Wider angle camera for logging larger wellbores • Most experienced camera operators in the industry

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T ec h n o lo gy M ag a z i n e s u p p le m e n t | N ov e m b e r 2 013

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Offset Frac Monitoring in Canada

ichael Beck, founder of Surface Solutions Inc. (SSI), has been an innovator since 1999, with his foot firmly planted on the gas pedal, driving surface data acquisition into the future. Headquartered in Grande Prairie, with locations across western Canada, SSI specializes in oil optimization, regulatory compliance and completions services, including high pressure, high accuracy DFIT (Data Frac Injectivity Testing), and critical offset frac monitoring that helps companies comply with AER Directive 083. SSI’s highly accurate high-resolution web-based platform is encrypted, and provides end users an easy interface to log into their wells. Logging into offset wells can be done on site, in Calgary, or from home, via desktop, tablet or smart phone. It was approximately six years ago that SSI implemented real time data transmission to its surface data acquisition equipment, making it possible for clients to see their pressure data on remote sites. Soon after, SSI expanded into offset frac monitoring, after seeing a need within the industry. “With horizontal drilling, I

“Surface Solutions is positioned as a thought leader in the industry, ahead of the need. I’ve been answering questions based on experience, long before the directive hit oil companies’ desks.”

could tell that wellbores and well spacing were getting closer, and there were going to be interwellbore communication issues from time to time,” Beck notes. “Developing my instruments with Canada’s top oil and gas producers helped guide a product that has been developed solely on customers’ needs.” In January 2012, after SSI had been monitoring offset wells for several years, there was a blowout incident in Innisfail, which resulted in Enform creating a committee focused on exactly what SSI had already been doing: offset frac monitoring. This focus group, IRP 24, consulted with Beck several times in order to obtain industry input. Fast forward to May 21, 2013, and Enform’s IRP 24 became an AER directive, now known as Directive 083, which was mandated Aug. 21, 2013. “Surface Solutions is positioned as a thought leader in the industry, ahead of the need. I’ve been answering questions based on experience, long before the directive hit oil companies’ desks,” Beck says. Going forward, SSI is broadening its capacity and helping take a product that was originally identified to help protect the

environment and public safety into reservoir analysis, frac programming, and competitor litigation, in terms of competitive drainage issues that can arise from one producer having adverse effects on another producer’s assets in the wellbore or producing zone. Other services that SSI has been offering since inception have come back into play, strengthening the conclusion of interwellbore communication. Such things as surface casing, vent testing, fluid-level determination and gas migration testing all enhance an already strong process and product. It’s no surprise that SSI is growing rapidly, with locations in Grande Prairie, Red Deer, Calgary, and Estevan, Saskatchewan. “The reason to call Surface Solutions for offset frac monitoring is that SSI can prevent companies from going places they don’t want to go in terms of harming the environment, human safety, and ground water, which can lead to huge costs—not to mention a negative public perception of hydraulic fracturing.” Michael Beck continues to innovate in areas where his competitors follow—and that’s what sets SSI apart in the optimization industry.

DOUBLE PAGE TECH PROFIL Surface So 5452

Please contact

for more information: Michael Beck Surface Solutions Inc. T: 780.538.1074 E: mikeb@surfacesolutions.ca www.surfacesolutions.ca Grande Prairie | Red Deer Calgary | Estevan

LE - (as far forward as possible) olution Inc. 264

Your Problems

Your Solution

❱ Interwellbore Communication ❱ Regulatory Compliance—Directive 083 ❱ Risk of Blowouts, Spills, Groundwater

Offset Frac Monitoring from Surface Solutions

Contamination

❱ Negative Publicity and Activist Attention ❱ Frac Cost Escalation ❱ Liability Issues and Risk Mitigation

❱ Quick, Cost-effective, Reliable, Accurate ❱ Real Time Streaming Data, Secure, Recorded

PHOTO: Sanjel Corporation

TEC H N O LO GY ADVAN C ES

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

tec H n o lo gY advan c es

Innovation

for horizontal multi-fracs SMEs are stepping up to the plate with new tools, systems and software By Godfrey Budd

hen it comes to the need for an oilpatch equivalent of the proverbial better mousetrap, it is almost, but not quite, as if the mice were the ones that came up with the goods. Time and again, it seems, it is the small- to medium-size enterprises (SMEs) that step up to the plate with an innovative tool or software program. There has to be a reason why service majors keep buying service-sector SMEs. The era of horizontal drilling and multistage fracking has seen costs per well skyrocket. It has also been a game changer for many aspects of field operationsâ&#x20AC;&#x201D;from assigning priorities for drilling programs to methods and new technologies for multi-frac completions. Service-sector SMEs keep meeting the challenges. Some issues, of course, hardly change. They might become more urgent, though, in a higher-cost environment. Drilling rate of penetration (ROP) is perhaps a case in point.

When Wavefront Technology Solutions Inc., with expertise in fluid flow technologies for enhanced oil recovery, developed a rapid pulse tool (RPT) for cavitation induction, it teamed up with Sicotte Drilling Tools Inc., a Canadian supplier of custom drill bits and specialty downhole tools founded in 1976. The partnership makes sense as the two companiesâ&#x20AC;&#x2122; respective technologies are complementary when it comes to the RPT, says Dave Herman, vice-president of business development at Sicotte. Cavitation, which involves the formation of liquid-free zones or bubbles in a liquid, usually occurs when a liquid is subjected to rapid changes of pressure that cause the formation of cavities where the pressure is relatively low. When subjected to higher pressure, the voids implode and can generate an intense shockwave. Herman points out that the steel propellers of ships and boats become pitted because of this action.

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Effidrill analysis wells - Bit run comparison Four wells selected between 2,350 and 2,900 metres 8-13-

6-14-

13-15-

15-24-

2,360 2,380 2,400

4.4 152

2,420

Smith / XRi35 1.75 / 7/8 2.6 Stg / HR

4.2

191

Baker / VGD-3ODX 2.12 / 7/8 5.0 Stg / HR

4.5

Baker / QD404X 2.12 / 7/8 2.9 Stg / HR

2,440 2,460 2,480 2,500 2,520 2,540

2.6

132

2,560

Smith / XR40 2.12 / 7/8 2.9 Stg / HR

2,580

2.0

Reed / R28AMP 2.12 / 7/8 2.9 Stg / HR

10.0

Security / FX64R 1.83 / 7/8 3.8 Stg / HR

2,600 2,620 2,640 2,660 2,680

3.4

118

177

3.5

Smith / XR40 1.83 / 7/8 2.9 Stg / HR

Reed / MSH613D 1.75 / 7/8 22.9 Stg / HR

7.5

241

Smith / MDSI 13 1.50 / 7/8 2.9 Stg / HR

4.6

Security / FX75R 1.50 / 7/8 2.9 Stg / HR

2.5

155

Reed / R37DH2 2.12 / 7/8 4.8 Stg / HR

Smith / MSI713 1.75 / 7/8 2.9 Stg / HR

2,700 2,720 2,740

6.4

3.1

2,760 2,780 2,800

Varel / VM613R 1.83 / 7/8 2.9 Stg / HR

6.7

217

Security / FX64R 2.12 / 7/8 3.8 Stg / HR

Smith / XRi35 2.12 / 7/8 2.9 Stg / HR

5.8

174

Reed / RD33DH2 2.38 / 7/8 4.8 Stg / HR

2,820 2,840 2,860 2,880 2,900

SOUrCe: eFFiDrill SOlUTiOnS inC.

