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Queensland ATP795 P Bowen/Surat Basin

Lacerta-44

Well Proposal

Originator: Mark Di Bacco Reviewed: Approved:

Issue Date: Revision: Total Pages: 35

Regulatory Input:

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Table of Contents

1 WELL DATA......................................................................................12 EXECUTIVE SUMMARY.................................................................23 BACKGROUND.................................................................................34 SAFETY...............................................................................................55 TECHNICAL.......................................................................................6

5.1 Environmental Setting.................................................................................65.2 Offset Wells...................................................................................................85.3 Drilling Rationale.........................................................................................85.4 Geophysical Prognosis..................................................................................85.5 Geological Prognosis....................................................................................95.6 Location Rationale........................................................................................95.7 Well Evaluation..........................................................................................10

5.7.1 Mud Logging and Sampling.....................................................................................105.7.2 Coring.......................................................................................................................105.7.3 Core Evaluation........................................................................................................105.7.4 Wireline Logging......................................................................................................105.7.5 Checkshot..................................................................................................................105.7.6 Testing.......................................................................................................................10

6 DRILLING PROGRAM..................................................................116.1 Drilling.........................................................................................................11

6.1.1 Drilling Contractor requirements..............................................................................136.1.2 Sunshine Gas Requirements.....................................................................................13

6.2 Drilling Fluids Program.............................................................................146.3 Testing Program.........................................................................................14

6.3.1 Gas Flow testing.......................................................................................................146.3.2 Drill Stem Testing.....................................................................................................14

6.4 Casing Program..........................................................................................146.4.1 Surface Casing..........................................................................................................166.4.2 Production Casing.....................................................................................................166.4.3 Production Casing Running Procedure.....................................................................16

6.5 Cementing Program...................................................................................186.5.1 Surface casing...........................................................................................................186.5.2 Production Casing.....................................................................................................18

6.6 Wellhead Design.........................................................................................216.7 Blowout Preventer Equipment..................................................................226.8 Additional Information..............................................................................22

6.8.1 Under Reaming.........................................................................................................226.8.2 Gas Flow Testing......................................................................................................22

7 Completion Program........................................................................237.1 Work Outline..............................................................................................237.2 Operations...................................................................................................23

7.2.1 Rig up Operations.....................................................................................................237.2.2 Post Drilling Cleanout..............................................................................................23

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7.2.3 RIH Work string and Circulate.................................................................................247.2.4 RIH Completion String with PCP.............................................................................247.2.5 RIH Rod String.........................................................................................................247.2.6 RU Wellhead and RD Operations.............................................................................257.2.7 Well Preparation for Handover.................................................................................25

7.3 Equipment Requirements – SHG Supplied.............................................267.4 Equipment Requirements – Contractor Supplied...................................27

8 Personnel............................................................................................28APPENDIX A: Reporting Procedures and Contact Numbers..........29APPENDIX B: Rig 101 Specification Sheet.........................................31APPENDIX C: Rig 101 Site Layout.....................................................32

List of TablesTable 1: Previous wells drilled in ATP 767P and ATP 795P..............................................................4Table 2: Geological Prognosis.............................................................................................................9Table 3: Plug closing pressures..........................................................................................................20

List of FiguresFigure 1: Lacerta Location Map...........................................................................................................6Figure 2: Lacerta Aerial Photo Map.....................................................................................................7Figure 3: ATP 767P and ATP 795P Remnant Vegetation Map...........................................................7Figure 4: Stratigraphic Column............................................................................................................9Figure 5: Proposed well design schematic.........................................................................................15Figure 6: Packer inflation pressure readings......................................................................................20Figure 7: Plug Diagrams.....................................................................................................................21Figure 8: Wellhead Design.................................................................................................................21

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Elevation K.B:

Ground Level:

1 WELL DATA

Well Name: Lacerta 44

Well Classification: Appraisal

Country/ State: Queensland

Permit: ATP 795P

Basin: Surat Basin

Operator: Sunshine Gas Limited

Permit Interests: BNG (Surat) Pty Ltd (100%)

38km northeast of Roma

Location:

Spud Date: November 2007

Drilling Contractor: Mitchell Drilling

Drilling Rig: Mitchell Rig 101

Primary Objective: Walloon Coal Measures

Proposed TD: 630m

Latitude: -26° 19’ 15.88” South GDA 94Longitude: 149° 02’ 13.38” EastEasting: 703 332 MGA Zone 55Northing: 7 087 155Datum: GDA94 / MGA Zone 55

436.2m

435m ASL

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2 EXECUTIVE SUMMARY

The primary objective of Lacerta 44 is to evaluate the CSG productivity of the Jurassic Walloon Coal Measures in the area north of Roma. The Walloon coal measures are known to be gas productive in the eastern side of ATP 795P. Lacerta 44 is part of a four well program to be drilled in the eastern region of the permit ATP 795P.

Production wells are to be drilled slightly underbalanced using freshwater in order to minimise fluid invasion whilst drilling. Post drilling and logging, selected coal seams will be under-reamed to approximately 16 inches diameter. Pre perforated 7” production casing will be run over the target seams of the Walloon Coal Measures.

Sunshine Gas Limited (SHG) is the Operator of permit ATP 795P in the Surat Basin, Queensland. SHG will manage the drilling and testing of Lacerta 44.

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3 BACKGROUND

ATP 795P is located approximately 30 kilometres north of the Roma. Sunshine Gas Limited holds a 100% working interest in ATP 795P via a wholly owned subsidiary BNG (Surat) Pty Ltd. The permit overlies the western Bowen and Surat Basins, immediately to the north of the Roma Shelf, and adjacent the sunshine permit ATP 767P

Exploration in the local area was primarily initiated in 2005 in the northern Roma Shelf. Subsequent drilling in this area reinforced the prospectivity of the Walloon Coal Measures in the western Surat Basin, and provided a forward step towards gas production from the Walloon Coal Measures. Production drilling at the Lacerta and Coxon Creek areas followed. These wells demonstrated strong positive results with good to exceptional gas and water flow rates. Lacerta 43, 44, 45, and 46 are designed to capitalise on these results.

