More than 80 years ago, Canada saw its first frack job take place at Turner Valley, southwest of
Calgary.
To bring wells on production, companies operating in
that early reservoir lowered “torpedoes” or tubes of nitro-glycerine down
wells. When they hit bottom, an explosive in the nose of the device set off
the nitro. This fractured the reservoir and spurred oil production. Using
this method to spur field production, many oilmen proudly proclaimed Turner
Valley as “the largest oilfield in the British Empire.”
The technique we use today and refer to as hydraulic
fracturing, emerged about 20 years after the Second World War. World-wide,
more than a million wells have been fractured.
Simply put, fracking
improves production from geological formations where natural flow is
restricted. Hydraulic fracturing pumps a mix of water, sand and soluble
chemicals into the well at high pressure. The pressure fractures the
formation, and the sand holds the fractures open so hydrocarbons can more
freely flow through them into the wellbore.
Dave Russum of Deloitte’s
petroleum consultancy offers a graphic image of how fracking
works, but you first have to think of the horizontal well as being like a
sock. “Between the heel and the toe of a horizontal well,” he says. “You
isolate an interval close to the toe and frack that
region. Then you move back towards the heel, isolate another interval and do
another frack. This breaks up a lot of rock, making
more production available. These new technologies are enabling us to access a
whole lot more low-permeability rock than you would ever be able to reach
with a vertical well.”
In the days of vertical drilling, producers
generally fracked just one or two zones per well.
With today’s technology, horizontal legs many kilometres in length can be fracked in many places. While hydrocarbons produced in
this way are cheaper than those produced by traditional methods, the
technology is challenging. To take on one such project may require a
40-member crew and 20 or more hydraulic compression systems mounted on huge fracking trucks. Numerous trucks with hydraulic pumping
equipment are needed to fracture each of these big wells. Large volumes of
water are also needed, as are propping agents: a single well can require
several thousand tonnes of sand.
Canadian
Roots
Canada has been a leader in the use of fracking and in its development. In the 1950s, fracking transformed the Pembina Cardium
oil discovery from what looked like an average play into an elephant of
global proportions. Fracking made the formation
that hosted the greatest reserves in Canada producible and exciting. The
Pembina field is now typically quoted as having had 8.4 billion barrels of
original oil in place, according to Russum, and “by
accessing oil from lower-quality rock [through fracking],
the field could end up producing perhaps 10 billion barrels.” For decades,
Pembina was the world’s biggest field in aerial extent.
In his engaging memoirs, the late Arne Nielsen (a
Hall of Fame Canadian oilman) describes Drayton Valley – population 75 – when
his team discovered the Pembina structure in 1953. “It was located in an
isolated bush and pioneering community,” he says, “…in a world that still
operated in a manner that had become extinct elsewhere in the province, in a
world still reliant on kerosene lamps and horses.”
That discovery led to one of Canada’s great post-war oil booms – a boom based
almost entirely on fracking. “Within weeks, dozens
of families living in vacation trailers were crowded into clearings around
Drayton Valley.” By 1955, the community’s population had shot up to 5,000 –
2,000 people short of its population today.
Oil doesn’t flow easily through the Pembina Cardium sands. It is a vast, tight sandstone formation.
When the company began producing its discovery well, only 132 barrels per day
came out of the hole. The company – it was later renamed Mobil Oil Canada,
and Nielsen became its president – used hydraulic pumps to force 3,000 pounds
of sand in fracking fluid into the zone. Production
trebled. In that period it was also common to acidize wells – pumping acid
into the formation under pressure to clean out and improve flow channels for
oil production.
The company had discovered the key to developing
this field, and exploration by Mobil, Amoco and Imperial accelerated. By
1987, more than 5,000 wells had been drilled into the Pembina Cardium.
Since those fairly primitive days, hydraulic
fracturing has become a mainstay of both oil and natural gas drilling.
According to University of Calgary historian Sandy Gow,
“by the mid-1950s hydraulic fracturing had become the best large-area
penetrator ever developed in the industry.” He describes the technology
as “a well-stimulation technique that subjected a formation to sufficient
hydraulic pressure from a ‘break down fluid’ to cause parting of the
formation [fractures]….These fractures were then extended from the well bore
by continued pumping of the fracturing fluid.”
George Mitchell – an American oilman worried about
meeting his gas-supply obligations – was the first to apply fracking to shales. His
pioneering efforts took place in 1998 in Texas, in the Barnett shales. Other companies soon noticed that he had found a
way to increase production from this formation and began to investigate. As
the secrets got out, others got into the act. The result is sometimes called
the “shale gale:” low-cost shale gas competing successfully with higher-cost
conventional production.
It was only a matter of time before the same
technologies would be used for oil production. The first great field
developed with this technology was the Bakken. This
huge formation – it stretches from Montana and South Dakota into Saskatchewan
and Manitoba – was first identified in 1953, but it was uneconomic. Fracking the Bakken changed all
that. For the record, when companies apply fracking
to oil reservoirs, the production is known as “tight oil,” since producers frack reservoirs of
sandstone and other rocks besides shale.
New
Applications
The story of fracking is a
narrative of technological development. It took rapid innovation in down-hole
tools to turn hydrocarbon-bearing shales and other
low-permeability rocks into producing reservoirs. Two such technologies stand
out: Coil tubing and horizontal drilling.
Coil (“coiled”) tubing is the workhorse of
underground technologies. A tool that began to make big inroads into industry
operations around 1990, coil tubing has transformed many aspects of
underground drilling and work-over operations. It refers to metal piping
spooled on a large reel and used for interventions in wells and sometimes as
production tubing in depleted gas wells. Coiled tubing is often used to carry
out operations previously done by wirelining. The
main benefit of coil tubing over wireline is that
you can pump chemicals through the coil. With coil tubing you are able to
push tools and chemicals into the hole; wirelining
relies on gravity.
