New Technology Magazine Supplement - November 2011

November 2011

Conventional oil's ComebaCk

How multistage fracturing and horizontal drilling are replenishing a declining resource

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New Technology Magazine supplement | November 2011 1

Features

Stars alignedTechnology, timing and tenacity unlock long-slumbering Bakken shale oil play

Crude’s comebackTechnologies developed for natural gas

set to transform tight oil production

Conventional crude’s second chance

Evolving technology opens doors

for new oil resource plays

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A fast-moving goal postTechnology playing catch-up as producers firm up plans to tackle tight oil plays

Meeting the tight oil challenge

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To witness the re-emergence of production growth in the conventional oil sector after almost

four decades of steady production declines is to bring to mind that famous Yogi Berra

witticism: “It’s déjà vu all over again.”

The sense of déjà vu comes straight from the experience of oil’s sister commodity, natural gas,

where the origins of crude’s comeback are traced. Much ink has been spilled describing the remark-

able turnaround in the fortunes of natural gas, which as recently as the early years of this century was

viewed as running out across North America. Multi-billion-dollar arctic gas pipelines and liquefied

natural gas import terminals by the dozens were widely viewed as the inevitable response to make

up for the coming shortfall.

That, of course, was before the paradigm-shifting transformation brought about by the twin techno-

logies of horizontal drilling and multistage fracturing. Originally pioneered by Mitchell Energy &

Development in the Barnett Shale of Texas, the new techniques transformed the industry as they spread

to other basins with such success that the pending shortage has turned into a persistently over-

supplied market, driving down prices and reversing import plans to opportunities for natural gas exports.

And now, the same scenario is playing out for conventional crude oil as the marginal oil once left

behind as not economical to produce, is transformed into new liquid assets due to the same technolo-

gies, adapted for use in oil pools.

In a sense, the technologies that have been too successful for the industry’s own good, among

gas producers at least, are now offering a lifeline as they are being adapted to the oilfield. Horizontal

drilling and multistage fracking, combined with healthy oil prices, have allowed the industry to take

up much of the slack left by the gas glut by putting rigs, workers, capital and technology to work on

tight and shale oil prospects.

While the application of these new technologies to conventional oilfields may not have quite the

transformative impact they have had on natural gas, they have been credited with halting the decades-

long decline in North American conventional oil output in recent years, with mild upticks in produc-

tion—once thought extremely improbable—now forecast over the short term.

As we report in this supplement, service companies large and small are actively pursuing new tools,

processes and concepts to advance development of these plays, resulting in rapidly evolving techno-

logical change that will benefit not only themselves and the producers that put the technology to work,

but the resource owners through increased royalties and the economy in general as activity levels are

sustained in troubled economic times.

While this is to be welcomed, it is also instructive to bear in mind the conclusions of the U.S.–based

National Petroleum Council (NPC), which cautions the industry to keep public perceptions in mind as

activity ramps up. In its September report, Prudent Development: Realizing the Potential of North America’s

Abundant Natural Gas and Oil Resources, the NPC acknowledges “public confidence in natural gas and oil

development and in some of the associated regulatory mechanisms has frayed,” in part due to concerns

about the impact of the increasingly widespread use of hydraulic fracturing.

While the rejuvenated conventional oil sector offers a resource base that “could provide substantial

supply for decades ahead,” the NPC states that access to these resources depends on “responsible

develop ment practices being consistently deployed.”

Certainly, conventional oil is back on the front burner and will be increasingly under the spotlight as

a result. It is still premature to say how large a contribution it will make to the energy picture in the dec-

ades to come, but if the experience of natural gas is any indication, further optimization of multistage

horizontal techniques applied on the oil side could end up making current projections look altogether

conservative in the years ahead.

Already, the NPC notes, “through technology leadership and sustained investment, the United States

and Canada together now constitute the largest oil producer in the world.” A remarkable accomplish-

ment, considering the sentiment of a few short years ago of an industry in North America in irreversible

decline. To those who preached hydrocarbons represented a sunset industry, another Yogi-ism comes

to mind: It ain’t over till it’s over. Maurice Smith

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New Technology Magazine is owned by JuneWarren-Nickle’s Energy Group, a subsidiary of Glacier Media Inc., and is published 10 times per year. Printed in Canada by PrintWest. ISSN 1480-2147.

Déjà vu all over again

editor's view

4 Conventional Oil's Comeback

T alk to anyone in the energy industry about tight oil prospects in

western Canada and invariably the conversation will revolve around

two issues: a major resurgence in the prospects of producing

several more barrels and the strategic role of cutting-edge technology to

make that happen.

While major Canadian oil companies are raring to go in their ef-

forts to invest big bucks in tapping into the resources in Alberta and

Saskatchewan, some have also unveiled details of their ambitious capital

expenditure plans.

A case in point is Penn West Exploration, whose president and chief execu-

tive officer, Murray Nunns, said in midsummer that some $1 billion would

be invested in the current year in four oil plays in western Canada, following

successful appraisals of the respective geology.

At stake for Penn West are tight oil formations in the Cardium play in

central Alberta, the Spearfish Formation in Manitoba, carbonate geology in

north-central Alberta and the Viking Formation of the Colorado Group in

south-central Saskatchewan.

“We have gone through a learning curve and drilled horizontal wells with

multistage fracture stimulations,” he said then. “Western Canadian light oil

plays have been underdeveloped for the past 40 years and the basin is now

undergoing a renaissance. We are positioning ourselves to be a major pro-

ducer in North America in the 100,000–500,000-barrel-per-day range.”

It is not Nunns alone who is upbeat about the prospects.

John Zahary, president and chief executive officer of Harvest Operations

Corp., says formations in western Canada such as the Cardium, Viking, Dina

and Ellerslie have had oil production going back decades,

yet only a fairly small percentage of the in-place resource

has been recovered.

“We have been forecasting the end of the conven-

tional industry since the start of my career,” he says. “I

expect it to continue to be vibrant until at least the end

of my children’s careers and likely much longer. The future

will depend on oil price and continuing the technical

entrepreneurial culture that has created the industry we

have today.”

InnovatIve solutIonsThe service industry is well aware of the challenges and is

constantly sharpening its tools to come up with the most

apt and suitable solutions and to rise to the expectations

of oil companies.

“They [oil companies] are waiting for us to develop

innovative solutions,” says Randal Biedermann, sales man-

ager for completions with Weatherford Canada, adding,

“New products are being installed no sooner than they

are being tested and commercially released. Over the

past five years, the industry has been growing immensely

and is pushing us towards new challenges and breaking

new barriers. We have to chase different avenues to

make the product work.”

A fast-moving goal postTechnology playing catch-up as producers firm up plans to tackle tight oil playsBy Ashok Dutta

SUNRISE INDUSTRYA Nabors Canada rig is at work near Dawson Creek, B.C. The advent of horizontal drilling and multistage fracturing is leading to a resurgence of oil drilling across North America.

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A fast-moving goal postTechnology playing catch-up as producers firm up plans to tackle tight oil playsBy Ashok Dutta

According to Darryl Firmaniuk, Canadian engineering manager for

completion systems at Baker Hughes Inc., the meat-and-potatoes solutions

for the industry are primarily a combination of multistage fracturing and

horizontal drilling. “Since 2005, we have been directly involved in rolling out

new technology for the Canadian market, and this is an ongoing process,”

he says.

The latest products being showcased by Baker Hughes include the

FracPoint systems used for open-hole applications. “It [the product] is run

in horizontal wells, with packers being placed strategically at intervals.

That helps in realizing the complete production potential. We have also

improved upon existing systems, like phenolic balls, that were encoun-

tering some issues and have now been replaced with a new design,”

Firmaniuk says.

The recently introduced IN-Tallic frac balls incorporate controlled

electrolytic metallic technology, which allows for the balls to disintegrate

chemically during the production phase and to do away with any restric-

tions during the flowback and production phase of a well. The technology

is based on an electrochemical reaction controlled by varying nanoscale

coatings within the composite grain structure, the company says.

Two other new products in Baker Hughes’ arsenal are its FracPoint EX-C

frac sleeve and OptiPort. While the former is a new sleeve design that

allows for additional fracturing intervals, the latter—using coiled-tubing

frac sleeve technology—offers unlimited numbers of interval capability to

open the sleeves.

Specifically designed for horizontal shale completions, the FracPoint

EX-C multistage fracturing system uses 1/16-inch incremental changes

in ball size to achieve an increased number of ball seats. The patented

design provides additional mechanical support to the ball during pumping

operations. “With EX-C, fracturing intervals could go up to 40 [stages], when

compared with 24 in our current FracPoint offering. More intervals imply

more entry points, increasing the prospects of enhanced recovery of crude

oil from wells,” Firmaniuk says.

The benefits derived from OptiPort are best viewed from savings that

could potentially accrue to an oil company from reduced surface costs.

The OptiPort frac sleeves are isolated and opened by the coiled tubing-

deployed bottomhole assembly (BHA), eliminating perforating or pumping

balls. The company says it has reduced average treating time by 45 per cent

or eight hours and fluid usage per treatment by 30 per cent or 120 cubic

metres per well.

For its part, Weatherford has also rolled out several cutting-edge solu-

tions, particularly for horizontal drilling, to the Canadian marketplace. “Even

though our EM MWD [electromagnetic measurement while drilling] is not

new to the industry, we have made some enhance-

ments to it,” says Don Cappelle, regional business unit

manager for drilling services with Weatherford Canada.

MWD is a tool used to gather several measurements

while drilling downhole.

