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TABLE OF CONTENTS

Page No.

1. GENERAL INFORMATION 1

2. PROJECT 52.1. Description 52.2. Management 5

3. GEOLOGY 83.1. Introduction 83.2. Predicted Stratigraphy 93.3. Reservoir Pressures 10

4. FORMATION EVALUATION 114.1. Wellsite Geologist's Responsibilities 114.2. Ditch Cuttings 114.3. Mud Logging 124.4. Coring 134.5. Testing 134.6. Wireline Logging 144.7. Sidewall Coring 154.8. Velocity Survey 15

5. SEQUENCE OF OPERATIONS 165.1. Pre-spud 165.2. 311 mm (12¼") Hole Section 165.3. 245 mm (9⅝") Casing and Cement 175.4. Install and test BOP 175.5. 216 mm (8½") Hole Section 185.6. 140 mm (5½") Casing and Cement 205.7. Suspend well 20

6. POTENTIAL HAZARDS 22

7. BITS, HYDRAULICS AND BHA 237.1. 311 mm (12¼") Hole 237.2. Rig Mud Pumps 237.3. Bit Hydraulics 247.4. Bottom Hole Assemblies 25

8. DEVIATION REQUIREMENTS 25

9. MUD PROGRAMME 269.1. 311 mm (12¼") Hole 269.2. 216 mm (8½") Hole 26

10. CASING AND CEMENTING DETAILS AND DESIGN 28

11. PRESSURE TESTING AND KICK TOLERANCES 30

12. ABANDONMENT 33

13. COMMUNICATIONS 3413.1. Origin Phone Numbers 3413.2. Daily Reports 3413.3. Origin After Hours Contact Telephone Numbers 3413.4. Emergency Reporting Numbers 34

13.5. Origin Offices 3413.6. Emergency Response Numbers 3513.7. Government Contact Details 3513.8. Contractor Contact Details 35Well Specifications Card 36

TABLESTable 1: Stratigraphic Prognosis 9Table 2: Reservoir Pressure Prognosis 10Table 3: Sample Requirements 11Table 4: Sampling Intervals 11Table 5: Bit Hydraulics 24Table 6: Bottom Hole Assemblies 25Table 7: Mud Type by Interval 27Table 8: Casing Details and Design 28Table 9: Cementing Details 29Table 10: Pressure Testing Requirements for BOPs 30Table 11: Kick Tolerance Calculations 31Table 12: Indicative Abandonment Programme 33

FIGURESFigure 1 WELL LOCATION 2Figure 2 STRATIGRAPHY: Surat / Bowen Basins 3Figure 3 Proposed Drilling Time/Depth Curve 4

ORIGIN ENERGY CSG LIMITED – CONVENTIONAL DRILLING OGILVIE CREEK 1 DRILLING PROGRAMMEI:\Ogilvie Creek\Ogilvie Creek 1\Pre-Spud\OgilvieCreek 01 DP_CDL07.doc

Page: 1 of 36 pagesIssued: March 2006Date Printed: 22-

1. GENERAL INFORMATION

WELL NAME: OGILVIE CREEK 1

OPERATOR AND Origin Energy CSG Ltd*(14.625%)PERMIT HOLDER: A.B.N. 68 001 646 331

Level 2, South Court John Oxley Centre, 339 Coronation Drive,

MILTON Qld 4064Tel: (07) 3858 0600

*100% owned subsidiary of Origin Energy Limited.

PERMIT: ATP 375P

BASIN: Surat Basin

SURFACE LOCATION: GDA 94 MGA 94 Zone 55

27o 02' 53.86" S149o 14' 9.51" E(Preliminary)

7 006 247 N721 781 E

(Preliminary)

SEISMIC LOCATION: Inline: 250Crossline: 327

ELEVATION: Ground Level: 244m Rotary Table:249.3m

PROPOSED T.D.: 2146.3 m RT

DRILLING CONTRACTOR: Century Drilling Limited,49 Campbell Ave,WACOL QLD 4076

DRILLING RIG: CDL 7

PRIMARY OBJECTIVE: Upper Tinowon Sst: 2059.3m R.T.

SECONDARY OBJECTIVES: Basal Rewan Sst: 1923.5m R.T.Lower Tinowon Sst: 2093.6m R.T.



Figure 1 WELL LOCATION(Prospect outline for Rewan structural closure)



Figure 2 STRATIGRAPHY: Surat / Bowen Basins



Figure 3 Proposed Drilling Time/Depth Curve

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2. PROJECT

2.1. Description

Ogilvie Creek 1 is a gas exploration well in ATP 375P. It will be drilled by Century Drilling Rig 7 in Q2, 2006.

Ogilvie Creek 1 is located in ATP 375P, ~700m north of Noorindoo 2 and will be mud drilled to a prognosed total depth of 2146.3 m, 30 m into pre-Permian economic basement (Timbury Hills Formation). Ogilvie Creek 1 is a stratigraphic test of the upper Tinowon sandstone, which is the main reservoir unit intersected in the Myall Creek and Churchie fields. The basal Rewan sandstone and the lower Tinowon sandstones are considered secondary objectives.

There will be a geologist, a two-man mudlogging crew and a mud engineer onsite from the surface casing point. This drilling campaign will be carried out on a 24-hour day basis.

2.2. Management

The drilling of the project is being managed by the Conventional Drilling Group. As such the Manager – Conventional Drilling and Well Completions is responsible for ensuring that all activities associated with the project are undertaken in full compliance with statutory regulations and are consistent with Origin Energy policy and procedures. The Origin Wellsite Representative is the delegated site representative of the Manager - Conventional Drilling and Well Completions with duties as outlined below and reports to the Senior Drilling Engineer who is also designated as the Drilling Operations Supervisor.

The customer is Onshore Exploration, whose designated representative is the Manager, Geoscience Surat. The customer representative will ensure that all environmental approvals, landowner agreements, JV and AFE approvals are in place for the project.

The Origin Wellsite Representative will liaise with the Kincora Production Facility, through the office of the Operations Superintendent Surat Basin, prior to the rig mobilising to the wellsite to discuss local issues that may impact on the project. A Wellsite handover from the Kincora Operations Superintendent to the



Origin Wellsite Representative will be required to hand control of the wellsite to the Drilling Group. The same form will be used to hand back the site upon Completion or Plug and Abandonment of the well.



The Origin Wellsite Representative is responsible for ensuring that Ogilvie Creek 1 is drilled in accordance with the Safety Management Plan – QLD 2006 and this Drilling Programme. This Drilling Programme is to be read in conjunction with the Safety Management Plan – QLD 2006. These are governing documents which reference the individual procedures, manuals and guidelines required for Origin Energy drilling operations with CDL Rig 7. The referenced documents are to be available on Rig 7, in Origin’s Brisbane office and in some cases in Century’s Brisbane office.