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Table 1: Previous wells drilled in ATP 767P and ATP 795PWell Name Date

DrilledOperator TD

(m GL)Status Comment

Solitary Creek 7 1929 ARO 1100 P&A Conventional Gas/OilMooga 1 1930 ARO 1087 P&A Conventional Gas/OilMt Beagle 1 1969 AAO 940 P&A Conventional Gas/OilNiella Northwest 1 1971 SUE 1145 P&A Conventional Gas/OilConn Creek 1 1987 CSR 916 P&A Conventional Gas/OilEldorado 1 1990 AGL 825 P&A Conventional Gas/OilTallawalla 1 1991 AGL 1144 P&A Conventional Gas/OilLacerta 2 2006 SHG 409 Monitoring CSG Core HoleLacerta 3 2006 SHG 577 Monitoring CSG Core HoleLacerta 4 2006 SHG 427 Suspended CSG Core HoleLacerta 5 2006 SHG 436 Producing Well CSG Production HoleLacerta 6 2006 SHG 433 Producing Well CSG Production HoleLacerta 7 2006 SHG 433 Producing Well CSG Production HoleLacerta 8 2006 SHG 434 Producing Well CSG Production HoleLacerta 9 2007 SHG 420 Suspended CSG Core HoleLacerta 10 2007 SHG 588 Monitoring CSG Core HoleLacerta 11 2007 SHG 420 Monitoring CSG Core HoleLacerta 12 2007 SHG 414 Suspended CSG Core HoleLacerta 13 2007 SHG 414 Suspended CSG Core HoleLacerta 14 2007 SHG 542 Suspended CSG Production HoleLacerta 16 2007 SHG 467 Suspended CSG Production HoleLacerta 18 2007 SHG 453 Suspended CSG Core HoleLacerta 19 2007 SHG 423 Suspended CSG Core HoleLacerta 20 2007 SHG 484 Suspended CSG Production HoleLacerta 21 2007 SHG 522 Suspended CSG Core HoleLacerta 22 2007 SHG 460 Suspended CSG Production HoleLacerta 23 2007 SHG 542 Suspended CSG Production HoleLacerta 24 2007 SHG 473 Suspended CSG Production HoleLacerta 25 2007 SHG 465 Suspended CSG Production HoleLacerta 26 2007 SHG 465 Suspended CSG Production HoleLacerta 27 2007 SHG 465 Suspended CSG Production HoleLacerta 28 2007 SHG 473 Suspended CSG Production HoleLacerta 29 2007 SHG 465 Suspended CSG Production HoleLacerta 30 2007 SHG 435 Suspended CSG Production HoleLacerta 31 2007 SHG 486 Suspended CSG Core HoleLacerta 32 2007 SHG 402 Suspended CSG Core HoleLacerta 36 2007 SHG 414 Suspended CSG Core HoleLacerta 37 2007 SHG 528 Suspended CSG Core Hole

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4 SAFETY

All operations considered in the course of drilling these wells shall be in accordance with the safety requirements specified by the following documents, copies of which will be available at the well site.

• The Petroleum and Gas (Production and Safety) Act (2004)

• Sunshine Gas Limited Health, Safety & Environment Bridging Document to the Mitchell Drilling “HS&E Management Plan”

• Mitchell Drilling Emergency Response Plan

• Mitchell Drilling “HS&E Management Plan”

Material Safety Data Sheets (MSDS) for all products that are to be used will be available at the rig (MSDS to be supplied by Mitchell Drilling).

Prior to the commencement of operations, new personnel will report to the Company Man (or person in charge of the site) for a Site Induction and complete the relevant Site Induction Form.

Such procedures shall be adhered to at all times and take into account the health, safety and welfare of all personnel engaged in all operations. The procedures shall also take into account environmental considerations and minimise the impact and/or release of effluents/contaminants to the environment.

Joint safety meetings will be held with all involved personnel prior to each major activity. The meetings should be noted on the daily report.

Job Safety Analysis (JSA) sessions will be applied for routine as well as for non-routine activities with a significant risk component, with written record made of subject discussion points and attendees.

BOP and Pit Drills will be held as specified in the Well Control Plan.

Pipe Rams and Annular Preventer are to be operated daily and Pipe Rams whenever the drilling, string is out of the hole, and their usage recorded in the tour book. The BOPs are to be tested at least once per week using the cup tester.

Lacerta 45Lacerta 46

Lacerta 43Lacerta 44

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5 TECHNICAL

5.1 Environmental Setting

Figure 1: Lacerta Location Map

Lacerta 44 is located 38 kilometres northeast of Roma, on the property Mt Hope owned by Mr Leon Price. Head east out of Roma along the Warrego Highway for approximately 32 kilometres then turn left into the Pickanjinnie turnoff (there is a cement turtle on the side of the road). Stay on the Pickanjinnie Road – after being on the Pickanjinnie Road for 15.6km you will reach a cattle grid, Dingo Fence and a T-Intersection – turn left at this T-Intersection. Immediately after this T-Intersection, veer left onto the signed Mt Hope Road. After being on the Pickanjinnie Road for approx. 25km you follow the signed road all the way to the wellsite.

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Figure 2: Lacerta Aerial Photo Map

Remnant vegetation within the immediate vicinity of Lacerta 44 is classed as “Not of concern” (figure 3). Tree clearing in the Lacerta area has been carefully planned so that the environmental impact has been minimised as much as possible.

Figure 3: ATP 767P and ATP 795P Remnant Vegetation Map

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5.2 Offset WellsThe closest well with mappable strata is Lacerta 3 and 13, approximately 1km northwest and southeast respectively.

5.3 Drilling Rationale

The Walloon coal measures are a growing CSG development target within the Surat Basin, and are known to be productive in the nearby Roma Shelf. Recent work in the Lacerta area has demonstrated productive Walloon coal section. Lacerta 44 aims to capitalise on the productive nature of the Walloon coal seams in the already known Lacerta productive area.

