VIC/P54 ORRI
Gas flaring at Longtom 3 Well
VIC/P54 Operator
Estimates that Longtom Gas Contract & Condensate Are
Equivalent to Approximately 57 Million Barrels of Oil
or $2,800,000,000 on ACOR's ORRI
Thursday January 25, 9:18 am ET
Longtom 4 Well to Drill in 2007
CISCO, Texas--(BUSINESS WIRE)--Australian-Canadian
Oil Royalties Ltd. (herein called ACOR) (OTCBB:
AUCAF
-
News) is pleased to announce that the operator
of VIC/P54 states in their annual report that their
best estimate of the 350 petajoules (PJ) gas
contract along with the 4 million barrel condensate
from the drilling of the Longtom 3 well on ACOR's
ORRI is equivalent to approximately 57 million
barrels of oil or approximately $2.8 Billion
Dollars, using current market prices.
In 2006, the operator of VIC/P54 signed a $1
billion gas contract with Santos Ltd, which provided
the commercial platform to appraise Longtom. The
contract calls for the delivery of 350 PJ of sales
gas from the Longtom field at an agreed price. If
Longtom produces in excess of 350 PJ of gas, a joint
marketing agreement exists for sales of a further
100 PJ of gas from Longtom at market prices.
The result of Longtom 3 well drilled in 2006 has
given the operator more confidence that they not
only have significant gas resource, but they have
more than adequate production on a per well basis to
justify a commercial development.
First gas from Longtom Gas Field on ACOR's ORRI
is currently expected to flow in mid-2008. VIC/P54
consists of 155,676 gross acre and is located
offshore Australia in the prolific Gippsland Basin.
The conversion rates used for the best estimates
figures stated above for the Longtom gas field are 1
barrel of condensate is equal to 1 barrel of crude
oil equivalent and 6.6 PJ is equal to 1 million
barrels of oil equivalent. These figures are taken
from the operator's annual report. In 2005, the
internationally recognized consultants Gaffney Cline
and Associates (GCA) increased their Best Estimate
of Longtom Contingent Gas Resources by 38% to 438
Bscf.
About the Longtom Gas Field:
The permit VIC/P54 contains the Longtom gas field
which was discovered by BHP Billiton in 1995 but was
considered non-economic. The Longtom 1 discovery
well intersected a 1,266 foot gas column in the
Emperor formation, which was confirmed in the
Longtom 2 appraisal well drilled by Nexus in late
2004 Longtom 2 intersected a 1,312 foot plus gas
column.
On test the lower reservoir section flowed at a
stabilized rate of 18-19 MMscf/d over a 12 hour
period. However the upper reservoir section did not
flow gas to surface after the failure of a
sub-surface valve in the well bore although a core
cut from the well confirmed an excellent upper
reservoir section highly capable of flowing gas.
The Longtom 3 well, drilled in July 2006,
confirmed the commercial potential of the Longtom
field when an estimated flow rate of over 75 MMscf/d
was recorded during the second production test over
reservoir sections including the upper sand which
did not flow in the Longtom 2 well. The Longtom 3
well intersected a total of 3,379 feet of gross gas
reservoir on ACOR's ORRI.
Longtom 3 was tested through a production
completion and Xmas tree leaving the well ready for
production without requiring any further rig
intervention. The Longtom 3 appraisal well was part
of a sole risk appraisal program operated by Nexus.
From deepest to shallowest, the gas bearing
reservoir units in the Longtom field are named the
100, 200, 300, 400 and 500 sands. The reservoirs
appear to be connected to a series of vertically
separate, but laterally connected, common aquifers.
Two production tests were conducted on the
Longtom 3 well were highly successful. The first
test produced gas from the 400 sand at 23 MMscf/d.
These results confirmed the flow potential of the
(upper) 400 sand reservoir in the Longtom field,
addressing the concern from the Longtom 2 well where
a gas flow was not achieved due to the valve
failure.