The above chart shows the drilling equipment used on one well versus others. Taken in context with the drilling parameters and resulting rates of penetration, it is helpful in identifying the probable causes of drilling inefficiency.

The authors of the Society of Petroleum Engineers (SPE) paper 162726 applied this principle using a tool designed for the same purpose as the RPT. But the device described in the paper included an impeller, piston and an impeller shaft, unlike the Wavefront/Sicotte RPT, which has no moving parts. The device, called a hydraulic-pulsed cavitating-jet generator, did, however, perform along the lines that cavitation theory had suggested. “The combination of hydraulic pulsation jet and cavitating jet can change the flow field at bottomhole and the rock stress state to enhance rock-breaking and cuttings-cleanout efficiency and improve the penetration rate of deep drilling,” according to the SPE paper. The authors of the paper, which received approval in April 2012, note that “a large number of field tests of hydraulic-pulsed cavitating-jet drilling technology with multiple drilling assemblies have been conducted.” Various fluid densities and depths were used in a series of field tests and the deepest well was 6,062 metres. “As a result, the average ROP was enhanced by approximately 16.7 per cent to 104.4 per cent,” the authors state. “The paper describes the same pressure our tool uses. Ours is less complex, more durable and does the same thing,” Herman says.

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

As drilling mud flows through the RPT, internal flow dynamics create a vortex inside the tool, causing a pulsing action that results in cavitation bubbles at the formation face, and the energy released at the bubbles’ implosion assists in rock fatigue. “The cavitation tool has three effects on the bottomhole: hydraulic pulse, instantaneous negative pressure and cavitating erosion,” Herman says. Benefits include reduced hydraulic chip-down and better hole cleaning. “It’s also believed to improve extended reach, help with better steering and remove dead zones in the flow pattern,” he says. The key utility, though, of the RPT, which is staged between the mud motors and the drill bit, is its ability to improve ROP. It was commercialized earlier this year and various companies have been using it. Depending on the well, rig and other factors, metrics from Talisman Energy Inc. have included ROP increases ranging as high as 94 per cent.

DRILLING STABILITY Control, stability and a precisely calibrated direction are among the essentials of horizontal drilling, but the question can be, how much should you spend? “If you want three-directional control, you go to rotary steerable. If you’re on a tighter budget and want some control on a horizontal, you use a stabilizer in

tec H n o lo gY advan c es

Test field wells on seven rigs in 2010 Chronological well times for one section with non-productive time Drilling sections not normalized by average meterage in the section 18

Q:2010/4 A:9.75 M:13.00

Q:2010/2 A:6.63 M:4.88

16 Q:2010/1 A:11.79 M:11.63

Q:2010/3 A:6.61 M:7.00

Rig B

Rig A

Rig B

Rig A

Rig B

Rig A

Rig B

Rig A

Rig B

Rig A

Rig B

Rig A

Rig F

Rig B

Rig A

Rig B

Rig A

Rig F

Rig A

Rig F

Rig A

Rig F

Rig A

2 Rig B

Hours

1 11.50 0.00

2 | | 7.50 0.00

3 9.25 0.00

4 | | 14.25 0.00

5 11.75 0.00

6 | | 16.50 0.00

7 4.75 0.00

8 | | 11.75 0.00

9 10.00 0.00

10 | | 4.50 0.00

11 5.00 0.00

12 | | 3.75 0.00

13 11.75 0.00

14 | | 4.00 0.00

15 7.75 0.00

16 | | 7.25 0.00

17 4.00 0.00

18 | | 7.00 0.00

19 4.50 0.00

20 | | 15.00 0.00

21 4.00 0.00

22 | | 13.50 0.00

23 3.00 0.00

24 | | 15.50 0.00

25 4.25 0.00

26 | | 13.00 0.00

SOUrCe: eFFiDrill SOlUTiOnS inC.

The above chart shows the performance by section on different rigs, which is useful in identifying rigs that perform better in one operation compared to others, and consequently aids in the transfer of knowledge to make all rigs perform better.

the bottomhole assembly, between the mud motor and the measurement-while-drilling [MWD] tool. The VersaStabe works in combo with the mud motor. There are other adjustable stabilizers. Now we’ve introduced a shorter version, the VersaStabe Jr.,” says Chris Konschuh, vice-president of engineering at Arrival Oil Tools Inc. The Calgary-based company develops and manufactures downhole drilling tools. The basic concept of the VersaStabe is a hydraulically actuated stabilizer that is designed for use in a 2-D directional drilling application to help control the inclination in extendedreach or horizontal wellbores. “The stabilizer is for sliding and rotating applications. The VersaStabe Jr. is 78 inches long compared to a version that is 125 inches long. The shorter one allows the sensors in the MWD to be closer to the bit, which is always important,” Konschuh says. The new product is being introduced in Canada, but has some history offshore that can be shown to potential clients, he says.

DIRECTIONAL DRILLING Pulse Directional Technologies Inc. (PDT), also Calgary-based, is an outfit focused on downhole directional drilling tools. “We’re a large R&D [research and development] company that builds MWD and LWD [logging-while-drilling] tools that

are compatible with a tensor-style platform,” says Desmond Anderson, executive vice-president at PDT. Noting that General Electric (GE) is the largest manufacturer of MWD products, he says, “Our product line is fully compatible with GE.” One of the recently introduced products from PDT that can work with a tensor-based platform is a retrievable propagation resistivity tool, sometimes called an RPRT. “These are out there in the industry, but we’re the only independent that sells an RPRT. Our tool is fully retrievable so that even if the BHA [bottomhole assembly] gets stuck, we can retrieve the costly tool and leave the collar in the hole. That’s a big selling feature, especially in the land-based market. The Omega [resistivity tool] is fully compensated, which enables you to work in all types of drilling fluid from water to oil,” Anderson says. The company’s new Omega replaces an earlier tool that worked only in water, known as a “short normal.” The new tool can be operated in tandem with gamma, directional sensors, annular and other real-time updates. “It’s not restricted to running propagation resistivity only. It’s a multi-platform tool with a modular design. The tool is about 10 feet long and the modular design allows you to add other technologies without having to purchase another platform tool. You can add gamma, directional, annular pressure, real-time vibration, etc.,” Anderson says.

