Gas flaring at Longtom 3 Well
ACOR is Set to Receive
It’s First Offshore Oil & Gas Stream of Revenue -
Offshore Australia Longtom Gas Field on ACOR’s ORRI
is Scheduled to Start Production Next Week
WIRE)--Australian-Canadian Oil Royalties Ltd.
(herein called ACOR) (OTCBB:AUCAF)
is pleased to announce that the operator states that
the TSMarine Rem Etive dive support vessel had
completed all hook-up activities for the pipeline
and control systems for the Longtom Gas Field and
tested the system.
Production is expected to start in the coming
week following coordination of the start-up with
Santos’s onshore Orbost gas plant. Santos has a gas
contract in place, at an estimated value of
approximately $1,000,000,000 (BILLION) to process
and purchase up to 350 Petajoules (PJ) of gas and
associated liquids from the Longtom Gas Field on
ACOR’s ORRI located in the offshore Gippsland Basin.
The gas from the Longtom Gas Field will be
transported via the newly-built pipeline by the
operator to the end of Santos’s Patricia-Baleen
pipeline, approximately 7.3 miles away. The raw gas
would then continue along the Patricia-Baleen
pipeline to shore where it would be processed at the
Orbost gas plant.
The Longtom gas project has proved and probable
reserves of approximately 350 BCF of gas and 4
million barrels of condensate. The daily production
is estimated at a volume of approximately 11,000 -
12,000 barrels of oil equivalent per day (100%
ACOR owns a 1/20th of 1% ORRI under
VIC/54 (including the Longtom Gas Field) covering
approximately 155,676 gross acres.
About the Longtom Gas Field
The Longtom gas field is located in production
license VIC/L29 in the Gippsland Basin, offshore
Victoria. The field is approximately 12 miles from
the coastline in approximately 183 feet of water
In September 2006, the Longtom-3 well flowed at
over 75 MMCF per day on test while bypassing the
separator, confirming that it can also alone meet
the contract requirements.
In September 2008, the Longtom-4 development
well was successfully flow tested. The test of the
primary production zone within the Admiral formation
flowed at a rate of approximately 58 MMCF per day
through a 64/64” choke on ACOR’s ORRI. The well
flowed for 35 hours before being shut-in to monitor
the pressure response from the reservoir.
The Longtom gas project is a significant long
term infrastructure development that has the
capacity to deliver over 10% of Victoria’s annual
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.
These two fairways
offer significant potential for the development of
large structural-stratigraphic and stratigraphic traps
within the Gippsland Basin sedimentary succession
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
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
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
The WI partner stated that the purpose in drilling the
Scampi prospect is two-fold:
To test the Scampi prospect’s ability to contain
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
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
The permeability in the pay section ranges between
5,000 and 40,000 millidarcies, which is extremely
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
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
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
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
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
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
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
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
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
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
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.
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
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 is a lowside fault-dependent closure at the
Golden Beach level with estimated reserves
potential of 34 MMb.
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.