Argonaut's latest report examines existing resources and reserves, supply options, current and future demand, the implications on gas prices and how the basin can play a role in meeting the future gas needs of the state, given the massive changes that are coming down the pipeline as the North West Shelf gas contracts - the backbone of the WA gas market - roll off.
WA is the largest producer of gas in Australia at 1700 petajoules per year, but just 365Pj is sucked into the domestic market for use by households and industry. The balance is sold by the big North West Shelf LNG projects for use in Asia.
Argonaut expects gas prices will rise to between $9-$11 per gigajoule over the next 10 years, driven by further LNG netback gas prices and the fact WA has never been a cheap gas state compared to New South Wales and Victoria, where Cooper Basin and Gippsland Basin gas make an attractive place to explore.
Argonaut estimates the domgas supply from the North West Shelf venture (NWSV) will rapidly decline from 2017, with only 100 terajoules per day from the Persephone field being supplied post-2020, leaving a shortfall of around 470Tjpd.
That will be met by new supply from Chevron's giant Gorgon domgas project (125Tjpd from 2015, rising to 300Tjpd in 2021) while the Wheatstone project is expected to deliver 200Tjpd after 2018-19.
Both gas sources will meet Chevron's need to reserve 15% of all gas reserves for domestic use.
It is questionable if the company would be as keen to spend the money establishing domestic gas supply as every molecule of gas sold into the WA market is lost revenue compared to the LNG prices it would otherwise command.
That's what the NWSV will do after decades of supplying cheap gas to the south down the Dampier-to-Bunbury Natural pipeline, which has supplied most of the state's gas needs, while the rest has typically come from gas produced in the Perth Basin.
These days, around 27Tjpd comes from the Perth Basin, primarily the Beharra Springs and Red Gully fields.
However, the 18Tjpd Beharra Springs is in its final years of production, although quite how long it will continue is a matter for conjecture given its recent strong operational performance, and the recently discovered potential for deeper resources.
Regardless, the hunt is on for reserves replacement close to the capital city.
For the past few years, the major focus has been on the potential for shale gas, but unconventional drilling has issues, not the least of which include high drilling and completion costs, a lack of access to rigs and frack spreads. So the focus has switched to conventional targets and known tight gas fields, and that led to the surprising discovery by AWE and Origin Energy of the Waitsia field last year.
While still to be appraised, early indications are that Waitsia could supply as much as 100Tjpd for up to 10 years, Argonaut predicts. Waitsia has the potential to be the largest onshore gas find in WA for 50 years, leading to what Argonaut calls "the renaissance of the Perth Basin".
AWE inherited its Perth Basin acreage through the takeover of ARC Energy in 2008, having left the basin earlier in the decade in search of bigger prizes. The 3200m-deep Waitsia field had been overlooked due to the lack of larger drill rigs in WA or rigs capable of drilling through the tough overlying shale, but
AWE now says it has the potential to rival the Dongara field, which has produced 500 billion cubic feet out of the total Perth Basin's historical production of 700Bcf.
Argonaut says the Dongara plant will probably need to be rebuilt, increasing its capacity from 48 million cubic feet per day to 100-140MMcfpd.
AWE is certainly talking about fast-tracking the development given the Senecio and Waitsia fields have a combined 360Bcf in recoverable reserves and Irwin-1 added 150Bcf of gas recently.
AWE estimates gross 2C contingent resources of 15Bcf for Irwin and 134Bcf for the adjacent Synaphea structure, and there remains substantial room to grow in the immediate area with the extent of the Kingia formation now confirmed, as well as the potential for the Dongara/Wagina formation.
Argonaut assumes 10 wells will be needed for the first stage of the development, although AWE managing director Bruce Clement has said it's simply too soon to think about numbers.
Drilling of the Waitsia-1 appraisal well in June hints at even further upside, with the gas-bearing High Cliff sandstone thickening to the south. The next well, Waitsia-2, will attempt to assess the southern extent of the field.
AWE also has exposure to the 316Bcf Arrowsmith unconventional field with Norwest Energy, but that remains a longer-term opportunity, likely supporting a standalone gas project.
Long known as one of the basin's penny dreadfuls, Empire has been revitalised following management changes and is actively trying to give its acreage holding a fresh shake. At 8Tjpd, Empire has found itself one of the largest gas producers in the Perth Basin and the largest acreage holder with 12,000sq.km. Its Red Gully 2P reserves and 2C resources stand at just under 30Bcf together with 1MMbbl of condensate.
Argonaut said the company has historically suffered from ineffective management, but with a new team in place, numerous high value defined targets at Gingin West, Gingin East, Bootine and Wannamal, plus upside from its ground adjacent to Waitsia, it was poised to grow.
It will drill the Gingin North-1 well later this year and hope to drill four wells in 2016.
An airborne gradiometric gravity survey is being undertaken to more fully map its underexplored exploration portfolio, which covers almost 50% of the available Perth Basin acreage. The survey will define targets away from the Red Gully field, including the potential of two large north-south trending structures, the Cataby anticline and the Lesueur Horst, both of which have untested oil potential.
There are a string of other plays in the basin, with a mix of granted licences or application areas Empire has paid little attention to in the past.
