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Offshore Western Australia WA 372 & WA 373 ORRI

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GIPPSLAND BASIN HISTORY

ACOR W.I. & ORRI AREAS

The history of oil production in the Gippsland Basin dates back to 1924 when Lake Bunga-1, intended to drill for water, was spudded near the township of Lakes Entrance. The well encountered a 13 meter oil column in glauconitic conglomerates (top Latrobe Group interval) and was followed by over 60 wells that, by 1941, had produced more than 8,000 barrels of heavy oil (40-60º API).

Extensive exploration in the Gippsland Basin did not commence before the mid-1960s, after seismic surveys had imaged the Central Deep and identified several anticlinal closures.

The first successful well, East Gippsland Shelf-1 (later known as Barracouta-1), was drilled by Esso in 1964/65 and discovered a 102.5 meter gas column at a depth of 1,060 meters. Following the subsequent major gas discovery at Marlin, the Gippsland Basin was initially perceived as a significant gas province.

However, when the Kingfish-1 was drilled in 1967 and encountered the largest Australian oil field known to date, the Gippsland Basin had gained international recognition.

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.

 
Despite its long history of extensive exploration, many parts of the basin, especially the eastern region, are still poorly understood.  New players have entered the exploration scene and the amount of seismic data, particularly 3D, is increasing. For such a prolific basin, the Gippsland Basin is relatively unexplored and ACOR believes there is still considerable potential for significant discoveries.

Offshore VIC/P60   

ACOR is so excited about our new discoveries on Permit 60.  ACOR management is now working full time to locate an oil company and/or investor(s) to take a look at the six new anticlines and a fault trap on the flank of an anticline with 1,100 feet of closure, with an outstanding bright spot anomaly indicating oil.

Roy Whiting, our Geophysicist has spent several months on the area and we are excited about his findings.  In our opinion, the Australian Government's VIMP report on permit 60 or V03-4 was incorrect. In one case, the crossection map of Pisces on VIC/P60 show the beds pinching out when in fact the beds get thicker. Roy has discovered that the beds on VIC/P60 are thickening to the SE and repeating the section found in the Giant Oil Fields to the NW.
 
Roy has identified six (6) structures on VIC/P60. One of the six (6) structures, the A-1 Prospect lies in 100-200 meters of shallow water.  Roy has estimated that the A-1 Prospect could possibly contain approximately $500,000,000 in reserves, if filled with hydrocarbons.

The A-1 prospect is approximately 4.97 miles long and 1.24 miles wide with a seismic bright spot anomalie rated good to excellent.  The seismic bright spot is 108’ thick and 820’ horizontal by 20,500’ perpendicular wide behind a fault on the flank of the anticline. He has traced the beds to the nearest oil and gas fields after processing 5,000 +/- seismic lines.

The Bass Strait part of the Gippsland Basin has near surface channels filled with limestone with a different velocity from the surrounding beds. Professors Malcolm Wallace and Gary Holdgate have released a report that not only described the velocity problem within the Seaspray Group but also gave a formula that when applied fixes the issues with false leads and the uplifting of structures.

 

Mr. Roy Whiting, using the Kingdom Seismic Software developed a seismic program which corrects velocities to get rid of this problem.  Roy tried it out successfully on the nearest producing fields and seismic over production and applied it to the 2-D seismic on Permit 60.

 

The big structure did not have any bright spots over the crest, but on the flank behind a fault trap discovered a spectacular bright and large anomalie. 

 

We think that this seismic bright spot anomalie may produce like the Fortescue Field or the Cobia Field on the south flank and west flanks of the Halibut anticline.

 

Here are some reasons why we feel this is a conservative estimate for the A-1 Prospect on VIC/P60:

 

  1. Porosity for the area is between 10 and 27 percent, 12 percent was used for the calculations on the A-1 Prospect, this is very conservative.
  2. The size of the A-1 structure is listed as being 4 miles long, this is because two parallel lines intersect the A-1 structure, so we know it is at least this size. We do not have any seismic lines that are outside of the parallel line of A-1, so we really do not know the total length; it could be larger. To acquire the total size we will need to run the 3D seismic then we can determine the true extents of the A-1 Prospect. 
  3. The calculations for the A-1 Prospect only used the middle zone to equate the oil percentage. We know there are at least two other zones in the A-1 structure. Again being very conservative.

We have just discovered these new structures in the Bass Strait Offshore Victoria on Petroleum Permit 60 from an approximately six month examination of nearly 5,000 2D lines.  Two permits to the north, the Halibut Field has produced 60,000,000 bbls. per well to date.  This amounts to $3,600,000,000 per well, if the oil were valued at today’s price.  On the west slope of the anticline, the fault trap forms the Fortescue Field, which has made 9,285,740 bbls. per well to date, or $557,144,400 per well, if the oil were valued at today’s price.  The fault trap on the side of the anticline on Permit 60 is a comparable situation to the Fortescue Field.  Permit 60 covers 339,769 acres.

The VIC/P60 Report

 

 

 

The End of The VIC/P60 Report

 

 

LIST OF ACOR OFFSHORE OVERRIDING ROYALTY INTEREST

 

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:

  1. To test the Scampi prospect’s ability to contain oil.
  2. 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.


 



 

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