“The EM tool is now retrievable and can be run with

a dual battery setup. We have also added an Inc-Sonde

[a system that gives the angle of the hole] to the bot-

tom of the MWD tool. It offers a simple, economical,

sonde-based alternative, compared with more compli-

cated at-bit measurement systems,” he says.

The Inc-Sonde measures inclination closer to the

bit and on the fly while sliding and rotating, Cappelle

explains. These capabilities help land the build section

of the well and assist in avoiding severe doglegs in the

laterals, improving the potential for drilling higher-

quality wellbores.

“With the information from the Inc-Sonde, our direc-

tional drillers will be able to react quicker and be more

efficiently in drilling the well,” he says.

Weatherford has also introduced new HyperLine mud

lube motors that deliver almost double the operating

torque and power output in comparison with other stan-

dard motors, thanks to its proprietary high-performance

elastomer and high torque-bearing sections.

Other products on offer from Weatherford are the in-

field reference (IFR) and the multi-station analysis (MSA)

for drilling multi-lateral wells with tight in-field spacing.

IFR surveys evaluate the magnetic influence of local

geology and measure how the direction of the earth’s

magnetic field varies through the oil or gas field. Apply-

ing IFR corrections can improve the accuracy of existing

MWD data and all future MWD surveys by up to 30

per cent, says the company. MSA combines data from

multiple survey shots to calculate any residual magnetic

interference from the BHA. This calculation can be

applied to ensure survey data are not being corrupted

by magnetic interference or applied as a correction to

downhole data to improve the quality of survey results.

Houston-based Halliburton’s new XBAT is the

industry’s first azimuthal sonic imaging tool to

measure anisotropy—which facilitates real-time

TECHNOLOGY EVOLUTION

Baker Hughes’ next-generation Frac-Point EX-C

completion system, specifically designed for horizontal shale

completions, is capable of delivering up to 40 frac stages.

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sonic geosteering—sonic fracture characterization and stress profiling for

optimizing wellbore stability, the company states in an email.

“Identification of natural fractures and of formation stress-profiling

is extremely important in identifying an optimal fracture stimulation

program. Our GeoSharp LWD tool allows imaging while drilling in oil-

based and other non-conductive muds—commonly ran in oil and gas

shale reservoirs—which are not available from any other oilfield service

company in the industry,” the company says. “From the completions and

fracturing side, we have successfully deployed a number of cased and

open-hole completion technologies, which significantly reduce the time

and associated costs required for multiple fracturing treatments along a

horizontal wellbore.”

ADVANTAGESA prime benefit oil companies target by applying the “latest and greatest”

technology is improved recovery rates from wells. One of the most exciting

results of horizontal multifrac technology is that it not only makes many

newly discovered tight oil reserves economic, but can in many cases also be

used to give a second life to older depleted reservoirs originally completed

with vertical wellbores only, the Halliburton statement says.

The Cardium is one example of a previously exploited reservoir that is

seeing renewed activity, the company says. “The overall impact of horizon-

tal multifrac technology on production has been to reverse the trend of

declining WCSB [Western Canadian Sedimentary Basin] oil production. We

are now seeing a steady increase in WCSB output as a result of this new

technology. In addition, Canada is becoming recognized globally as a cen-

tre of excellence for this technology, which other countries are beginning

to beneficially apply.”

Along with enhanced output, oil companies also

desire cost savings. Firmaniuk says it could vary be-

tween 30 and 80 per cent, depending on the number

of horizontal wells.

Cappelle says the advantages could be virtually limit-

less with the drilling of an increasing number of multi-

lateral wells. “A smoother wellbore with minimal dogleg

severity is very critical when it comes to the production of

the well. The savings are tremendous when you talk about

staying in the hole for double the time with the dual

battery, as it could save the client NPT [non-performance

time]. Besides, the Inc-Sonde system allows companies to

stay in the pay zone which results in better ROP [rate of

penetration] and more production,” says Cappelle.

The new products carry varying price tags, ranging

from $50,000 to $500,000.

But it is not cost but rather the benefit an oil com-

pany could derive that proves to be the win-win factor

in the long run, according to Weatherford’s Biedermann.

“Cost is generally overruled when measured against

increased production and with higher efficiency levels.

We can now fracture five intervals with a single ball,

increasing efficiency five times,” he says.

According to Halliburton, the application of horizon-

tal multifrac technology has allowed some newer tight

oil plays to be economically viable.

From a drilling perspective, saving rig time saves

the operator money. Having a good understanding of

TARGETING TIGHT OILBaker Hughes’ FracPoint technology, often used in the Williston Basin’s Bakken tight oil play, is a modular system that can be optimized according to customer specifications.

DOUBLE THE TORQUEWeatherford’s new HyperLine mud lube motors deliver almost double the operating torque and power output compared to standard motors.

IMAGE: WEATHERFORD CANADA PARTNERSHIPIM

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TECHNOLOGY ADVANCES


the formation being drilled and definitive measure-

ments to the adjacent formations allows operators to

drill more quickly with confidence of not drilling out

of the zone. It is not uncommon to save days off a well

from unplanned exits and sidetrack mitigation, the

company says.

The new products come with their fair share of chal-

lenges, however, with service companies being pushed

constantly to test the limits.

“For multistage fracturing, at its infancy the design

was ball-activated sleeves. We then moved to coil-

activation, and now there is activation of more than

one sleeve with a single ball. Looking ahead, we are

working to eliminate the ball altogether, as it will

reduce the need to introduce a com-

ponent to a wellbore that could be a

potential obstruction,” Biedermann says.

Weatherford is also pursuing develop-

ment of a product to keep a close eye on

real-time, in-line fracture monitoring that

would allow oil companies to monitor

what is happening downhole.

At Baker Hughes, the envelope is

being pushed constantly for the ability of

completions equipment to handle higher

differential pressures, says Firmaniuk. The

company, which currently offers 10,000

pounds per square inch (psi), is working

to increase that to 15,000 psi to enable oil

companies to crack rocks and geological

structure more efficiently.

“It is being worked out of our R&D [research and

development] centre at Houston. There are challenges

involved in the process, as a new component will have

to be tested from metallurgic and elastomeric perspec-

tives,” he says.

The verdict will be awaited, but success stories are

already in hand for service firms.

“We have successfully completed a complex geom-

etry well, which was a 20-leg multilateral, for Baytex

Energy [Corp.] in the Seal field. We worked along with

the client to create efficiencies and complete the well

in a safe and timely manner. A well of this magnitude

requires precise engineering and tools, constant com-

munication and teamwork,” Cappelle says.

He also cites another success story Weatherford ac-

complished recently for an unidentified firm in Alberta.

“We have just completed a program to drill 30

horizontal wells. With tight well spacing require-

ments, this project made use of two new survey

techniques to improve accuracy of the MWD system.

An IFR survey was used to measure the variation of

the Earth’s magnetic field across the area and the

MSA analysis technique was used to measure and

reduce the effects of BHA magnetic interference.

Weatherford worked in partnership with our Tech 21

Engineering Team out of the U.k. to introduce these

techniques and deliver benefits to the customer. The success of this

project contributed to us being awarded another 60 horizontal well

project utilizing MSA,” Cappelle says.

While some oil companies are receptive to the latest technology and are

willing to go that extra mile, others are as yet staying put.

“The real drivers are the majors, who have more money in their coffers.

For now, the small- and medium-size operators are playing a wait-and-

watch game and evaluating successes of majors before taking that plunge,”

Firmaniuk says.

Service companies are not waiting for their order books to become

heavy. Rather, they are on a treadmill to produce more innovative solutions.

“Technology is being developed all the time and we are using our

engineering resources. A large engineering team from Weatherford is in

Edmonton working with clients,” Biedermann says.

Innovation, both on the domestic and global fronts, is the mantra for

service companies.

The Opti packer system, introduced recently in Canada, is a homegrown

product that has performed successfully during field trials, Firmaniuk says.

The product will now be introduced to the U.S. market. In a reverse vein,

the expectation is for the IN-Tallic controlled electromagnetic system to be

offered in Canada, given the success it has achieved after being used at the

Bakken Formation in North Dakota.

Meanwhile, at a major industry conference in New York in early

September, a top official of Halliburton said public concerns about

water usage and the chemicals used in fracturing fluids are driving his

company to develop more environmentally sensitive fluids and reduce

fresh water use.

“We know water is an emotional issue,” says Dave Lesar, Halliburton’s

president chief executive officer. “The issue of chemicals in fracturing fluids

is a hot topic today and we are disclosing the chemicals that go into the

ground. But we are also working to develop a new fracturing fluid that

contains no petroleum products,” he says.

One new Halliburton fracturing formulation is called CleanStim, with

ingredients sourced exclusively from the food industry. “One ingredient

goes into cake mixes. Who can argue against these chemicals if they go into

our food every day?” Lesar says.

Despite all their efforts, a major issue that service companies have to come

to terms with is that technology is still proving to be a fast-moving goal post.

“With multistage fracturing, the whole industry was trying to make

things work. However, now it seems we still have miles to go,”

Biedermann says.

0 hrs100 hrs 210 hrs

460 hrsTest begins with ball on

seat

Ball unseated

VANISHING BALLSBaker Hughes’

IN-Tallic controlled electrolytic metallic

frac balls are designed to dissolve downhole.

At left, a ball in its seat measures 3.5

inches. It shrinks to 2.9 inches after 100

hours and 1.5 inches after 210 hours. At

right, little is left after 460 hours.

