Background

Falcon Oil & Gas Australia Limited (“Falcon Australia”) is a 98% owned subsidiary of Falcon. Falcon Australia holds 30% 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.

The details of the exploration and appraisal programme were as follows:

  • 3 vertical exploration/stratigraphic wells and core studies;
  • 1 hydraulic fracture stimulated vertical exploration well and core study;
  • 1 hydraulic fracture stimulated horizontal exploration well, commercial study and 3C resource assessment; and
  • 4 hydraulic fracture stimulated horizontal exploration/appraisal wells, micro-seismic and 90 day production tests.
  • Farminees to pay the full cost of the following two horizontally fracture stimulated wells, 90 day production tests and micro seismic data collection with a capped expenditure of A$53 million, any cost overrun funded by each party in proportion to their working interest.
  • Farminees to pay the full cost of the final two horizontally fracture stimulated wells and 90 day production tests capped at A$48 million, any cost overrun funded by each party in proportion to their working interest.

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.

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  “Test the Best” – confirm commercial production rates and EURs in most prospective play

Beetaloo JV timeline 2014-2020

Stage 1 – Exploration & Discovery

Stage 1 was completed with the successful drilling of 3 vertical wells and the drilling and the subsequent multi-stage hydraulic fracturing and extended production testing of a horizontal well. The technical work in Stage 1:

  • proved the Middle Velkerri shales as pervasive, stacked play fairways in various maturity windows (dry to wet gas) continuous over >80 km;
  • identified three organic rich shale intervals (A, B & C shales) in the Middle Velkerri sequence;
  • found the gross thickness of Middle Velkerri ~500 m, net pay in B and C shales >50 m each;
  • found an average total organic carbon (“TOC”) 3-4 % in prospective shale intervals along with excellent gas shows;
  • demonstrated excellent reservoir and completion quality;
  • confirmed favourable geomechanics and good frackability of target shales;
  • estimated gas in-place density comparable to successful North American shale plays.

The Amungee NW-1H horizontal well was completed with 11 hydraulic stimulation stages in the 1,000 m long horizontal section within the Middle Velkerri B shale zone. The production well test took 57 days. Early stage gas flow rates through 4 1/2” production casing regularly reached over 1-1.5 MMscf/d. Extended flow test rates through 2 3/8″ production tubing ranged between 0.8-1.2 MMscf/d. Test results in the Amungee NW-1H well proved up the discovery of gas accumulation in the Middle Velkerri B shale.

Location of the JV wells drilled in the Beetaloo permits.
Middle Velkerri correlation across the Beetaloo permits
The stimulated section of the Middle Velkerri B shale in the Amungee NW-1H horizontal well.

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
Area km216,1454,751
OGIP (TCF)496146
Combined Recovery / Utilisation Factor16%16%
Technically Recoverable Resource (TCF)8525
OGIP Concentration (BCF/km2)3131

1 The Report and estimates included in the table above were not prepared in accordance with COGEH

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
Areakm21,968
Original Gas In Place (OGIP)TCF61.0
Gross Contingent ResourceTCF6.6
Net Contingent ResourceTCF1.94

1 Contingent resource estimates have been prepared on a statistical aggregation basis and in accordance with the Society of Petroleum Engineers Petroleum Management System (SPE-PRMS).  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.

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

Additional Plays

In addition to the Velkerri shale dry gas play, considered presently as the most materially and technically mature resource, 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

Stage 2 – Explore & Appraise Additional Play Types

The Stage 2 exploration and appraisal drilling program will 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. Field activities planned for 2019 will include the drilling of one vertical well and the drilling and hydraulic fracture stimulation of two horizontal wells.

An early commitment to Stage 3 capital expenditure during 2019 was also agreed, enabling an efficient transition from Stage 2 to Stage 3, in the case that Origin and Falcon agree to proceed to Stage 3.

Stage 3 – Test the Best

Stage 3 will focus on the most prospective play type identified in Stage 1 and 2 by drilling and hydraulic fracture stimulation of two horizontal wells.