A reserve report was prepared
on March 28th by independent petroleum engineers of Calgary,
Alberta based on public well log information showing a
contingent resource.
A contingent resource is
defined as those quantities of petroleum which are estimated,
on a given date, to be potentially recoverable from known
accumulations and will require additional work and success to
be commercially recoverable.
The independent petroleum
engineers showed a contingent resource potential of 17 million
barrels (high) to 10 million barrels (low) across all the
lease sections in which Great Northern now has an ownership
interest in.
The Leismer sections are well
located in a producing area in the Athabasca oil sands and is
in very close proximity to major oil sands projects by Conoco
Philips, Encana, Petrobank, North American Oil Sands and
Petrobank's Whitesands Oil Sands Project, an experimental
in-situ "SAGD" (Steam Assisted Gravity Drainage) facility.
OIL SANDS SECTION, Athabasca, Alberta, Canada
Leismer – Section 19, Township 77, Rge 9, W4M
Leismer - Section 5, Township 78, Rge 8, W4M
Leismer – Section 11, Township 78, Rge 9, W4M
Great Northern has been advised by the operator that the
seismic operations are now complete and the data is being
assessed. The seismic data, combined with the core sample,
will be interpreted with the evaluation on this first test
hole completed shortly. This prospect lies directly between
Petrobank and North American Oil Sands and viewing the initial
data would appear that the formation and thickness on our
property is consistent with these companies. Petrobank has
stated a potential resource of 1.6 billion barrel and North
American Oil Sands with a stated 4.09 billion potential
barrels in ground.
EIGHT MILE Property, British Columbia, Canada
The Corporation, and its partners, have just completed a
seventy-two hour production flow test on the 7-8-81-17 W6M gas
well (ie. the “7–8 Well”). This well was drilled late in 2006
as an exploration well targeting the Triassic Age formations,
including the Halfway and Doig zones, and reached a total
depth of 1,988 meters. The 7-8 well was logged and cased in
December 2006, and has remained standing until the recent
completion operation last week. The logs indicated
approximately 9 meters of Doig pay with average porosities of
9.5% in the one interval tested.
The 7-8 well was completed in early March 2007 and a
seventy-two hour production test was conducted March 14
through 17, 2007. After fracture stimulation the final test
rate was 3.5 mmcf/day at a flowing pressure of 7,700 KPag.
Great Northern, and its partners, are proceeding with plans
to participate with the operator to drill additional wells to
the south of the 7-8 well in an effort to delineate the size
of the pool. The location of the 7-8 well was originally
selected because it was projected as the highest and the most
northerly location on the defining seismic anomaly. The first
follow-up location is being planned in Section 5 of the same
township, with a second follow-up location currently under
review.
The 7-8 well was part of a farmout arrangement entered into
by Great Northern on or about October 12, 2006, along with
three industry partners. The Group committed to approximately
80% of the cost of two farmin wells, with a view to earning
approximately 48% of the working interest in two sections per
well. The farmout arrangement includes a rolling option to
continue drilling and earning on the same basis in the total
22 Sections making up the Eight Mile North Field. Great
Northern is paying a 20% cost share with the operator
retaining a carried Gross Overriding Royalty. The interest of
the Corporation reduces to 12% once it has achieved payout.
KERROBERT Property, Saskatchewan, Canada
Great Northern has current long term production from 19
shallow oil wells. The company has a right to participate in a
proposed 50 oil well drill program in the prolific Kerrobert
region of Saskatchewan, Canada. Saskatchewan is one of the
largest oil producers in Canada, second only to Alberta. The
province produces approximately 20% of total Canadian oil
production. Cumulative oil production from Saskatchewan to
December 31, 2000 was 3.6 billion barrels. Remaining
recoverable reserves are estimated to be1.2 billion barrels.
More than 18,000 active wells in Saskatchewan produce in
excess of 400,000 barrels of oil per day. The formation is
located on the Saskatchewan-Alberta border and is considered
to be a highly productive, low-risk, high-reward area.
The oil is comparable to West Texas No 1. The experience by
other oil companies in the area suggests an approximate
fifteen year life for the shallow oil wells.
CECIL-EUREKA Property, Alberta, Canada
Great Northern has a 45% working interest to earn 27% working
interest after pay-out in a seismic test well program for gas
and oil at Eureka, Alberta.
The Cecil-Eureka project is comprised of 5 separate sections
totaling 3200 acres in north central Alberta, the core area
for the operator, where the operator has been directly
responsible for the discovery of 1.7 million barrels of oil.
The Peace River arch area is known for producing a high rate
of delivery and high reserves. The project is a multiple zone
project targeting both oil and gas with three primary zones
and ten zones overall.
LLOYDMINISTER Property, Alberta, Canada
The company has drilled two wells. These wells are ready for
production but are currently shut in and awaiting a service
rig. Future production expected to be 30 – 50 BOE per day per
well.
By drilling and completing the first well the Company
earned a 30% working interest in the balance of the farmout
lands and a 50% working interest in the test well spacing unit
subject to a convertible after payout overriding royalty such
that if converted reduces the Company’s interest to a 30%
working interest. The second well was drilled with the Farmor
having to participate by converting his overriding royalty
prior to drilling into a working interest. As a result the
Company paid 30% of the cost of the second well to earn a 30%
working interest in that well spacing unit.