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.TECHNOLOGY ADVANCES

close co-operation by the 20 clients that have contributed well files and continually collecting fracturing data. “We are continually expanding the data model as we learn new technologies and data elements that our clients need. We add wells in our clients’ areas first, in order to give them increased production and profit from their exploitation programs.”

Leshchyshyn, who founded his Calgary-based company nearly two years ago, has found there is great demand for people with independent fracturing expertise with

relatively few who are able to provide it. “Our team has members with up to 40 years of experience, and have generated many technical papers on fracturing using large frac databases tied to production over the last 7 years,” he notes. Frac Horizontal currently employs a dozen workers who do area frac research, frac optimization, training courses, and live technical supervision of fracs to maximize companies’ profit and production, by helping reduce costs, prove up new plays and improve old ones.

Frac Horizontal serves the Alberta Innovates–Technology Futures (formerly the Alberta Research Council) in northwest Calgary, where Leshchyshyn helped establish a $1,000,000/year tight oil exploitation joint industry research and development project that Frac Horizontal is helping to lead. The project addresses primary production via fracturing, reservoir characterization and improved oil recovery, with participation by a wide range of energy firms including PetroBakken, Devon, Penn West, Arcan and Pengrowth.

Billions of dollars in incremental profits and revenue are sitting in the ground across Western Canada, waiting for oil and gas companies to reap the benefits.

The Frac Knowledge database, brought to you by Fracturing Horizontal Well Completions Inc., is Canada’s fastest growing and largest completion, fracturing, drilling and well files database tied to well production and costs. “By using the right tools, finding the right solutions without starting from scratch and shortening the learning curve with good fact-based production, companies are able to determine successful technologies and frac designs when exploiting new unconven-tional or conventional oil or gas plays,” says Fracturing Horizontal President and CEO, Tim Leshchyshyn, P.Eng. “We can help E&P companies figure it out years earlier which shows tremendous incremental revenue and profit.”

What sets Frac Horizontal apart, Leshchyshyn says, is that it’s the largest, fastest growing company of its kind in Western Canada. “We are THE fracturing experts and pioneers of this new standard for detailed industry information. Other domestic players as well as international companies are trying to learn from well analogs which are rich with information.”

Frac Horizontal engineering portion of the team designs fracturing plans for multi-stage fractured horizontal wells and vertical wells in Canada, U.S.A., Mexico, China, Hungary, India, Australia and Ireland.

Frac Horizontal has gathered the hundreds of thousands of documents on wells from B.C. to Manitoba, covering the Cardium, Montney, Viking, Horn River, Pekisko, Beaverhill Lake, Bakken and dozens more formations. The frac expert extracted dataset has software tools that allow clients to quickly research offset well production,

map trends, and clearly understand costs. The database covers production with five methods, frac type, size, fluid, proppant, isolation/diversion technology, rates, pressures and more.

Frac Horizontal’s experienced team of fracturing experts populates this database, which is searchable by map or forms - whatever method works best for the user. “For instance, within two minutes we can grab the whole Montney play and see the average well production trends vs. technology and frac design. We can cross plot total fracturing stages with initial gas rates. We can cross plot stage spacing with reserves recovery at two and four years or any one of 100 other variables that we’ve collected that don’t exist in the public realm, with production or other design variables that we’ve collected - to form the new standard to maximize production and profit from exploitation.”

This database, Leshchyshyn says, is known as the largest unofficial joint industry project for the entire Canadian oil and gas industry. “We collect this knowledge base at merely our cost for our clients,” he explains. “Often, we have the offset information they’re looking for; if not, we go to the provincial boards for the same cost or less than they would pay the board directly to get the well files.” The database has grown as quickly as it has because Frac Horizontal takes care of everything. This way, “oil company clients spend their time analyzing the informa-tion and its production impacts, rather than spending weeks pouring through 100 well files to collect the data first.” The database is growing at its maximum rate thanks to

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Service outfits respond with a range of products, systems and innovations

By Godfrey Budd

Meeting the tight oil challenge

The stunning success of horizontal drilling and multistage fractur-

ing technologies in shale gas has doubtless played a role in the

increased application of these technologies in conventional oil plays

that are designated as “tight oil” because of their low porosity and perme-

ability. Armed with these technologies, companies smell fresh profit potential

from old oil reservoirs. In the Western Canadian Sedimentary Basin (WCSB),

as the Canadian Energy Research Institute (CERI) noted in a report published

in June, “The industry is returning to old, thought to be depleted, reservoirs

equipped with horizontal well drilling techniques to recover more of the

resource that remains in the ground.”

With the lion’s share of conventional oil’s low-hanging fruit in the WCSB

already exploited, and oil prices rebounding since the third quarter of 2009,

operators have increasingly pursued tight oil plays in the Cardium, Viking,

Bakken and elsewhere across the basin. CERI’s numbers for Alberta, for ex-

ample, highlight the expanded role of horizontal wells and tight oil plays in the

region’s conventional oil sector. “In Alberta, in 2010, the number of horizontal

oil-directed licences grew to 62 per cent of all oil-directed licences. This is a sig-

nificant change from 2006 where the number was 24 per cent,” said the report.

Multistage horizontal fracturing (MSHF) has not only a critical role in

the productivity of a well in a tight oil formation, but, as in shale gas, it

typically accounts for a huge part of a completion budget. According to

an analysis from Fracturing Horizontal Well Completions Inc., frac days, on

average, account for about 70 per cent or more of total

completions and stimulations costs when using MSHF.

Pointing to a chart used in the analysis, Tim Leshchyshyn,

president of Fracturing Horizontal, says it refers to all

formations, based on data his firm has gathered. He adds,

though, that because some completions expenses are

entered as part of drilling reports, “particularly in the case

of open-hole packers,” his figure of around 70 per cent

may understate the actual percentage of completions

costs. “[It] could be five to 10 per cent higher.”

Leshchyshyn says that, once the oil is found, as much

as 90 per cent of well productivity optimization is “frac-

related.” So, given the costs involved and importance

of its role, implementing the best possible fracking

program—for every well that uses MSHF—has become

imperative for operators.

Also, because of the demand for fracking services, he

says, companies can no longer count on free consulta-

tions from fracking outfits, and must plan their comple-

tions programs carefully in advance.

A chemical engineer with more than a dozen years

of experience in the fracturing sector, Leshchyshyn is in

demand for his consulting services in North America and

overseas and as a conference speaker. He was conference

chair at the recent Shale Oil Summit for Western Canada

in Calgary and will chair the Insight Tight Oil Forum in

Calgary in December. The reason has to be his firm’s

unique suite of services, which are geared to resolve

some of the key well history/data challenges of the hori-

zontal fracking era—as well as play a key role in helping

companies figure out how best to proceed with each of

their specific frac jobs.

Fracturing Horizontal, in partnership with Geo

Webworks Inc., which has been providing public explora-

tion and production (E&P) data to industry since 2000,

appears to have a critical tool for MSHF completions and

improving productivity in the form of a fast-growing

completion, fracturing, drilling and well files database

that is tied to production figures. “It’s a database for

optimizing frac completions,” says Leshchyshyn.

FLUIDS DELIVERYCalfrac has launched several custom frac fluid solutions in the past two years designed to increase production, result in quicker cleanup and better flowback, and reduce produced water.

PHOTOS: CALFRAC WELL SERVICES LTD.


Besides bridging a knowledge gap between key input variables of fracking

completions and production figures, the firm’s Fracknowledge database—

which is supported by software, maps, graphing, reports, tables and ways

to export to Excel from Geo Webworks—can save engineers a lot of time.

“Reports go to provincial libraries—fine—but about 10 years ago, companies

started scanning all documents and putting the [well] reports on a site. But an

engineer might have to look at over a hundred reports, each 100–300 pages

long. It took too much time. With Fracknowledge, all the key variables of the

reports are captured and categorized,” says Leshchyshyn.

The database, supported by Geo Webworks software tools and Fracturing

Horizontal’s consulting, when needed, is a significant step in the develop-

ment of data-supported analytic tools for fracking optimization, says David

Burns, business development manager at Geo Webworks.

The complexity of today’s completions sector and the lack of data tying

MSHF completions variables with production history have been a challenge

and source of debate within the industry. The advent of Fracknowledge looks

like an important step toward reducing risk and improving the chances of

success, putting uncertainty and debate to rest on some issues, while, as

Burns suggests, sparking new debates on other issues as the fast-growing

completions sector continues to evolve.

For decades, the key determinants of productivity were porosity and

permeability, says Leshchyshyn. “But in the last five years, multifrac horizontals

have changed everything.”

When vertical wells dominated the industry, the number of key input

variables, aside from geology, when deciding on the type of frac to do, could

be boiled down to three, he says: frac fluid type, proppant type and amount

of sand. “Today, the inputs are cost, frac fluid chemistry, total number of stages,

spacing, the type of isolation or diversionary liners—for example, cemented

liner versus openhole are among the variables—tonnes of proppant per stage,

production figures; all these can be cross-referenced in several ways,” he says.

Fortunately, “about 90 per cent of the time, all the key input variables are

reported to the provinces—for us to find,” he adds.

Geo Webworks provides clients with training on running the software

analytic tools and Fracturing Horizontal provides some consulting to help

clients understand the data content and, says Leshchyshyn, “we support their

getting more data of a specific type that they might request.”

NEW PRODUCT DIVERSITYTo meet the demand for fine-tuned fracking solutions, established com-

panies and firms in the service sector have been expanding their product

offerings, with newer firms often filling a gap with niche solutions or, as

in the case of Fracturing Horizontal, specialized products with potentially

broad application.