The Drilling Operations Supervisor is to ensure that these documents are present on the rig prior to drilling operations commencing. A signed copy of the following page must be faxed to the Drilling Operations Supervisor prior to spud, and also placed on the rig notice board to make all persons on the rig aware that these documents govern the work. Any queries and concerns are to be immediately raised with the Drilling Operations Supervisor. Any clarifications or changes are to be sent to the rig in the form of an approved Change Control Record.

The Origin Wellsite Representative shall ensure that written instructions are given on a daily basis to each driller. These instructions shall include basic drilling parameters, flow check requirements, or reference to the connection gas procedure and any other matters relevant for that day.

The Rig Manager will be the designated Drilling Contractor Site Safety Manager for the conduct of the Contractor’s activity and associated plant and equipment. Where applicable, the senior Service Provider personnel on site will be the designated Site Safety Manager for their specific activity and/or plant and equipment.

The Rig Manager will be the designated Wellsite Permit Authority under the Wellsite Permit to Work System. The Origin Wellsite Representative must sign off on any PTW prior to work proceeding under the Permit.

Routine communication with the Rig is via the Drilling Operations Supervisor, who maintains 24-hour contact, seven days a week.



THIS PAGE IS TO BE SIGNED AND FAXED TO THE ORIGIN BRISBANE OFFICE PRIOR TO SPUD.

Attention: Brendon Jones (Senior Drilling Engineer) Fax: 07 3369 7840

The documents listed below govern the drilling of Ogilvie Creek 1:

Present on Rig (Circle)

Document Owner Date

Site Management DocumentsYes No Drilling Programme- Ogilvie Creek 1

Origin Yes No Safety Management Plan / Risk Register - QLD 2006

Origin Yes No Drilling Emergency Response Plan

OriginYes No Origin Energy Connection Gas Procedure OriginYes No Century Site HS&M Manual

CDL Yes No Century Standard Operating Procedures Manual

CDL Yes No Century Risk Assessment Register

CDLYes No Onshore Permit to Work System CDL

Government RegulationsYes No Queensland Petroleum and Gas (Production and

Safety) Regulations 2004Origin

Technical ManualsYes No Wood Group Wellhead Manual Origin

Name Position Signed DateOrigin Wellsite RepresentativeOrigin Wellsite RepresentativeCDL Rig ManagerCDL Rig Manager



3. GEOLOGY

3.1. Introduction

Ogilvie Creek 1 is proposed as a gas exploration well to be drilled in ATP 375P (Figure 1). Ogilvie Creek 1 is a stratigraphic test of the upper Tinowon sandstone, which is the main reservoir unit intersected in the Myall Creek and Churchie fields. The basal Rewan sandstone and the lower Tinowon sandstones are considered secondary objectives.

Ogilvie Creek 1 is located ~700m to the north of Noorindoo 2 on the upthrown side of a fault bounding the northern limit of Myall Creek 8 and Noorindoo 2. Modelling data suggests that this area to the north is not currently being accessed by production from the Myall Creek Field. The well will address a zone which displays thickening in the upper Tinowon similar to that seen at Myall Creek. Seismically there is a relatively bland zone which looks similar to Myall Creek 8 and the acoustic impedance section shows a low impedance unit above the Wallabella, similar also to the Myall Creek wells.

The drilling programme for Ogilvie Creek 1 is to mud drill to a prognosed total depth of - 1897mSS, 30 m into pre-Permian economic basement (Timbury Hills Formation). The Ogilvie Creek 1 well has been designed to obtain stratigraphic and reservoir data required to advance the geological understanding of the Tinowon play to the north of the Myall Creek Field. Data acquisition will include a comprehensive wireline logging suite and formation pressure testing over select intervals dependant on shows and indication of permeable reservoir from wireline logging. Whilst Ogilvie Creek 1 has been positioned on a trend interpreted to have upper Tinowon sandstones present, reservoir presence and quality of the upper Tinowon sandstone remains the critical risk for the Ogilvie Creek 1 well.

Ogilvie Creek 1, if successful, will be connected to the Myall Creek facility, located adjacent to Myall Creek-3.



3.2. Predicted Stratigraphy

Ogilvie Creek 1 is expected to intersect the following stratigraphic section:

Table 1: Stratigraphic PrognosisFORMATION DEPTH (m

SS)DEPTH (m

RT)Bungil Formation -42.4 291.7Mooga Sandstone* -182.0 431.3Orallo Formation -366.6 615.9Gubberamunda Sandstone*

-508.0 757.3

Westbourne Formation -628.0 877.3Walloon Coal Measures* -824.0 1073.3Hutton Sandstone -1076.9 1326.2Evergreen Formation -1275.7 1525.0Boxvale Sonic Marker* -1319.0 1568.3Boxvale sandstone -1320.2 1569.5basal Evergreen -1373.7 1623.0Moolayember Formation -1381.4 1630.7Snake Creek Mudstone -1548.4 1797.7Showgrounds Sandstone -1565.1 1814.4Rewan Formation* -1579.0 1828.3Basal Rewan Sandstone -1674.2 1923.5Bandanna Formation* -1693.0 1942.3Black Alley Shale -1762.4 2011.7Winnathoola Coal Member*

-1774.0 2023.3

Tinowon Formation* -1786.0 2035.3Upper Tinowon Fm* -1810.0 2059.3Wallabella Coal Member* -1824.0 2073.3Lower Tinowon Sandstone -1844.3 2093.6Basement -1867.0 2116.3TD -1897.0 2146.3

* Denotes a geophysical pick



3.3. Reservoir Pressures

Potential over pressured formations in Ogilvie Creek 1 include the Mooga and Gubberamunda aquifers and the target sands of the upper and lower Tinowon. It is not anticipated that the Showgrounds / Rewan would be more than ~ 50 psi greater than a normal fresh water gradient. The Mooga and Gubberamunda sand pressures are not known exactly but surface flowing pressure is unlikely to exceed 60 psi.The Tinowon pressures have been estimated from the ‘Eastern Surat Regional Pressure Data’ with the minimum pressure being derived from the regional pressure gradient and the maximum from the highest known deviation. With Ogilvie Creek being an untested structure, all pressure estimates are a ‘guide only’ with all well control procedures to be in place.

Table 2: Reservoir Pressure Prognosis

SandstonePrognosed

Formation top

Ogilvie Creek 1 Predicted Pressure

Equivalent Mud Weight at max

predicted pressure

(m RT) min (psi)

max (psi)

(sg)/(ppg)

Mooga 431.3 613 673 1.10/9.2Gubberamunda 757.3 1076 1136 1.06/8.8Upper Tinowon 2059.3 3440 3500 1.20/10.0Lower Tinowon 2093.6 3690 3740 1.26/10.5

Sandstone Planned MW

Ogilvie Creek 1 Predicted

Overbalance(sg)/(ppg) min

(psi)max (psi)

Mooga 1.14/9.5 26 86Gubberamunda 1.14/9.5 91 151Upper Tinowon 1.26/10.5 189 249Lower Tinowon 1.31/10.9 153 203

ALL PRESSURE PROGNOSES ARE SUBJECT TO UNCERTAINTY.BE ALERT AT ALL TIMES FOR INDICATIONS OF THE WELL FLOWING OR

TAKING FLUID.



