The world of oil and gas was quite a
different place a quarter century ago. Production mostly came straight up out of
vertical holes. Though the Texans had drilled the first horizontal well in 1929,
in Canada horizontal drilling was still mostly an esoteric, unproved and
untested technology.
In 1987, all that began to change – so much
so that, during the last 25 years, it simultaneously emerged as a standard
production technique and revolutionized production. One result is that many
petroleum resources have become technology-driven plays. Another is that
reserves are way, way up.
In a sense, the most important uses of
horizontal drilling technologies are reverse images of each other. “What makes
horizontal drilling for nonconventional resources (like shale gas and tight oil)
so attractive to the financial community is the very high initial rate of
return. In the beginning, production rates are extremely high, although they
quickly taper off. You have to remember that these applications enable you to
get highly desirable hydrocarbons out of really poor reservoirs,” according to
Dave Russum, who is director of geosciences at AJM
Deloitte, a consultancy.
The oilsands
represent the mirror image of this situation. “You are drilling into tremendous
reservoir rocks – highly porous and very permeable, so there’s plenty of oil in
there. But until you process the stuff it isn’t a particularly attractive
commodity.”
The Bitumen Story
It’s true that in April 1978 Imperial Oil
drilled Canada’s first horizontal well into the Clearwater formation at Cold
Lake – a storied well overseen by Dr. Roger Butler in an early test of a system
of oilsands production now known as steam-assisted
gravity drainage (SAGD). After that test and a less interesting effort by Texaco
a couple of years later, in Canada the technique mostly languished until 1987.
Then the advent of improved down-hole
drilling motors and the invention of other necessary supporting equipment,
materials, and technologies – particularly down-hole telemetry equipment, which
enabled rigs to drill straight on target – led to an explosion of new
applications for this technology. Producers and the drilling and service firms
that support them found endless new uses for directional drilling – especially
as it is used for horizontal wells.
Appropriately, in Canada the first
horizontal wells drilled after Imperial’s early test were part of the
Underground Test Facility (UTF), which celebrated its official opening on June
29th, 1987. Developed by the Alberta Oil Sands Technology and
Research Authority (AOSTRA), the UTF involved a pair of tunnels driven into
limestone 15 metres below the reservoir.
Within those tunnels, AOSTRA constructed
large well chambers. “Pairs of injection and production wells were drilled
upwards from the well chambers at a 170 slant,” according to the
mining engineer behind the project, Gerry Stephenson, “and deflected
horizontally into the base of the reservoir. The mobilized bitumen drained by
gravity from the steam chamber in the reservoir to the well head in the tunnel
and all of the production was pumped from a central location.” Those tests
proved Butler’s theories about SAGD beyond any possible doubt.
Over its 15-year life, the UTF also
evaluated other recovery strategies, but nothing compared to its SAGD results.
“AOSTRA’s staff had estimated that the recovery might be somewhere between 30
percent and 45 percent of the bitumen in place” during the Phase A tests,
according to Stephenson. “We actually got 65 percent recovery. The steam
chambers formed by mobilization of the bitumen spread way beyond the area we’d
expected….Over the 10-year life of the well pairs, Phase B got a steam/oil
ratio, the most critical figure of all, of 2.3 to one.”
The tests at the UTF forever transformed
Canada’s oilsands industry. Today, SAGD is responsible
for more than half of Canada’s bitumen production.
Ironically, Sceptre Resources drilled the first horizontal well in
Saskatchewan to test a SAGD-like system at Tangleflags, just as the UTF began its definitive tests.
Drilled into the shallow (450-metre) Lloydminster sandstone, this primitive
application of a form of SAGD illustrated the kinds of problems horizontal
drilling could overcome. With an active aquifer below and a gas cap above, the
reservoir’s pay thickness was about 27 metres. The oil
was heavy: about 13o API. Primary production from the field had been
meagre (0.6% of the oil in place), and the use of
cyclic steam stimulation, which uses vertical production wells, had flopped when
they tapped the aquifer and started producing 99% water.
That was when the company decided to try
SAGD – not the technique we use today, but the primitive version Imperial had
tried out nine years earlier. Sceptre injected steam
through four vertical wells near the gas-oil contact, draining the mobilized oil
through a horizontal well. At the industry’s leading edge, the company found
itself with a technical and economic success.
Fast Production from Tight
Reservoirs
More than any other series of innovations,
the technology-intensive processes that now surround directional drilling have
enabled the industry to get production out of otherwise unproductive rock. In
August of that same transformational year, Alberta Energy drilled the first
horizontal well into the Glauconitic formation at Suffield. This was the first
time a Canadian operator drilled horizontally into a conventional oilfield.
Things then quickly sped up. In February
1998 alone, three significant projects based on horizontal drilling took off.
Amoco began a 10-well horizontal drilling program at Athabasca, into the Wabiskaw formation. Canadian Hunter drilled gas wells at
Ansell (Alberta) into the Cardium formation and at
Helmet (British Columbia) into the Jean Marie. A few months later, Shell Canada
drilled for Mississippian oil in Saskatchewan, at Weyburn. This early application of the technology was meant
to connect isolated small reservoirs or improving contact within heterogeneous
rocks to enhance the sweep efficiency.
“In the 1990s the big push was to explore
conventional carbonate rocks, especially from the Mississippian in
Saskatchewan,” according to AJM Deloitte’s Russum.