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tec H n o lo gY advan c es

Kevin Cote, business development lead for drilling and well servicing at NOV Wilson. Described by Cote as “earth-friendly,” the downhole drilling fluid treatment has been on the market for about two years and has been used on about 600 wells in the United States. “We can use XPL and then don’t have to use invert mud. It makes waterbased mud behave like oil-based mud—in fact, better,” Cote says. He says that XPL is a natural for shale plays as invert mud is often required in shale laterals. The patented XPL is partly derived from plant-based oils.

STACKING UP Sanjel’s SUREstack multistage fracturing system allows the operator to retrieve the inner components of the sleeve in one trip, thereby avoiding the need for the milling required by conventional ball-drop systems.

He emphasizes that the Omega had a very specific dual purpose—fully retrievable with a very competitive price point. The company, he says, typically rolls out a new commercial product per year. Drillform Technical Services Ltd. is another firm with a focus on some of the particular service and product requirements of the horizontal sector. “As we go deeper into the horizontal, there’s a need for specialty drill pipe, and it’s more costly. In the past, the cost of damaged pipe was the cost of doing business,” says Tracie Reed, vice-president, business development, at Drillform. The company has just launched an automated drill floor wrench called the Bulldog 90. The hands-free unit has 18 standard dies to grip the pipe evenly, reducing tool joint wear, and can handle pipe sizes from 3.5 inches to 8.25 inches. “There are four independent spinners in the top part of the tong. No one else has that. It helps to deliver consistency of torque and minimize slippage,” Reed says. Its fully enclosed sensors play a role in protecting the pipe, one of the key benefits of automation combined with the unique die configuration. At the other end of the drill stem is an innovation called XPL+ from ProOne, Inc. and marketed by NOV Wilson. “Everyone wants to drill faster and cheaper, and this fits the bill nicely. It can deliver six-figure savings per well,” says

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

Beyond the niche issues of some shale formations is the more widespread challenge of organizing terabytes of data generated in today’s complex operational environment of directional drilling operations. Critical data is dispersed across diverse file formats, media and locations. Companies need to somehow extract the critical information and metrics from the mass of data to assess past performance and optimize future programs. “Our software is a way to bring together well log data, BHA, bit data and rig instrument data—raw data—and turn it into reports. For example, with a drilling parametric comparison report and a rig activity states report, you can quickly identify where the inefficiencies are,” says Olu Adedipe, drilling business intelligence specialist with Effidrill Solutions Inc. The company has been selling its product and services for about 18 months, but “Our website is more of a data hub for clients. Clients can go in remotely and obtain data and interpretations,” he says. Some reports can take as little as 0.3 seconds to run. A bigger one took 19.2 seconds to develop a report on seven wells. Adedipe points to another report that analyzed 27 days’ worth of data on one well. By tying in time and depth curves with rig activity states, reports can be generated that flag inefficiencies. “The key to this is that you could have 100 wells, and once the data for them is loaded, you can go from one to another without any backing out or reload[ing],” Adepipe says. Companies are buying into new reporting and software solutions that present them with key information and objective metrics on a range of issues. Andy Newsome, vice-president, drilling services, of XI Technologies Inc., says that since last June, two large exploration and production companies joined TourXchange, a collaborative effort bringing operators together to compile and share a well tour database. “We’re building [the] TourXchange database with more analytic tools, more applications to harness knowledge,” he says. A recently released product, Offset Analyst, was made possible from the data drawn from TourXchange. Western Canada–based companies are continuing to make advances in streamlining the completions side of the equation. The new H2 line—“the next generation of packers and ports systems,” says Dan Themig, Packers Plus Energy Services Inc. president and chief executive officer—is designed to cope with some of the inter-well depletion issues. The H2 line has been designed for pressures up to 12,000–13,000 pounds per square inch. “The concept is to handle high-pressure differential downhole,” says Themig.

PHOTO: Sanjel COrPOraTiOn

DATA MANAGEMENT

tec H n o lo gY advan c es

SELECTIVE TARGETING Sanjel’s SUREselect system is a hydraulic fracturing dart and sleeve system that allows operators to select specific stages that can be fractured with a single dart while reducing the time between fracturing stages.

Another new product is the QuickPORT 5. With this system, which is designed for QuickFRAC, an operator can do two to five stages at a time, with greater frequency along the drill stem. An option with QuickPORT 5 is that at a later date, an operator can return to close off a designated section of the well.

iMaGe: Sanjel COrPOraTiOn

SMART TOOLS A third new product coming from Packers—described by Themig as futuristic—does not have conventional ball seats, but, instead, involves a dart system with magnetic counting ability, which is electronically actuated. “It’s the first in a line of smart tools with downhole electronics,” he says. Sanjel Corporation has also been testing a dart system, which can be used on open or cemented holes, to actuate sleeves. “The dart will pass non-target sleeves and only engage the selected target. So, either one or selected multiple sleeves can be actuated with a single dart,” says Darryl Firmaniuk, engineering manager with Suretech Completions Canada Ltd., a Sanjel Specialized Energy Service. The company’s SUREstack multistage fracturing system, introduced about two years ago, has been attracting clients. It is a ball-drop system, but differs in that an operator can retrieve the inner component of the sleeve, including balls and ball seat, in one trip. The system eliminates the milling and drilling required for conventional ball-drop systems. “You can save up to 40 per cent of post-frac completion time,” Firmaniuk says. Technologies first developed by SMEs in western Canada’s oilpatch are being adopted across the continent and beyond. XEM electromagnetic MWD, which was commercially launched by Extreme Engineering Ltd. in 2006, is a case in point. “Our tools, especially XEM electromagnetic MWD, are used daily in horizontal plays in North America—the Marcellus, Utica, Fayetteville, Eagle Ford, Duverney and Montney,” says Paul Meek, general manager of Extreme Engineering. “Up to the acquisition of Extreme by Schlumberger [June 2008], Extreme had received numerous honours, awards and accolades, including the coveted R&D 100 and ASTech [Foundation] Outstanding Commercial Achievements [in Alberta] in Science [and] Technology,” according to a page on the Extreme website.