4. FORMATION EVALUATION

4.1. Wellsite Geologist's Responsibilities

The Wellsite Geologist will supervise formation evaluation services on the rig and reports functionally to the Drilling Operations Supervisor. The Wellsite Geologist takes direction from the Project Geologist / Drilling Operations Supervisor (as appropriate) about programme details and operations planning. On the rig site the Wellsite Geologist reports directly to the Origin Wellsite Representative.

The Wellsite Geologist shall call the Project Geologist at ~4PM daily to review current operations status.

4.2. Ditch Cuttings

Table 3: Sample RequirementsSet

Size No

Type

In For

A 500 g

1 Unwashed & air dried Cloth bag Origin

B 200 g

1 Washed & air dried Minigrip bag

Qld DNR&M

C 200 g

1 Washed & air dried Minigrip bag

Origin

D 1 Washed Samplex tray

Origin

Note : Samples sent to QDNRM (& ACS)should arrive with a Transmittal Advice with the following- Well Name and Number,- No. of boxes- Start depth and end depth within each box- Samples shall be dry

Table 4: Sampling IntervalsInterv

alFrom To

10 m Surface

1900 m

3 m 1900 m

Total Depth

Additional samples will be taken to evaluate shows and at any time deemed necessary by the Wellsite Geologist. Commencing at 1800 m, 1 litre mud sample will be taken every 100 m while drilling and preserved with biocide for future analysis. A



mud sample will also be taken prior to taking fluid samples by wireline or running DST’s.



4.3. Mud Logging

Mud logging services will be used from surface casing point to total depth, to provide continuous 24 hour surveillance, and digital recording at 0.5 m intervals, of drilling operations including:

Total gas detection Rate of penetration Chromatographic gas analysis

Pump stroke rate Measured depth Mud pit levelsWOB RPMPump pressures Torque

A comprehensive 1:200 scale mud log will be maintained at all times from surface to total depth, and will include WOB and RPM in the ROP column. An up to date log is to be submitted daily to the Wellsite Geologist in time for the daily report along with a *.PDF file for transmission to Brisbane. A complete ASCII file containing the metres drilled, rate of penetration, WOB, RPM, torque, total gas and gas breakdown is to be transmitted to the Brisbane office on reaching Total Depth, and at other times as requested.

All instrument charts are to be annotated with: depth (in metres), attenuation changes, dates, times and sample collection intervals. Charts are to be submitted to the Origin Wellsite Representative prior to release of the mudlogging unit.

Gas detectors and chromatographs are to be calibrated with standard check gas blends each trip. Total gas detectors are to be calibrated so that 1% methane in air will produce a chart deflection of 50 units. CO2 and H2S draeger tubes will be on site for evaluation of formation gas samples from RFS or DST.

Calcium carbide lag checks will be run once per day or every 300m, whichever occurs first (or at the discretion of the Wellsite Geologist). Total gas units and lag times (actual and calculated) are to be recorded on the mud log in minutes. No carbides are to be run whilst evaluating prospective hydrocarbon zones.

Formation Integrity Tests, pit losses/gains, tight hole, bit data; mud information and survey data are to be recorded on the mud log. The mud loggers will be responsible for time lagging, collection and description of drill cutting from surface casing shoe to total depth. Routine microscopic and fluoroscopic examination of cuttings for hydrocarbon shows will be undertaken.



At the pre-tour meetings all personnel will be informed when the drilling process is likely to enter the significant section of the well. This significant section is defined as the most likely section of the well to incur a fluid or gas influx/loss. During these phases the DRILLER will



perform a FLOW CHECK on a significant drilling break (the interval is to be penetrated by no more than 2 metres). The mud loggers will ensure that the DRILLER is informed that a significant drilling break has occurred. The Wellsite Geologist and the Origin Wellsite Representative will determine the need for circulation of a Bottoms Up sample. Bottoms up will be circulated if a sample of the new lithology is required for hydrocarbon show evaluation. Pull up at least 6m above the top of the drilling break to minimise formation damage. If a PDC bit is in use, the drilling parameters (WOB etc) should be kept relatively constant as the primary objective is approached, and any significant change in drill rate (increase or decrease) investigated as above. If the Wellsite Geologist is not present, inform the Origin Wellsite Representative.

4.4. Coring

No coring is programmed for this well.

4.5. Testing

An open hole DST may be conducted over the upper Tinowon and/or secondary objectives on penetration, or after wireline logging, contingent on reservoir development, hydrocarbon indications and indicative formation pressures, to determine if gas reserves are sufficient to warrant future completion of the well as a gas producer. Additional open hole DST’s and/or cased hole production tests may be added to the programme if warranted. DST equipment and personnel will be on standby throughout drilling activities. No separator is planned for the gas tests and any formation fluid remaining in the pipe will be reverse circulated into the 100 bbl test tank. A fail-safe testing head will be used.

The following samples are required for each DST undertaken. All samples will be labelled with: Well Name, Date, DST Number, DST Interval, Formation, Sample origin and Temperature.

4.5.1. Crude Oil Samples

If crude oil is recovered, two 5 litre can samples will be taken for analysis. Preliminary analysis of the API gravity and pour point of the oil will be made at the wellsite.



4.5.2. Gas Samples

A minimum of two samples will be collected under pressure in an evacuated steel cylinder (500 - 1000 ml) for analysis. A sample of any gas to surface will be analysed at the wellsite using the chromatography in the mudlogging unit. The sample will be tested for the presence of H2S and CO2 using draeger tubes supplied with the mudlogging unit. Avoid saturating the detector by diluting with air.

4.5.3. Water Samples

The following samples are required for hydro geochemical evaluation(i) Drilling mud sample - 1 litre plastic bottle,

Samples are to be collected while drilling, every 100 m commencing at 1800 m, and immediately prior to testing. Preserve samples with biocide.

(ii) Make-up water - 1 litre plastic bottle(iii) DST samples - 1 sample from the top

- 1 sample from the middle- 1 sample from the bottom

(iv) Mud filtrate - 20 ml sample

Collect each sample in a 1 litre plastic bottle. If an organic extraction of possible petroleum components from the water is required, then two samples in 1 litre GLASS bottles should be collected.

4.6. Wireline Logging

A comprehensive logging suite will be run in the 8 ½” hole section. No logs are programmed for the 12 ¼” hole section.

Logs are to be displayed at 1:500 and 1:200 scales.

NB: A PDF of each main log at 1:500 and repeat section at 1:200 is to be transmitted to the Brisbane offices ASAP after acquisition. A single paper copy of the logs is to be produced on site. This will be quality controlled in the Origin Energy Brisbane office and edited by the logging contractor before final prints are made.