“The idea was to develop known reservoirs where the rock quality was variable,
using horizontal wells to extract more oil from those formations…. Many
different companies hopped on to the horizontal drilling band wagon in
Saskatchewan with more than 500 wells drilled into the Mississippian in 1997
alone. In that year more than 1300 horizontal oil wells were drilled across the
basin – a tally that was not beaten until 2007.”
Horizontal drilling also began to tap the
heavier oils in Saskatchewan and southeastern Alberta in the 1990s, and there
was a lot of experimentation in other reservoirs. Also, of course, in that
decade SAGD began to be developed in its modern form.
As horizontal drilling became more
commonplace, the petroleum industry began combining it with innovations in both
drilling and well completion technologies and ideas. The result has been like a
snowball rolling downhill. Horizontal drilling has been enhanced by
geo-steering, measurement-while-drilling, coil tubing, down-hole motors and new
bit design, for example. Also, producers can now drill multilateral horizontal
wells from a single drilling pad.
Perhaps the important recent development on
the drilling side is the monobore. Monobore drilling involves running a casing string, then
forcing a steel cone down the well to expand it in the hole. This process is
repeated with identical casing strings. Thus, monobore
completions have the revolutionary characteristic of installing a string with
the same interior diameter from top to bottom. “These are making a huge
difference,” said Russum. “In the past you had to
drill a vertical well, then run the casing to the bottom and wait for the casing
to set before you could begin to drill the horizontal leg. Monobores help reduce those time-consuming steps.”
Although technologies like microseismic are also making a difference, the most
important developments on the completion side have involved the increasing power
and sophistication of hydraulic fracturing. Better fracking has developed because of new packers, better
pumping equipment and better treatment fluids and proppants. “It’s now easier to isolate horizontal wells and
to put fractures into certain points of the formation,” according to Russum. “In the early days, each stage of multistage fracking would take a whole day. Each frack would have to be tested separately before you
proceeded to the next one. Today it’s a continuous process.”
These clusters of technological
breakthroughs first created the shale gas revolution. Pioneered by an American,
George Mitchell, in the Barnett shale in Texas, tight gas reservoirs began
yielding highly economic volumes of natural gas – and, not incidentally, drove
down the price of gas. Some observers now describe natural gas as a low-value
by-product encountered in shale reservoirs in the quest for natural gas liquids.
From a production perspective, the other
great outcome from this cluster of technologies has been the development of
tight oil from shale – what Russum prefers to call
“conventional oil from more shaley, low-permeability
reservoirs.” One outcome is that both western Canada and the US are experiencing
growing light oil production for the first time in decades – much of it coming
from the Bakken play in North Dakota and Montana.
After decades of decline in Alberta, for example, light oil production has
recently risen to ten year highs.
An Explosion of Uses
These new technologies are changing almost
everything about Canada’s petroleum industry. For example, horizontal wells are
now a huge part of gas storage. “You can store gas very quickly into those
wells,” said Russum, “and you can extract it quickly,
too. Then there is the whole area of trying to reduce surface impact. I think
we’re going to see more and more of that. Surface owners are more and more
reluctant to have pumpjacks and other surface
equipment on their land, and horizontal wells are less likely to disturb natural
habitat. There is also extended reach, so you can reach under lakes and towns
and cities. You can use it to reduce water production in a thin reservoir
located over an aquifer.”
The economics of the horizontal well are
also greatly improved, especially when you are planning production from a narrow
reservoir – ten metres thick, for example. Horizontal
wells provide much greater contact with the reservoir per dollar of drilling
than do their vertical kin. And when they are drilled in search of
unconventional resources like shale gas and tight oil, the producer gets a quick
payback because initial production rates are so high.
Still not convinced? Then let the numbers
tell the tale. According to an AJM Deloitte study which is complete to late
2011, more than 30,000 horizontal wells have produced conventional oil or gas in
Western Canada over the past twenty five years. Of that tally, 4,300 were
completed in 2011. This set a record for horizontal oil drilling: nearly 3,500
wells (led by the Cardium, Viking and Bakken), and an additional 800 wells focused on gas – mainly
attracted by the high liquids content in the Montney
and Middle Mannville. Today, half of Western Canada’s
wells are being drilled horizontally.
Is horizontal drilling helping bring about
any other changes? Perhaps it is even changing the way corporations work.
“Companies that fail to adequately research the geology are putting themselves
at considerable risk if they assume all resource plays are alike and that more
and larger fracks are the solution to economic
production,” according to Russum. Even so, engineers
are increasingly replacing geologists in the executive suite.
Traditional geologists who spent entire
careers looking for conventional reservoirs are now more interested in minor
variations in rock properties, in stress regimes and in proximity to source
rock. In terms of traditional petro-geology this is a difficult concept to
grasp, but to a large extent it is a response to the revolution spawned by
horizontal drilling.
Oilsands companies in particular, but
also other companies involved in modern resource plays are basing their business
plans on step-by-step, decades-long development of vast and well-defined
resources. This means traditional wheeling-and-dealing is at least partly on the
decline – to a large extent replaced by courting cash-rich foreign companies
with deep pockets and the desire to support these capital-intensive
activities.
Peter
McKenzie-Brown
Peter McKenzie-Brown
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Peter McKenzie Brown is the vice president of a resource
company. He has written several volumes of history, and has worked in the
corporate and academic worlds. He is British by birth, American by upbringing
and Canadian by choice. Disclaimer : Although the writer is a director and
officer of Stratabound, the thoughts and views herein are his only and not those
of Stratabound. He is not registered in any jurisdiction as a broker or
investment adviser, so nothing herein should be construed as advice on whether
to buy, sell or hold shares of Stratabound or any other company mentioned
herein.
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