WORSLEY Property, Alberta, Canada
Great Northern has a 50% working interest to earn a 27.5%
working interest after pay-out in a seismic and test well
program for oil at Worsley, Alberta. This is a Multi-zone
Charlie Lake Oil, and Leduc, Bluesky Gas Zones with 3D seismic
shot and interpreted. The company expects to identify a target
location in 2007.
MEDICINE HAT Property, Alberta, Canada
Great Northern has drilled one well and presently awaiting
production results.
The company has a 45% working interest to earn 22.5% working
interest after pay-out in a seismic and test well program for
oil at South Medicine Hat, Alberta. The project is a
Glauconite oil play and a Farm-in with 2 D seismic shot and
interpreted.
Canada's Oil Sands: Meeting Global Energy
Requirements for the Next 100 Years?
SECOND LARGEST IN WORLD-The oil sands deposits in
Alberta, Canada contain the second largest known reserve of
oil in the world after Saudi Arabia, an estimated 175 billion
barrels trapped in a complex mixture of sand, water and clay.
They are abundant, accessible, and economically affordable to
recover - especially at today's crude oil prices.
In actual fact, the oil sand deposits in northern Alberta
could contain 1.7 to 2.5 trillion barrels of oil in place,
more than all the presently known reserves of the Middle East
Alberta's oil sands deposits were described by Time Magazine
as "Canada's greatest buried energy treasure," one that "could
satisfy the world's demand for petroleum for the next
century."
OIL SANDS CREATION -The most prominent
theory of how this vast resource was formed suggests that
light crude oil from southern Alberta migrated north and east
with the same pressures that formed the Rocky Mountains. Over
time, the actions of water and bacteria transformed the light
crude into bitumen, a much heavier, carbon-rich and extremely
viscous oil that requires upgrading.
Bitumen is best described as a thick, sticky form of crude
oil, so heavy and viscous that it will not flow unless heated
or diluted with lighter hydrocarbons. At room temperature, it
is much like cold molasses. Oil sands are substantially
heavier than other crude oils. Compared to conventional crude
oil, bitumen requires some additional upgrading before it can
be refined. It also requires dilution with lighter
hydrocarbons to make it transportable by pipelines.
RECOVERY METHODS - While conventional
crude oil flows naturally or is pumped from the ground, oil
sands are recovered using two production methods: mining and
in-situ (in place).
The mining of oil sands requires an open-pit mine
operation where the bituminous material is moved by trucks and
shovels to a cleaning facility where it is mixed with warm
water to remove the bitumen from the sand.
About two tonnes of oil sands must be dug up, moved and
processed to produce one barrel of oil and roughly 75% cent of
the bitumen can be recovered from sand. The processed sand has
to be returned to the pit and the site reclaimed. Today, all
operating oil sands mines are linked with upgraders that
convert the bitumen to synthetic crude oil.
For oil sands reservoirs that are too deep (more than 75
metres) to support economic surface mining operations, in-situ
recovery is required to produce bitumen. Most in situ bitumen
and heavy oil production comes from deposits buried more than
400 metres below the surface of the earth. This method of oil
sands production is similar to conventional means of oil
production where oil is recovered through wells. The
government of Alberta estimates that 80% of the total bitumen
ultimately recoverable will be with in-situ techniques.
In general, the heavy, viscous nature of the bitumen means
that it will not flow under normal conditions. As a result,
numerous in-situ technologies have been developed that apply
thermal energy to heat the bitumen and allow it to flow to the
well bore. These include thermal (steam) injection through
vertical or horizontal wells such as cyclic steam stimulation
(CSS), pressure cyclic steam drive (PCSD) and steam assisted
gravity drainage (SAGD). Other technologies are emerging such
as pulse technology, vapour recovery extraction (VAPEX) and
toe-to-heel air injection (THAI).
There are also reservoirs in the oil sands where primary or
"cold" production is possible. The bitumen in these areas will
flow to the well bore when co-produced with sand through the
use of progressive cavity pumps, the same technology that is
used in conventional heavy oil production.
This type of production technology is commonly called cold
heavy oil production with sand (CHOPS). While this bitumen is
lighter than the bitumen found in mineable and other in-situ
reserves, it is heavier than conventional heavy oil. A
significant difference between primary bitumen and
conventional heavy oil production is the amount of sand that
is co-produced. Sand production in primary bitumen wells may
be two to three times greater than sand production in
conventional heavy oil wells.
FOCUS ON ALBERTA OIL SANDS - With the
continuing decline of conventional North American crude oil
reserves, the focus is turning towards oil sands exploration,
development, and production. According to the Alberta Energy
and Utilities Board (AEUB), production from Alberta averaged
just over one million barrels per day (bpd) of bitumen in
2004. Of this total, marketable production included more than
600,000 bpd sold as synthetic crude oil and distillates, and
approximately 320,000 bpd sold as bitumen.
At the present time, marketable sales of synthetic crude oil
and bitumen are estimated to account for 50% of Canadian crude
oil output and 10% of North America's output.
A survey by an Alberta industry association from early 2005
indicates that Alberta's oil sands industry may spend $63.5
billion on new oil sands projects from 2005 to 2010 and as
much as $79.5 billion in the 2005 to 2015 period. Another
$16.5 billion may be spent on sustaining capital during 2005
to 2015 period.
In the 1996 to 2004 period, the oil sands industry spent an
estimated $29 billion on new projects, plus an estimated $4.8
billion on sustaining capital.