Horizontal log scales:GR 0 - 200 APISP -50 - +50 MVDLL, SLL, MLL 0.2 - 2000 ohmmSonic 140 - 40 u/secDensity 1.95 - 2.95 g/ccNeutron Porosity 0.45 - -0.15 pu

8½" Openhole:RUN: 1. Super Combo (Firm)

(DLS-SP-MLL-CSS-CNS-PDS-SGR- TAC)

GR to surfaceLaterologs to surface casing shoeSGR, Density-Neutron to Snake

Creek MudstoneRUN: 2. MDA-GR (Firm) T.D. to Snake Creek Mudstone

MDA to be run in P&S mode, first motion detection and upper dipole mode.

RUN: 3. MFT-GR (Contingent) 20 pressure test points contingent on holecondition, shows and log evaluation Wellsite Processing: MFT Pressure Profile

RUN: 4. RFS-GR (Contingent) Contingent on MFT evaluation

4.7. Sidewall Coring

No sidewall cores are programmed.

4.8. Velocity Survey

No velocity survey is planned for this well.



5. SEQUENCE OF OPERATIONS

Rotary Table (RT) height above ground: 5.3 metres. All depths referred to throughout this programme unless otherwise noted refer to “along hole measured depth below rotary table”.

5.1. Pre-spud5.1.1. Before the rig moves on site, the location will be surveyed; access

roads, rig and camp locations will be built; a cellar will be installed; and a 406 mm (16”) conductor will be pre-set at ~ 12 m below Ground Level.

5.1.2. Move in rig and rig up, drill and case mouse hole and rat hole using gel spud mud.

5.1.3. The rig will be put in a safe and good housekeeping order prior to spudding the well. The Origin Wellsite Representative is to complete Rig Safety and Environmental Checklist and forward to Drilling Superintendent in Brisbane office.This Checklist is to be reviewed and signed by the Manager – Conventional Drilling, or his delegate, before spudding the well or as soon as practicable thereafter.

5.1.4. Hold pre spud safety and environmental meeting with both crews to outline the Drilling Programme and to reinforce the need for all personnel to be aware of and to work in a safe manner, in accordance with the governing documents for the well.

5.1.5. All personnel to be made aware that activities carried out on site by Contractor and Service Provider personnel should be governed by the relevant Safety Management Plans and Standard Operating Procedures. In absence of such plans or procedures, a risk assessment or JSA must be undertaken prior to the activity.

5.2. 311 mm (12¼") Hole SectionSection total depth: 240 mDrilling Fluid: Gel spud mudHazards: Hole instability

Communication to surface at conductor shoeRecommended drilling parameters: WOB: 5 - 20 Klbs, RPM: 100 – 120

5.2.1. Use Bit 1, as per Section 7, and make up 311 mm (12¼") BHA 1 as per the BHA programme. A totco ring will be in the BHA.

5.2.2. Drill to section TD using gel spud mud. Take inclination only survey using Andedrift at 150 m and at section

TD. Wireline surveys will be run only if required as a back-up to the Andedrift, with a FOSV to be used for all surveys run on wireline.

Mudlogging service and wellsite geologist are not required in this hole



section. Rig crew to catch samples every 10 m from surface, for later evaluation.



5.2.3. At section TD, the hole will be circulated clean and a wiper trip conducted to surface. The system viscosity will be raised to a minimum 45 sec with

additional Gel and/or a light addition of Lime, prior to running casing. No open hole wireline logging will be conducted in this hole section.

5.3. 245 mm (9⅝") Casing and CementThe 245 mm (9⅝") casing will be set in the Wallumbilla Formation at 240 m.Casing details: 53.69 kg/m (36 lb/ft), K55, BTCAccessories: Float shoe, non-rotating float collar, non-rotating top and

bottom cement plugs, 3 centralisers, thread-lock compound.

5.3.1. Clean, drift, strap and tally casing.5.3.2. Run 245 mm (9 ⅝") casing:

Install float shoe. Install non-rotating float collar between first and second joints and thread-lock these joints together with the second and third joints.

Install bow type centralisers at approximately mid first joint, secured with lock ring, and at second and fourth collars above shoe.

Run casing, pick up landing joint, install cement head and circulate at least the total volume of casing whilst slowly reciprocating. Chain casing down prior to mixing and pumping cement.

Casing collar is to be spaced and landed such that the installation of the BOP stack, bell nipple and flow line do not need modification.

5.3.3. Cement 245 mm (9 ⅝") casing as per cementing programme. Pressure test all lines to 2000 psi Use non-rotating top cement plug Displace cement with water. Monitor for returns during cement job. When plug bumps, test casing to 1500 psi for 15 minutes.

5.4. Install and test BOPSurface Pressure: Maximum expected surface pressure, calculated assuming gas

to surface from the Lower Tinowon reservoir without leak-off, is ~3170 psi (assuming ~3740 psi max reservoir pressure). However, with the Mooga and Gubberamunda aquifers open below the casing shoe, the maximum surface pressure is unlikely to exceed 1000 psi.

Wellhead: Wood Group ‘A’ section: 279 mm (11") 5000 psi x 245 mm

(9 ⅝") casing head.BOP stack: One (1) 347 mm (13-5/8") – 5000 psi Shaffer LWS ram-type



double gate studded hydraulic BOP and one (1) 347 mm (13-5/8") – 5000 psi Hydril GK Annular BOP studded top and flange bottom.



5.4.1. Wait on cement for 4-6 hours, check surface samples are set before proceeding.

5.4.2. Install A section wellhead following manufacturers instructions.5.4.3. Nipple up BOP stack and pressure test according to BOP test

programme (Section 12) using portable pressure testing unit. Test pipe rams and annular against drill pipe prior to drilling out cement.

5.5. 216 mm (8½") Hole SectionSection total depth: 2146.3 mDrilling Fluid: KCl-PHPA mudHazards: Water influx from shallow aquifers

Differential sticking in permeable water sands Over-pressured gas in Tinowon reservoirOver-pressured coals

Recommended drilling parameters:PDC: WOB: 10 - 20 Klb, RPM: 100 – 120TCI: WOB: 20 - 40 Klb, RPM: 80 – 100

5.5.1. Use Bit 2 ( 5 blade, 16/19 mm PDC) as per Section 7 and make up BHA 2 as per the BHA programme. A stabilised rotary assembly will be run to minimise hole drift and to improve PDC performance. An Anderdrift and a totco ring will be run in the BHA to check hole inclination. A float will be run in the string.

5.5.2. RIH, test pipe rams as per BOP test programme, RIH, tag cement and drill out cement and shoe with water. Drill 3 - 5 m of new formation and circulate hole clean.

5.5.3. Displace the well to KCl - PHPA mud. Perform FIT to 18 ppg (2.16 SG) EMW. Complete FIT/LOT report and transmit to Brisbane office ASAP.