Another case in point of the latter is NCS Energy Services Inc., relaunched

in 2008 as a downhole tool company focused on MSHF. In 2010, NCS intro-

duced a new sliding sleeve which sits as a section of the casing string and

runs with the same internal diameter, burst and collapse strength of the host

casing. Instead of perforating at the frac-initiation point, the sleeve’s frac ports

provide access to the formation and are opened by the Mongoose packer

on the tubing string. There is thus no need for pump-down plugs for stage

isolation or sleeve actuating balls. The casing annulus sealing can be either

cement or swellable packers.

The key benefits of the new sleeve, says Eric Schmelzl, sales manager at

NCS, are cost reduction, better reliability and improved speed of execution.

“You don’t need to go in and out of the hole for each stage,” he says.

In the event of a sand-off, “Since you have the tubing in the hole, you just

circulate to remove the sand. Also, while doing the frac, the operator can

see the actual bottomhole pressure because of static

pressure inside the tubing, and it is being measured right

where the ports are. By having an accurate pressure read-

ing, it’s easier to predict screen out and avoid it,” he says.

NCS’s new Multistage Unlimited system’s frac

isolation assembly, which combines the new sleeve

technology with many elements of its existing

Mongoose packer and frac system, includes among its

key components a resettable bridge plug, a mechanical

sleeve locator, an abrasive jet perforating sub and an

equalizing valve/reverse-circulating sub. “The locator

saves time by only recognizing frac sleeves, which

makes locating the next stage of the frac operation fast

and simple,” says Schmelzl.

After a frac stage is done, a pull on the coiled tubing

opens the equalizing valve and un-sets the bridge

plug and the isolation assembly is moved to the next

sleeve. Once all frac stages are completed, tubing and

isolation assembly are pulled from the hole, with no

components to remove and no plugs or ball seats to

drill out.

With only about five minutes between fracs, Schmelzl

says a key benefit of Multistage Unlimited is the money

saved with a speedier, more seamless fracking operation.

“With this system, we have routinely placed 10 30-tonne

stages in less than eight hours,” he says. The system can

accommodate additional frac stages on the fly, even

where there is no sliding sleeve, by using the system’s

integral jet-perforating sub.

Schmelzl estimates that between 1,200 and 1,300

Multistage Unlimited sliding sleeves are now in the

ground. He expects accelerating sales in the wake of a

new low-cost version of the sleeve, which targets the

lower pressure frac requirements found in some of the

more shallow Viking, Spearfish and Bakken formations.

BETTER AIMEarlier in the E&P process, during horizontal drilling, guid-

ing the drill bit along what is sometimes a relatively thin

formation pay zone can be tricky, especially in some of

today’s tight oil plays. Horizontal Solutions International

(HSI) has worked on horizontals since the late 1980s

BUILT-IN FLEXIBILITY

Sanjel is launching large-capacity,

skid-mounted 3,500- horsepower pumpers

that can run on diesel, natural gas or

combinations of both.

PHOTO: SANJEL CORPORATION

TECHNOLOGY ADVANCES


the Cardium, Bakken and Viking, which are predomi-

nantly low permeability. It’s green and low-viscosity and

minimizes filter cake, and, more importantly, chemical

residuals. The proof is in the numbers. We’ve seen higher

production, lower produced water, quicker cleanup and

better flowback, and faster production start,” says Chad

Leir, sales and marketing manager at Calfrac.

The water-based frac fluid can be pumped on its own

or foamed with nitrogen.

Most fracking fluid suppliers include both oil- and

water-based products, but one company, GASFRAC

Energy Services Inc., has been focused almost exclusively

on a particular type of petroleum-based fracking system

since it was launched in 2007. According to its latest

annual report, GASFRAC is the only fracture stimulation

company using gelled liquefied petroleum gas (LPG),

usually propane, as the frac fluid.

One of the main reasons for the LPG-based system is

that fracking operations can benefit from the exception-

ally low surface tension of liquefied propane—about

one-tenth the surface tension of water and about a third

that of most frac oils.

“When you use a liquid wedge with such a low

surface tension, the fluid cleans out the fracture almost

completely, increasing the effective fracture length. This

translates into improved well productivity over the short

and medium life cycle of the well, higher recovery factors

and improved reserves,” says Reid MacDonald, president

and chief operating officer at GASFRAC. He says the

system has been successfully used in tight oil formations

in the Cardium and depleted reservoirs in the Viking.

and provides software and consulting services to keep

the drill bit on track. “We’ve geosteered and geo-navigated

about 8,000 wells. We also provide software to some

end-users that use the software on their own,” says ken

Bowdon, president and chief executive officer of HSI.

The company uses LatNavNet software to incorporate

a range of data sets from the well and the formation,

including gamma ray data. “It models the data so that

the distortion that results from the horizontal plane is

removed. The software does require an interpreter. The

data is sent off site to the geosteering team, or some-

times to a geologist on site. Directions typically come

back within a short time,” says Bowdon.

Supported by Gydex LLC IT, HSI has recently beefed

up infrastructure and client support services to meet the

current growing demand, says Bowdon, who is a co-founder and managing

partner at Gydex.

A technology for augmenting horizontal drilling, which has been success-

fully used in the United States to depths of over 12,000 feet, has begun to

be used more in Canada. Departure Energy Services Inc. recently added an

electromagnetic measurement-while-drilling tool to its suite of downhole

equipment. The technology is much less expensive than those used offshore

but can improve the depth capacity of horizontals. Also, “it helps operators

steer better within reservoirs,” says Dan Robson, director of strategic develop-

ment at Departure. In some of the thin formations of tight oil plays in the

Cardium, it’s likely this could be helpful.

Quality materials and high-end metallurgy are also assuming a greater role

in the composition of downhole tools for horizontal drilling. “We now build a

mud motor for the horizontal drive train to advanced metallurgy [standards]

in order to support the aggressive [action] of drill bits and power sections,”

says Robson. Until recently, some of Departure’s downhole tool steel compo-

nents had a yield strength that equalled that of landing gear for a Boeing 747

jumbo jet. But now those same parts are made to specs that compare with

those on a satellite, he says.

FRAC FLUID CUSTOMIzATIONFracking fluids have assumed increased importance because of MSFH

and their growing variety is a response to the need for precisely targeted

products. Sanjel Corporation’s recently introduced kappajel water-based

surfactant is geared to clean up, so there is no chemical residue left to reduce

porosity at the wellbore. “It’s becoming more widely used in light oil in the

Cardium and Viking plays. Its single purpose was flowback without residue. It

can be used in oil and gas,” says ken Berg, vice-president of sales at Sanjel.

The company is also adding large-capacity, 3,500-horsepower pumpers to

its fleet. Each of these almost replaces two standard units.

“Construction costs are cut and the pumps are so robust

that repairs and maintenance are also cut. A frac job

could go from 25 to 15 units by using them,” says Berg.

The skid-mounted units can run on diesel or natural gas

or combinations of both.

The renewed interest in the Cardium and other tight

oil plays requiring MSFH has also prompted others to

expand their fracking fluid offer. Calfrac Well Services Ltd.,

for instance, has introduced several new targeted, cus-

tom solutions in the last two years. Under the company’s

rating system, some are classified as green, including one

called CleanTech. “CleanTech was designed specifically for

DRILLING GUIDANCESupported by Gydex, Horizontal Solutions International, a provider of software and consulting services for geosteering and geo-navigating horizontal wells, has been able to strengthen its infrastructure and client support services in response to greater demand.

R&DSanjel, below, and Calfrac, right, are among those companies devising a growing variety of fracture fluid formulations in the laboratory for application in emerging tight oil fields.

TECHNOLOGY ADVANCES

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Ground Effects Environmental Services Inc. (GEE) is a full-service environmental remediation company specializing in innovative, in-situ remediation solutions. GEE has developed more than 70 techno-logical innovations in a wide variety of areas including multi-phase extraction, electro-kinetic remediation, electro-coagulation water treatment, bioremediation, electro-kinetic and high pressure injection, pneumatic fracturing systems and more. GEE provides turnkey solutions (manufac-ture, installation and maintenance) of environmental remediation equipment that can effectively treat impacted soil and groundwater on site, offering the lowest lifecycle costs in the industry.

Founded 13 years ago in Regina, GEE manufactures a variety of technologically advanced equipment, including mobile and fixed wastewater treatment packages, serving clients across Canada, the United States and Australia.

On the service side, GEE is predominantly active in Western Canada, providing complete turnkey options for all of its technologies.

ElectroPure Technology Water Treatment SystemOne of GEE’s newest, most exciting technol-ogies is its ElectroPure water treatment system, developed nearly three years ago for the oil and gas industry, utilizing electricity to destabilize and remove contaminants. Exploration and Production (E&P) companies can reduce their operating costs while lowering greenhouse gas emissions with GEE’s ElectroPure technology, which uses a chemical-free process to treat frac flowback, produced, and other wastewater streams on site at rates of 500—3,000m3 per day. Fully automated and easy to use, GEE’s system can be efficiently set up in short order and requires minimal maintenance when in operation. It uses a proprietary two-stage electro-coagualtion process that achieves outstanding results. It’s 99 per cent effective

on a majority of contaminants (http://groundeffects.org/index.php?option=com_content&task=view&id=176&Itemid=119) and environmentally sustainable since the water is treated for reuse on site. GEE’s system is one of very few in North America to use electrocatalytic oxidation to purify frac flowback and produced water.