Made to measure New manufacturing plant could be model for the future By Godfrey Budd

new plant that Packers Plus Energy Services Inc. just opened in Edmonton could prove something of a model for manufacturing facilities of the future, especially in high-cost environments like Alberta. The 230,000-square-foot MX Manufacturing Centre consolidates the activities housed in two former outlets. One, at 120,000 square feet, was used for manual assembly, testing and warehousing, and also included offices. Robotic assembly of the company’s main product lines like packers and ports was done at a smaller facility located about 15 minutes away. Now under one roof, the MX Manufacturing Centre is Packers’ biggest plant, employing more than 200 people. Opened in September, it is capable of assembling about 180,000 tools per year, based on a five-day work week with perhaps some overtime. Besides what it calls the first robotic assembly of its type in the world and a proprietary tracing process that can pinpoint the exact source on a worldwide basis of any Packers Plus tool or, indeed, any of its components, the plant includes an automated storage and retrieval system that occupies barely a quarter of the floor space of an equivalent traditional warehousing operation. “When we looked at future growth, we figured as much as 60 per cent of the floor space would have been taken up by [using] standard 18-foot racking. Instead, we have racks that are 60 feet high,” says Marlon Leggott, director of manufacturing at Packers. The result is that just 15 per cent of the floor space is used for warehousing.

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tec H n o lo gY advan c es

80 Cube HZDW Invert Drilling Fluid Tanks

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

FracPORT™ sleeve

RockSEAL® H2 packer

STAYING AHEAD Packers Plus’s expanding line of downhole tools, made available at its new Edmonton manufacturing facility, are enabling more accurate, faster horizontal multistage fracturing in shale gas and tight oil plays.

iMaGeS: PaCKerS PlUS enerGY SerViCeS inC.

The way Leggott describes it, the facility’s automated storage and retrieval system, which holds up to 20,000 tonnes, operates with robotic precision and efficiency under the roof of a 20-metre-high bay. The storage process begins in earnest when the racking system scans the bar code on a pallet loaded with product from the factory. “That tells you what’s in it. The info goes to a PLC [programmable logic controller] that decides where [the product] is stored. Next, a forklift loads the pallet onto a conveyor, which then takes it to a stop point, and a crane on a track then takes it to its specific storage location,” he says. Retrieval is simple—a worker just keys in product identification data and “the system gets it for you.” Leggott adds that inventory management is built into the racking system. The new plant expands the company’s manufacturing capacity in Edmonton and is clearly more than the sum of its two previous parts. It is designed to increase production dramatically, when needed, according to Dan Themig, company president and chief executive officer. In conjunction with the company’s Houston plant, the Edmonton plant provides equipment for all Packers operations anywhere in the world. The plant’s capacity, however, in common with many such assembly operations and factories today, depends

iMaGeS: PaCKerS PlUS enerGY SerViCeS inC.

tec H n o lo gY advan c es

MANUFACTURING MIGHT The latest in robotic technology allows Packers Plus to build 180,000 tools annually at its new Edmonton manufacturing hub.

on an extensive network of machine shops and other suppliers, with a great deal of the machining, manufacturing and fabrication done in shops across the country. “We design all the tools, but source our raw materials from different mills and send materials and steel to about 60 different machine shops—from Vancouver to Quebec. A majority are here, but there are different capabilities, depending on the shop,” Leggott says. Once the manufactured parts, components and products arrive from the shops, dimensional inspection is done with the deployment of a variety of coordinate measuring machines. Leggott says that a robotic device checks to tolerances of 1/10,000 of an inch. Parts are then stored prior to assembly. Further checks are done once the tools have been assembled. They go to a testing station unit to verify the functionality of the tools. Either manual or automated torque testing is also done, depending on product requirements. Leggott says that the new centre’s level of automation enables higher production volumes and better quality control. As for the overall costs of operating an Alberta-based plant of this type, he says, “There are a lot of steel suppliers here. It’s possible to get good machining at a very good price if you’re set up properly.”

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advertorial

technologyprofile

Tartan Announces a Breakthrough in Multistage Fracturing A

s the O&G industry increasingly shifts focus to unconventional plays, completion costs have risen so fast that they can now account for the majority of a well budget. Now, an Alberta-based company has come up with a hydraulic fracturing system that is not only faster and more flexible than traditional methods, but is also a simpler and more robust design. “Essentially, our system can run a complex stimulation at less cost when compared to current completion techniques in both cemented and open hole liner applications,” says Dwayne DuBourdieu, Business Development Manager with Tartan Completion Systems. For the last 20 years, Tartan Controls has designed, manufactured and supplied thru tubing drilling tools utilized in completions. “But we now have a wide scope of other services, including equipment design and manufacturing for fracture stimulation products,” says DuBourdieu. The three main fracking techniques currently employed today are coiled tubing, sliding sleeve ball drop, and plug and perf. “Coiled tubing has limited fracturing flow rates and limited reach in the horizontal,” says DuBourdieu. “Sliding sleeve ball drop is more efficient, but you are limited by ball sizing on the number of points of entry possible in a horizontal well, and it’s restricted to open hole installation. Plug and perf is effective, but time consuming, which means you have higher equipment and personnel costs.” Tartan realized that there was an opportunity to develop an entirely new system that combined the advantages of each while eliminating the drawbacks. In 2010, they formed a new subsidiary, Tartan Completion Systems, and began conducting R&D at their 57,000 square foot manufacturing facility in Edmonton. They focused on two technologies: sliding sleeve ball drop, which they dubbed MultiFrac™, and BurstPoint™ ports. “The two technologies are not new, but the combination into one system is unique,” says DuBourdieu.

The MultiFrac sliding sleeve technology has the advantage where one ball opens multiple sleeves. “In theory, there is no limit to the number of sleeves you can have in one liner,” says DuBourdieu.

"Essentially, the MultiFrac and BurstPoint technology combines the efficiency of a ball drop system with the effectiveness of plug and perf systems." The BurstPoint is the key element to the MultiFrac completions liner. “The BurstPoint is fully customizable, allowing the operator to easily control the fracturing rate at each sleeve,” says DuBourdieu. “The operator can define the pressure at which the BurstPoint functions, the size of the BurstPoint opening and the actual number of BurstPoints installed in each sleeve. The ability to allow the operator to adjust the BurstPoint pressure setting enables one to store an enormous amount of energy in the liner. When the BurstPoint opens, that stored energy is delivered through the BurstPoint, penetrating the formation at precisely where you want it.” By early 2013, Tartan had a system that was robust, reliable, and simple to deploy. BurstPoints are first engineered to a specified rupture rate and installed in precise orientation in multistage sleeves in the liner. The liner is lowered into position, and the target reservoir portion is isolated with inflatable packers or cement. A ball then sequentially opens the

