Background

Falcon Oil & Gas Australia Limited (“Falcon Australia”) is a 98% owned subsidiary of Falcon. Falcon Australia holds 22.5% interest in 4.6 million gross acres in exploration permits EP76, EP98 and EP117 covering the most prospective core area of the Beetaloo Sub-basin.

The Beetaloo Sub-basin is located in the Northern Territory, 600 kilometres south of Darwin, close to infrastructure including a highway, a pipeline and a railway, offering transport options to the Australian market and beyond via liquefied natural gas (LNG) capacity in Darwin to the north and in Queensland to the east.

The sparsely populated and remote Beetaloo Sub-basin is a relatively underexplored onshore basin of Proterozoic age within the larger McArthur basin. It has excellent unconventional hydrocarbon potential such as shale gas, shale oil and tight gas.

Work was previously undertaken by a Rio Tinto Group subsidiary company, Sweetpea Petroleum, Hess Australia and Falcon Australia. Sweetpea drilled the Shenandoah-1 vertical well, which was deepened by Falcon Australia. Hess acquired 3,490 kilometres of 2D seismic data, to date the largest onshore 2D seismic program in Australia. The seismic database, along with existing well data, provided a solid platform to elaborate and extrapolate a detailed structural and stratigraphic model for the Beetaloo Basin, concluding that the Beetaloo Basin is an active petroleum system.

Location of the Beetaloo JV permits in the Northern Territory, Australia.

Transformational Farm Out of Beetaloo unconventional acreage

In August 2014, Falcon Australia completed a A$200 million, nine-well farm-out deal with Origin Energy and Sasol each farming into 35% of Falcon Australia’s exploration permits. In May 2017, Origin acquired Sasol’s interest, bringing its overall interest to 70% in the Beetaloo JV. Origin is operator of the Beetaloo project.

In August 2018 Falcon signed an agreement to amend the Farm Out Agreement with Origin, to deem Stage 1 of the exploration and appraisal drilling programme in the Beetaloo Sub-basin complete and to commence Stage 2 with a A$15 million increase to the Stage 2 Cost Cap.

On 7 April 2020 Falcon announced that Falcon Australia had executed an agreement which included a restated Farm-Out Agreement and Joint Operating Agreement (collectively “the 2020 Agreements”) with Origin to farm down 7.5% of Falcon Australia’s 30% PI in the Exploration Permits.

Transaction details

  • With the necessary approvals, the PI of the respective JV partners will be:
    • Falcon Australia 22.5%
    • Origin 77.5%
  • In consideration of Falcon Australia transferring 7.5% of its PI, Origin increases the gross cost cap of the work program by A$150.5 million.
  • The previous farm-in arrangement included a Stage 2 gross cost cap of A$65.3 million and a Stage 3 gross cost cap of A$48 million, or A$113.3 million in total. Under the 2020 Agreements, the Stage 2 and Stage 3 gross cost caps will be combined and increased by A$150.5 million to A$263.8 million (“Overall Cost Cap”).
  • This Overall Cost Cap will be applied to the completion of the Stage 2 and Stage 3 work programmes.
  • Amounts of the Overall Cost Cap not utilised during Stage 2 and Stage 3 will be applied to future work programmes.
  • Expenditure above the Overall Cost Cap will be borne by the JV partners in proportion to their PI.
  • Origin will assume 25% of the cost of Falcon Australia’s remaining call option to reduce the overriding royalties with the TOG Group.

Work Programme

The Beetaloo JV has a 3 stage work program to explore and appraise the asset with the following main objectives:

Stage 1  Prove the presence, quality and continuity of the Velkerri shale play
Stage 2  Evaluate the potential of liquids fairways in the Velkerri and Kyalla shale plays
Stage 3  Confirm commercial production rates and EURs in most prospective play

Stage 3 – Work Program Overview

Falcon provided details of the Stage 3 work programme on 4 May 2022.

As noted in Falcon’s press release published on 25 January 2022, 2022 will see Falcon and Origin progressing to the Stage 3 work programme of the restated Farm-Out Agreement. Following discussions with Origin, in order to maximise the impact of Stage 3 operations the joint venture has agreed to modify the Stage 3 programme announced previously, which will now include a step out location for one well.