5.4 Geophysical Prognosis

Seismic mapping of the Walloon coal measures package indicates that Lacerta 44 lies on a gentle ramp shallowing northward from the Roma Shelf. There are no seismically visible structures in the local area.

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5.5 Geological Prognosis

The stratigraphy anticipated in Lacerta 44 is annotated below:

Table 2: Geological PrognosisAge Formation Depth (mKB) Depth SS (m)Jurassic Gubberamunda Sst Surface +435mJurassic Injune Creek Group 180m +255mJurassic Walloon Coal Measures 210m +225m

TD 615m –180mNOTE: Do not drill into the underlying Hutton Formation Aquifer.

Figure 4: Stratigraphic Column

5.6 Location Rationale

Recent work in the eastern Lacerta area has demonstrated a productive Walloon coal section. Lacerta 44 aims to capitalise on the productive nature of the Walloon coal seams in the already known Lacerta area.

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5.7 Well Evaluation

5.7.1 Mud Logging and Sampling

Mudlogging contractors will not be utilised in the drilling of Lacerta pilot program. The cuttings will be sampled and described as deemed appropriate by the wellsite geologist. Any samples to be taken are to be placed in disposable plastic cups and stored out of harms way. The wellsite geologist will wash and dry these samples and place them in labelled calico bags for later storage at the Sunshine Gas premises in Roma.

5.7.2 Coring

No cores are proposed to be cut in this well.

5.7.3 Core Evaluation

No cores are proposed to be cut in this well.

5.7.4 Wireline Logging

A basic suite of wireline tools will be run in Lacerta 44, consisting of Gamma Ray, Density, Resistivity, Temperature and Caliper. These tools will be run from TD to surface. If no temperature log is recorded, a Bottom Hole temperature must be noted in the Las file header

5.7.5 Checkshot

No checkshot survey is planned for this well.

5.7.6 Testing

Lacerta 44 will be production tested once the well has been fully completed.

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6 DRILLING PROGRAM

Prior to the commencement of operations, new personnel will report to the SHG Company Man. All personnel will be required to complete the relevant site induction form and other induction procedures.

Operations carried out during this drilling program shall at minimum be in accordance with and comply with the relevant legislation, IADC guidelines and the drilling contractor’s procedures manuals.

Such procedures shall be adhered to at all times and take into account the health, safety and welfare of all personnel engaged in all operations. The procedures shall also take into account environmental considerations and minimise the impact and/or release of effluents/contaminants to the environment.

Joint safety meetings will be held with all involved personnel prior to each major activity (eg spudding in, cementing, and commencement of coring). The meetings should be noted on the Daily Drilling Report.

Job Safety Analysis (JSA) sessions will apply for routine as well as for non-routine activities with a significant risk component, with written record made by the rig manager of subject discussion points and attendees.

The pipe should be strap measured out prior to any logging or testing.

6.1 Drilling

The following sections outline the drilling program to be followed for the drilling of the Development Wells. Minor changes to the drilling program by on-site personnel may be made in consultation with SHG representatives. Any major changes to the program must be approved by SHG Brisbane office.

1. The access roads and lease pad will be cut and prepared for as per the rig lease layout supplied by Mitchell Drilling, meeting all safety and environmental standards. (see appendix 1) Ensure earthwork contractors have liaised with drilling personnel so that the lease diagram is appropriate for the operation being conducted. No permanent cellar is to be used. All wellhead equipment will be above ground level.

2. Mobilise drilling rig on to location and rig up rotary tools.3. Hold pre-spud safety meeting outlining the overall drilling scenario, well control issues,

emergency response plan, designated first aid personnel, emergency muster points, smoking/hot work areas, and location of first aid kits and fire extinguishers.

4. Perform pre-spud rig inspection5. If required drill surface hole and set conductor into competent formation.6. Make up 12 1/4” bit and BHA and drill 12 1/4” hole to 80m with water or polymer mud.

The 80m depth is a pre-drill estimate only, and will be altered accordingly out in the field. Do not blindly drill to the above depth, the wellsite geologist will be monitoring cuttings around this depth, and will pick the casing point out on site. At TD circulate hole clean and POOH in preparation for running casing.

7. Move rig off hole and move over crane to RIH 9⅝” casing8. Pick up float shoe and run 9 5/8” casing to TD as per Casing Program Section 6.4.1

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9. Cement 9 5/8” casing annulus to surface as per SHG cementing program (Section 6.2.) Mix and pump slurry, drop wiper plug and displace to float shoe. Do not over-displace. Release pressure and check for flowback, if float is not holding, shut well in at surface with final displacement pressure.

10. Top up cement in casing annulus if necessary. Wait on cement and install tee piece with Blow-out Preventer. The cement surface samples must be adequately set before the casing is to be released. A guideline time of 8 hrs curing time is suggested. Release crane and move rig back over hole.

11. Install drilling spool, Blowout Preventer, flow tee and kill and choke line connections and valves. Connect kill line to mud pump, choke line to choke manifold, mud return and flare line. Pressure test surface casing, BOP, choke manifold and kill line to 500psi. Hold for 10 minutes. Record the results in Daily Drilling Report. After satisfactory test, proceed with drilling.

12. Run in hole with 8 1/2” bit, drill collars on drill pipe. Ensure stabbing valve is readily available for drill pipe connection during all drilling operations.

13. Ensure cement samples are set. Drill out float shoe and cement. Clean cement contamination from mud system.

14. Condition water/mud system to drill formation. – Refer to Drilling Fluids Program (Section 6.3.)

15. A methane gas detection system is to be operational whilst drilling the Walloon Coal Measures. Readings should be continuously monitored so as to detect the buildup of potentially dangerous methane levels. Adequate access to the blooie line is also required for cuttings sample collection.

16. Drill 8 1/2” hole and monitor cuttings and ditch gas continuously. If required by the geologist, drill 1 or 2 metres into new formation and perform a leak off test.

17. Drill through Walloon Subgroup to total depth (to be called by wellsite geologist.) Flow checks are to be regularly conducted, with any gas flows measured by the flow prover (see section 6.6.2 for details.)

