Empire Energy is predicting an increase in gas flow from its Carpentaria-3H well (C-3H) following a five-month post-fracture stimulation shut-in and soak at its permit within the Top End’s giant Beetaloo Basin.
The company’s planned pause before a restart to testing at the well was designed to allow its reservoir shales to release more gas. The same technique proved successful in a sister well that targeted the same formation within the EP187 permit.
Empire’s 100 per cent-owned shale gas project in the Northern Territory’s Beetaloo Basin targets shales, which in their virgin state possess the low porosity and permeability that inhibits their ability to flow gas locked up within the rock. Globally, shale gas has been proven to be economic through advancement in engineering design and fracture stimulation technology.
Fracture stimulation is a process in which fluids are pumped downhole to induce and propagate fractures in a reservoir to increase its ability to flow gas or oil that was previously held within the rock, into the wellbore and up to the surface.
Soaking is the practice of shutting-in a well for a period of time following fracture stimulation to maximise long-term productivity through the mixing of residual ground water within the newly-formed features.
Empire Energy managing director Alex Underwood said: "The Empire team is excited to recommence flow testing at C-3H, the longest horizontal well drilled in the Beetaloo Basin to date and the largest fracture stimulation carried out in Australian history. The results of renewed flow testing from this well will continue to build Empire’s technical knowledge base as we progress rapidly towards a final investment decision for the pilot project. Subject to FID, this would make Empire the first company to commercially extract gas from the Beetaloo Basin.”
Four wells have been drilled by Empire within EP187 – Carpentaria-1, 2H, 3H and 4V. Carpentaria 1 and 4V are vertical holes, while Carpentaria 2H and 3H were drilled from the same surface location and are horizontally-deviated in opposite directions to target the relatively flat-lying shale reservoir intervals at about 1600m below the surface.
C-3H was drilled to a depth of 4460m measured depth (mMD), referencing the length of the wellbore, with a total horizontal section length of 2632m and a successful fracture stimulation of an impressive 1989m of the horizontal wellbore.
The well was then shut in and left to soak for the five-month period to allow the gas-bearing shales to release their pay and the company is now ready to open the floodgates by restarting the production test.
When testing restarted at C-H2 after its five month wait following fracturing, the well delivered at a 17 per cent higher gas flow rate, with pressures sufficient to lift wellbore fluids in 11.5cm casing without production tubing or artificial lift.
Empire hopes to see a similar result at C-H3, or possibly better since the well will produce from the reservoir about 150m deeper than C-2H. The company says it may drive higher production rates given the increased reservoir pressure depth and therefore, pressure.
Management says the flow testing results following soaking at C-2H prove the method is effective in the Beetaloo Basin shale reservoirs and with a 270 per cent increase in best-estimate contingent resource volume revealed in May this year following an independent review, the shales seem worth the effort.
The contingent resources for the EP187 permit now sit at a best-estimate volume of 1739 petajoules, with a low-case estimated of 304 petajoules and the high-case at 3507 petajoules. Due to the high calorific value of the low carbon dioxide EP187 gas, estimated at 1.15 terajoules per million standard cubic feet of gas, the amount of gas is expressed in energy units rather than the more typically-seen volumetric units.
For reference, 1 petajoule is enough to power 19,000 homes for a year, suggesting Empire may be sitting on a major transformative discovery for the Australian East Coast gas market.
Amid accelerating urgency for new gas supply options, the company is sitting on what it now says is a “nationally significant resource”. Management will make a final investment decision on an initial gas project by year’s end, ahead of the anticipated first gas production in 2025.
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By Andrew Duffy
