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The notion that since conventional oil production has peaked and the
world will soon face a crisis of inadequate supply has a lot of true
believers, but they seem to be in short supply in the heavy oil sector.
According to Cenovus vice president Dave Goldie,
“Technology is opening up new frontiers for oil production – not
just in heavy oil and oilsands, but also in light
oil. Given everyone’s ingenuity, we are finding ways to access more
oil.” The numbers seem to back him up: there are major heavy oil
deposits on every continent, and global heavy oil and oilsands
deposits embrace more than five trillion barrels in situ – at least
potentially, enough supply to meet market demand for a long time yet to come.
At least two technologies developed in Canada that have become familiar in
the oilsands sector are being deployed in
conventional heavy oil to expand production and increase recovery rates.
Steam Assisted Gravity Drainage
The late Dr. Roger Butler’s steam assisted gravity drainage (SAGD)
originated as a procedure for producing bitumen from the oilsands,
and the technology has a huge impact on oilsands
production. Recently, it has begun to change production economics at some
conventional heavy oil reservoirs – notably Baytex
Corp.’s Kerrobert project, Husky’s
Pikes Peak operation and Senlac in Saskatchewan, owned by Southern Pacific
Resources.
Baytex purchased its project from True Energy (now Bellatrix Exploration) in 2009. At present, Baytex Kerrobert produces 2,000
barrels per day, and those volumes are increasing. “We placed a new
SAGD well pair on production late in the third quarter of 2010,” says Baytex spokesman Brian Ector. “Subsequent to the
end of the quarter, this well pair produced at a 30-day average rate of
approximately 1,000 barrels per day. We believe that, through the remaining
life of this project, we can drill 11 additional SAGD well pairs. For 2011,
we will likely drill two new pairs on the property.”
For Southern Pacific, the Senlac property in many ways was a company maker.
The company acquired it from Cenovus for $90
million, and it enabled the company to move to the Toronto Stock Exchange by
providing cash flow. “As soon as we had that we were a going
concern,” according to company president Byron Lutes. “It enabled
us to advance (from Venture) to the TSX. That means more due diligence, but a
lot more investors now will put their money into the company.”
Since acquiring the property last spring, Southern Pacific has begun to face
the reality of having to develop the property. The company has done some
infill drilling, and at the end of last year drilled a SAGD well pair. The
previous well pair produced about 1,300 to 1,500 barrels per day, according
to Lutes. “From a rate perspective, (the new pair) won’t do
better than our other wells (even though they include 650-metre horizontal
wellbores) because we are not going to put on bigger pumps. However, we
expect better recovery over the life of the well than if the well pairs had a
smaller horizontal section.”
Southern Pacific is planning to spend about $10 million a year on the
project. That will tie in one SAGD pair a year and will keep field production
in the 4,000-5,000-barrel per day range, although he is optimistic that
production will occasionally oscillate above 5000 barrels per day. “We
estimate that this project will continue to produce at those levels for 10 to
15 years” he adds, and he is extremely optimistic about field economics.
“The oil quality is better (12° API) than Athabasca (8° to
9° API), so the steam/oil ratios are typically lower and it takes less diluent to bring your oil up to spec. We will get a $39
per barrel netback on $77 per barrel WTI.”
Netback notwithstanding, Lutes pauses to brag about a recent field
acquisition. “We were planning to replace a boiler this year, and the
guys found it on Kijiji of all places. It was the
exact boiler we needed, unused. It needed a few parts, but we bought it for
about $90,000. When you factor in installation we saved ourselves maybe
$700,000.”
Toe to Heel Air Injection
If Southern Pacific is a junior producer on the rise, PetroBank
is one with global growth aspirations. The company’s THAI production
technology involves using a vertical injector to feed air into a horizontal
producer to keep underground ignition going. “There’s nothing
magic about it,” according to company spokesman David McLellan, although the system has the potential to
transform production from heavy oil deposits around the world.
PetroBank is developing its first commercial
application of this process in Kerrobert,
Saskatchewan. “We’ve had two wells on production there since
November 2009, and this year we’re expanding to a 12-well total”
says McClellan. “We’ve done the reservoir simulations and modelling and we feel as though each well will be capable
of producing about 600 barrels per day. When you go through the pre-ignition
cycle you’re trying to establish communication between the injector
well and the producing wells. We think it will take 12 to 15 months to get up
to full production.”