18. Circulate hole completely clean of cuttings and cavings. Once there are no appreciable amounts of cuttings emanating from the blooie line, a wiper trip up to the casing shoe must be performed. During the wiper trip, any tight spots must be taken note of, and worked with the drill pipe until the hole is adequately free of any potential downhole blockages. Circulate hole on bottom for a minimum of 1.5 hours. Ensure mud weight is below 9ppg and viscosity is below 40 sec/qt. Perform a flow check, and proceed to POOH

19. Run wireline logs as per section 5.7.4. The type and order of tools to be run downhole is to be decided by the wellsite geologist and the wireline logging contractor. Paper prints and digital LAS files are to be provided to the wellsite geologist, and their quality confirmed before the wireline logging contractor is to leave site. Ensure a BHT is recorded.

20. Perform a flow check on the well. If gas flows occur, the rate of flow should be recorded using the flow prover and any water and gas samples taken (see section 6.6.2)

21. Identify coal seams which are to be underreamed from the wireline log information. The decision as to which coals are to be selected is to be made by Sunshine Gas staff (wellsite geologist and the staff in the Brisbane office)

22. Perform underreaming on the identified coals using the harvest underreaming tool. The diameter to which the coals are to be underreamed is nominally 16-24 inches, and this is to be confirmed by the wellsite geologist immediately prior to commencement of underreaming operations. During underreaming, a continuous injection of water must be maintained. For additional information, see section 6.6.1.

23. Perform a flow check on the well. If gas flows occur, the rate of flow should be recorded and water and gas samples taken (see section 6.6.2)

24. Rig down drilling rig and prepare for crane to move over hole to run 7” production casing. Release rig.

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25. Run 7” K-55 LTC 23# Range 3 casing string as per the casing program to be supplied onsite by the wellsite geologist. The casing shoe is to be landed as near as practicable to PBTD.

26. Position top of casing collar at 300mm (1ft) above ground level with landing joint.27. Install 7” cementing head, and cement casing as per the cementing program detailed in

Section 6.5. Ensure cement samples are taken28. Once cement samples have set, slack off and remove landing joint.29. Rig down BOP.30. Ensure a cover is installed over the wellbore to prevent objects falling in.31. Install and secure wellhead, suspend well for future completion32. Release crane and all service contractors.33. Demobilise rig. Perform any immediate housekeeping and rehabilitation activities at

wellsite.

6.1.1 Drilling Contractor requirements

9 5/8” circulating head and 9 5/8” casing accessories Adequate mud pump capacity for efficient drilling and pumping and displacement of cement Drill bits as required Under reamer and accessories Appropriate casing handling equipment Rig capacity to enable a crane (placed adjacent to the drilling rig) to run range 3 casing

downhole (13m lengths) Daily drilling reports to be made available to the wellsite geologist by 8:00am daily Site clean up before the rig moves off site Mudweight scales and viscosity funnel

6.1.2 Sunshine Gas Requirements

Access roadways and lease preparation Water supply 9 5/8” casing 7” casing and accessories 7” casing cementing contract services Geological services Wellsite supervision and reporting services Logging contract services Drill stem testing services Flow prover, orifice plates and appropriate fittings

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6.2 Drilling Fluids Program

Lacerta 44 is to be drilled to TD with a basic freshwater mud system. Additives such as liquid polymer should be added in consultation with the wellsite geologist. The mud stsyem is to be monitored on at least a daily basis to ensure the mudweight and viscosity never exceeds 9.0 ppg and 40 sec/qt respectively. If any of these properties are exceeded, then freshwater should be added to dilute the mud mixture and bring the mud properties in line.

When the TD of the well is reached, a complete wiper trip is required to ensure that no bridges will be encountered by the wireline logging tools. The mud weight and viscosity are to be adjusted to ensure that they are not greater than 8.7ppg and 40 sec respectively.

Note: while adjusting mud conditions, it is recommended to proceed gradually, avoiding large changes in one step only. With shallow wells, having sufficient water stored on site is important to achieve a successful job.

6.3 Testing Program

6.3.1 Gas Flow testingOccasional flow testing may be ordered by the wellsite geologist to establish the flow potential of a geologically significant zone. If this is the case, the wellsite geologist will instruct the drilling crew for assistance in conducting the flow test. The wellsite geologist will be monitoring pressues through the flowprover and will instruct the drilling crew when the test is to be ceased. For further information regarding gas flow testing and procedures, refer to section 6.9.2.

6.3.2 Drill Stem TestingOccasionally, Sunshine Gas will request a drill stem test (DST) over a specified zone of interest. If testing is scheduled, then refer to separate testing procedures to be drawn up in the Brisbane office and made available at the wellsite.

6.4 Casing Program

Type Size Setting DepthSurface Conductor 14” 6mSurface Casing 9 5/8” 80mProduction Casing 7” 630m (TD)

Note: Setting depths are preliminary, and will be refined slightly once the well is being drilled and geological prognoses are amended.

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Figure 5: Proposed well design schematic

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6.4.1 Surface Casing

9⅝” casing will be set as surface casing to the depth detailed in Section 6.4. The guide shoe and bottom two joints of casing are to be thread-locked (epoxy or weld). Centralisers are to be run above the float shoe with a stop collar and across joints 3-4.

6.4.2 Production Casing

7” production casing will be run to the depth detailed in Section 6.4, and will be cemented from above the External Casing Packer (ECP) to surface by the cementing contractor. A casing guide shoe or notched collar is to be run on the bottom of the casing.

Perforated casing is to be run across the target seams of the Walloon Coal Measures.

The Packer Cementing Collar (PCC), consists of an ECP below a stage cementing tool, and will be placed above the Top Coal Seam to ensure isolation from the shallower aquifers.

Joints immediately above the guide shoe, float equipment and packer are to the thread locked.

The casing is to be centralised with the bottom centraliser run directly above the float shoe. The SHG representative on site will indicate the positioning of remaining centralisers, which will be approximately one per casing joint over the target coal seams, and one every three joints back to surface.