Stage 3 Planned Work Programme includes:

  • Acquisition of a 58km line of high spec 2D seismic on the Amungee NW-1H well lease area;
  • Drilling one ~1,000 metre horizontal well on the Amungee NW-1H pad, targeting the Amungee Member (formerly knowns as the Middle Velkerri) B Shale;
  • Step out location approx. 10km from the Amungee NW-1H pad, drilling a vertical pilot and a ~1,000 metre horizontal well also targeting the Amungee Member B shale;
  • 15 stage fracture stimulation on both horizontal wells;
  • Extended production testing of between 90 and 180 days on each well;
  • As previously announced there will also be:
    • follow up core and log analysis of the very encouraging preliminary evaluation of the 2021 Velkerri 76 well results; and
    • further evaluation of the results of the Kyalla 117 N2-1H well to better understand the issues encountered during testing in 2021.

Stage 3 Drilling and 3D Programme Objectives:

  • The primary objective of the two wells is to:
    • Obtain a production rate over the first 30 days of between 2-3 MMscf/d to support a multi-well pilot programme in 2023/24.
  • Secondary objectives for the Stage 3 programme are to:
    • Achieve a drill duration of less than 45 days;
    • Characterise natural fracture network and complexity; and
    • Integrate well data with seismic data and assess merits of future 3D seismic surveys in the Beetaloo.

Stage 2 – Explore & Appraise Additional Play Types

The Stage 2 exploration and appraisal drilling program was designed to evaluate the potential of the liquids rich gas fairways in both the Kyalla and Velkerri shales to determine the most commercially prospective play to be targeted during Stage 3.

Amungee NW-1H  

09 August 2021 – Falcon announced the commencement of production testing operations at Amungee NW-1H (“Amungee”). On-site operations at Amungee had begun with all equipment on site and preparatory works complete.  A production test was underway to determine whether all eleven frack stages contributed to the initial extended production test in 2016.

On 3 September 2021 Falcon provided the results of the production log test at the Amungee well. The results suggest a normalised gas flow rate equivalent of between 5.2-5.8 MMscf/d per 1,000m of horizontal section.

  • The well was successfully put back on production testing on 7 August 2021.
  • Initial flow rates during the first 48 hours of testing ranged between 2 – 4 MMscf/d with rates averaging 1.23 MMscf/d over the first 23 days.
  • A production logging tool (“PLT”) was run on 19 August 2021 to 3,098mMD, just prior to the casing deformation at 3,112mMD.
  • The PLT data confirms that:
    • Only 5-15% of the production came from stages 1-7 beyond the casing deformation point at 3,112 mMD.
    • 85-95 % of the production came from stages 8-11 spanning a 200m horizontal section, prior to the casing deformation.
  • The low contribution from stages 1-7 is likely the result of a restriction caused by the casing deformation or the plugs having not milled out, or both.
  • Conclusion: stages 8-11 may be representative of the deliverability that can be achieved within the Middle Velkerri B Shale at Amungee.
  • The PLT test results equate to a normalised gas flow rate of between 5.2-5.8 MMscf/d per 1,000m of horizontal section.
  • A typical future production well would be likely to have a horizontal production section up to three kilometres.
  • The result validates the decision to undertake a second EPT in order to run a PLT.

Velkerri 76 S2-1 

Falcon announced the spudding of the Velkerri 76 S2-1 well (“Velkerri 76”) on 12 August 2021. Velkerri 76 would target the Velkerri play along the south-eastern flank of the Beetaloo Sub-Basin, which is predicted to be in a liquids rich gas window.

The principal objectives for the drilling of Velkerri 76 are to:

  • drill a vertical pilot well to acquire core and log and conduct a diagnostic fracture injection test data across the Velkerri;
  • penetrate the Velkerri formation to assess hydrocarbon maturity, saturation and reservoir quality;
  • provide further information on the areal distribution of the Velkerri formation; and
  • collect data for potential future horizontal drilling, completion, stimulation and production testing, including ability to flow liquids rich gas.

Falcon announced that drilling of the Velkerri 76 vertical appraisal well was completed on 15 October 2021, with the well drilled to a vertical total depth (“TD”) of 2,129 metres with JV partner Origin.

Preliminary evaluation of the Velkerri-76 well was very encouraging and confirmed:

  • The presence of four prospective intervals within the Amungee Member (formerly known as the Middle Velkerri), the A, AB, B and C shales, as established in the Amungee NW-1 / 1H, Beetaloo W-1 and Kalala S-1 wells.
  • The continuation of the regionally pervasive Amungee Member within the Velkerri Formation towards the eastern flank of the Beetaloo Sub-Basin approximately 78 kilometres from the Amungee NW-1H and 73 kilometres from the Beetaloo W-1 wells.
  • The Amungee Member is likely within the wet gas maturity window as evidenced by mud gas data during drilling.

