Geothermal Exploration In The North Perth Basin, Australia

Abstract

IHot Sedimentary Aquifer (HSA) geothermal systems share many characteristics with petroleum systems, and similar data and work flows are used to define them. The North Perth basin (NPB) in Western Australia provides all the geological ingredients for an HSA geothermal system, leading to an exploration campaign over the period from 2010 to 2014 to identify and drill HSA geothermal prospects in the area (Ballesteros, 2015; Ballesteros & Oppermann, 2013). One of the biggest challenges to a successful geothermal development is accurately identifying and mitigating the sub- surface risks. Undertaking geothermal exploration where sub-surface data such as wells and seismic surveys (2D and 3D) have been acquired for petroleum exploration offers a cost effective way to address these sub-surface risks. Petroleum exploration has been carried out in the NPB since the 1960s, resulting in a substantial database of wells and seismic data (2D and 3D) in the public domain. Although accurately predicting the temperature in the sub-surface is a critical element in defining a geothermal prospect, identifying a reservoir with adequate permeability to sustain the high flow rates required for a commercially viable geothermal project is arguably the most critical element (Cooper & Beardsmore, 2008). In most cases, degradation of matrix porosity and permeability with depth as a result of compaction and diagenesis means it can be difficult to achieve the necessary combination of temperature and flow rate. In contrast, naturally occurring open fracture systems can offer a viable alternative reservoir target (egs. Luschen, et. al, 2011; Schindler et al., 2010). In the NPB, a thermal model highlighting areas of high heat flow was created using temperature data available from existing petroleum wells. However, this data also suggest that matrix permeability at the 150oC isotherm is unlikely to be adequate to sustain the necessary flow rates. Attention therefore turned to the identification of natural fracture systems that could provide a viable alternative reservoir (Ballesteros & Oppermann, 2013). Borehole image logs were used to identify the location and orientation of naturally occurring fracture systems and distinguish open from closed fractures. The regional stress field and fracture orientations most likely to remain open were predicted using the available geomechanical data, which was then correlated with the results of the borehole image log interpretations. Existing 3D seismic surveys were interpreted and integrated with the bore hole image log results. In particular, an automated fault extraction algorithm was applied to identify the density and orientation of faults and fractures in the seismic data. Taken together, these results highlighted areas with higher probabilities of both open fracture systems and adequate temperatures needed for a viable geothermal prospect. The final stages of this effort were carried out in partnership with one of the leading petroleum operating companies in the area. The company farmed in to the geothermal project with the intention of undertaking a drilling program with complementary geothermal and petroleum objectives. Unfortunately, due to non-technical reasons, the company withdrew at a late stage and the project subsequently had to be abandoned before drilling a well. This highlights both the potential synergies of petroleum and geothermal exploration as well as the challenges inherent in attempting any significant variation to established practice. Keywords: geothermal exploration, hot sedimentary aquifer, geothermal systems, fracture identification, borehole image log interpretation, automated fault extraction, 3D seismic interpretation, fracture permeability.

AAPG Datapages/Search and Discovery Article #90345 © 2018 AAPG European Region, Geothermal Cross Over Technology Workshop, Part II, Utrecht, The Netherlands, April 17-18, 2018