The top of the 7” casing collar is to be set 300mm above ground level.

6.4.3 Production Casing Running Procedure

Leaving the BOP (or annular only) nipple up to the surface casing, release drilling rig. Rig Down drilling rig & move off location. NOTE: the drilling rig KOOMEY unit must

remain connected to the BOP until the crane KOOMEY unit is connected to BOP. This will ensure well control at all times.

Move in Crane Casing Package & Rig Up. Spot cat walk & pipe racks. Rig up required casing equipment. Connect crane KOOMEY so the rig KOOMEY can be released. Function test BOP & casing tong.

Load racks with casing. NOTE: The ideal situation would be for Wild Desert to strap & tally when we load the truck, then it can be transferred directly from truck to racks. Truck to wait until completion of job & return any casing or well equipment to ensure lease remains tidy.

Make up casing shoe, packer, stage tool & other required components on the catwalk. This way when the running of casing starts there are no stoppages to make up downhole components.

Commence RIH casing as per the correct space out. Make up landing jnt set casing @ required depth. Rig up cement circ head & Cement

Contractor surface lines. Chain down casing landing jnt to BOP. Break circulation to ensure good hole condition.

Hold Pre Job safety Meeting involving all contractors onsite. Pressure up to inflate casing packer. Continue to pressure up to open stage tool. Circ 2 bbls

to ensure good communication through tool & returns @ surface (see details on ACP procedures in section 5.5.2).

Pump required cement volume. Install wiper plug & pump displacement. NOTE: should be good cement returns @ surface.

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Pressure up on casing to close stage tool. Close cement head valve & monitor pressure to ensure no leak off.

Rig down surface lines & release Cement Contactor. Maintain pressure & monitor cement samples.

WOC. Bleed off pressure in casing. Rig down Cement Head. Break out landing jnt. Nipple down BOP. Top up casing with cement. Cut & bevel casing, install 7 1/16 B-Section & nipple up. Install

side outlet valve to ensure well secure. NOTE: well is now ready for workover rig 7 1/16 BOP.

Ensure all left over well components & casing is loaded out on Wild Desert truck & returned to laydown yard. Ensure well site clean & free from rubbish.

Release Crane Casing Package.

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6.5 Cementing Program

6.5.1 Surface casingCement returns to surface are expected during cementing of surface casing. If however, cement losses occur some time after the initial cement returns, the drilling supervisor and the geologist will decide whether a top-up cement job with or without various additives be added from the surface.

6.5.2 Production Casing

Equipment

A Model 754 Stage Cementing Tool furnished with a 754 Shut-Off Plug & Baffle and a ClosingPlug can be run above one or more Annulus Casing Packers (ACP’s) for multiple stage cementing. Conventional, automatic fill, or differential fill float equipment may be used below the Shut-Off Baffle. A 754 Landing Collar with shut-off baffle is required for threads other than 8-round or Buttress. Use of a bypass plug ahead of the first stage cement is optional.Refer to the specification chart or sheet for information concerning the dimensions, plugs, and ratings of each stage tool. Information on stage tools with Buttress or 8 Round connections are charted for the most common sizes and weight ranges. Specific specification sheets are provided with the stage tool for any variation not listed in the chart (i.e. premium connections, different material grades or weight ranges.)

Inspection

Inspect Stage Tool and auxiliary equipment upon arrival at location. Check Stage Tool for dents, damaged threads, etc. Check the Closing Plug to verify that it will seat properly in Stage Tool Ascertain that the Shut-Off Plug Nose O.D. is smaller than the Stage Tool Seat I.D.’s and will seat properly on the landing baffle, and that the Screw-In Baffle, or Landing Collar, threads match the casing threads. Verify that the cementing head contains no foreign plugs or objects. If plugs are to be pre-loaded, verify that the plug release mechanism is operable and sufficient to retain the plugs. Also verify that cementing head has a means, such as an equalizing channel or standpipe, to prevent the top cup of the cementing plug from forming a vacuum against the top cap, this could prevent the cementing plug from launching. Verify that the appropriate numbers of shear screws are installed in the hydraulic sleeve to achieve the desired opening pressure and that tool opening pressure does not exceed casing internal yield pressure or casing hardware ratings. Verify that the maximum OD of the stage tool and ACP are less than the drift of the prior casing and hole size. Set ACP inflation pressures according to manufacturer’s recommendations at a safe level above maximum expected cementing pressures.

Note: Stage Tool opening pressure should exceed by at least 700 psi the maximum differential pressure expected across the tool while circulating, when activating ACP’s, liner hangers or auto- fill equipment, and while cementing. High differential pressures often occur during first stage cementing when the casing above the tool is filled with cement or when the first stage cement is displaced. Do not exceed safe internal pressure ratings of the casing and cementing equipment.The production casing is to be cemented by the cementing contractor using the following procedure:

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After drilling to TD and conditioning hole, proceed with appropriate logging programs (callipered hole size is critical). Determine from open hole logs desired position for ACP(s).

Install the landing collar with Shut-Off baffle at desired location in casing string. Note: Install insert baffle with taper facing up.Note: Remove “knock-off” pins from ACP prior to installation; they may cause the shut-off plug not to land properly in the landing baffle.

While running casing, install the ACP(s) then the 754 Stage Cementing Tool at the desired location in the casing string. The Stage Tool can be positioned directly above the ACP as following sequence.

o Float Shoeo Shoe jointso Float Collaro Required joints of casingo Weatherford Annulus Casing Packer (ACP)o Weatherford Stage Tool – 754HOo Handling Subo Required casing to surface

Note: Do not place tongs on any part of the Stage Tool or packer element. Land casing and circulate to condition hole.

Note: 754 Shut-Off Plug and Closing Plug can be pre-loaded in plug container only if retaining mechanism is sufficient to retain plug in cementing head. It is recommended that a positive plug release indicator (tattle tail, flag, etc.) be used but only if it does not interfere with the sealing ability of the plug fins.