sleeves as pressure rises. The BurstPoint ports have a shear tolerance of only +/- 0.2%, so once the rupture point is achieved, they simultaneously burst open and fracture the formation. The MultiFrac and BurstPoint system has several advantages. “The operator can now easily control fracturing rates at the sleeve by properly engineering the size and number of BurstPoints installed in any sleeve,” says DuBourdieu. “This, in combination with clustering of sleeves for each surface treatment, allows the operator to create a more complex fracture network within the reservoir. It is also approximately 30–40% faster than an equivalent plug and perf, so you have significant savings.” Tartan Completion Systems has organized an extensive round of company meetings and unveilings at trade shows and conferences throughout the year. “Everyone who has seen it has agreed that it’s a significant advancement in completions technology. The operators that rely on plug and perf methodology are extremely excited because BurstPoints replace the open slots/openings in the outer housing of conventional sliding sleeve designs, allowing complete isolation of the sliding sleeve internals from the cementing process. “Tartan originally designed and manufactured BurstPoint technology for low-rate coiled tubing fracturing process. After successfully completing over 10,000 stages (80,000 BurstPoints) in cemented liner applications, Tartan is now combining this proven technology to the high rate fracturing market using ball drop sliding sleeve methodology. Essentially, the MultiFrac and BurstPoint technology combines the efficiency of a ball drop system with the effectiveness of plug and perf systems,” says DuBourdieu. “Operators face a multitude of challenges, and it’s our job to support them as best we can,” says DuBourdieu. “We’re here to listen to their operational problems, and supply the appropriate solutions.”

Calgary – Sales Office Suite 350, 1201 – 5 Street SW Calgary, Alberta Canada, T2R 0Y6 Ph: (403) 232-1490 Ext. 6

Edmonton – Manufacturing 4003 – 53 Avenue Edmonton, Alberta Canada, T6B 3R5

Email: info@tartancompletions.com Web: www.tartancompletions.com

s e rvi c e an d s u p p lY

Proppant preps for multi-fracs New transport and silo systems for on-site storage and deployment reduce footprint, boost efficiency

he increasing predominance of horizontal drilling and multistage fracturing has boosted demand for related support systems, including a rapidly burgeoning proppant sector with its own requirements in logistics strategies, new systems, technologies and products. Across the continent’s drilling sector, the horizontals’ share of the pie continues to grow. In the first nine months of this year, 10,675 well authorizations were granted in Canada. The total is down about two per cent from last year’s 10,915 authorizations from January to September, but of this year’s tally, 72 per cent were for horizontals, up from 67 per cent of wells by Sept. 30, 2012. The North American proppant market, including raw frac sand, ceramic and resin-coated proppants, was approximately 22 million tonnes, with raw frac sand accounting for about 17 million tonnes in 2011. From 2007 to 2012, proppant demand by weight averaged an annual increase of about 28 per cent, with the market projected to grow to about 30 million tonnes by 2016.

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In 2011, the value of the market was about $3.7 billion and is projected grow 10.5 per cent annually to 2016, according to The Freedonia Group. Besides the surge in numbers of multistage horizontal fracs, other demand drivers include increased length of laterals, more frac stages per metre along wellbores and increased volumes of proppant per stage. A further factor involves “recurring efforts to offset steep production declines in unconventional oil and natural gas reservoirs, including the drilling of new wells and secondary hydraulic fracturing of existing wells,” states Hi-Crush Partners LP in a 2012 U.S. Securities and Exchange Commission filing. The company has a 561-acre facility, with an annual capacity of 1.6 million U.S. tons of frac sand, in Wisconsin. More natural gas–powered electricity, tighter well spacing— from 10 to 16 wells per 640 acres, in the Eagle Ford, for example— and increased drilling productivity could also boost frac sand shipments, according to a presentation

PHOTO: FB inDUSTrieS inC.

By Godfrey Budd

SERVICE AND SUPPLY

SAND ON DEMAND Set up in minutes, FB Industries’ portable silo system for frac proppant handling and storage is designed to take up as little space on location as possible.

from PLG Consulting at a frac sands conference in Minneapolis in September. Also, over a recent 18-month period, average drilling days per horizontal well had dropped from 25.7 to 20.5, according to figures cited by the firm’s president, Taylor Robinson. The state of Wisconsin, the source of an estimated 70 per cent of the continent’s current production of premium monocrystalline sand used for proppant, has 72 operational frac sand mines, with another 20 in development. In neighbouring Minnesota, some 20 frac sand mining, processing and transloading facilities are in operation, with over 20 more in the planning stages, according to Robinson. Rail and other infrastructure are being built on both sides of the border. Canadian National Railway Company (CN) announced in July that it will start serving a new frac sand transloading terminal north of Grande Prairie, Alta., beginning in November. “The new 20-acre facility being built by Di-Corp of Edmonton will have an annual throughput capacity of 550,000

tons of frac sand and have three tracks capable of holding 44 rail cars for unloading,” CN said in July. Besides more rail transport, trucks, water tanks and frac sand silos to support multistage horizontal fracking, the last three or four years have seen the commercialization of a number of innovations designed to streamline the vectors between rail transloading facilities and the wellhead. As more trucks and equipment fill a rig site to support today’s completions and frac jobs, available space on the lease and potential spikes in demurrage costs have, perhaps predictably, emerged as issues. Traditionally, frac sand was stored in specialized sand trailers equipped with fill tubes linked to their respective compartments, each of which was numbered along the exterior of what was often a 50-plus-foot unit that hooked up to a tractor. Pneumatic sand trucks loaded the sand trailers at the site and filled the series of compartments of the trailer by forcing sand up the fill tubes. On one of today’s big frac jobs, pneumatic sand trucks might have to line up, perhaps even outside the lease, before

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T ec h n o lo gy M ag a z i n e s u p p le m e n t | N ov e m b e r 2 013

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unloading their cargo at the sand trailer on a crowded lease with space at a premium. Reducing the footprint of on-site frac sand storage has been one way to address such potential bottlenecks. The result has been the development of various systems of vertical silo storage. That makes sense. A vertical silo can have roughly the same capacity, depending on the model, as a conventional sand storage trailer, but takes up a lot less space on the ground. For instance, the silos supplied by Winkler, Man.–based FB Industries Inc. occupy an area of about 15 by 15 feet, leaving more room for other on-site equipment, including pneumatic sand trucks to deliver their payloads to the storage units. The spectacle of multiple trucks waiting at a frac site to offload into containers prompted a couple of years of research and development culminating in the commercialization of the company’s Titan sand silo. With four sizes, capacity ranges from 3,256 square feet (180 tonnes) to 5,229 square feet (260 tonnes). Two models, the SS-220 and SS-180, have on-board 12/24volt direct current solar power for operating gates and load cells. The high-capacity units, the SS-260 and SS-210, include 36-inch-wide conveyors with 20,000 pounds of carrying capacity per minute, supported by a 7.5-horsepower motor, with a three-phase, 230-volt drive. An optional generator or generator trailer package are available with these. Load status and bin inventory in real time are part of the package with all units. “The solar panel [equipped] silos are more environmentally friendly, but have less capacity. With a genset, you can line up more silos as you have a conveyor belt for the sand. The solar