“The unique thing about the ElectroPure platform is that it can treat a very wide range of contaminants in frac flowback and produced water,” says GEE President and CEO, Sean Frisky.

For mobile treatment of frac flowback water in the oil and gas industry, ElectroPure’s capabilities are unmatched. GEE can fine tune the system to reduce radically varying levels of polymers, total suspended solids (TSS), guar gum, iron, bacteria, scaling agents, H2S and almost any other contaminant resulting from the fracking process to required levels for reuse. GEE has consistently treated gel fracs and hybrid fracs, which generate the most difficult types of wastewater to treat. As Frisky puts it: “The system has worked for every single water source we’ve hit.”

GEE’s systems can be remotely accessed, controlled and optimized from anywhere in the world via satellite or cellular link, including real-time access to critical process informa-tion and intelligent trending.

GEE can build fixed facilities, so that E&P companies have their own treated supply for fracking. As a completely scalable and mobile service, treatment can be completed at the well head or at a location centralized to multiple drilling sites in one area.

“So far we’ve deployed the system in Western Canada, with awesome results,” Frisky says, noting that the system creates high quality brine that can be used for fracking and other oilfield uses such as water flood.

The ElectroPure mobile water treatment system consists of three trailers, which are completely plug-and-play, provide protection in the most extreme of weather conditions,

can be operated in a Class I Zone II environ-ment, and have a typical set-up time of approximately one hour. GEE operates six mobile water treatment plants and is currently fabricating more.

GEE’s ElectroPure system can substan-tially reduce costs for E&P companies when compared to current methods, which require trucking, water disposal and the purchase of fresh water. In comparison, GEE estimates that producers save anywhere from 30—80% of conventional trucking and disposal costs by using GEE’s ElectroPure system.

“The economics really work when you figure out the real cost of your water, including all of those hours of trucking and waiting at the disposal site, the disposal costs themselves, and buying and trucking the equivalent volume of fresh water back to site,” says GEE Business Development Manager, Calvin Prokop.

And by eliminating the constant flow of trucks, the ElectroPure system not only reduces CO2 emissions, but also enhances safety for everyone in the area by taking trucks off the road.

GEE’s ElectroPure water treatment system has applications in many industries in addition to oil and gas, including the mining, industrial, agricultural and marine industries.

technologyprofileadvertorial

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For more information, please contact:

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frac flowback water treatment

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tHe resultsContaminants Result

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Stars alignedTechnology, timing and tenacity unlock long-slumbering Bakken shale oil playBy Jim Bentein

We’ve always known the oil was

there, but it took a convergence

of factors to make it happen.

Those elements included the development

of new, more sophisticated horizontal drilling

and fracturing technologies, timing—as higher

oil prices made investments in those costly

technologies viable—and the tenacity of start-

up explorers and producers, and oilfield service

firms who made it possible.

Those three Ts—technology, timing and

tenacity—have led to the development of a

number of tight and shale oil plays in North

America that is unlocking billions of barrels of

oil and turning once-sleepy economies like

those of North Dakota, southern Saskatchewan

and now even parts of southwestern Manitoba

into booming areas where there are never

enough skilled workers, houses or hotel rooms.

Dubbed Saskatchewan’s and North Dakota’s equivalent

of the oilsands, the king of the shale oil plays is the

Bakken, a pool of light oil trapped under an impermeable

layer of 350-million-year-old shale within the Williston

Basin, a huge formation under the plains of North Dakota,

eastern Montana, southeastern Saskatchewan and the

western corner of Manitoba.

Until the early part of this decade, that potential mother-

lode—Saskatchewan alone has an estimated 5.5 billion

barrels of crude trapped in its Bakken, with North Dakota

having that and more—lay virtually dormant, since conven-

tional vertical wells were only able to tap about one per cent

of the crude in place, rendering the Bakken uneconomic.

Then came a series of technological advances, led by

horizontal drilling, which allowed for access to more of

the reservoir. By drilling horizontally into the shale, then

fracturing the rock with high-pressure liquid and sand,

fissures were created in the source rock through which

the oil could flow.

That technology was further refined so that fractures

could be accurately positioned, creating multiple flow

points, sending oil gushing into one long horizontal well.

Trent Yanko decided early in the decade the potential

of the Bakken was too great to pass up, and he has

since become a wealthy man as a result and one of the

pioneers of development there.

In the early part of the decade, the start-up he led,

Mission Oil and Gas Inc., began picking up land positions

in Saskatchewan and contracting with oilfield service

companies deploying the new technologies being used

to unlock the Bakken’s potential. Mission expanded its

production there from just 500 barrels of oil equivalent

(boe) per day to 7,000 boe before being sold in 2007 to

dominant Bakken player Crescent Point Energy Corp.

for $670 million. Calgary-based Crescent now produces

almost 50,000 boe, mostly in Saskatchewan’s Bakken and

North Dakota.

But for Yanko that wasn’t the end of his tight oil adven-

ture, as soon after he and partners formed Legacy Oil +

Gas Inc., which evolved after the takeover of the former

Glamis Resources Ltd. in 2009. A series of acquisitions

followed, starting with buying privately owned Medora

Resources Inc. and Renegade Oil & Gas Ltd. and then with

the purchase of a land position in Saskatchewan from

Bonavista Energy Trust for $282 million.

Those acquisitions have continued as Legacy more re-

cently bought Connaught Energy Ltd., CanEra Resources

Single Treatment

Single Treatment

Single Treatment

One fracture treatmentfour simultaneous stages

RockSEAL IIpackers

QuickPORT sleeves

TRANSFORMATIVE TECHNOLOGY

Horizontal multistage fracturing systems,

like Packers Plus Energy Services'

QuickFRAC multistage batch

fracturing system, were instrumental

in making shale gas and tight oil plays

economic.

ILLU

STRA

TIO

IN: P

AC

kERS

PLU

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RVIC

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C.


Even as Bakken production surpasses the 60,000-

barrel-per-day mark this year in Saskatchewan, up from

just 750 barrels in 2004, it continues to be a developing

technology story.

North Dakota production, almost all from the Bakken,

has risen from 100,000 barrels per day to almost 400,000

per day.

The technology most often credited with unlocking

the Bakken’s potential was Calgary-based Packers Plus

Energy Services Inc.’s StackFRAC completion method,

which allows individual zones in the same horizontal well-

bore to be isolated and fracked separately. Legacy and

other producers utilize similar approaches, which dramati-

cally raised Bakken production rates and profitability.

Crescent Point has increasingly shifted to cemented

liners for its completions, based on the belief they are

better suited to large-scale waterfloods, which it is turn-

ing to increasingly to boost production.

PetroBakken continues to utilize Packers Plus

completion technology (see sidebar on the next page),

along with bilateral horizontal wells. In this approach,

two 1,400-metre horizontal legs are drilled from one

vertical wellbore with 15 fracs per horizontal leg. Most of

PetroBakken’s wells are now bilaterals, says Peter Scott, its

chief financial officer.

Scott says it is doing pilot tests of gas floods on its

Bakken lands. “It would be a new approach there,” he says.

“Crescent Point and Legacy have done waterfloods, but

we feel natural gas might be more effective.”

He says the company tested CO2 injection but has

decided gas floods may have more potential, especially

since it co-produces gas. It has been testing gas since

late March in one well and plans to test it in two or

three more.

The company has stakes in 430 net sections of land in

the Bakken, all in Saskatchewan, with production ranging

from about 17,400 barrels per day to 23,000 barrels per day.

Robin Bertram of AJM Petroleum Consultants says

production from Bakken and other tight oil plays will

to seven per cent, that could mean 70 [million] to 100

million barrels more of potential reserves.”

And Yanko believes that kind of potential and beyond

is possible.

It starts with relatively simple approaches, such as in-

fill drilling, then moves on to waterfloods, which Legacy,

Crescent Point and other large Bakken producers have

deployed. Eventually, he sees CO2 injection unlocking

even more of the oil in place.

Yanko believes it’s not inconceivable that eventual re-

coveries, now at 10–15 per cent, could reach 35 per cent

from his company’s lands and from much of the Bakken.

“We are big believers in enhanced recovery,” he says.

So is Mike Carlson, Calgary-based manager of reser-

voir engineering with RPS Group Canada, who points

out the miscible floods with hydrocarbons (gas and

oil) have long been used in aging oilfields in western

Canada, such as Swan Hills, Alta., and CO2, abundant

in parts of the United States, has been used there to

boost recoveries.

“CO2 injection probably makes more sense than

waterfloods, but government policy [which would lead

to the capture of more CO2, which could be used in

enhanced oil recovery] would be a big part of that.”

A government move to force large polluters to

capture CO2 or some form of climate tax that compels

them to do so might be the answer, he suggests. CO2

is already being used successfully to coax oil out of

an aging conventional oilfield in the Weyburn area of

Saskatchewan.

Calgary-based engineering consultant Granger Low,

of Proven Reserves Exploitation Ltd., argues that miscible

floods using natural gas would unlock hundreds of bil-

lions of barrels of oil in reservoirs like the Bakken and in

conventional oil pools.

“Injecting low-priced gas to produce high-cost oil

just makes sense,” he says, commenting on a paper he

recently produced on the subject.

He calculated that doing so would lead to the produc-

tion of 30 billion barrels of oil in Alberta’s conventional

pools alone, almost double the 16 billion barrels that has

already been produced from those reservoirs. He also cal-

culated that at today’s prices, that would cost $1 billion

and would unlock $1 trillion in oil production.