Mix and pump first stage cement (if applicable). Drop 754 Shut-Off Plug on top of first stage cement and pump displacement fluid. (Cement

lines may be washed before displacement.) Pump calculated amount of displacement fluid. Lower pump rate to 2 to 3 bpm just prior to

landing the 754 Shut-Off Plug on the baffle.o Always record flow rate and pressure required to pump plug prior to bumping.o The Shut-Off Plug may be pumped through the stage tool at flow rates of up to 10

bpm. When the plug lands, allow the pressure to slowly increase to 50% to 75% of the calculated

ACP opening pressure and hold that pressure for 2 to 5 minutes. Record volume in displacement tank.

Pressure up to 300psi, record volume in the displacement tank, increase surface pressure to balance pressure plus rated differential shear pin pressure in 200psi increments, holding each step 2 minutes, until reaching opening pressure. Stop pumps and note pressure decrease indicating valve action. If no pressure decline, increase pressure by 200psi or as needed to open valve. Record volume in displacement tank.

Inflate the ACP by sequentially increasing surface pressure and monitoring pressure decline as the packer inflates. Record volume in displacement tank after each increase in surface pressure.

Note: Once the packers are fully inflated, surface pressure will stabilize and not decline. Record the volume in displacement tank. The inflation chart should look similar to the picture below.

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Figure 6: Packer inflation pressure readings

Bleed surface pressure to pressure recorded at Step 9 and record flow back for net inflation volume calculation.

Re-apply pressure to casing until stage tool opens (Refer to specifications furnished with tool for stage tool opening pressure). Surface pressure required to open tool is equal to the specified stage tool opening pressure less the internal static pressure at the tool (casing fluid height in ft. X density in ppg X .052) plus the annular static pressure at the tool (annular fluid height in ft. X density in ppg X .052).

When stage tool opens, establish circulation to condition hole, then mix and pump second stage cement. (If optional pump-down opening plug is used as a spacer, release it ahead of the second stage cement.)

After pumping cement, release Closing Plug and verify that plug has left cementing head. (Cement lines may be washed before displacement.)

Note: Verify you are pumping through the stage tool by comparing to circulation pressure recorded when the Shut-Off Plug landed.

Pump calculated amount of displacement fluid to seat Closing Plug in Stage Tool.Note: The Closing Plug should be landed at a flow rate in barrels per minute (bpm) equal to one- half the casing diameter, in inches, up to a maximum of 8 bpm and a minimum of 3 bpm.

When Closing Plug seats, continue pumping until the pressure indicated below in psi over displacement pressure is achieved. These are minimum pressures in excess of displacement pressures; higher pressures may be required as needed. (Do not exceed safe limits of casing or cement head.)

Table 3: Plug closing pressures

TOOL SIZE CLOSING PRESSURE (PSI)4-1/2” thru 5-1/2” 15006-5/8” thru 10-3/4” 120011-3/4” thru 13-3/8” 1000

16” thru 20” 800Hold this pressure for 1 to 5 minutes

Check to determine whether the Stage Tool has closed by releasing pressure and observing the volume of fluid bleed-back.

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3-1/2” EUE TUBING

If excessive and continued bleed-back is observed, "run into" the Stage Tool with a higher pump rate and/or pressure. Check again for closure as above. (Do not exceed safe limits of casing or cement head.)

Options: If excessive bleed-back continues with no drop in surface pressure after several attempts to close the stage tool, or if the pressure drops off when applying pressure to the closing plug, it is recommended that the casing be shut-in at the surface after releasing 50’ to 100’ of cement back into the casing. (This could be a result of a casing leak. The cement may seal off the leak path.)

Figure 7: Plug Diagrams

SHUT-OFF PLUG AND BAFFLE

CLOSING PLUG

*** DROP PLUGS IN ORDER AS SHOWN FROM LEFT TO RIGHT ***All 754 2-stage tools are supplied with this plug set unless otherwise specified. Premium

connection tools will be supplied with a landing collar (not shown).

6.6 Wellhead Design

Figure 8: Wellhead Design

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6.7 Blowout Preventer Equipment

Rig 101 is equipped with a 9” x 3000psi Reagan annular, drilling spool, choke manifold and 3 station Koomey accumulator.

6.8 Additional InformationInformation in this section is to be read in conjunction with section 6.0 of this report.

6.8.1 Under Reaming

Under reaming is an operation that increases the effective wellbore diameter at a discrete productive zone. The goal is to widen the effective wellbore so as to intersect a greater number of fractures in the targeted coal seam, therefore increasing production from that coal.

Water will be used as the circulating fluid whilst under reaming. Drillers must not be aggressive with this tool. The rpm required to under ream should be gradually increased to the maximum recommended guideline for the tool. The torque should be constantly monitored so as to avoid putting too much strain on the under reamer. Excessive treatment will result in the under reaming tool’s arms bending and not being able to close properly, leading to the tool being stuck when attempting to trip out of the hole.

6.8.2 Gas Flow Testing

A gas flow test can be called by the wellsite geologist, usually once the well has finished drilling and the final circulation is being conducted. Gas kicks are not uncommon while drilling the Walloon Coal Measures. If such a gas kick occurs, the wellsite geologist may order a gas flow test. It is important to ensure the well is significantly clear of cuttings before a flow test commences.

In order to initiate a flowtest, the well should be “unloaded” or circulated free of cuttings. Once the well is clear of cuttings, circulation is to be ceased and a flow check done. Quite often after a period of circulation an isolated gas kick will cease. However, if the well is still flowing a considerable rate of gas, then a flow test can be commenced.

After the flow check confirms a gas flow, the BOP is to be closed and the choke manifold opened through the flareline. This way, any gas flows from downhole can be diverted and vented through the flare line. On the end of the flare line, a flowprover should be set up with an appropriately sized orifice plate. The pressure behind the orifice choke should be monitored, along with the size of the orifice choke. Monitoring is to continue until a pressure has stabilised. A minimum pressure of 15psi is to be read on the flowprover pressure gauge in order to produce a meaningful flow rate. If the pressure is below 15psi, then a smaller orifice plate should be fitted to the flowprover and the test re-done.