The second test, over the 100, 200 and 300 sand
intervals exceeded expectations producing an
estimated 77 MMscf/d when bypassing the test
separator and 59 MMscf/d when flowing through the
test separator.
Longtom Gas Field Could Be Bigger
The Longtom 3 appraisal well in VIC/P54 has
confirmed the potential for gas charged sands in the
Admiral Formation along the northern margin of the
Gippsland Basin to flow gas at commercial rates and
has opened up a new exploration play in this area.
The drilling of the well has also confirmed the
viability of a new technique for defining
exploration targets in this area. The horizontal
section of the Longtom-3 appraisal well was drilled
along a sinusoidal path, specifically designed to
target seismic amplitude anomalies, which were
interpreted to correspond to thin gas charged sands
within the Longtom Field.
The technique proved to be very successful in
predicting the presence of gas sands within the
field and further analysis of the 3D seismic data
has highlighted the potential for several other
exploration targets close to the Longtom Field,
which are characterized by similar seismic
anomalies.
The most significant of these is a shallower
exploration target that directly overlies the
Longtom field and has a very similar, well defined
seismic anomaly on the 3D seismic data.
The 'Longtom Upper' sand is expected to extend
over an area of approximately 8 miles and be as
thick as 131 feet in certain areas. The possible
resource potential of the Longtom Upper sand is
approximately 250 BCF of gas and will be tested by a
future well. If successful, these sands could be
readily integrated into a Longtom development at
modest additional cost.
ACOR owns 5% of 1% ORRI under VIC/P54.
About The Gippsland Basin:
In excess of 4 billion barrels of oil/condensate
and 12 TCF gas reserves have been discovered in the
Basin since exploration drilling began in 1964, with
remaining reserves estimated at 600 million barrels
of oil and 5 trillion cubic feet of gas. Current
production of the basin is around 140,000 barrels
per day of crude and 570 million cubic feet per day
of gas. At peak rates, the Gippsland Basin can
deliver more than 1,000 million cubic feet a day.
Some of the very best oil production in the world
is found in the Gippsland Basin. Take for example,
the Halibut Oil Field. The average well in the
Halibut Oil Field has produced 60,000,000 bbls of
oil per well or $3,000,000,000 worth of oil per
well, at current crude market prices.
$
A second objective in the VIC/P54
permit is the Longtom Upper prospect,
a lead which represents a possible
extension to the Longtom field containing
up to 250 bcf of additional gas
which will be tested by a future exploration well.
VIC/P45 ORRI
$22
Billion Oil Company - Apache Becomes Operator of
ACOR's ORRI Under VIC/P45
VIC/P45 consists of
214,896 gross acres. The Kingfish Field begins 1-1/2
miles west of VIC/P45. VIC/P45 is located offshore in
the most prolific oil-producing basin in Australia,
approximately 1 1/2 miles east of the Kingfish Oil
Field in the Southern Gippsland Basin in the Bass
Strait.
The Kingfish Oil
Field, the largest oil field in Australia, has
produced 1,100,000,000 barrels of oil since its
discovery. Calculating at current crude oil prices of
$US62.77 per barrel, this represents approximately
$69.05 billion worth of production. There are
currently 23 producing wells in the field. The
permeability in the pay section ranges between 5,000
and 40,000 millidarcies, which is extremely high. On
mapping there are 14 structures on VIC/P45, which
includes one oil and gas field discovery with 16 pays
and over 1,000 feet of pay section and a second with
one gas pay section. This was a discovery well drilled
off projected prospects.
Apache has agreed to
pay 100% of the cost to drill the 1st well; in return
Apache will earn a 66.6667% working interest.
Depending on the results from the 1st well, Apache may
elect to drill a second well and pay 100% of the cost
to drill the second well. Any discovery location, as
defined in the Petroleum (submerged Land) Act shall,
at Apache's discretion, be exercised from any such
reconveyance (should there be any).