H o r i z o n ta l d r i lli n g a n d m u lt i stag e f r ac k i n g

one doesn’t have this kind of power,” says Tyler Friesen, sales and marketing manager at FB Industries. The silos with gensets are typically sold in groups of four or six, and are controlled from a single source. The company has about 130 Titan units in the field. “The majority of our business has been in Texas and Alberta, and seven units in the Bakken,” Friesen says. In common with other comparable frac sand storage systems that have come on stream in the past few years, speed of on-site setup is a key part of the Titan silo system. Its patented design and features, including a hydraulic power pack, allow the FB Industries’ Scorpion trailer to unload and erect the silo in a matter of minutes. For removal from the site, a “quickattach” system aligns the trailer for hookup. “Our clients are saving so much in demurrage costs that their investment has been paying out within a year,” Friesen says. He adds, “All our products have dust control mitigation.” The issue of dust has been on the radar lately, and the potential impact on air quality and human health from silica sand processing has become a source of concern in Wisconsin and elsewhere. “The big thing is dust control because of the risks of silicosis. Our proppant storage system on site is equipped with special features to control dust,” says Doug Reder, a Calgarybased sales representative with Propell Oilfield Equipment, part of TYCROP Manufacturing Ltd. The company’s SandStorm product went commercial about two years ago and, as one of the new breed of proppant storage and management systems, is designed for rapid proppant deployment, reduced site footprint and quick setup. The system consists of three main components. The GravityBox takes about 10 minutes to raise prior to being

PHOTOS: PrOPell OilFielD eQUiPMenT/FB inDUSTrieS inC.

GOING VERTICAL Propell’s GravityBox, left, is one of three components of the company’s SandStorm rapid deployment proppant handling system. FB Industries’ Titan sand silos, right, are positioned using a self-erecting silo trailer.

s e rvi c e an d s u p p lY

PHOTOS: FB inDUSTrieS inC.

SELF-POWERED FB Industries offers an environmentally friendly solar powered silo option, which can reduce the requirement for multiple generators on site.

loaded. Units have their own load scales that are tied into a master control system. “Each box can be hauled by a tractor, and boxes usually come in sets of three. A GravityBox can deliver 20,000 pounds per minute, released onto a conveyor. The silos are free-standing, no anchorage or pilings needed. They have gravity-controlled sand flow, so no moving parts. They use a simple guillotine sand gate,” Reder says. A key part of the design concept is a remote-controlled all-terrain hydraulic power unit with a 225-horsepower diesel motor, which houses controls and provides the power to run the SandStorm system. “The hydraulic power unit on each box for raising it is run from the HydraBear, which runs the conveyor belts. The HydraBear can be controlled from an iPad,” says Reder. The third key part of the system is a horizontal and incline conveyor system that can be configured for multiple layouts. The company’s VectorBelt conveyors are fully enclosed for dust control. Another mobile sand silo system, from Loadcraft Industries, Ltd., is all-electric, with no hydraulics, apart from the trailer system that erects the silo. Silo capacity is 420,000 pounds and a loaded three-pack base (with three silos) can hold 1.26 million pounds of proppant. “The silo is transported on a patented trailer system that transports and erects the silo onto the base unit. The intent was to make it as mobile as a conventional frac fleet with additional equipment—but no cranes, forklifts or man-lifts,” says Greg Garcia, executive vice-president of business development at Loadcraft. The trailer was developed about two years ago and has been in the field since June 2012.

Our clients are SAVING SO MUCH in demurrage costs that their investment has been paying out within a year. — Tyler Friesen, sales and marketing manager, FB Industries Inc.

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advertorial

technologyprofile

Frac Sand Handling's Superior Solution FB Industries prides itself on providing the unsurpassed solution for frac sand handling equipment and storage, both on site and off-site. Based in Winkler, Manitoba, with sales and service representation in Alberta and Wisconsin, and a full service shop and manu facturing in Texas, FB Industries opened its doors to address an unmet need for frac sand storage within the oilfield industry. To fulfill that need, FB Industries developed its innovative Titan Sand Silo and Scorpion Trailer system, a portable silo system that is positioned by a self-erecting silo trailer. The Titan silo was designed to address an industry trend—going vertical in order to reduce a company’s on-site footprint. “We developed a system that has huge potential cost savings for service companies and sand providers,” says FB Industries sales and marketing manager, Tyler Friesen. “Three years ago, we were the first in the world to build something this size that is truly portable. We knew it was the direction the industry was headed. We were the first to market in this size, in terms of capacity on site and portability.” The Titan, which holds 260 tons per silo, reduces downtime and demurrage costs, and is the largest in its class of 220-ton-plus silos. The Titan silo’s larger capacity and vertical footprint storage solution lowers demurrage costs, and at the same time reduces lease sizes for service companies. “Our largest customer tells us they pay back the investment for the entire system in approximately one year,” Friesen notes. “That is huge for our customers.” Since its success with the Titan silos, FB Industries has developed a number of other products, including portable transloaders. FB

Industries is also the exclusive distributor in North America of Convey-All Industries’ oil and gas equipment, “which complements our product offerings very nicely,” says Friesen. Convey-All’s signature piece of oil and gas equipment is the SandKing, and Convey-All is the second largest manufacturer of equipment in this category.

conscious, offering solar powered silo options, reducing the need for multiple generators on site. “We continually strive for improvement in all of our existing models, with technological advances in our field to bring the best product to market that pays dividends to our customers,” Friesen says. “Customer relationships are the determining factor for our success.”