Injecting gas into tight and other unconventional oil

plays would multiply those production levels many times

more, he argues.

However, Carlson is a skeptic, arguing that gas prices

won’t always stay low and it would be better to shift to

CO2 floods.

PetroBakken Energy Ltd., with over 1.8 billion barrels of

light oil in place in its southeastern Saskatchewan Bakken

lands, is also a big believer in enhanced recovery. The

company has only booked five per cent of its reserves

there as proven and probable, but company executives

have said they think that could rise to 25 per cent once

secondary recovery technologies are applied.

Inc. and also picked up a land position from

Athena Resources Limited.

All those acquisitions have been focused

on shale oil plays in Saskatchewan, North

Dakota and Manitoba and on an emerging

play in southeastern Alberta dubbed, optimisti-

cally, the Alberta Bakken (although it is not

geologically connected to the Saskatchewan

and North Dakota Bakken). Legacy also has

a substantial land position now in the Turner

Valley area of Alberta.

While the Bakken is the most established

of the tight oil developments, other tight oil

plays, such as the Cardium, Viking and Lower

Shaunavon, are either in development or seen

as having great promise.

Illustrating tight oil’s potential, two-year-

old Legacy has now achieved production of

about 13,000 boe, and Yanko says it should be

producing 15,750 boe by the end of this year.

He continues to be a strong believer in the

potential of tight oil, likening it to the “resource

plays” in shale gas areas such as the Horn River

Basin of northeastern British Columbia or the

Alberta oilsands.

“You know the resource is there, and there’s

a big target,” he says. “It’s technologically driven.

The frac is the secret to a lot of these plays and

execution by management is the key. We’re

spending $1.5 million to $10 million per well,

so you need to have a technical focus and you

need to execute.”

Most wells cost $1.6 million to $1.7 million

and the payout is in 12–18 months, he says,

contrasted with years for oilsands invest-

ments. But the plays have characteristics

similar to oilsands investments, since they are

long-lived, says Yanko. “Once you’re there, and

you have the land position, you can produce

for years,” he says. “You could have 10 or 15

years of inventory.”

As with the oilsands, it also helps that oil

prices have remained elevated. “We wouldn’t

be doing these tight oil plays if oil prices were

at $15 a barrel,” he says.

It is also an economy-of-scale process, much

like other resource plays, says Yanko. “It’s tough

to be a 10-person, 1,000-barrel-a-day operator,”

he says. “If you’re producing 10 barrels a day

from 500 drilling locations, the economics are

more challenging than if you’re producing 10

boe per day from 1,500 locations.”

The good news is secondary recovery meth-

ods will only lead to increased production.

“We have 120 sections overall and we could

have 1.2 billion barrels under management,”

he says. “If we can increase recoveries by five

UNLOCKING TIGHT OILHigh-end horizontal multistage fracking like that provided on an industrial scale by Packers Plus Energy Services vastly outperforms vertical well completions while limiting the surface footprint.

IMA

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EARLY ADOPTERS


When the history of all of the business success

stories emerging from the development of the

tight oil and gas reservoirs in western Canada

and the western United States is chronicled, the story of an

11-year-old Calgary-based company that specializes in an

area of oilfield technology unheard of until the last few years

might be the most remarkable .

“We started small,” says Dan Themig, president of Packers Plus

Energy Services Inc . “When we were starting to set up

our offices, I brought a computer from my house and

we bought office furniture at the Salvation Army .”

A decade later, the privately owned company

employs 500 and has annual sales likely in the

hundreds of millions of dollars—although Themig

refuses to divulge revenue figures . He says dollar

figures aren’t important and serving customers is .

Packers Plus is building a new 42,000-square-

foot office in Edmonton and has a slightly smaller

office in Houston . It has eight offices and/or facilities

overall in Canada, 10 in the United States and has

offices worldwide, including in the Middle East, the

North Sea and Brazil, with 28 offices overall .

And Themig says it’s inevitable it will double its

workforce in the next few years .

Themig and partners Ken Paltzat and Peter

Krabben, who had all worked together at the former

Dresser Industries and then for Halliburton Energy

Services Inc ., which bought out that company,

knew exactly what they wanted to do with the

fledgling company when they left secure jobs and

formed it .

“We were committed from day one to bringing

technology to the land-based drilling industry, with

a focus on horizontal completions,” says Themig .

That focus led to the development of a number

of completion technologies, starting with the

StackFRAC system, which revolutionized the

completions sector by introducing multistage

fracturing systems in horizontal wells, credited

with unlocking the potential of tight and shale oil

and gas .

The firm has since introduced dozens of prod-

ucts, including the new QuickFRAC system this past

spring, which allows for up to 60 stages downhole

while pumping 15 treatments at surface .

“QuickFRAC is a great technology that can

meet the need for increased stage numbers

in formations such as the Bakken, Horn River

and the Montney, as well as many others,” says

Themig . “QuickFRAC allows the operator to do

the job of pumping 15 stages on surface while

Packers Plus does the job downhole, providing

as many as 60 individual stages . This is done by

taking a single pumping treatment on surface

and precisely directing it into two to five stages

downhole . For the operator, pumping time and

costs are reduced significantly and production

results are greatly increased .”

This past summer it introduced its new

RepeaterPORT sleeve technology, which allows op-

erators to increase

Leadingthe wayMultistage fracking pioneer Packers Plus plays major role in cracking the tight oil code

the number of stages per lateral when they utilize

existing Packers Plus systems .

“When we started the company we saw the

need for high-end fracturing completions technol-

ogy,” says Themig . “There was horizontal drilling

going on, but nobody was fracking .”

The idea of starting a service firm that concen-

trated on a value-added niche came partially as a

result of a class Themig took while he was studying

towards a master’s degree in business administra-

tion . “The professor says a business can either be a

Saks Fifth Avenue or be a low-end alternative,” he

says . “We picked the Saks model .”

Packers Plus first introduced its completions

technology in the Barnett shale in 2003 and it now

dominates the completions segment in most land-

based tight and shale oil plays .

“When we started, you could do five fracs,” he

says . “Our StackFRAC brought that up to 20, and

now we have technology that can do 60 .”

More recently it has moved into the offshore

market . “Offshore reservoirs might have an

extended production life of 20 years or so because

of our technology,” says Themig . “We don’t think the

market understands that potential yet .”

It continues to be an engineering-focused

company, with about 10 per cent of its employees

having engineering or technology degrees .

He says the company will introduce up to three

new technologies in the next few months . “We

have 84 engineering projects underway now and a

number of projects in the developing stages .”

Themig says the firm will be introducing a range

of new products over the next six to seven years .

And it’s expanding its manufacturing capacity for a

good reason .

“We can’t keep up with demand,” he says .

only grow over time. “I attribute it to cracking the code,”

he says. “Companies are continuing to push the envelope

with technology.”

Horizontal drilling technologies have improved,

better fracking fluids and muds have been developed,

computerized approaches have allowed for better place-

ment of stages and the industry is increasingly shifting

to enhanced production methods like waterfloods,

gas floods and CO2 injection that sweep the remaining

hydrocarbons to where they can be produced.

“There are some technologies we haven’t developed

yet, and they and existing technologies will ultimately

lead to more production from tight reservoirs,” Bertram

says. “I don’t know what that production will be, but it will

be a big number.”

FASTER, GREENERCapable of fracturing

60 stages downhole while only pumping

15 treatments at surface, Packers

Plus Energy Services’ QuickFRAC technology, by using consistent pumping

rates, also greatly reduces water usage.

PHO

TO: PA

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EARLY ADOPTERS

New Multistage UnlimitedTM frac-isolation system

All the fracs you need, exactly where you want them, in a fast, nonstop completion sequence

No actuating balls, no pumpdown plugs, no perforating

THE MULTISTAGE UNLIMITED SYSTEM delivers all the pinpoint fracs you need to optimize well production, yet thesystem is so simple and the operation is so fast that it costsless than methods that limit your completion options.

Only 5 minutes between fracsThe system requires no pump-down plugs, actuating balls,or perforating tools. Here’s how simple it is:

• Run the casing with a Multistage Unlimited sliding sleeve in the string wherever you plan to frac. You can either cement or run swellable packers to seal the annulus.

• Run the Multistage Unlimited frac-isolation assembly oncoiled tubing to the lowest sliding sleeve.

• Set the resettable bridge plug inside the sliding sleeve andshift the sleeve with string weight and annular pressure.

• With the bridge plug sealing below the open frac ports,pump the frac down the casing/coiled tubing annulus.Monitor frac pressure at the surface via the coiled tubing.

• When the frac is away, pull up to open the equalizing valveand unset the bridge plug. Move to the next sleeve and repeat. In about 5 minutes, you’re ready to frac again.

Add stages on the flyYou can add a stage where there is no sliding sleeve by usingthe integral jet-perforating sub. The added stage is frac-readyin less than 40 minutes.

Full-open, production-ready wellboreWhen the frac-isolation assembly is pulled from the well afterthe last frac, you have an unrestricted wellbore all the way tothe toe, with nothing to retrieve or drill out.

Uses 10% to 20% less waterThe Multistage Unlimited system cuts water requirements by eliminating pump-down components, by circulating lead-ing-edge fluids down instead of bullheading them, and by re-ducing casing volume by the volume of the coiled tubing.

Ultra-reliable operationThe Multistage Unlimited system is easier to operate andmore reliable than any other multistage equipment:

• All-mechanical operation. An automatic j-slot sets and unsets the bridge plug with up-and-down string motion.