In addition, Apache
has undertaken to assume its share of Royalty
obligations to third parties. Upon approval of this
transaction by regulatory authorities, Apache will
become operator of VIC/P45, and begin to select the
drilling location for the 1st well. The well is
planned to be drilled after a suitable drilling rig
can be contracted.
IMI, an independent
third party geological appraisal company estimated
that VIC/P45 could possibly contain approximately 350
million barrels of oil and 4 TCF of gas.
VIC/P45 is located
within the offshore Gippsland Basin, for many years
Australia’s premier oil and gas producing province
(Figures 1 and 2). Recent interpretation of 3D
seismic data by Exoil has identified the presence of
two new intra-Latrobe (Volador Formation) reservoir
play fairways within the permit:
- Lowstand
prograding wedge sandstones at the paleo-shelf edge
and slope.
- Coastal
barrier/shoreface sandstones.
These two fairways
offer significant potential for the development of
large structural-stratigraphic and stratigraphic traps
within the Gippsland Basin sedimentary succession
(Figure 3).
Shelf edge and slope
lowstand prograding wedges
Lowstand wedges that
occur along the shelf edge margin and slope are
typically sandstone-rich, reflecting focused
sedimentation via the funneling of fluvial sands to
the wedges through incised-valley feeder systems
during periods of lowstand as illustrated by the model
in Figure 4. Their setting within slope and
basinal shales creates ideal conditions for potential
hydrocarbon migration and entrapment and are thus
prime exploration targets wherever they can be
located.
This play can be very
prolific. In the Gulf of Mexico, most Miocene
hydrocarbon production from originates from lowstand
systems tracts (LST) containing these prograding
lowstand wedges.
Interpretation of
seismic facies and key surfaces in VIC/P45 reveals the
presence of several prograding wedges in the Late
Maastrichtian, Upper Volador Formation (equivalent to
the prospective Roundhead Sandstone) on a SE-facing
paleo-slope (Figures 5 and 6). The interpreted
lowstand turbidite wedges thicken to the SE and form
oval-shaped depositional “thicks” that dip to the SE
and strike NE-SW.
The WI partner has
announced the location for the next well to be drilled
on VIC/P45. The
location is called, the Scampi Prospect.
The Scampi Prospect is based on stacked sands
at the Top Latrobe level, with further stacked pay
potential mapped down to a four-way dip closure at Top
Golden Beach level. Scampi is considered by the
operator to be a relatively low-risk play with an
interpreted well-defined structural closure, the
potential for high quality reservoirs and proximity to
proven hydrocarbon charge. The primary target depth
for Scampi is about 2700m.
The prospect has the potential to contain mean
reserves of 34 million barrels of oil, if hydrocarbons
are present at the Scampi prospect. There is
further potential in the various deeper zones of this
prospect. Both porosity and permeability at the Scampi
location are assessed to be favorable, as evidenced by
the same zones penetrated in the nearby oil discovery
well, Archer-1, located to the immediate west, also in
VIC/P45.
The WI partner stated that the purpose in drilling the
Scampi prospect is two-fold:
-
To test the Scampi prospect’s ability to contain
oil.
-
If Scampi does contain oil, then Scampi could form
the nucleus for a hub of development of both the
Scampi Prospect and the known Archer oil
accumulation, and any other oil that might
subsequently be discovered in the fault blocks in
the vicinity of the known Archer discovery.
An extension of Year 3 of VIC/P45 to May 2006 has been
received from the Designated Authority.
The WI partner states that a well could be
drilled on VIC/P45 by May 2006, subject to rig
availability, joint venture and other necessary
approvals.
VIC/P45 is located
offshore in the most prolific oil-producing basin in
Australia, approximately 1 ½ miles east of the
Kingfish Oil Field in the Southern Gippsland Basin in
the Bass Strait.
The Kingfish Oil Field,
the largest oil field in Australia, has produced
1,100,000,000 barrels of oil since its discovery.