93 metres of continuous conventional core was acquired in the Velkerri B and AB shales and extensive wireline logging data was collected to enable detailed formation evaluation of the prospective zones within the Amungee Member. The diagnostic fracture injection test (DFIT) is to be carried out shortly and will provide further understanding for future appraisal of the Velkerri wet gas play.

Falcon provided details on the preliminary petrophysical interpretation and mud gas composition data from Velkerri 76 on 12 November 2021.The preliminary petrophysical interpretation of the Velkerri-76 wireline logs has now been carried out, which has confirmed positive indications in particular from the B shale of the Amungee Member (formerly known as the Middle Velkerri). Other intervals within the Amungee Member, also show positive indications, and further analysis will now be undertaken to confirm these results.

The Amungee Member B shale was the principal area of focus with Falcon’s operations at Amungee NW-1H and the results obtained to date compare very favourably to some of the most commercially successful shale plays in North America.  The Amungee Member B shale is also the focus of activities in the neighbouring Santos and Empire Resources operated blocks.

Mud gas composition data also provides evidence that the Amungee Member is within the wet gas maturity window and contains good LPG yields and high heating gas value.

Key information with respect to the preliminary petrophysics and mud gas composition of the Amungee Member B shale are included in the table below:

Amungee Member B Shale
Gross thickness (metres) 53.9
Total Porosity Ave. (%BV) 7.7
Total organic carbon Ave. (TOC, %wt) 4.3
C(mol%) 79.65
C2 (mol%) 16.49
C3+ (mol%) 3.86

The results of preliminary petrophysical interpretation confirm:

  • The prospectivity of the Amungee Member B shale.
  • Reservoir quality of the B shale (TOC, porosity and gross thickness) compares strongly with commercial shale plays in the United States.
  • The Velkerri 76 S2-1 well provides yet another robust data point for the joint venture to consider various commercialisation options across its permits.

Additional analysis of the conventional core acquired during the drilling of Velkerri 76 will be required to confirm the preliminary petrophysics interpretation outlined above and will take place over the coming months.

Laboratory analysis of gas samples collected during drilling will be carried out to further refine gas composition data within the Amungee Member shale intervals.

Kyalla 117 N2-1H S2  

Spudding of the Kyalla 117 N2-1 appraisal well in the Beetaloo Sub-Basin took place on 9 October 2019 with completion of drilling of the vertical section to a vertical total depth of 1,895 metres announced on 20 November 2019.

On 10 December 2019 Falcon announced that drilling of the horizontal section of the Kyalla 117 N2-1H appraisal well in the Beetaloo Sub-Basin, Australia had commenced, along with the advancement of the vertical well evaluation.

Drilling of the horizontal production hole section with a target length of 1,000 to 2,000 metres, commenced in early December, however, after reaching a horizontal length of 700 metres, operational challenges were experienced in maintaining adequate clean hole conditions and stability over portions of the horizontal production hole section appropriate to complete operations.

On 13 January 2020 it was announced that the initial horizontal production hole section would be plugged in line with regulatory requirements and would be followed by sidetracking and drilling a new horizontal production hole section. The commencement of the sidetrack to drill the new horizontal production hole section of the Kyalla 117 N2-1H ST2 (“Kyalla 117“) took place on 30 January 2020 with drilling operations, including casing and cementing successfully completed by 20 February 2020.The well was drilled to a total measured depth of 3,809 metres, including a 1,579 metre lateral section (from 90 degrees) in the Lower Kyalla Formation.

Following the implementation of the necessary control procedures Falcon announced that the JV elected to temporarily pause activities at the Kyalla 117 site given the unprecedented circumstances brought about by COVID-19, reducing those on site to essential personnel only, whilst ensuring the required regulatory and environmental management conditions to monitor and maintain the site can be met.

By 21 September 2020 operations had recommenced at Kyalla 117 with the fracture stimulation of the well. A technical update provided on 2 October 2020 confirmed the completion of 11 hydraulic stimulation stages along the 1,579-metre horizontal section in the Lower Kyalla Formation with the successful execution of stimulation treatments.

As announced on 4 November 2020, flowback operations of the fracture stimulation fluid commenced in early October before Kyalla 117 was shut in and production tubing was successfully installed, with flowback operations recommencing in late October. Kyalla 117 continued to flow back fracture stimulation fluid, with some gas shows; however, a measurable gas breakthrough that would allow the commencement of extended production testing to assess the extent of the resource that may be present had yet to occur.