5.5.4. Drill to TD (~2146 m) using KCl – PHPA mud Mud density will be a minimum of 9.5 ppg (1.14 SG) prior to

drilling the Mooga Sandstone (~431 m) and 10 ppg (1.20 SG) prior to wiper tripping below the Hutton Sst.

Mud density will be a minimum of 10.5 ppg (1.26 SG) prior to the top of the upper Tinowon Sandstone (~2059 m) or prior to wiper tripping immediately above this zone. An ‘on penetration’ DST of the upper Tinowon Sandstone is contingent on evaluation while drilling and 10.5 ppg mud density should be maintained to the base of the upper Tinowon sand.

After the DST, or after confirmation to drill ahead without testing, raise density to 10.9 ppg (1.31 SG) prior to the top of the lower Tinowon Sandstone (~2093 m). This may necessitate circulating and raising the density prior to drilling ahead due to the short drilling section to the lower Tinown.



Contingent wiper trips back to the previous wiper trip depth have been planned at the following depths:



i. 1550 m- after drilling through the Hutton Sandstoneii. 2020 m – prior to drilling the Tinowon Formation (primary target)

Final decision to conduct wiper trips will be dependent on hole conditions and will be confirmed by Brisbane Office.

Flow check significant drill breaks, at the top of known sand formations and prior to connections, taking surveys and pulling out of hole. Raise the density as required to balance formation pressure. Sufficient Barite will be kept on location.

Mud loggers to monitor, and report, incidences of connection gas. Take inclination only surveys using Anderdrift every 150 m and at

section TD. If wireline surveys are required as a back-up to the Anderdrift, a FOSV is to be used.

Full mudlogging service, mud engineer and wellsite geologist are required in this hole section.

5.5.5. Contingent bit trip. Should a bit trip be required, trip for a TCI bit. A totco ring and a float

will be run in the BHA. Pick up additional drill collars as required to have maximum BHA

weight available for the TCI bit.5.5.6. Wellsite Geologist to confirm TD with Drilling Operations Supervisor

before POH. Total depth is programmed for 2146.3 m, approximately 30 m into basement.

5.5.7. Flow check and circulate clean.5.5.8. Perform short wiper trip, to previous wiper trip depth or 10 stands

minimum. Evaluate mud gas levels on circulation of ‘bottoms up’. If gas levels are significant, consult Brisbane office regarding possible mud density increase.

5.5.9. Pull out of hole. On all trips, monitor hole fill up volume required using the trip tank

to ensure the hole is taking the correct mud volume on the trip. Use average joint length method to confirm depth.

5.5.10. Perform wireline and formation evaluation activities as detailed in sections 4.6 to 4.8. An additional wiper trip is contingent on the duration of the wireline

programme. Use average joint length method to confirm depth.

5.5.11. Contingent post logging DSTs are programmed for the Primary and Secondary objectives, dependent on log evaluation and hydrocarbon shows and estimated formation pressures. Approval for any DST will be issued by the Brisbane office.

5.5.12. If the well is to be cased and suspended, perform a wiper trip and condition hole prior to running casing. In the case of P&A, a plugging program will be issued by the Brisbane Office. Lay out drillpipe.



Clean tanks and rig release or run casing as per section 5.6.

5.6. 140 mm (5½") Casing and CementThe 140 mm (5½") casing will be set at TD for further evaluation and/or production.Casing details: 25.3 kg/m (17 lb/ft) N80, LTCAccessories: Float shoe, float collar, top and bottom cement plugs,

centralisers, lock ring, thread-lock compound.5.6.1. Clean, drift, strap and tally casing.5.6.2. Run 140 mm (5 ½") casing:

Change pipe rams to suit the casing size. Install float shoe. Install float collar between first and second joints.

Threadlock these joints together as well as the following joint of casing.

Install centralisers: mid 1st joint and on 2nd and 4th collars. Ensure that a lock ring is used to locate the shoe joint centraliser. Run centralisers on every joint from 20 m above to 20 m below production zones.

Run casing, tag bottom, install cement head and circulate at least the total volume of the casing whilst slowly reciprocating.

5.6.3. Cement 140 mm (5½") casing as per cementing programme. Pressure test all lines to 5000 psi. Any pre-flush used must be weighted to the density of the drilling

mud in use at the section TD. Use top and bottom cement plugs Casing is to be reciprocated continuously until at least half of the

cement is outside the casing shoe. Displace cement with water (inhibited to minimise corrosion). Monitor for returns during cement job. When plug bumps, test casing to 5000 psi for 15 minutes.

5.7. Suspend wellOnce the casing is cemented, the well will be suspended and the rig released. A separate programme will be issued for the well completion.5.7.1. Suspend well.

Land casing in slips (no waiting on cement). Rough cut casing. Nipple down BOPs. Prepare casing stub and install ‘B’ section following

manufacturer’s instructions. DO NOT ENERGISE SECONDARY SEAL . Install temporary blank flange on the ‘B’ section. Release rig.



6. POTENTIAL HAZARDS

The following potential hazards have been identified:

Potential Hazard

PotentialConsequenc

es

Actions Required/Contingency

PlanningCommunication to surface at conductor shoe

Lost circulation on drilling out conductor shoe

Check for downhole losses on drilling out the conductor shoe, and perform remedial cementing if required, before drilling ahead.Set 12 m conductor where possible

Water influx from shallow aquifers

Water cutting of drilling fluid

Maintain Barite on site to increase density to control water flow. A density of 1.14 SG is programmed for top Mooga.Monitor mud for water break through during stationary periods eg logging and testing.Raise mud density to 1.20 SG prior to the first wiper trip or bit trip.

Over pressured gas in Showgrounds, basal Rewan reservoirs or Tinowon reservoirs

Well kick on drilling into reservoir

Weight up to 1.26 SG prior to the upper Tinowon sand and 1.31 SG prior to the lower Tinowon sand.Monitor flow line for flow during stationary periods. Maintain Barite on site to increase density if required to control formation pressure.Connection gas and increased gas readings after wiper trips are to be handled according to the “Origin Energy Connection Gas Procedure”.

Over pressured coals Sticking of drill string As above. If drill break is expected to be a coal drill no more than 5 m before working the hole. Raise drill bit above coal tops while circulating bottoms up.

Differential sticking in permeable water sands

Sticking of drill string Keep pipe moving where practical. Use spiral drill collars if available. Maintain low solids content.Maintain low fluid loss with thin filter cake.If string becomes stuck and no gas zones are open, spot water to reduce hydrostatic pressure. If gas zones are open, use spotting fluid.

Hole instability Unable to run casing to bottom

A wiper trip will be conducted to surface after logging, prior to running casing.

Note – for a full Hazard Listing, refer to the Safety Management Plan – QLD 2006



7. BITS, HYDRAULICS

AND BHA 7.1. 311 mm

(12¼") Hole

Use a Varel CH1GMS (IADC 117) with BHA 1.