If the company’s calculations are right, when the project is up and
running Kerrobert will be a 7,200 barrel per day
facility. “What is really interesting about this project is that
existing cold flow production is in the single-digit range – six,
seven, maybe ten barrels per day per well.” With that kind of
production the recovery factor for the pools would be only 4-7%. On the other
hand, “with the THAI system we can recover between 70 to 80% (of oil in
place). Five years ago, this was just theoretic. Today we have corroborated
that we can do all this.”
McClellan says the Kerrobert project will produce
an additional 7,200 barrels per day for capital cost of only $75 million.
“That’s capex of only $10,400 per
flowing barrel. Even if we got only half the production that we anticipate
from those wells that would be a pretty good investment.”
Of particular interest to the company and its licensees is that the THAI
process actually upgrades the oil underground, creating an oil with lower
viscosity which therefore needs less diluent when
it’s pumped into the pipeline. “It’s the heat that does
this,” according to McClellan. The process takes 11° API heavy oil
that underground and alters it to about 16°. “It is the heat that
does this. The system cokes the oil underground, burning the heaviest asphaltines in the reservoir as fuel. The lighter stuff
that’s mobilized out in front of ignition drains out into our
production wells.”
He adds, “We have every conviction that this is going to be a game
changer in heavy oil recovery. Once we have completely proven this
technology, then the world will start to change.” Polymer Flooding
Polymer Flooding
Southern Pacific and PetroBank are medium-sized
companies. Cenovus and Canadian Natural Resources
aren’t. Respectively Canada’s third-largest and largest
conventional heavy oil producers, each company has assets at Pelican Lake
which exemplify how large producing properties are being used as
laboratories. Experimentation in heavy oil production in this area receives
important incentives from the province, which has designated it an oilsands production area. This means for royalty purposes
the company equalizes production across all wells.
Cenovus initially began producing conventional
heavy at Pelican Lake in 1997 from a series of horizontal wells; the field
now produces about 24,000 barrels per day. According to Dave Goldie, who has
executive responsibility for his company’s Pelican Lake assets,
“The main method we’re using right now is polymer flood”
– a technique partially pioneered by the Alberta Research Council, and
which found one of his first commercial applications at Pelican Lake.
“The injection of polymers creates a more powerful piston effect, and
it enables us to better push the oil out of the reservoir,” says
Goldie. “Polymer is a pretty benign petrochemical – one of its
uses is for disposable baby diapers. It turns water into a thick, viscous
fluid which is great for heavy oil production. Over half our wells here at
Pelican Lake are now based on polymer flood. We’ve applied this to over
170 wells.” Eventually, the entire field will use polymer flood.
It takes a while for the field to respond to the polymer. “After a
period of time you see an increase in production which is associated with
this extra push from the polymer flood.” Originally developed as a cold
waterflood using horizontal wells, Pelican
Lake’s original infrastructure included wells 200 metres
apart. With that kind of spacing “it takes up to two years before you
see a response. Now we’re infilling those patterns, and that’s
increasing production rates. We’re constantly looking at new
formulations of the polymer, adapting the well spacings
to increase production. With cold waterflood we can
get maybe a 12% recovery factor, but with polymer flooding we can more than
double that. We keep on experimenting and it’s getting better.”
While polymer flood is the workhorse at the Pelican Lake project, Cenovus is testing a lot of other ideas on the property.
According to field superintendent Gary Tebb,
“Greater Pelican assets include the Pelican Lake project, which
produces from the Wabiskaw. We’re also doing
collaborative work with our Ventures team in the Grand Rapids (formation). We
have an experimental project to access what we call the immobile Wabiskaw – an area where the oil is extremely
viscous. We are also doing some work in the Grosmont
zone, which is bitumen carbonate, and one part of the property we are
experimenting with polymers plus surf it's actants.”
Dave Goldie clarifies that the Grand Rapids project will involve “in
situ combustion using natural gas from a gas cap over the field in another
formation. We have a patent pending on that particular scheme,” he adds.
“Other companies are doing similar things; there’s a lot of
experimentation going on. In these reservoirs different things work in
different places.”
Canadian Natural Resources has a similar project at Pelican Lake/Britnell, where the company estimates original oil in
place at 4.1 billion barrels. Like the Cenovus
project, CNRL began with primary production, shifted to waterflood
and, in 2005, to polymer flood. Now producing 38,000 barrels per day, the
company expects project production to peak in 2015. It should plateau at more
than 80,000 barrels per day – an amount equal to today’s total
production from the company’s 10 largest conventional heavy oil
projects along the Alberta/Saskatchewan border.
Peter McKenzie-Brown
Language Instinct
Although the writer is a director and officer of Stratabound, the thoughts and views herein are mine only
and not those of Stratabound. I am 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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