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7 Completion Program

The following sections outline the completion program to be followed to clean out the development wells post drilling and complete with downhole PC pumps and rods. Minor changes to the completion program by on-site personnel may be made in consultation with SHG representatives. Any major changes to the program must be approved by SHG Brisbane office.

7.1 Work Outline

Install wellhead RIH with drill string and 6 1/8” bit Drill out Packer Cement Collar and Float Collar RIH to TD and circulate clean POOH drill string RIH work string with jetting tool and float Jet with air across perforated intervals RIH to TD and circulate clean with air POOH work string RIH completion string with PCP RIH rod string RU wellhead and drivehead RDMO location with rig

7.2 Operations

7.2.1 Rig up Operations

Hold toolbox meeting to discuss completion programme. Ensure all rig crew are inducted to SHG policy

Prepare flare pit for rig operations (based on blooie line direction) Ensure tanks are clean and filled with water. Rig up blooie line Install tubing hanger wellhead, 7” LTC with 7-1/16” 3000# top flange Rig up pump line to standpipe and return line with choke from annulus to mud tanks.

Ensure all pump lines are pressure tested to 500 psi

7.2.2 Post Drilling Cleanout

Nipple up BOP with blooie line diverter. Function test BOP Pick up 6-1/8” bit with junk basket on 3-1/2” drill string with drill collars (bit will require

12,000-18,000 lbs of drilling weight to drill out packer cementing collar) Ensure stabbing valve for drill string is readily available on rig floor Tag Packer Cementing Collar (approx depth 175 mKB) Install circulating head and drill out collar. Drill at least 40-60 rpm (never exceed 100 rpm)

and use a pump rate that will circulate cuttings without decreasing bit weight on the target (approx 5 – 6 bpm)

Continue to RIH to float collar (approx depth 290 mKB)

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Drill out float collars. Drill at least 40-60 rpm (never exceed 100 rpm) and use a pump rate that will circulate cuttings without decreasing bit weight on the target (approx 5 – 6 bpm)

RIH to 7” casing guide / TD and circulate until clean returns Rig down circulating head POOH with bit

7.2.3 RIH Work string and Circulate

Ensure stabbing valve for work string is readily available on rig floor Pick up jetting tool with float on work string Carefully RIH to above perforated casing interval (to be advised), blowing hole dry at 200

mKB Install circulating head and jet with air across perforated intervals Circulate with air for a minimum of 15 minutes per joint or until clean returns RIH to TD and circulate until clean returns Rig down circulating head Load hole with fresh water and POOH jetting tool Observe well

7.2.4 RIH Completion String with PCP

RIH 1 joint of 3 ½ ” EUE, J55, 9.3#, R-2 tubing as tailpipe with the 10’pre-perforated joint on the bottom with a mule shoe or bull plug.

Pick up pump assembly and RIH:o 3 ½” EUE 7” csg no turn toolo 3 ½” 2ft pup jointo 3 ½” EUE nippleo BMW PC Pump Stator (3-1/2” connections)o 3-1/2” 6ft pup joint

RIH pump assembly on approximately 35 joints of 3-1/2” EUE, J55, 9.3#, R-2 tubing, setting the top of the pump at approximately 290 mKB, and the end of the tail pipe at 377 mKB (subject to change by SHG)

Note: Torque settings: 2-7/8” – 1650 ft-lbs3-1/2” – 2280 ft-lbs

Measure distance from rig floor to top of wellhead hanger and mark on landing joint Land tubing in wellhead using a 3-1/2” EUE pup joint and ensure tubing hangar is seated Observe well before removing BOP

7.2.5 RIH Rod String

Remove BOP. Install flanged Rod-lock Composite pumping tee on tubing hanger Install rod stripper (contractor owned) above composite unit and adjust rig floor Ensure an annulus return/flare line is available and open Pick up rotor with pony rod. Ensure rotor is thoroughly greased RIH with rotor on 1” rods, Type Norris 97 (115k psi yield), c/w SH couplings. Should

require approximately 36 rods

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Two-rod guides to be placed on each rod except that immediately above the pump (no rod guides). Rod guides to be placed approximately 2 feet from collar

Tag pump tag bar Space out rods using 1” pony rods to allow 6” (max 24”) stick up on polished rod above

drivehead with the rotor 12” off tag bar. Pull up further to allow for rod stretch-operating position

Ensure any burrs or rough spots on the polished rod have been filed off and install the 36ft polished rod

Rest rotor on tag bar. Recheck stick up Ensure polished rod is greased where exposed

7.2.6 RU Wellhead and RD Operations

Remove rod stripper. Install drive head. Protect stuffing box packing using a thread protector on polished rod threads. Stuffing box packing is to be no more than hand tight and to be thoroughly greased before installation

Pick up rod string and clamp polished rod Operate rods with rig tongs to check that the pump is operating correctly Pressure test wellhead to 100 psi and check for leaks Bleed off test pressure Begin rig down

7.2.7 Well Preparation for Handover

Reclaim flare pit Prepare well site for operations, installing LPG bullet and gas engine Hook up wellhead fittings, production flow lines and flare line as advised by SHG onsite

representative Start up pump at 50 rpm and ensure fluid to surface. Monitor for leaks Install site fence and safety signs Hand back well to SHG Operations Release rig

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7.3 Equipment Requirements – SHG Supplied