216 mm (8½") Hole

Use the bits indicated below with BHA 2.

BIT NO. MAKE TYPE IADC

2 HC605S

5 blade 19mm cutter PDC

n/a

3 (if required)

TBA TCI 437 or 447

7.2. Rig Mud Pumps

The rig is equipped with two National 8P 80 800 HP triplex pumps. Hydraulics will be designed to maximise flow rate with the PDC bit. Initial circulating rate will be +/- 600 gpm reducing as required as the SPP rises.PUMP No. 1 No. 2

Type

National

National

StrokeMax. Speed Permitted

8 P80216 mm (8 ½")

160 spm

8 P80216 mm (8 ½")

160 spmLiners Installed 152 mm (6") 152 mm (6")Max. Pressure Permitted 17000 kPa (2470

psi)17000 kPa (2470

psi)Pump Output (95% efficiency) 11.24 l/stk (2.97 gps) 11.24 l/stk (2.97 gps)



7.3. Bit Hydraulics

Table 5: Bit Hydraulics

Bit Number 1 2Bit Size mm 311 mm (12

¼”)216 mm (8 ½”)

Bit Manufacturer Varel HTCBit Type CH1GMS PDCIADC Code 117

In Out

In Out

Nozzles /32” 3 x 16

5 x 14

TFA in2 0.59 0.75

Depth m 0 240 240 2146

Pump Output gpm 650

650 600 500

Pump speed spm 220

220 202 168

Pump Pressure psi - - 1341

2061

Jet Velocity m/s - - 78 65Pressure @ bit % - - 41.6 21.6Bit HSI hhp/in2 - - 3.44 2.28DP-CSG ann velocity m/min - - 76 63DP-OH ann velocity m/min - 37 86 71DC-OH ann velocity m/min - 44 135 112

If a backup bit is required to complete the 216 mm hole section, contact the Brisbane office. Bit choice and hydraulics will vary depending on depth and formation.



7.4. Bottom Hole Assemblies

The planned bottom hole assemblies are listed below:Table 6: Bottom Hole Assemblies

BHA 1

No. Tool1 311 mm (12¼") Bit1 Bit Sub, 6 5/8" Reg x 4.0” IF, bored for float1 Anderdrift Survey tool2 159 mm (6¼") Drill Collar1 311 mm (12¼") Stabiliser with X/O s

14 159 mm (6¼") Drill Collars4 114 mm (4½") Hevi wate Drill Pipe

114 mm (4½") Grade “G” Drill Pipe (as required)

BHA 2

No. Tool1 216 mm (8½") Bit1 216 mm (8½") NB Stabiliser, bored for float1 Anderdrift Survey tool1 159 mm (6¼") Drill Collar1 216 mm (8½") String Stabiliser

14 159 mm (6¼") Drill Collars4 114 mm (4½") Hevi wate Drill Pipe

114 mm (4½") Grade “G” Drill Pipe (as required)Note:

Run sufficient collars in BHA 2 to have adequate BHA weight to run 25,000 lbs weight on bit while maintaining all drill pipe in tension with 15% safety margin..

If a bit trip is required and a TCI bit used, increase the number of drill collars so as to have adequate BHA weight to run 40,000lbs weight on the bit.

All BHAs shall incorporate a float valve.

8. DEVIATION REQUIREMENTS

Spud - 240 m. Inclination only survey using Anderdrift tool at 150 m and at casing point.

240m – TD Inclination only survey every 150 m and at TD using Anderdrift tool. The target tolerance is a radius of 50 m from well centre - as calculated assuming a constant azimuth.



9. MUD PROGRAMME

9.1. 311 mm (12¼") Hole

Drill the rat hole, mouse hole and spud the well with gel spud mud using a “long system” in the mud tanks to effectively keep the sand content low. Maintain the pH at 9 to 10 with Caustic Soda. As drilling proceeds, native clays should contribute to fluid viscosity. Add water at the flowline to maintain volume and minimise the density increase. A small quantity of PAC or XCD polymer may be used with Gel to maintain rheology. Solids control equipment will be run at all times to ensure that the sand content does not build up excessively. The hole will be circulated clean prior to wiper trips and running casing. The system viscosity will be raised to a minimum 45 sec with additional Gel and/or a light addition of XCD polymer, prior to running casing.

9.2. 216 mm (8½") Hole

Drill out the cement and shoe with water, perform an FIT, and displace the well to a KCl-PHPA fluid. Basic composition will be 3-4% KCl, 1.5 ppb PHPA (Dry), and 1.0ppb PAC. A small quantity of XCD Polymer may be required to aid rheology and suspend Barite. Vary the PAC composition to maintain the filtration control. Add Caustic Soda to maintain the pH in the 9.0- 9.5 range. Oxygen scavenger should be added to give a minimum sulphite residual of 100 ppm. The system volume should be maintained with pre mixed mud only, with no direct additions of water permitted. If highly reactive clays are encountered, the PHPA level will need be increased to 1.75 to 2.0 ppb.

The low density solids should be kept to a minimum by the use of all solids control equipment. However the mud density will be raised to 1.14 SG prior to the Mooga and Gubberamunda Sandstones to prevent a water influx. Subsequently, the density should be raised to 1.20 SG prior to the first wiper trip.

Density will then be increased to 1.26 SG prior to the upper Tinowon sand and maintained at this level while the sand is drilled and evaluated. The density should be further increased to1.31 SG prior to the lower Tinowon sand and raised further should formation pressures dictate. Barite should be used to raise the density in preference to allowing a build up of drill solids. Add biocide as required to preserve the mud.



When running production casing, the mud left in the casing/open hole annulus should be treated with biocide to reduce bacteria and the pH should be increased to at least 10 to minimise corrosion. An oxygen scavenger or proprietary corrosion control additive may also be considered. The production casing may be displaced with brine and, if so, a corrosion inhibitor should be added.

Table 7: Mud Type by Interval

Interval (Hole Size)

Weight (SG)

Viscosity

API Fluid Loss (cc)

Mud Type

0 - 240m311mm (12¼")

Minimum 1.04 - 1.10

30 - 40Raise to

45+prior tocasing

N/C Spud with gel spud mud. Maintain volume with water addition. Native clays should aid viscosity. Maintain pH at 9 - 10. Raise viscosity with polymer prior to casing.

240 – TD

216mm (8½")

1.14 – 1.31or as

required to

control formatio

n pressure

35 – 45 Initially +/ 10ccs,

then down to6 - 8 by

the Evergre

en

Drill out with water. Displace to 3-4% KCl- PHPA mud. Maintain the pH at 9 - 9.5 with Caustic Soda. Add oxygen scavenger to 100 ppm Sulphite. The system should be maintained with pre mixed mud only. Adjust density to 1.14 SG prior to Mooga and1.2 SG prior to wiper trip. Increase to 1.26 SG by upper Tinowon and 1.31 SG prior to the lower Tinowon. Run the finest shaker screens and all other solids control equipment to keep the low density solids toa minimum. Add biocide as required.