Data collected and analysed to guide ongoing operations showed greater pressures in the horizontal section of Kyalla 117 than in the surrounding reservoir, due to the saline content and density of the flowback fluid and the hydrostatic column weight of this fluid in the vertical section. This pressure difference could prevent the flow of gas from the reservoir into the fractures and then to surface and it is not unusual in shale plays to observe the salinity and density of the flowback fluid to increase as salt easily migrates from the formation.

The JV decided by 10 December 2020 to execute operations without delay with all of the necessary equipment and consumables for the nitrogen lift being prepared to mobilise to the well site. The coiled tubing unit and all necessary consumables had arrived at the wellsite and the rigging up of the equipment was in progress by 24 December 2020.

19 January 2021 Falcon announced that Origin had submitted a notification of discovery and an initial report on discovery (“Notification of Discovery”) to the Department of Industry, Tourism and Trade of the Northern Territory (“DITT”) on the Kyalla 117. The Notification of Discovery is a requirement under s64(1) of the Petroleum Act 1984 (Northern Territory) and the NT Guidelines for reporting a petroleum discovery.

Details of the Notification of Discovery from Origin to the DITT are as follows:

  • The Notification of Discovery is supported by preliminary production test data and petrophysical modelling.
  • This follows the introduction of nitrogen to lift the fluids in Kyalla 117, which has enabled Kyalla 117 to flow unassisted for a period of seventeen hours.
  • Unassisted gas flow rates ranging between 0.4-0.6 MMscf/d over seventeen hours were recorded.
  • Flow back of hydraulic fracture stimulation water to surface over the same period, averaged between 400-600 bbl/d.
  • Initial analysis suggests a liquid-rich gas composition with less than 1% CO2.
  • Condensate shows were also observed.

Further Information

  • These early-stage flow rates are preliminary indications of well performance, and an extended production test (“EPT”) will be required to determine the long-term performance of Kyalla 117.
  • Longer-term measures would need to be put in place to flow back sufficient hydraulic fracture stimulation water to allow Kyalla 117 to flow continually without assistance and enable an EPT to continue in the coming months during the dry season.

On 22 January 2021 Falcon announced details on the first gas composition data obtained during the 17-hour unassisted flow period of Kyalla 117.

The initial analysis of natural gas by gas chromatography confirms a liquids-rich gas stream low in CO2 as follows:

  • C1 = 65.03 mol%
  • C2 = 18.72 mol%
  • C3 = 8.37 mol%
  • iC4 = 1.29 mol%
  • nC4 = 2.03 mol%
  • C5+ = 2.73 mol%
  • CO2 = 0.91 mol%
  • N2 = 0.92 mol%

The elevated C3+ gas component of 14.42 mol%, meets pre-drill expectations, confirms the Lower Kyalla Shale as a liquids-rich gas play. Gas composition data also support the view that the Kyalla gas stream will have elevated LPG and condensate yields.

Operations at Kyalla 117 commenced in June 2021 following the wet season.  Activity focused on the continued clean-up of Kyalla 117 in preparation for extended production testing, using nitrogen to support operations. This allowed Kyalla 117 to begin flowing again without assistance for intermittent periods, however, production was not sustained and there was evidence of a potential downhole flow restriction. Operations were temporarily paused while the cause of the restriction investigated, the results of which would inform the development of a go-forward plan for Kyalla 117.

On 14 September 2021 Falcon announced that operations have resumed at Kyalla 117. As noted in the Company’s press release on 20 July 2021, while Kyalla 117 flowed liquids rich gas without assistance for intermittent periods, production was not sustained and there was evidence of a potential downhole flow restriction. Current operations, if successful in resolving the restriction, will result in an extended production test being carried out to determine the expected longer-term performance of the well.

On 14 September, coil tubing operations recommenced at Kyalla 117. No apparent restriction or blockage was identified in the production casing. Following a nitrogen lift, the well was able to flow unassisted at rates between 0 (i.e. rates too small to measure) and 1.5 MMcsfd for five days before loading up with water. Further analysis will be undertaken, including additional core analysis and well design considerations, to enable a conclusion to be reached on the results from operations at Kyalla 117, which will inform the future approach to further drilling and testing of the Kyalla play in the Beetaloo Sub-basin.

On 7 October 2021 Falcon noted that production testing was completed and the well shut in at Kyalla 117.