• The resettable bridge plug has been used for more than10,000 stages and has been cycled more than 40 timesduring a single completion operation.

• With its sand-friendly design, the system is impervious tomalfunctions caused by contamination.

• Sand-outs can be quickly reversed out.

The Multistage Unlimited system is currently available for 41⁄2-in (114 mm) and 51⁄2-in (140 mm) casing. Call us or visit ourwebsite for more information.

www.ncsfrac.com 409.925.7160 (U.S. Sales) 403.816.1011 (Canada Sales) 403.720.3236 (Central Dispatch) [email protected]

©2011, NCS Energy Services, Inc. All rights reserved. Multistage Unlimited and “Leave nothing behind.” are trademarks of NCS Energy Services, Inc. Patents pending.

Leave nothing behind.TM

Coiled tubing

Frac ports

Equalizing valveStandby jet perforating sub

Resettable bridge plugSliding sleeve


CHICKEH

DOE CREEKDUNVEGANU.TRIASSIC

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SWAN HILLS

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SECOND WHITE SPECKSJURASSIC

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A L B E R TA S A S K AT C H E WA N

U N I T E D S TAT E S O F A M E R I C A

M A N I T O B A

The resurgence in North American natural

gas production, precipitated by the deploy-

ment of game-changing horizontal drilling

and multistage fracturing technologies, appears set

to repeat itself in oil, as the technologies are applied

to previously marginal tight and shale oilfields.

While it’s still early on the crude oil side, as

companies experiment with the best production

parameters to solve individual plays, an increasing

number of studies are suggesting the prize—in not

just increased production, but in new jobs and grow-

ing royalties—could be huge as more and more

plays are solved.

As with natural gas before it, North American

crude shows signs of halting its decades-long

production declines to—at least in the short to

medium term—resurrect an industry thought to be

in terminal decline.

Assisted by buoyant oil prices while natural gas prices remain weak, drill-

ing has shifted from gas to oil as the technologies are increasingly adapted to

oil plays—as well as liquids rich gas plays—in Canada and the United States.

In addition to an “enormous” natural gas resource base that’s “potentially

transformative for the American economy, energy security and the environ-

ment,” the National Petroleum Council (NPC) stated it is “perhaps surprising to

many [that] America’s oil resources are also proving to be much larger than

previously thought…. The United States and Canada together produce four

per cent more oil than Russia, the world’s largest producer.”

In a comprehensive draft report delivered to U.S. Energy Secretary Steven

Chu in September entitled Prudent Development: Realizing the Potential of

North America’s Abundant Natural Gas and Oil Resources, the NPC stated these

oil resources “offer substantial supply for decades.”

Technology leadership and sustained investment led the way, according

to the study, which involved about 400 people, half outside the oil and gas

industry, and took two years to complete. After years of decline, North

American oil production rose in 2009 and 2010 “due to advances in

technology and significant investment in exploration and development by

companies over a number of years.”

While the oilsands and offshore fields are contributing to the resur-

gence, tight oil, found in geological formations where the oil does not

easily flow through the rock, such as the Bakken formation of

Saskatchewan and North Dakota, could play a major role as it benefits

from “technologies similar to those used for shale gas, including hydraulic

fracturing. Over the next 20 years, tight oil production could continue to

grow,” the report states.

The rapid learning and deployment of new production techniques in

recent years to unlock the natural gas supply are still being adapted to oil,

it states, pointing to future potential as techniques mature. “Such learnings

have not yet been fully applied to new and emerging oil opportunities. As

the emerging oil opportunities develop both onshore and offshore and

with application of some of the technologies now enabling access to un-

conventional natural gas, similar upward re-appraisal of potential oil supply

will likely follow.”

DECLINE REVERSALConventional oil production in the Western Canadian Sedimentary Basin

has been on the decline since it peaked at about two million barrels per

day in the early 1970s. Production had fallen more than 50 per cent by

2010 to about 900,000 barrels per day, even with significantly increased

wells on production—38,886 in 2010 compared to about 9,100 wells

in 1970.

The migration of drilling and completions technologies that had

been so successful for tight and shale gas to the oilfield is only

now changing that picture. Prior to the worldwide recession of

2008, the move towards horizontal drilling targeting tight oil was

Crude’s comebackTechnologies developed for natural gas set to transform tight oil productionBy Maurice Smith

TIGHT OIL REVISITED

New production technologies have put

once ignored tight and shale oil plays

back on the map.


TECHNOLOGY-DRIVEN GROWTHAccording to the Alberta Energy Resources Conservation Board’s (ERCB's)

supply/demand outlook 2011-20, crude oil production will increase by 6.8

per cent in 2011, in contrast to the slight decline of 0.4 per cent in 2010

and the five-year average decline rate of 4.2 per cent, “primarily due to

the expected increase in drilling activity and use of multistage fracturing

technology on horizontal wells. Crude oil production is expected to peak in

2013 and begin declining at an average decline rate of four per cent over the

remainder of the forecast period as production from increased wells drilled

and wells drilled with new technology somewhat offset declining produc-

tion from existing wells.”

The ERCB cautions, however, that “if the use of multistage completion

technology in horizontal wells becomes more widespread in Alberta, the

forecast may prove to be conservative.”

Horizontal multistage fracked wells drilled in 2010 were credited with

halting the decline in average annual production of oil wells that dated back

to 1973. In 2010, 2,308 successful oil wells were drilled, a surge of 143 per cent

from 2009. The last time Alberta experienced a drilling level this high was in

2005, says the ERCB in its annual review.

In 2010, 1,023 new horizontal oil wells (including those using multistage

fracturing technology) were brought on production, a 276 per cent increase

from 2009, raising the total number of horizontal wells to 4,850.

The largest reserves change in 2010 was recorded in the Pembina Cardium

Pool, where initial established reserves rose almost seven per cent as a result

of extensive horizontal drilling over the last several years, mostly to the south

of the main pool. “Horizontal multistage fractured wells have expanded the

limits of the pool by allowing economic production from lower permeability

sands and silts,” the ERCB notes.

Reserves were also increased in several Suffield Upper Mannville pools

in part due to infill horizontal drilling, and there is “potential for significant

reserves growth from new horizontal wells in the Cardium Formation at

Pembina, Willesden Green and other fields. Horizontal multistage fractured

wells are being drilled on the periphery of the main pools where permeability

declines to less than one milliDarcies (mD) as a result of a change to a shalier

facies. These techniques are also being used in many other formations, includ-

ing Montney, Glauconitic, Pekisko, Duvernay and Viking.”

The ERCB’s forecast, which included the category of multistage fractured

horizontal wells for the first time despite limited information available on their

production, projected the number of new multistage fractured horizontal oil

wells placed on production to increase from 745 in 2010 to 1,200 from 2011

to 2013. This number is expected to decline to 1,000 in 2014 and remain at

this level for the remainder of the forecast period.

“This projection considers the option that companies have in diversify-

ing their drilling activity with natural gas, given the expected increase in gas

demand and price over this same period, but may prove to be conservative

based on the crude oil opportunities present in the basin,” it concludes.

already underway in Canada, being first noticed in

Saskatchewan, according to the Canadian Energy

Research Institute (CERI). Emerging horizontal well

technology was directed particularly to the Bakken play

of southeastern Saskatchewan, where the number of

horizontal wells climbed from 384 to 1,233 between

2003 and 2008, acting to stabilize production declines

in that province.

With economic recovery, the pace has quickened, in

some regions very rapidly. “In Saskatchewan, the per-

centage of horizontal wells grew from 24 to 49 per cent

between 2004 and 2009 and the assumption is that this

percentage will continue to grow,” states the June report,

Economic Impacts of Drilling, Completing and Operating

Conventional Oil Wells in Western Canada (2010-2035).

Similarly, in Alberta—where plays such as the Cardium

and Viking are leading the way—the number of horizon-

tal oil-directed licences swelled from 24 per cent of all oil

wells in 2006 to 62 per cent in 2010, when a total of 3,095

oil-directed wells were drilled.

Driving the growth in more costly horizontal wells, of

course, is improved production. Fewer but more produc-

tive horizontal wells will stabilize and grow production in

Alberta and Saskatchewan, CERI predicts. With increased

horizontal well drilling comes “the potential for increasing

initial production rates in the future based on longer

horizontal legs.”

In some cases, the increases have been striking. CERI

points to average initial production rates increasing, for

example, from 50 to 170 barrels per day over three years

in the Edmonton area. While not quite as dramatic an in-

crease was reported in the Bakken, the average horizontal

well there still consistently accomplishes initial production

rates three times greater than a vertical well does.

CERI forecasts conventional oil drilling will plateau

by 2016 and thereafter decline two per cent per year as

oilsands and natural gas activity pick up toward the end

of the decade.

The impact on the economy of oil will continue to be

substantial. Examining the impact of conventional crude

developments anticipated in Alberta, which will create

the largest impact of all the provinces, CERI predicts a

cumulative sum of additional Canadian gross domestic

product from 2010 to 2035 (as a result of continued

operation of existing wells and the addition of new wells)

of $572 billion.

Employment in Canada (direct, indirect and induced)

is anticipated to grow from 87,000 jobs to a peak of

130,000 jobs in 2018, while direct employment in

Alberta is estimated at 29,000 jobs at the beginning of

the study period, reaching a peak of 42,000 jobs in 2018.

Compensation of Canadian employees is expected to

reach a cumulative total of $155 billion by 2035. Alberta

royalty payments are projected to grow from $1.98 billion

in 2009 and just $700 million in 2010 to a peak of

$4.7 billion in 2027, and fall off slightly year-to-year after

that to $4.57 billion by 2035.