NB: Additions of any diesel or hydrocarbon based chemicals MUST be first discussed with the wellsite geologist and Wellsite Representative and approved by the Manager, Conventional Drilling. Subsequently, such additions must be fully documented.



10. CASING AND CEMENTING DETAILS AND DESIGN

Table 8: Casing Details and DesignSTRINGDETAILS CONDUCTOR* SURFACE

CASINGPRODUCTION

CASINGHole Size 445 mm (17½") 311 mm (12¼") 216 mm (8½")Casing Size 406 mm (16") 245 mm (958") 140 mm (5½")Setting Depth 12 m 240 m 2146 mGrade K55 N80Weight 53.69 kg/m (36 lb/ft) 25.30 kg/m (17

lb/ft)Strength Burst psi Collapse psi Tension lbs

35202020

564,000

77406280

348,000Safety Factor Required Actual Load Design

Conductor pipe only

1.15/1.0/1.61500/376/162,53

62.34/5.37/3.47

1.10/1.0/1.65000/2190/176915

1.55/2.87/1.97

Design Assumptions Burst

Collapse

Tension

Conductor pipe only

Pressure test @ 3M

Cement w/ 1.0SG displace fluid Drilling with1° dogleg severity

Pressure test @ 4.5M

Cement w/ 1.0SG displace

fluid Drilling with

1° dogleg severity

Connection BTC LTCOptimum Torque

- 3480 ft-lb

Float Equipment

Float shoe, NR float collar one

joint offbottom

Float shoe, float collar one joint off bottom

Wiper Plugs Top and bottom NR

Top and bottom

CentralisingAt mid 1st joint and

at 2nd and 4th collars above shoe

At mid 1st joint, 2nd

and 4th collars and each collar 20 m

above and below any potential pay

zones

Accessories 279 mm (11") 5K x 245mm (9⅝") casing head

279 mm (11") x 140 mm (5½") slip and

sealassembly

ThreadlockShoe through to 1st connection

Shoe through to 1st

connection above



abovefloat collar

float collar

BOP Test Pressure

1500 psi 5000 psi

Note: Surface casing is to be spaced out and landed so that the top of the ‘A’ section flange is approximately ground level.



Table 9: Cementing Details

SURFACE CASING PRODUCTIONCASING

Hole/Casing Size 311 mm (12¼")/ 245 mm (958")

216 mm (8½")/ 140 mm (5½")

Setting Depth 240 m 2146 mCement Type Lead – Class A with 6% Gel

Tail – Class ALead – Class A with 8% Gel

Tail – Class G, Fluid Loss Additive

Cement Top Class A to SurfaceClass A/Gel to 220 m

(~ 20 m above Casing Shoe)

Class G to 300 m above Rewan (~ 1528 m)

Excess 100% in open hole 15% in open holeEstimated Sacks

Yield

Basis of Calculation

430 Class A

Class A: 1.18 cu

ft/sack Gauge +

100%

590 Class A / Gel 470 Class

G

Class A/Gel: 1.92 cu ft/sack Class G: 1.15 cu ft/sack

Gauge + 15%

Slurry DensityTail – 15.6 ppg

Lead – 13.1 ppg Tail – 15.8 ppg

Mix Water Fresh Fresh

AdditivesTBA

Lead 0.5% HR7Tail 1% Halad 322

(to be confirmed on lab test)

Bump Plug Pressure Bump 1000 psi above final pumping pressure. Test to 1500 psi

Bump 1000 psi above final pumping pressure. Test to 5000 psi



11. PRESSURE TESTING AND KICK TOLERANCES

Table 10: Pressure Testing Requirements for BOPs

EQUIPMENT PRESSURE

(psi)

TIME(minute

s)

PRESSURE

(psi)

TIME(minute

s)

SURFACE CASINGCasing, Blind Rams, HCR 250 15 1500 15Choke Manifold

Rear Valves 250 5 1500 5Mid Valves 250 5 1500 5Front Valves 250 5 1500 5

Pipe Rams 250 15 1500 15Annular Preventer 250 5 1500 5Kelly Cocks 250 5 1500 5Kill Line Valves 250 5 1500 5

A BOP Pressure Test Checklist shall be completed and submitted to Brisbane office together with any relevant pressure recording charts.

Note:1. Initial pre drill-out testing is to be conducted against the casing2. Subsequent BOP tests will be performed using the cup tester



Table 11: Kick Tolerance Calculations



Note:1. An FIT of 18ppg EMW will provide positive kick tolerance to drill to the hole

section TD, where the weakest point is at the casing shoe and a swab kick is taken from a lower Tinowon reservoir sand. Assumption is that 10.9 ppg balances the formation pressure, including a safety margin.

2. The largest swab kick that can be circulated out of the hole without breaking down the formation at the surface casing shoe is 5 bbl. Calculations show that a similar 5 bbl kick could only be contained at the Mooga Sandstone level if the formation strength is greater than 13.8 ppg. This is assumed to be unlikely based on regional experience, and hence there is no chance of breaking down the formation at the shoe as leak-off into the Mooga will occur at a lower pressure. Given these circumstances the kick tolerance is acceptable.

3. LOT/FITs were conducted to 20.5 ppg EMW at 227 m on Myall Creek 8, 18.9 ppg EMW at 237 m on Myall Creek 7, 24 ppg EMW at 265 m on Myall Creek 3 and 20.2ppg EMW at 227 m on Myall Creek 4.



12. ABANDONMENT

Should there be no significant hydrocarbon indications, the well will be abandoned by setting cement plugs in the open hole and at the surface, as per guidelines in Table 11. Emphasis will be placed on isolating permeable formations.

A 73 mm (2-7/8”) tubing stinger with a mule shoe shall be used to set abandonment plugs.

The shoe plug shall be tagged and pressure tested.

Table 12: Indicative Abandonment Programme

Plug No.

Formation Depth Sacks of Cement

8 Surface Surface to 10m

15

7* Surface Casing Shoe 210m to 270m 70

6 Gubberamunda Sandstone

730m to 790m 70

5 Hutton Sandstone 1300m to 1360m

70

4 Basal Evergreen 1600m to 1660m

70

3Showgrounds ( if any indication

of hydrocarbons)1790m to

1850m70

2 Basal Rewan Sand 1900m to 1960m

70

1 Tinowon Fm 2020m to TD 150

* Test for position The final plugging program will be advised after wireline logs have

been run and evaluated.

ABANDONMENT WILL NOT COMMENCE WITHOUT APPROVAL FROM THE BRISBANE OFFICE.



13. COMMUNICATIONS

13.1. Origin Phone Numbers

Communication to the Joint Venture participants will only take place through Origin's office in Brisbane.

