Over the past year, the Queensland Government has promoted new exploration acreage and highlighted the economic potential of deeper onshore petroleum development, including in the Taroom Trough. At the same time, there has been a noticeable increase in applications to amend existing Environmental Authorities (EAs) to include hydraulic fracture stimulation (HFS), disposal of drilling residuals, injection of materials into confined formations and development of lower-permeability targets.
Taken together, these signals suggest Queensland may be entering a more stimulation-dependent phase (fracking) of unconventional extraction as shallower coal seam gas resources decline. This means that wells can be up to 4km deep and extend horizontally for up to 1km.
Regulatory Readiness and Strategic Agricultural Land
This transition warrants careful scrutiny — not only of the resource opportunity, but of the regulatory framework that will govern it. We must not repeat the mistakes of the past whereby gas was oversold and land use conflict reported.
Approximately 18,500 coal seam gas and petroleum wells have been drilled across Queensland, with roughly 10 per cent historically involving stimulation. Industry projections indicate this proportion may increase up to 40 per cent as operators move into tighter formations requiring fracture stimulation to achieve economic production.
Recent examples include:
- Origin Energy’s Ironbark amendment (EPPG00968013), seeking to stimulate 37 wells and expand activities across multiple petroleum leases.
- OGT’s EA P-EA-100227919 (PL1158, formerly PL202), proposing hydraulic fracture stimulation within a declining field.
- New exploration acreage released in the Taroom Trough.
These developments point to increasing industrial intensity, operational complexity and long-term management requirements.
Strategic Cropping Land and the RPI Framework
A significant proportion of proposed activities are located within Strategic Cropping Land (SCL) and Priority Agricultural Areas regulated under the Regional Planning Interests Act 2014 (RPI Act). These land classifications were established to safeguard high-quality agricultural land from incompatible development.
However, the RPI framework was designed primarily to manage land-use conflict at the project level. It was not structured to evaluate cumulative industrial transformation arising from repeated EA amendments, intensification of hydraulic fracture stimulation or long-term embedding of petroleum infrastructure across agricultural landscapes.
In 2023, the Queensland Government commissioned a public review of the RPI Act in response to sustained concerns that the Act was not effectively protecting strategic agricultural land. The review identified limitations in how agricultural values are defined, how cumulative impacts are assessed and how landholder participation is structured. At the time of writing, substantive legislative reform has not been enacted.
Independent peer-reviewed research examining the implementation of the RPI framework has identified procedural justice shortcomings within coexistence decision-making processes. These include constrained participation pathways, limited cumulative impact consideration and a regulatory structure that prioritises project-level approval over landscape-scale assessment. The practical effect is a system that formally recognises agricultural value while permitting incremental industrialisation through successive approvals.
Recognition of regulatory limitations without timely reform raises concerns that the next phase of unconventional development may again rely on reactive safeguards rather than proactive system calibration.
Adaptive Management and Regulatory Escalation
Queensland’s resource regulation architecture relies on:
- Environmental Authority approvals under the Environmental Protection Act 1994
- Tenure and access provisions under the Mineral and Energy Resources (Common Provisions) Act 2014
- Land-use assessment through the Regional Planning Interests Act 2014
- Workplace duties under the Work Health and Safety Act 2011
During the initial coal seam gas expansion phase, safeguards frequently evolved through adaptive management — that is, regulatory settings were refined in response to emerging impacts rather than fully implemented in advance.
Adaptive management can be appropriate where impacts are reversible, monitoring is robust and feedback loops are transparent. However, deeper, stimulation-dependent unconventional extraction introduces longer-term well integrity considerations, expanded fracture envelopes and more complex waste management pathways.
As development intensity increases, the question becomes whether regulatory systems are being recalibrated before industry escalation, or whether they will again evolve reactively and belatedly, in response to impact.