“Our largest customer tells us they pay back the investment for the entire system in approximately one year.” In the design of all of the solutions it creates, FB Industries emphasizes innovation, integrity, quality and flexibility. “We have a strong focus on health and safety,” Friesen says. For example, FB Industries teamed up with Convey-All to develop a unique dust collection system for the Convey-All SandKing. The system is unique in that it eliminates the need for a baghouse or collection house, making it more compact and user friendly. Almost all of FB Industries’ major frac sand handling equipment now includes dust collection options that virtually eliminate silica dust. “We are ahead of the curve,” Friesen says, noting that silicosis, a respiratory condition, is a serious issue in the industry if proper measures are not taken, and FB Industries incorporates dust control measures and safety into all of its equipment designs. In addition to its strong focus on health and safety, FB Industries is environmentally

Please contact for more information: FB Industries T: (204) 325.7337 E: info@fbindustriesinc.com www.fbindustriesinc.com

TEC H NOLOGY DISSEMINATION

Cra ck i ng

Enormous quantities of oil and gas within reach if the rest of the world can duplicate North America’s success By Maurice Smith

he so-called shale gas and tight oil revolution that has transformed North America from what was perceived as an inexorably depleting oil and gas province into what is rapidly becoming the world’s leading hydrocarbon producer is poised to spread to the rest of the planet. But there remains much debate over how quickly that will occur, and whether it will have anywhere near the impact it has had in North America, which has a number of advantages over other jurisdictions that made it the perfect testing ground for the revolution to occur. It’s no accident that the key to unlocking access to shale gas and tight oil originated in North America, where independent, innovationminded, risk-taking companies flourish. George Mitchell, the former president of Mitchell Energy & Development Corp. who died in July at the age of 94, spearheaded efforts to crack the code, wagering millions in research and development in the 1990s to perfect the application of horizontal drilling and multistage hydraulic fracturing technology for the challenge.

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the

tec H n o lo gY d i s s e m i nati o n

MaP: UniTeD STaTeS BaSinS FrOM U.S. enerGY inFOrMaTiOn aDMiniSTraTiOn anD UniTeD STaTeS GeOlOGiCal SUrVeY; OTHer BaSinS FrOM ari BaSeD On DaTa FrOM VariOUS PUBliSHeD STUDieS

c o d e

FIGURE 1 Map of basins with assessed shale oil and shale gas formations, as of May 2013

LEGEND Assessed basins with resource estimate Assessed basins without resource estimate

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TOP 10 COUNTRIES WITH TECHNICALLY RECOVERABLE

SHALE OIL RESOURCES

TOP 10 COUNTRIES WITH TECHNICALLY RECOVERABLE

SHALE GAS RESOURCES

RANK

COUNTRY

China

1,115

Argentina

802

Algeria

707

U.S.

665

Libya

Canada

573

Australia

Mexico

545

Venezuela

Australia

437

Mexico

South Africa

390

Russia

285

Brazil

245

RANK

COUNTRY

SHALE OIL (BILLION BARRELS)

Russia

U.S.

China

Argentina

(48)

Pakistan

Canada

WORLD TOTAL

345

(335)

For the U.S., EIA estimates used for ranking order. Advanced Resources International, Inc. estimates in parentheses.

WORLD TOTAL

SHALE GAS (TRILLION CUBIC FEET)

7,299

(1,161)

(7,795)

For the U.S., EIA estimates used for ranking order. Advanced Resources International, Inc. estimates in parentheses.

SOUrCe: U.S. enerGY inFOrMaTiOn aDMiniSTraTiOn, TeCHniCallY reCOVeraBle SHale Oil anD SHale GaS reSOUrCeS, jUne 2013

But it has also been North America’s already existing oil and gas drilling, producing and transportation infrastructure, the knowledge gained from decades of drilling, its trained labourforce and cultural acceptance of the industry that has enabled the boom to spread—if not always trouble-free—across the continent from its birthplace in the Barnett Shale of north-central Texas. It is a combination of attributes not often found elsewhere. But in North America, the turnaround the technology has enabled has been nothing short of extraordinary. Global natural gas resources are now estimated by the U.S. Energy Information Administration (EIA) to total 790 trillion cubic metres, more than 230 years of production at current rates. In October, the EIA estimated the United States will be the world’s top producer of combined petroleum and natural gas this year, surpassing Russia and Saudi Arabia. Since 2008, U.S. oil underwent dramatic growth in Texas and North Dakota, while much of the growth in natural gas came from the eastern United States. Production estimates for the United States and Russia for 2011 and 2012 were roughly equivalent—within one quadrillion British thermal units of one another. In 2013, however, the production estimates widen out, with the United States expected to outproduce Russia by five quadrillion British thermal units, the EIA says. For the United States and Russia, total oil and gas production, in energy-content terms, is almost evenly split between them, whereas Saudi Arabia’s production heavily favours petroleum (see graph, page 38). The EIA earlier projected the United States will become the world’s largest global oil producer by around 2020.

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“This is a remarkable turn of events,” EIA administrator Adam Sieminski told The Wall Street Journal. “This is a new era of thinking about market conditions, and opportunities created by these conditions, that you wouldn’t in a millions years have dreamed about.” Recent studies have shown that this remarkable resource potential exists in jurisdictions just as well-endowed, or more so, as Canada and the United States. On the oil side, a study released by global analytics firm IHS in September concluded the rest of the world has potential technical recoverable resources of tight oil possibly several times those of North America, and that commercial production of these resources could equal and exceed the current estimates for North America tight oil output. Its study, Going Global: Predicting the Next Tight Oil Revolution, identified the 23 highest-potential plays throughout the world and found that the potential technically recoverable resources of just those plays is likely to be 175 billion barrels—out of almost 300 billion for all 148 play areas analyzed for the study. “While it is too early to assess the proportion of this that could be commercially recovered, the potential is significant compared to the commercially recoverable resources of tight oil [43 billion barrels] estimated in North America by previous IHS studies,” states IHS. The study used a comprehensive framework to group and analyze international plays based on their geological and depositional characteristics. Each play was then compared to its closest North American equivalent to provide the most accurate assessment of its technical potential.

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tec H n o lo gY d i s s e m i nati o n

SHALE GAS LEADS GROWTH IN TOTAL GAS PRODUCTION THROUGH 2040 TO REACH HALF OF U.S. OUTPUT

U.S. dry natural gas production trillion cubic feet

2011

History

Projections

Shale gas

Non-associated offshore

Tight gas

Alaska

Coalbed methane 5

Associated with oil Non-associated onshore

1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

2040

SOUrCe: eia, annUal enerGY OUTlOOK 2013

“This study makes clear that the potential for global tight oil is there and that it is very, very large,” says Jan Roelofsen, IHS research director and adviser for unconventionals. Since well-level data does not exist in most of the study areas, a final measure of technical or commercially recoverable resources cannot yet be determined, Roelofsen concedes. “But this study’s unique, data-based assessment shows that the potential of just the highest-ranking plays is likely double the size of North America’s resources, and that is a conservative estimate,” he says. Among the 23 highest-ranking tight oil plays identified were the Vaca Muerta (“dead cow”) Formation in Argentina, the Silurian “hot” shales in North Africa and the massive Bazhenov Shale in western Siberia. The range of geological characteristics and risks of these 23 highest-ranking plays “compare favourably, or even better in some cases, than those of leading North American plays,” notes Steve Trammel, IHS research director and adviser for unconventionals and project manager for the study. The EIA has also turned its gaze to basins around the world. It found recently that combined tight oil and shale gas resources in 137 shale formations in 41 other countries, combined with those in the United States, represent 32 per cent of