Full details of the respective updates outlined above can be located under press releases within the investor center -> click here to access

Stage 1 Recap – Successful Initial Drilling Program

Notification of Discovery and Declaration of a Material Gas Resource

Following the completion of the extended production testing at the Amungee NW-1H exploration well of the “B Shale” member of the Middle Velkerri Formation, Origin submitted a notification of discovery and an initial report on discovery (“Notification of Discovery”) to the Department of Primary Industry and Resources of the Northern Territory, Australia (“DPIR”) in October 2016.

Subsequently, in February 2017 it was announced that Origin had submitted the Results of Evaluation of the Discovery and Preliminary Estimate of Petroleum in Place for the Amungee NW-1H Velkerri B Shale Gas Pool (“Report”) to the Northern Territory Government and had also prepared a contingent gas resource estimate.

Middle Velkerri B Shale Volumetric Estimates (1)

 Gross
Best Estimate
Net Attributable
Best Estimate(2)
Area km2 (3)16,1453,564
OGIP (TCF) (4)496109
Combined Recovery / Utilisation Factor (5)16%16%
Technically Recoverable Resource (TCF)8519
OGIP Concentration (BCF/km2) (6)3131

1 The Report and estimates included in the table above were not prepared in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”)

2 Falcon’s working interest is 22.07% (revised as of 7 April 2020 following the farm down, previously 29.43%), net attributable numbers do not incorporate royalties over the permits

3 Area defined by a depth range at a maturity cut-off consistent with the dry gas window within the Beetaloo JV Permits (EP76, EP98, EP117)

4 Trillion cubic feet

5 The combined recovery/utilization factor range was applied stochastically to the OGIP range to calculate the range of technically recoverable resource within the Beetaloo JV permits.

6 Billion cubic feet per square kilometre

Assessment of 2C Contingent Gas Resource Estimates for the Middle Velkerri B Shale Pool within EP76, EP98 and EP117 as of 15 February, 20171

Measured and Estimated ParametersUnitsBest Estimate
Area (2)km21,968
Original Gas In Place (OGIP) (3)TCF61.0
Gross Contingent Resource (4)TCF6.6
Net Contingent Resource (4)(5)TCF1.46

1 Contingent resource estimates were prepared on a statistical aggregation basis and in accordance with the Society of Petroleum Engineers Petroleum Resources Management System (“SPE-PRMS”). SPE-PRMS was developed by an international group of reserves evaluation experts and endorsed by the World Petroleum Council, the American Association of Petroleum Geologists, the Society of Petroleum Evaluation Engineers, and the Society of Exploration Geophysicists. Contingent resource estimates are those quantities of gas (produced gas minus carbon dioxide and inert gasses) that are potentially recoverable from known accumulations but which are not yet considered commercially recoverable due to the need for additional delineation drilling, further validation of deliverability and original gas in place, and confirmation of prices and development costs. If the estimates were to be prepared in accordance with COGEH, Falcon is highly confident that there would be no change to the contingent resource estimates above.

2 P50 area from the Contingent Resource area distribution

3 OGIP presented is the product of the P50 Area by the P50 OGIP per km2

4 Estimated gas contingent resource category of 2C. There is no certainty that it will be commercially viable to produce any portion of the resources

5 Net to Falcon’s 22.07% (revised as of 7 April 2020 following the farm down, previously 29.43%) working interest in EP76, EP98, and EP117, the net contingent resource number does not incorporate royalties over the permits

Full details relating to the above technical recoverable resource and gross contingent resource can be found here.

Plays

In addition to the Velkerri shale dry gas play tested during Stage 1, Origin has identified four additional play types in the Beetaloo Basin:

Kyalla shale and hybrid liquids rich gas plays

  • Two source rock and two hybrid target intervals in Kyalla Fm.
  • Estimated CGR at 15-60 bbl/MMscf
  • Kyalla Fm. prospective areas confined to central part of JV permits
  • Likely cost advantage over the Velkerri given it is shallower (1,500m v’s 2,500m)
  • Likely to be wet gas that could also improve economics considerably
  • Could lead to a ‘stacked’ play development along with Middle Velkerri shales

Velkerri shale liquids rich gas play

  • Liquids rich gas play fairway along the northern and south-eastern flanks at 1,200-2,000 mTVD
  • Good reservoir and completion quality in wet gas window, estimated CGR at 5-40 bbl/MMscf
  • Indications that porosity and permeability are higher in these areas.

Hayfield sandstone oil/condensate play

  • Regionally extensive sandstone in the northern part of permits
  • Tight sand, stratigraphic trapping
  • Penetrated, DST’d in Amungee NW-1 well
Source: Côté 2018