Technical Escalation and Monitoring Considerations
HFS is used to increase permeability in low-flow formations. In tight systems such as those proposed in the Taroom Trough, stimulation may be operationally necessary to achieve economic production.
Recent applications reference:
- Fracture propagation potentially extending over 1,500m from wellbores (this could cause potential incursion into nearby gas wells)
- Use of hydrotreated light petroleum distillates and synthetic drilling muds that may contain BTEX constituents
- Disposal of drilling residuals (cuttings) across multiple sites (lax monitoring of constituents including radioactive substances)
- Increased water extraction volumes
Public summaries from the Gas Industry Social and Environmental Research Alliance (GISERA) report limited observed impacts in specific monitored contexts during earlier development phases. Those findings reflect defined geographic and operational conditions.
Stimulation Fluid Transparency and Regulatory Classification
Queensland introduced restrictions on certain BTEX-related compounds in hydraulic fracture stimulation fluids in 2010 following concerns raised during the early coal seam gas expansion phase. These measures were widely described as a “BTEX ban” in CSG fracking.
However, regulatory treatment of subsurface petroleum-based fluids remains divided across categories. Stimulation fluids are restricted under petroleum legislation, while drilling muds and other subsurface fluids are regulated separately under Environmental Authority conditions. Although these categories are administratively distinct, both involve injection of petroleum-based mixtures into subsurface formations where complete containment and retrieval cannot be guaranteed.
A recent amendment attempt involving synthetic-based drilling muds containing BTEX-related compounds illustrates how regulatory outcomes can hinge on classification pathways and amendment processes rather than on functional risk equivalence. While that proposal was ultimately withdrawn and existing prohibitions retained, the episode highlights the importance of transparency in how chemical acceptability thresholds are determined and applied.
As stimulation intensity increases and tighter formations are targeted, clarity regarding the following becomes proportionally more important:
- The scope of chemical prohibitions across all subsurface injection activities
- The consistency of Environmental Authority conditions
- Pre-approval assessment criteria for petroleum-derived components
- Public notification pathways for chemical amendments
If Queensland is entering a more stimulation-intensive phase, proportional transparency regarding monitoring scope, cumulative aquifer interaction assessment, long-term well integrity performance and independent verification mechanisms becomes increasingly important.
Applying “Lessons Learned” to the Next Phase
The publication Lessons from the Queensland Onshore Gas Industry presents the State’s coal seam gas experience as a case study in regulatory evolution and adaptive learning. It emphasises improvements in baseline data collection, monitoring and governance responsiveness over time.
If those lessons are accepted, they imply preparedness before escalation.
As Queensland transitions toward deeper unconventional extraction, the following questions arise:
- Has cumulative regulatory performance from the first CSG phase been independently evaluated?
- Are stimulation-dependent developments being assessed at landscape scale rather than solely at project level?
- Has the RPI framework been reformed to address previously identified deficiencies?
- Are monitoring systems demonstrably scaled to the technical intensity now proposed?
A lessons-learned framework suggests proactive calibration rather than retrospective adjustment.
Conclusion: Regulatory Readiness and Public Confidence
Queensland’s resource sector has undergone significant evolution over the past two decades. That history provides valuable experience.
However, as the State appears to transition toward deeper, more stimulation-dependent, unconventional extraction, regulatory readiness should be transparently demonstrated rather than assumed.
Escalation in technical intensity warrants proportional review of:
- Cumulative impact assessment frameworks
- Agricultural land protection mechanisms
- Monitoring independence and transparency
- Adaptive management performance during earlier phases
Transparent public accounting of regulatory capacity would strengthen confidence across stakeholders — whether one supports or opposes further development.
The central question is not whether unconventional extraction should occur. It is whether Queensland has demonstrated that its governance systems are calibrated for the scale and intensity of the next phase.
During the preparation of this blog we used ChatGPT generative AI in order to improve language and readability only. After using this tool/service, we reviewed and edited the content as needed. The ideas and the content are not AI generated.