There are currently (23) producing wells in the
field.
The permeability in the pay section ranges between
5,000 and 40,000 millidarcies, which is extremely
high. On
mapping there are 14 structures on VIC/P45, which
includes one oil and gas field discovery with 16 pays
and over 1,000 feet of pay section and a second with
one gas pay section.
This was a discovery well drilled off projected
prospects.
Prospectivity
VIC/P45 is prospective for oil and gas at the top
Latrobe and also at the deeper intra Latrobe and
Golden Beach levels. A number of prospective features
have been identified, several of which are analogous
to existing Gippsland Basin discoveries. Almost the
entire area of the 900 Kms2 permit is covered by a
high quality 3D survey acquired and processed by BHP
Billiton in early 2003 (replacement cost estimated at
approx. $10 million). Further processing is proposed
by the operator with respect to depth conversion
calculations.
The wells drilled in the past in Vic/P45 have tested
prospects in all three of the main play groups (top
and intra-Latrobe and Golden Beach), with success in
the intra-Latrobe and Golden Beach plays. The drilled
wells are suitably positioned to help define the
extent of the prospective section in the Vic/P45 area.
The three hydrocarbon discoveries drilled at Anemone
1A, Archer 1 and Hermes 1 established the existence of
working petroleum systems in the permit area.
Recent evaluation work, following 3D mapping by BHP
Billiton, (the previous operator) has identified
appraisal potential in the Archer Prospect.
Other targets include numerous structural and
stratigraphic prospects and leads interpreted at
intra-Latrobe, top Golden Beach and Emperor Subgroup
level.
Of the approximately 15 prospects and leads identified
by the operator, some four of these have been graded
very high: Archer/Anemone, Scampi, Archaeopteryx and
Saratoga.
Errol Lead
The Errol Lead margins
one of the northern boundaries of VIC/P45 (Figure 2).
. Its up-dip termination is marked by a strong,
structurally concordant “bright spot” (Figure 7).
This is interpreted as a direct hydrocarbon indicator
(DHI) related to a possible gas accumulation. It
implies the presence of an effective stratigraphic
seal that provides an active stratigraphic trapping
mechanism. The permit is located in a
particularly “oily” part of the Gippsland Basin with
significant potential for the presence an oil leg
down-dip of the interpreted gas. The lead as
presently defined encompasses 2.7 sq km, but its size
could be substantially greater if the oil leg extends
further down-dip.
Coastal barrier/shoreface
sandstones
A recent paper by
Bernecker and Partridge (2005) describes a series of
straight to gently arcuate palaeoshorelines within the
Paleocene and Eocene section of the petroliferous
Latrobe Group. In the central part of VIC/P45, Exoil
has identified similar shoreline sequences in the
underlying mid- to Upper Cretaceous Volador Formation.
These coastal barrier and shoreface sandstone
sequences are defined by well and 3D seismic data as
sediment thicks associated with several, large, NE-SW
trending, coarsening-upwards sandstone bodies(Figures
5 and 8). The sands are also characterised by high
amplitude reflections that appear to increase in
amplitude up-dip.
The sandstone bodies
are interpreted as laterally restricted, transgressive,
coastal barrier to shoreface sandstones that display a
SE transition into offshore sealing marine claystones.
Vertical seal is provided by intraformational
transgressive marine claystones. Sediments
belonging to lagoonal and lower coastal plain
environments are interpreted to the NW, in a landward
position behind the barrier.
Neptune & Trident
Leads
Neptune and Trident are
two adjacent leads defined in the central part of
VIC/P45 involving interpreted coastal barrier and
shoreface sandstones in structural-stratigraphic traps
(Figure 2).
Their“seismic” limits
are defined by the extent of mappable high seismic
amplitudes of an upper sandstone sequence (Figure
9). Sandstones thin and eventually pinch out to the NE
and SE, sometimes terminating against NW-SE trending
faults. The trap is a combination structural-stratigraphic
trap with the major boundaries defined by
stratigraphic pinchout. Interpreted facies
development of barrier / shoreface and marine
sediments related to a shoreline model and present-day
Gippsland coastline is illustrated in Figure 10.