Item Qty DescriptionCompletion1 1 3-1/2” EUE J55, 9.3#, 2ft pup joint2 1 3-1/2” EUE pin x 2-7/8” EUE pin x-over3 1 No turn tool 3-1/2” box x pin for 7” csg4 1 3-1/2” EUE nipple5 1 PCP BMW 120-600 (stator)6 1 3-1/2” EUE J55, 9.3#, 6ft pup joint7 2 3-1/2” EUE collars8 35 3-1/2” EUE J55, 9.3#, R-2 tubing joints9 1 3-1/2” EUE J55, 9.3#, R2 10’ pre-perforated pup joint10 1 120-600 1” rotor11 40 25ft x 1” Type Norris 97(115Ksi Yield) rods with SH collars12 10 1” Rod collars (spare)13 80 1” x 3” Rod guides for 3-1/2” tbg14 1 2ft x 1” pony rod, type Norris 97 (for rotor pick up)15 1 4ft x 1” pony rod, type Norris 9716 1 6ft x 1” pony rod, type Norris 9717 1 8ft x 1” pony rod, type Norris 9718 1 36ft 1-1/4” polished rod19 1 rotor clamp (for rotor pick up)20 1 7/8” x 1” collar x-over (rods to polished rod)21 45 2-7/8” EUE J55 6.5# R-2 tbg for workstring (2nd hand)22 1 2-7/8” jetting toolWellhead23 1 7” pin LTC by 7-1/16” 3000# flange, with a 3-1/2” EUE tbg

mandrel, and 2” NPT outlets. Ring gasket R-45.24 1 Flanged composite rod BOP with Flow Tee (7-1/16” 3000# and

3-1/8” 3000#). Ring gasket R-31.25 set Wellhead fittings and valves26 1 Polished rod clamp27 1 OilLift Drive head w/ stuffing box28 1 Gas Engine and Hydraulic power unit29 1 LPG bullet and fittings30 5 2-7/8” tbg joints for flare line (2nd hand)31 Set Flow prover and pressure recorder

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7.4 Equipment Requirements – Contractor SuppliedThe contractor shall provide all equipment and materials necessary to complete the works detailed in the programme (excluding equipment specified in Section 2.0), including but not limited to:

Item Qty DescriptionOperational1 1 6-1/8” long tooth drill bit2 1 2-7/8” float valve for air circulation3 1 Pressure gauge 0-500psi, ½” NPT4 1 2” NPT x ½” NPT xover5 Set 3-1/2” Drill collars (min 12,000 lbs-18,000lbs)6 Set 2-7/8” or 3-1/2” drill string (+/- 600 m)7 Set Air package equipment (min 2 x 350 psig, 900 scfm compressors

+ 1 booster compressor for 1000 psig)8 Set 180 Bbl mud tank9 Set 5-6 Bbl/minute rated mud pump10 1 Junk basket for 3-1/2” DP and 7” csg11 Set Pressure control equipment ( BOP etc)12 Set Stabbing valves for all strings (eg 2-7/8” & 3-1/2” tbg)13 Set Rod stripper/BOP14 Set Blooie line, cement blocks and safety tie-downs

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8 Personnel

The SHG Company Representative is the senior site representative and is responsible for ensuring that the operational procedures contained within this document are conducted in a safe and environmentally sound manner. The Drilling Supervisor is responsible for ensuring that all personnel participating in the project receive a suitable site induction prior to commencement of activities at the site.

During the drilling, personnel shall comprise of two crews, each working 12 hour shifts to allow drilling and evaluation operations to be carried out on a 24 hour day / continuous basis; and one Drilling Supervisor to provide overall rig and personnel supervision on behalf of Mitchell Drilling.

The wellsite geologist will be responsible for geological evaluation and reporting according to QDNRM regulations and SHG requirements.

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APPENDIX A: Reporting Procedures and Contact Numbers

Daily ReportingA Daily Drilling Report (DDR) and below ~250m a daily geological report (DGR) will cover the previous 24 hour period to 24:00 hours, with a status report for 06:00 next day. The reports will be faxed or emailed to SHG by 08:00 hours each day. An update on depth and operation will also be sent to SHG by 16:00 hours each day.

Operations Contact Details

Drilling Operations Sunshine Gas Limited

Exploration Manager: John Phillips Telephone: 07 3221 4400GSM Mobile: 0402 322 730Email: john.phillips@sunshinegas.com.au

Queensland Government

Queensland Department of Natural Resources and Mines Podium 2, Ground FloorLand Centre BuildingCnr Main & Vulture Streets Woolloongabba Q 4102 Contact: Andy Kozak Telephone: 07-3238-3739Facsimile: 07-3405-5409After Hours: 04-1772-9512, 07-3237-1415 (John Fleming) Email: andy.kozak@nrm.qld.gov.au

Landholder Contact Numbers

Name: Jim and Rosemary Humphries Telephone:Mobile:Email:

Drilling Contractor: Mitchell Drilling

Rig Manager: Phil SpencePhone: 07 3376 7577Fax: 07 3376 2806Mobile: 0428 873 824Email: p.spence@mitchelldrilling.com

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Rig Supervisor: Eric Kennedy & Lewis PepperPhone:Fax:Mobile: 0428 754 751Email: rig101@mitchelldrilling.com

Wireline Logging: Precision Energy Services Coal Seam Wireline ServicesPhone: 07 4622 5303 (Roma) 08 9244 4882 (Perth)Fax:Attn: Tony Hill Stuart Power (Dalby)Mobile: 0401 304 606Email: tony.hill@ap.weatherford.com 0429 955 344

Civil Works: TW EarthworksPhone: Wayne and Tim ColleyAttn: Wayne ColleyMobile: 0427 274 510Attn: Tim ColleyMobile: 0429 234 128Email: tos16722@bigpond.net.au

Roma Operations Support:

Wild Desert Oilfield Services: David WhylieTelephone: 07 4622 6004Facsimile: 07 4622 6003Mobile: 0428 755 946Email: david@wilddesert.com.au

Roma Equipment Hire Attn: RobAddress: 182 Mitchell Rd Roma 4455Phone: (07) 4622 2875Fax: (07) 4622 6783

Emergency Contact Numbers:

For all emergency services, please phone 000

Roma HospitalAddress: 197-234 Mc Dowall Street ROMA Qld 4455 Phone: (07) 4624 2700

Roma Police StationPhone: (07) 4622 9333

Queensland Fire and Rescue Service (South Western Region)Phone: (07) 4639 9106

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APPENDIX B: Rig 101 Specification Sheet

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APPENDIX C: Rig 101 Site Layout