" THE UNITED STATES AND CANADA TOGETHER PRODUCE FOUR PER CENT MORE OIL THAN RUSSIA, THE WORLD’S LARGEST PRODUCER.” — National Petroleum Council

TIGHT OIL POTENTIAL


A L B E R T AS A S K A T C H E W A N

B R I T I S HC O L U M B I A M A N I T O B A

E D M O N TO N

C A LG A R Y

R E G I N A

W I N N I P E G

While there’s a finite amount of oil to be extracted from the

Western Canadian Sedimentary Basin, with new technologies,

new ideas and innovative people there will still be great long-

term opportunities with the right assets, an investment conference heard

in September.

“Quite frankly, all the easy stuff has been found, all the easy stuff has

been produced and it’s going to take newer and better technologies to

unlock whatever is left,” John Wright, president and chief executive officer

of PetroBakken Energy Ltd., said during a panel session at the Peters & Co.

Limited conference.

PetroBakken, whose Bakken assets were spun off from Petrobank Energy

and Resources Ltd., was set up less than two years ago. The idea was that if

leading-edge technologies were applied to some of the evolving resource

plays in the Western Canadian Sedimentary Basin, the company could

generate significant long-term sustainable growth and that dividend yield

could also grow over time in a strong price environment, said Wright. With its

Bakken assets now a “cash cow,” PetroBakken is pursing similar objectives in

the Pembina Cardium.

Legacy Oil + Gas Inc., whose main focus is the Williston Basin, was created

in 2009 specifically to take advantage of advances in light oil development

such as horizontal wells and multistage fracturing, said Trent Yanko, president

and chief executive officer. His previous company, Mission Oil & Gas Inc., was

at the forefront of light oil resource development, mainly in the Bakken. “We

have a lot of plays that are technology-driven, that are using multistaged

fracking, enhanced recovery techniques, in this case waterfloods, to get more

oil out of the ground,” he said.

The next stage in the Bakken is going to be enhanced oil recovery

(EOR), Wright said. PetroBakken has looked at a number of different

methods, including waterflooding and CO2 flooding,

but has opted for natural gas flooding in the Bakken.

Solution gas is readily available in the area and is less

expensive and corrosive than CO2.

“What we are trying to do is attenuate the decline

and extend the economic life of the field by signifi-

cantly increasing the ultimate recovery of each one

of these wells,” he said. PetroBakken has its first gas

injection well on injection now with a total of five

planned for this year with $20 million allocated for

EOR pilots.

If gas-flooding works, PetroBakken has identified

about 100 locations, probably about 20 a year over the

next five years, which will result in about half of its

Bakken production on EOR in that period.

“The beauty of this is that we are actually going to

start injecting our own solution gas,” said Wright. At

today’s low prices, natural gas is almost a waste product,

so in putting it “in the ground, it becomes a storage

project,” he said.

“Displacing oil out of the ground and ultimately pro-

ducing that natural gas back on final depletion

Conventional crude’s second chanceEvolving technology opening doors for new oil resource playsBy Elsie Ross

TIGHT FOCUSLegacy’s core

operations are concentrated in

southwestern Alberta and the Williston Basin

in Saskatchewan, Manitoba and North

Dakota, including the prolific and fast-

growing Bakken light oil resource play.

PRAIRIE PROSPERITY

Drilling activity has been brisk

across southeastern Saskatchewan and is gaining steam in

Alberta as producers shift from natural

gas to tight oil fairways.

PHOTO: LEGACY OIL + GAS INC.

SOLVING THE PUzzLEM

AP:

LEG

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could be an optimal way to get the most value out of the Bakken and we are

pretty excited about the potential that this offers for us.”

Over the next six to 12 months, PetroBakken expects to have some initial

indication whether the gas flooding is working.

evolvIng technIquesCompletion technologies have continued to evolve since the company

started out drilling 1,400–1,600 metre horizontal wells in the Bakken.

PetroBakken began looking at ways to increase the frac intensity (which will

result in higher oil recoveries) and to become more efficient.

The next evolution was drilling the field using bilateral completions, in

which the field was effectively downspaced to eight wells per section using

only four wellheads. Two parallel wells are drilled and then they are individu-

ally and separately completed using between 15 and 20 stages of fracs down

each of the laterals.

The company had “some significant results comparing 140 bilateral

wells and 140 offsetting single wells,” said Wright. Each bilateral well cost

$2.6 million compared to $4 million for two single

lateral wells to access the same resources.

“They make more oil, they pay for themselves faster

and on a capital intensity basis it’s a better way to put

money into the ground and get the oil out,” he said.

Another PetroBakken technological innovation was

prompted by necessity. In late 2010, in the northern Bakken,

the company started encountering instances in which

production would drop and the water cut would increase.

That was a clear indication it had fracked out of the zone

and that it had problems with the Bakken caprock.

The problems occurred after wells were brought on

stream at high production rates (200–250 barrels a day)

and as PetroBakken dropped the pressure in the reservoir,

starting to deplete the fracture system.

In response the company came up with a new solu-

tion, using a new frac completion protocol called CleanTech, which allows it to

frac the wells with a very low-viscosity, great-carrying-capacity frac fluid. The

fluid can deliver high concentrations of sands with about the same volume of

fluid but at much lower pressures and with no fears of sanding off. “These wells

are actually outperforming our bilateral wells,” said Wright.

The results have been so successful that PetroBakken is looking at using

the technology in all of its Bakken wells. “This obviously pushes out the eco-

nomic limit of where the field can be exploited.”

on to the cardIumIn 2010, PetroBakken acquired three companies and has now accumulated

about 260 net sections in the Cardium where it is continuing to look at new

technologies to exploit the field. The company sees the West Pembina area

of central Alberta as the most prospective area in which to employ new tech-

nologies. It has focused on the halo area because it has the original reservoir

pressure and has not yet been depleted.

PetroBakken believes its latest innovations will, over time, increase produc-

tion to about 250,000 barrels of oil per well. It currently uses slickwater fracs

for completions. “We think it is a great answer today but it may not be a great

answer tomorrow so we are trying a bunch of new things,” said Wright. Other

completion methods it is looking at to try to squeeze more oil out of the rocks

involve different frac densities, injection pressures and sand concentrations.

Responding to a question from an analyst who suggested that one of

the side effects of new technologies is high initial decline rates, which put

companies on a production treadmill, Wright said that

over time the average corporate decline rate actually

declines into the teens as the plays mature. “The biggest

cure for us for declines is execution of multiple years

of programs and our base decline just goes down and

down and down as production goes up.”

Legacy is interested in large oil-in-place accumulations

with low recovery factors where every small increase in

the recovery factor leads to a big change in reserves. At

Turner Valley, Alta., “the application of an unconventional

technology in a conventional field is leading to a lot of

value creation,” said Yanko.

While some horizontal wells were drilled more

than a decade ago, Legacy thought that changing the

completion techniques from standard open-hole to

multistage acid fracking would greatly improve the

economics of horizontal drilling. It drilled some vertical

wells, and then did some fracking to understand

the reservoir parameters before applying that to an

understanding of the unconventional component

of the completion. In February, Legacy recompleted

an existing horizontal well that had been producing

25 barrels of oil equivalent per day. Initial production

from the well was 110 barrels of oil equivalent per day

and it is still producing 80–85 barrels of oil equivalent

per day.

The field recovery factor at Turner Valley is only 12 per

cent of the 1.3 billion barrels of 48-degree API crude in

place. Legacy estimates that every 15 barrels per day of

incremental initial production adds about $1 million to

the company’s present net value.

Another play that is going to be reliant on technol-

ogy is the newly emerging Alberta Bakken play in

southern Alberta, Yanko said. A large play, it has a lot of

different oil shows from a lot of different zones. The size

of the play means it is going to take some time to figure

it out, he said.

However, “these types of plays would not exist without

this technology and without high oil prices,” he said. “We

would not be doing a lot of the stuff we are doing today

at $15 oil and we all fully understand that.”

“ the bIggest cure for us

for declInes Is executIon

of multIple years of

programs and our base

declIne just goes down

and down and down as

productIon goes up.”— John Wright, president and chief executive

officer, PetroBakken Energy Ltd.

ENERGIzED ACTIVITYAfter years of steady declines, conventional oil production in Canada and the U.S. has been on the upswing due to the success of tight oil plays.

PHOTO: LEGACY OIL + GAS INC.

SOLVING THE PUzzLE

we are the people of Baker Hughes.

and we installed the first one-trip, 40-stage completion.

www.bakerhughes.com

Working with our customer, we engineered, installed, and fractured a 40-stage

openhole completion system—the most stages ever performed in a single trip.

Using a FracPoint™ EX-C multistage fracturing system, our team delivered precise

zonal isolation and fracture placement without cementing. And because the

system is modular, we can optimize it according to your specifications to help

push your production envelope in unconventional reservoirs.

Our one-trip fracture completion system helps you reduce your completion costs by

eliminating wireline and liner cementing operations and reducing pumping times,

while accelerating reservoir drainage and boosting your overall productivity.

© 2011 Baker Hughes Incorporated. All Rights Reserved. 32103

To find out how Baker Hughes and

our industry-leading multistage

fracturing systems can lower your costs

and boost productivity, contact your

Baker Hughes representative or, visit us

at www.bakerhughes.com/fracpoint

New Technology Magazine Supplement - November 2011

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Transcript of New Technology Magazine Supplement - November 2011