Based on the mapped
extent of the upper sandstone, the Neptune Lead
encompasses an area of 12.8 sq km and Triton some 9.6
sq km.
The upper sandstone was
intersected by Helios-1 where a 55 m section is
present. Although water wet in this down-dip
well location, the sandstones exhibit excellent
reservoir properties with high net-to-gross reservoir
and porosities that range up to 29% and average
between 23% and 25%.
The high amplitudes
that characterise the interpreted barrier sandstone
system of the Neptune and Trident leads are intriguing
and could imply the presence of hydrocarbons.
The 3D seismic requires additional processing and
analysis for a better understanding of the cause of
the high amplitude reflections associated with
potential sandstone reservoirs. Proposed well
calibrated inversion and AVO modeling should help
determine the variable contributions of porosity,
lithology (reservoir/seal) and fluids (oil, gas or
formation water).
Archer and Anemone Prospects
The Archer /Anemone Prospects represent the existing
oil and gas discoveries made by the Archer-1 and
Anemone-1A wells, together with deeper untested
potential reservoirs. The oil discovery made in
Archer-1 will be the subject of investigation to
determine whether there is potential for further oil
in the Archer feature, and whether an economic oil
development scenario may exist.
On the basis of the new 3D data, Anemone-1A is
interpreted to have drilled into the Archer fault
block. Overpressure and poor quality reservoirs
encountered in Anemone-1A are now interpreted as being
likely to result from drilling into the fault plane.
Improvements in reservoir quality may occur up-dip and
away from the fault zone.
Further potential resources are associated with
shallower gas accumulations proven by the Archer-1 and
Anemone-1A wells, as well as potential additional gas
reservoirs not tested by either well. Deeper horizons
in Archer provide the opportunity to explore, at
relatively low risk, for a gas resource close to
infrastructure and key markets.
BHP Billiton have assessed the ultimate recoverable
reserves potential for gas and condensate in Archer
Deep/Anemone to be from a lowside of 51 BCF and 3 MMB
to a highside of 923 BCF and 96 MMB.
Scampi Lead
An oil prospect, Scampi is an upthrown fault block
lead in stacked Cretaceous sands and a deeper 4-way
dip closure at top Golden Beach.
BHP Billiton assessed reserves potential for the
Cretaceous sands only (primary target) as 34 MMb of
recoverable oil.
Archaeopteryx Lead
A further oil lead, Archaeopteryx is a low relief
four-way dip closure set up by the palaeo-shelf break
(Kingfish Field analogue). The main risks with this
lead relate to the depth conversion and top seal.
BHP Billiton estimate recoverable reserves potential
of 123 MMb.
Saratoga Lead
Saratoga is a lowside fault-dependent closure at the
Golden Beach level with estimated reserves
potential of 34 MMb.
Conclusion:
VIC/P45 contains a
wealth of prospects yet to be drilled, nearly all of
which are associated with existing hydrocarbon
discoveries. We rank VIC/P45 very highly.
Apache Northwest Pty Ltd, as
Operator, have interpreted prospects and leads in
Vic/P45, drawing
upon the existing modern, 1,100 km²
high quality 3D seismic survey that covers most of
Vic/P45.
Apache have advised that
Coelecanth is the most likely well location.
While prospects are ready for
drilling, the very tight market for offshore drilling
rigs is likely to push
any Vic/P45 drilling activity into
2008.
VIC/P53 ORRI
ACOR's ORRI under
VIC/P53 is located in the prolific Gippsland Basin.
VIC/P53 consists of 182,858 gross acres. VIC/P53 is
also called the “Hole of The Donut” as VIC/P53
is surrounded by 9 giant oil & gas fields, leaving
VIC/P53 in the middle.