Besides Origin, AWE and Empire, the balance of the Perth Basin's players are minor, usually one-project shows.
Norwest is actively pushing ahead with two advanced projects in the basin, and hopes to drill the Arrowsmith-3H well next year. It has also defined an oil target, Xanadu, in the coastal permit TP/15 that it is desperate to farm-out.
Xanadu contains a best estimate 160MMbbl of oil in a similar structure to the offshore Cliff Head and onshore Hovea oil fields.
Only one commercial oil field has been discovered offshore, with 60 wells drilled since the 1940s, but hope springs eternal. Recently the Chinese-backed Rey Resources took a position in Norwest, and is in discussions to take an equity stake in the Xanadu well.
Hopefully Norwest will not replicate Murphy Oil, which has drilled three dusters in the offshore area of the basin in recent months. To date, offshore exploration has offered more disappoint than success, with Cliff Head still the only commercial offshore oil discovery.
CalEnergy Resources, a subsidiary of Warren Buffet's Berkshire Hathaway Energy, was a big investor in the basin more than 10 years ago, and is attempting to unlock the tight Whicher Range gas field in the basin with Whicher Range Energy. A new test of the 4Tcf field is planned for mid-year.
CalEnergy will be joined in the test by Queensland-based private oiler Perseverance Energy, which has 36% of Whicher Range Energy and a single coastal permit, awarded in 2012.
Perseverance is planning to acquire seismic over its 100%-owned T/P26 in 2015 to meets is commitments.
Eneabba Gas is a relatively new upstream player, seeking gas for its proposed Centauri power project.
It has the Walyering and Ocean Hills gas projects, discoveries that are yet to be proven commercial. It has agreed to a farm-in agreement for $15 million with Finder Exploration, and has as its foundation a JV with UIL Energy, with an EP 447 commitment well due by August.
That well will need to be rescheduled given the partners' funding positions and the lack of rig availability. To meet its other commitments, 91sq.km of 2D seismic will be acquired over UIL's EP 488 and EP 489 in 2015. UIL's permits EP 447, EP 488 and EP 489 have been independently assessed to contain a prospective resource of 328Bcf.
Key Petroleum owns a single permit, EP 437, with Rey and Caracel Exploration, but a recent test of the Dunnart-2 oil shows did not open the Bookara sandstone play.
Titan Energy was a pioneer in Perth Basin coal seam gas, but when that didn't work it refocused on the US, where it has a $75 million funding agreement with Gulf South Holdings. It retains has an 18.5% working interest in EP 455, where it drilled the Drover-1 well last year with AWE, but Titan says Perth Basin unconventionals are too expensive, despite the potential for a share in 2.4Tcf and it may divest the asset.
Perth's Transerv Energy is another hopeful. It has teamed up with major gas buyer Alcoa to try to develop the Warro tight gas field. It hasn't worked so far due to water and faulting issues, but there are two more wells to be drilled this year, aimed at unlocking the 3-4Tcf resource. Enerdrill Rig-3 is expected to mobilise to Warro in August following completion of the Waitsia appraisal program.
Scottish-based Warrego Energy is another contender.
It owns the West Erregulla tight gas field where there is an estimated 185Bcf of gas in place. It has a farm-out for $40 million with two European concerns that will fund a seismic and drilling program, with a rig slot secured in 2016.
There are also a number of permit applications in the basin.
Private oiler Southern Sky Energy and the Macallum Group have EPA 0065 and EPA 0066 over some 4000sq.km, which they hope to get granted this year. Southern Sky holds the view that faulting of the basin margin and associated terraces has provided hydrocarbon migration pathways within the eastern section with the presence of suitable regional seals.
A listed iron ore explorer, Dragon Energy, last year secured the 1277sq.km EPA 0123 just north of the Mount Horner oil field in the state's acreage release. The permit straddles the Bookara Shelf, a relatively shallow basement containing up to 3600m of Permian to Jurassic strata, and to a lesser extent the Wicherina, Irwin and Allanooka Terraces. Only 10 stratigraphic and exploration wells have been drilled in the permit area, with recorded hydrocarbon shows in Jay-1 and Rosslyn-1.
Dragon will initially focus on performing geotechnical studies, reprocessing existing 2D seismic data and the acquisition and analysis of 3D seismic data. A small 27sq.km 3D seismic survey in the southwest of the block should upgrade some 13 existing prospects and leads, while infill 2D in the southeast should help expand the prospect and lead inventory.
Palatine Energy - a company started by Tamboran Resources co-founder and former associate director of the Australian Geological Survey Organisation Dr David Falvey - is the preferred applicant for EPA-STP-0127, which when granted would be the largest exploration permit in the Perth Basin covering some 10,000sq.km.
The permit is transected by the Dampier-to-Bunbury gas pipeline and covers the Coolcalalaya Sub-Basin, a transition zone between the Perth and Carnarvon Basins.
Palatine will primarily focus on the potential of the Permian Carynginia shale with additional potential in the Devonian Gneudna formation, which had hydrocarbon shows in the Merlinleigh Sub-Basin to the north, and Permo-Carboniferous sandstones reservoirs.