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the world’s natural gas and 10 per cent of the world’s crude oil technically recoverable resources—those that can be produced using current technology without reference to economic profitability. In a report released in June, the EIA said more than half of the identified shale oil resources outside the United States are concentrated in four countries: Russia, China, Argentina and Libya. More than half of the non-U.S. shale gas resources are concentrated in five countries: China, Argentina, Algeria, Canada and Mexico. The United States would be ranked second for shale oil resources and fourth for shale gas resources if compared with the 41 countries assessed. Canada ranked fifth in shale gas and 10th in shale oil. (The terms shale oil and tight oil are often used interchangeably, though shale formations are only a subset of all low-permeability tight formations, which include sandstones and carbonates, as well as shales. While the EIA typically ranks tight oil in the United States, in this report it looked exclusively at shale resources and did not consider other types of tight formations.) Because they have proven to be quickly producible in large volumes at a relatively low cost, tight oil and shale gas resources have revolutionized U.S. oil and natural gas

tec H n o lo gY d i s s e m i nati o n

U.S. TIGHT OIL PRODUCTION BY SELECTED PLAYS

U.S. crude oil production million barrels per day

2011

History

Projections

1.0

Bakken

0.9

Eagle Ford

0.8

Other 0.7

Spraberry Wolfcamp

0.6

Austin Chalk

0.5

Avalon/Bone Springs 0.4

Niobrara

0.3

Woodford Monterey

0.2 0.1 0

1990

1995

2000

2005

2010

2015

2020

2025

2030

2035

2040

SOUrCe: eia, annUal enerGY OUTlOOK 2013 earlY releaSe

production, providing 29 per cent of oil production and 40 per cent of natural gas production in 2012, says the EIA. In a single year, from 2011 to 2012, U.S. oil production shot up 847,000 barrels per day due mostly to tight oil production, by far the largest growth in production of any country. In Canada, tight oil production climbed to almost 300,000 barrels per day in 2012 while shale gas reached 0.7 trillion cubic feet. It remains to be seen if that success will translate elsewhere. Currently, only the United States and Canada are producing tight oil and shale gas in commercial quantities. While there has been a blossoming of interest in shale resources elsewhere, the EIA notes that economic recoverability can be significantly influenced by above-the-ground factors as well as by geology. “Key positive above-the-ground advantages in the United States and Canada that may not apply in other locations include private ownership of subsurface rights that provide a strong incentive for development; availability of many independent operators and supporting contractors with critical expertise and suitable drilling rigs and, pre-existing gathering and pipeline infrastructure; and the availability of water resources for use in hydraulic fracturing.” Other issues could include government policy, land access constraints and regulatory frameworks, accessibility to

advanced technology, and public and environmental opposition. Such issues also lead to higher costs—IHS estimates an average tight oil well costs about $5.6 million in North America, but averages $8 million elsewhere, ranging from $6.5 million in Australia to more than $13 million in parts of the Arabian peninsula. And different jurisdictions have taken very different approaches to the application of horizontal drilling and multistage fracking, from banning the practice outright, such as in France and Quebec, to offering tax concessions and funding studies to generate interest and actively promote shale gas and tight oil development. While the challenges may be greater elsewhere—and there will be hits and misses as exploration picks up—the spread of the tight oil and shale gas revolution offers opportunity for those with the expertise to exploit the resource. Foreign firms interested in acquiring the technological expertise have invested heavily in North American shale plays, with many farming into the plays with big payments to fund drilling, while those with the expertise are testing favourable plays overseas. Norway’s Statoil ASA, for example, which is best known for its offshore expertise, jumped into the shale fray with large investments in North American fields, quickly acquiring

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ESTIMATED U.S., RUSSIA AND SAUDI ARABIA PETROLEUM AND NATURAL GAS PRODUCTION

quadrillion British thermal units

million barrels per day of oil equivalent

United States

Russia

Saudi Arabia

natural gas

petroleum

2008

2009

2010

2011

2012

2013

SOUrCe: eia, annUal enerGY OUTlOOK 2013 earlY releaSe

production expertise. By 2012, Statoil had advanced from actively preparing for an operatorship in shale gas and tight oil to actually operating tight oil and gas activities on the Bakken and Three Forks formations in the Williston Basin of western North Dakota and eastern Montana. The company said it would move toward operatorship of its shared shale gas and gas liquids assets with joint-venture partner Talisman Energy Inc. on the Eagle Ford formation in southern Texas during 2013. It has an active partnership with Chesapeake Energy Corporation in the Marcellus formation in several states in the U.S. northeast, and in late 2012 it acquired Marcellus acreage in Ohio and West Virginia that it operates. As well, in 2012 Statoil farmed into its first shale exploration asset outside the United States when it joined Calgary-based PetroFrontier Corp. to explore for shale hydrocarbons in the Northern Territory of central Australia. Though international success in shale hasn’t materialized yet, the biggest oil companies, along with service and supply companies with fracking expertise, are leading the charge to duplicate North America’s success in the most promising regions. Royal Dutch Shell plc has been active in Chinese basins and Exxon Mobil Corporation has teamed with Rosneft to develop Siberia’s Bazhenov Formation, touted to be five times larger than the Bakken, perhaps the United States’ leading tight oil play, and the great hope for a resurgence in Russia’s stagnating oil production. Subsidiaries of Schlumberger Limited, Baker Hughes Incorporated and Halliburton have followed, bringing the technology, equipment and even some drilling crews from the Bakken and the Eagle Ford in Texas.

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While the key to exploiting the Bazhenov hasn’t yet been unearthed, Russia recently granted tax concessions to help keep companies interested. Other areas of high potential have fizzled as more was learned of the plays. Poland and Ukraine have struggled to establish shale production, and the EIA has downgraded some plays, as early exploration has made more data available. It dropped its assessment of Norway’s Alum Shale, for example, from 83 trillion cubic feet in 2011 to zero in its current report because of disappointing results obtained from three Alum Shale wells drilled by Shell in 2011. “The Shell wells were drilled in the less geologically complex portion of the Alum Shale that exists in Sweden, which significantly reduced the prospects for successful shale wells in the more geologically complex portion of the Alum Shale that exists in Norway,” it states. Given the enormous resource in place, there is certainly plenty of potential for large-scale shale gas and tight oil production around the world as the technology developed in North America is increasingly applied to them. But the immense opportunity they offer could be a long time coming. “Given the range of below- and above-ground issues to be managed, launching global tight oil development outside of North America will probably be much slower overall,” says Peter Stark, IHS senior research director and adviser for unconventionals. “But the potential is certainly there and there will be opportunities for early progress where the right conditions exist.”

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