Geochemical modelling of petroleum well data from the Perth Basin. Implications for potential scaling during low enthalpy geothermal exploration from a hot sedimentary aquifer
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NOTICE: This is the author’s version of a work that was accepted for publication in Applied Geochemistry. Changes resulting from the publishing process, such as peer review, editing, corrections, structural formatting, and other quality control mechanisms may not be reflected in this document. Changes may have been made to this work since it was submitted for publication. A definitive version was subsequently published in Applied Geochemistry, Vol. 37, (2013). doi: http://doi.org/10.1016/j.apgeochem.2013.07.004
This project is part of an Australian Research Council (ARC) linkage project (#LP110100597)
Chemical analyses derived from petroleum exploration wells are notorious for their lack of key solute data and their potential to represent mixtures of reservoir and drilling fluids rather than pristine formation compositions. These drawbacks notwithstanding, they usually pose the only access to the reservoir geochemistry. Two literature protocols were applied to a dataset of incomplete major element analyses from 148 petroleum well samples from a database compilation of the Perth Basin whose deeper aquifers may serve as potential hot sedimentary aquifers for geothermal direct heat applications. The first protocol included a set of quality control criteria that reduced the number of relatively genuine formation well samples from the raw data pool by 71%. The remaining well analyses are invariably NaCl solutions of low to medium alkalinity and an ionic strength only occasionally reaching seawater salinity. The low amount of total dissolved solids indicates the absence of extended evaporites in the North Perth Basin and the prevalence of meteoric water infiltration and circulation at depths.The culled well samples underwent as a second protocol a forced equilibrium treatment to reconstruct in situ reservoir concentrations of missing elements (Si, Al, K), organic acid anions and non-carbonate alkalinity, and pH. The petroleum well samples were modelled to be in equilibrium with chalcedony (and kaolinite, albite, and paragonite) in the reservoir which yielded better convergence than using quartz instead. The derived formation temperatures correspond to geothermal gradients in the majority of cases between 25 and 35°C, in accord with literature findings. Those wells drilled to depth <1600 m returned questionably high geothermal gradients, an indication of incomplete mineral–fluid equilibrium. The measured pH (at ambient temperature) deviated in >90% of the wells from the calculated pH, either due to degassed CO2 or unaccounted acetate alkalinity. The wells were further modelled to be undersaturated with respect to amorphous silica and anhydrite and not likely to experience scaling of any of these two phases during geothermal production at depth <3800 m. For calcite, scaling predictions depend in how far bubbling and phase segregation can be suppressed. For the six different stratigraphies investigated here, calculated bubble points were low, indicating that pressurisation of the entire production and re-injection line seems viable.Based on a calcite growth model from the literature it is shown that, if bubble formation and concomitant carbonate flash scaling cannot be averted, the production well should be as shallow as the temperature requirements of the geothermal production allow for. This study promotes the application of readily accessible protocols and a scaling model to deep well samples that may otherwise appear to have little geochemical value because of the way the samples were collected and handled. After data culling and treatment, insights into the geochemistry and scaling potential of deep clastic formations of the North Perth Basin that may hold the potential for geothermal exploitation as hot sedimentary aquifers can be gained.
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