The $200 Billion
Dollar Neighborhood
When purchasing Real
Estate you are always told, Location, Location, &
Location. ACOR management feels VIC/P53 is
located in a great neighborhood. For example,
Some of the very best oil production in the world is
the found in the Halibut Oil Field. The Halibut Oil
Field is approx. 1.8 miles west of ACOR's VIC/P53,
where the average well has produced 60,000,000 bbls of
oil or $4,200,000,000 worth of oil per well, at
today's prices.
The nine giant oil &
gas fields that surround ACOR’s VIC/P53 have some very
impressive production figures as shown below.
The fields are still producing.
1.
Kingfish Field has produced 1,100,000,000 barrels of
oil or $70,000,000,000 at current market prices of
$70.00 per barrel.
2.
Bream
Field has produced 88,000,000 barrels of oil or
$6,160,000,000 at current market prices of $70.00 per
barrel.
3.
Barracouta Field has produced 1.1 TCF of gas or
$2,750,000,000 at $2.50 per mcf gas prices.
4.
Snapper Field has produced 630 BCF of gas or
$1,575,000,000 at $2.50 per mcf gas prices.
5.
Marlin Field has produced 2.4 TCF of gas or
$6,000,000,000 at $2.50 per mcf gas prices.
6.
Fortesque Field has produced 260,000,000 barrels of
oil or $18,200,000,000 at current market prices of
$70.00 per barrel.
7.
Halibut Field has produced 820,000,000 barrels of oil
or $57,400,000,000 at current market prices of $70.00
per barrel.
8.
Cobia
Field has produced 135,000,000 barrels of oil or
$9,450,000,000 at current market prices of $70.00 per
barrel.
9.
Mackerel Field has produced 450,000,000 barrels of oil
or $31,500,000,000 at current market prices of $70.00
per barrel.
The WI partner of
VIC/P53 has completed the shooting of 524 square
kilometers of high resolution 3D seismic data in
VIC/P53 at an estimated cost of $US5,000,000. One of
the prime purposes of the 3D seismic survey in VIC/P53
was to investigate the area to the east of the
Veilfin-1 well, which produced oil and gas shows,
referred to as the Bazzard Lead.
The WI partner is now
processing the seismic data and will employ leading
interpretation and depth conversion experts to
interpret the data and to carry out detailed depth
conversion calculations. By early 2006, the operator
plans to have completed its studies and to be then
ready to drill a well in the Permit.
Vic/P53 is considered
prospective for oil and gas at the top Latrobe and
also at deeper intra Latrobe levels. Vic/P53 is
surrounded by the oil and gas producing fields held by
EXXON/BHP. The location, adjacent to this
infrastructure, and proximity to pipelines, processing
facilities and major markets, offers potential
advantage through infrastructure savings and gives
encouragement to participation in Vic/P53. The
hydrocarbons recorded at Veilfin-1 established the
existence of a working petroleum system in the permit
area.
Seismic Coverage
Vic/P53 is a complex block but, given its location, is
inherently prospective, provided depth conversion
complexities can be addressed using new 3D seismic
data. Updip potential may exist in the permit to the
east of Veilfin-1. Importantly, there has not been a
well drilled within the area of Vic/P53 during the
last 20 years. Likewise, no dedicated 3D survey has
yet been shot in the block, apart from surveys shot in
adjacent acreage which peripherally covered the edges
of Vic/P53. Over this period, technology and the
ability to deal with the complexities of depth
conversion have improved dramatically. This aspect,
when taken with the strategic geological location of
Vic/P53, argues well for the development of top and
intra Latrobe plays, once the new high resolution 3D
seismic survey has been completed. A substantial part
of the funds raised by this issue will be used for
this purpose.
Work Program
The 470 kms2 3D seismic survey planned in early 2005
will highlight the potential of Vic/P53. Depth
conversion work is anticipated to be enhanced through
the use of the proposed new 3D seismic.