Of particular importance in the context of
production from shale, coil tubing can be used to fracture the well – a
process where fluid is pressurized to thousands of pounds per square inch on
a specific point in a well. This blasts some of the rock into rubble,
permitting the flow of hydrocarbons to the well-bore.
The tool string at the bottom of the coil can range
from something as simple as a jetting nozzle, for jobs involving pumping
chemicals or cement through the coil, to a larger string of logging tools,
depending on the operations. Coil tubing is also used for relatively
inexpensive work-over operations. It is also used to perform open-hole
drilling operations.
Borrowed
Technology
Another vital technology actually originated with
the oil sands. Sometimes described as “low-quality oil in a high-quality reservoir,”
the oilsands themselves do not require fracking. Canada’s greatest-ever (though indirect)
contribution to fracking came in 1987, after
Alberta’s Oil Sands Technology and Research Authority (AOSTRA) had
constructed a bunker known as the Underground Test Facility (UTF).
The immensity of the UTF is hard to imagine. It
involved sinking two shafts into the oilsands with
a drill bit almost four metres in diameter and weighing 230 tonnes. The
shafts were 223 metres deep and neither one deviated from the vertical by
more than an inch. As a safety measure, AOSTRA constructed two parallel
tunnels through the limestone. More than a kilometre in length, the tunnels
were five metres wide by four metres high.
The purpose of the facility was to enable researchers
to undertake tests in producing bitumen from horizontal wells, and the
outcome was the development of SAGD (steam assisted gravity drainage), which
involves injecting steam through one horizontal well into the oil sands, and
producing it from a parallel well just below.
To develop SAGD projects, the industry had to find
or develop a number of new technologies. In the beginning, for example,
drillers couldn’t drill horizontal wells from the surface. They soon found
ways to do so, and horizontal drilling is now a key feature of fracking practice. The advantage of fracking
from a horizontal well is that it gives the operator access to much more of
the oil or gas pay zone. Today horizontal legs many kilometres in length are being
drilled. This is possible because of improvements in bit design, better
down-hole motors and bigger rigs.Another
contributor to the shale-gas revolution is multi-lateral horizontal drilling
– the ability to drill several horizontal laterals from a single well bore.
Geo-steering is another critical down-hole
technology. In recent years it has been given a lift by high-impact
measurement-while-drilling (MWD) tools and techniques. More importantly, the
industry can now isolate many completion zones in horizontal wellbores. This
enables producers to use their vast hydraulic pumping systems to pump many
fractures into a single production zone. This makes reservoir fracturing (and
therefore production) possible over long distances. It’s a far cry from the fractures
of Arnie Nielsen’s day, which could only be done once on a vertical well.
As these technologies increased in sophistication
and declined in relative cost, they led to a fundamental change in field
economics. The petroleum sector is now investing a much bigger slice of the
development pie underground. For the first time, the North American industry
(not including oilsands) is investing more money
down-hole than in gathering lines and other surface facilities.
Uncertain
Future
One vital new technology mostly involves surface
activity. A relatively new technology, microseismic
enables geo-engineers to improve reservoir development and productivity by
monitoring fracture efficiency from the surface.
One of the leaders in this area is Houston-based Microseismic Inc. The company was founded by Peter
Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics
from the University of Toronto, and cut his teeth working for Shell Canada in
Alberta and offshore Nova Scotia. He stresses that the technology in itself
is not new. It has been used for years for earthquake location, for example.
Applying the technology to producing reservoirs, however, is a new and
rapidly developing field.
Duncan explains micro-seismic with vivid analogies.
“Regular oil and gas seismic is like an X-ray,” he says. “Micro-seismic is
more like a stethoscope. You can ‘hear’ the sound of fluids underground.”
Micro-seismic involves cementing geophones on the
surface and underground. This enables the operator to monitor production for
the life of the field and better produce these shales.
“With the developments we are making today, these arrays are like a big-dish
microphone. (Using a computer) you can essentially beam-steer that array
around the reservoir to find out what’s going on where. The cost-effective
way to do this is to set up a permanent array of phones to monitor the fracking of every well during the development of the
field.” For shale gas production, a key feature of this technology is that it
can tell you where fracking has been effective, and
where it hasn't.
In a public document, EnCana stresses the value of
micro-seismic. “A recently developed technology known as micro-seismic
monitoring allows us to monitor micro-seismic events associated with
hydraulic fracturing in three dimensions and in real time. Where it is used,
micro-seismic monitoring provides a way to evaluate important elements of
each hydraulic fracture treatment, such as vertical extent, lateral extent
and fracture complexity. We can then decide when to end one fracturing stage
and begin the next.”
As
importantly, microseismic reduces the risk of fracking fluids flowing into non-targeted areas –
ground-water aquifers, for example. This is a matter of considerable concern
for many environmentalists, and public concern about fracking
has brought the practice to a halt in many jurisdictions in North America –
in Canada, notably Quebec. In response to a public outcry, two years ago the
province announced that, pending a review by a panel of experts, it would no
longer authorize fracking. Environmental groups
like the Pembina Institute are encouraging other provinces, like BC, to
embargo fracking.
People in
the oil industry generally discount this concern. Ziff Energy VP Bill Gwozd, for example, notes that there are typically
several kilometres of rock between the reservoir being fracked
and any potable ground water. “What are the chances fracking
fluids could penetrate all that rock to reach someone’s water well?” he
asks.
This article appears in the 2013 Unconventional Resources Guidebook; graphic from here
Peter
McKenzie-Brown