Operations Contact:

Brendon Jones (Drilling Operations Supervisor/Snr Drilling Eng)

Office Telephone (07) 3858 0600Direct Telephone (07) 3858 0635Office Facsimile (07) 3369 7840Electronic Files (07) 3367 3090E mail [email protected]

After Hours Operations Mobile

0429 998 089

13.2. Daily Reports

Daily reports covering 0000 - 2400 hours, transmitted by 0700 hours Eastern Standard Time, to the Brisbane Office. These reports will be sent to the following e-mail address:

[email protected]

13.3. Origin After Hours Contact Telephone Numbers

Mark Fleming (Field Services) Mobile 0427 262244Dave JONES (Mngr, Conventional Drilling & Completions) (07) 3878 4784, Mobile 0418 717 886

13.4. Emergency Reporting Numbers

Name & Position Work Home Mobile1. Drilling Operations Supervisor – 24 HRS on call 0429 998 0892. Dave Jones

Manager - Conventional Drilling

07 3858 0622

07 3878 4784

0418 717 886

13.5. Origin Offices

OFFICE

Phone: Fax:

1 Origin Brisbane 07 3858 0600

07 3369 7840

2 Origin Surat (Kincora Plant)

07 4626 8188

07 4646 8186

3 Origin Roma 07 4622 07 4622



2244 2969



13.6. Emergency Response Numbers

Surat Roma

All Emergencies 000Not available from sat

phone

000Not available from sat

phoneHospital: 07 4626 5166 (24hrs) 07 4624 2700 (24hrs)Ambulance: 07 4626 5368 (BH)

Toowoomba 07 4632 1133 (24hr)

07 4622 1202 (BH)

Police: 07 4626 5200 (BH) 07 4622 9333 (BH)

SES: Refer to Roma 07 4622 2188 /0417 642 831 (A/H)

RFDS: Charleville 07 4654 1443 Rockhampton 07 4931 7198

13.7. Government Contact Details

Government

Number

Department of Natural Resources and Mines LandcentreCnr Main & Vulture Streets Woolloongabba QLD 4102 Australia

Reports to be emailed to: [email protected]

(07) 3237 1491 (phone)(07) 3237 1534 (fax)

Andy KozakQld DNR&M Gas & Petroleum Emergencies 0419 888 575

13.8. Contractor Contact Details

Company Contact Work Facsimile A/H

Century Drilling 07 3879 3333

07 3879 3322

0419 846 102

Darren Thompson

Ops Mgr Rig 7

07 3879 3333

07 3879 3322

0437 934 437

Damien Fellows

HSE

07 3879 3333

07 3879 3322

0428 768 715

Flower Earthmoving Steve Flower 07 4626 8393

07 4626 8125

0427 623 384

Halliburton Australia Paul Larkins 07 4622 4588

07 4622 3674

0418 832 884

Rheochem Michael Bartsch 08 93318281

08 93318283



Roma Transport Ian Forbes 07 4622 5222

07 4622 4822

0411 455 397

Geoservices Leigh Foreman 08 8186 3611

08 8186 2611

0419 847 734

Precision (Reeves) Matt Barnes 07 3482 9900

07 3881 0005

0417 646 754



Well Specifications CardWELL NAME : Ogilvie Creek 1 WELL TYPE : Exploration AFE No. : 070

ADMINISTRATION LOCATIONINTERESTS : % LICENCE : ATP375POrigin Energy Ltd 100.00 LATITUDE : 27 0 2 ' 53.86 " S

LONGITUDE :EASTING : (GDA94)

149 0 14 ' 9.51 "721 781

E

NORTHING : (GDA94)SEISMIC INLINE:

7006247250

XLINE: 327GROUND LEVEL :(Est) 244.00 metres

249.28 metres244.00 metres

-1897.0 metres AMSL

2146.3 metres R.T.Century #7

ROTARY TABLE :(Est)SRD :PROPOSED T.D. (AMSL) :PROPOSED T.D. (R.T.) :RIG :

NEARBY FACILITIES/WELLS :TOTAL % 100 "Closest point from THIS well"

OBJECTIVES STRATIGRAPHIC PROGNOSISFORMATION DEPTHS DEPTHS

Primary : m AMSL m R.T. FORMATION m AMSL m R.T.

upper Tinowon sandstone -1810.0 20 .3 Wallumbilla Formation 244.0

Bungil Formation -42.4 291.7Mooga Sandstone* -182.0 431.3Orallo Formation -366.6 615.9Gubberamunda Sandstone* -508.0 757.3Westbourne Formation -628.0 877.3Walloon Coal Measures* -824.0 1073.3Hutton Sandstone -1076.9 1326.2Evergreen Formation -1275.7 1525.0Boxvale sonic marker* -1319.0 1568.3Boxvale sandstone -1320.2 1569.5basal Evergreen -1373.7 1623.0Moolayember Formation -1381.4 1630.7Snake Creek Mudstone -1548.4 1797.7Showgrounds Sandstone -1565.1 1814.4Rewan Group* -1579.0 1828.3basal Rewan Sandstone -1674.2 1923.5Bandanna Formation* -1693.0 1942.3Black Alley Shale -1762.4 2011.7Winathoola Coal Member* -1774.0 2023.3Tinowon Formation* -1786.0 2035.3

Secondary : m AMSL m R.T. upper Tinowon sandstone* -1810.0 2059.3basal Rewan sst -1674.2 1923.5 Wallabella Coal Member* -1824.0 2073.3lower Tinowon sandstone -1844.3 20 .6 lower Tinowon sandstone -1844.3 2093.6

Basement -1867.0 2116.3* Geophysical picks.

-1897.0 2146.3TOTAL DEPTHFORMATION EVALUATION MISCELLANEOUS INFORMATION

MEASUREMENTS DEVIATIONWIRELINE LOGGING TOP BASE SPECIFICATIONS Surveys to be taken every 150m to monitor drift. Corrective

action to be taken if deviation exceeds 50m target radius.GR-DLS-MLL-CSS-SP-CALS PDS-CNS-SGS-TACDipole Sonic (MDA)

SCSSnake Crk Snake Crk

TD TD TD

GR to surface.Firm Firm

MDT/RFT/FMT 20 points Contingent

MUDLOGGING Yes OTHER INFORMATIONThis well will be drilled, logged and cased to total depth using a mud system.CORING None

FORMATION TESTS

DST over Upper Tinowon and secondary objectives contingent on gas shows, sandstone development, and log evaluation (on- penetration or post logging).EXPLANATIONS / JUSTIFICATIONS REMARKS / RECOMMENDATIONS

VELOCITY SURVEY

NoneTotal depth is planned for 30m into basement (minimum 27m required). Casing to TDdependant on log evaluation. Dipole Sonic to be run in 3 modes:1) 1st motion detection2) P&S3) Upper Dipole

SWCs None

RFTsYes - 20 points contingent on hole condition, shows and logevaluation.

CHECKED & AGREED

DRILLING MANAGER TEAM LEADER: