Stephan Thiel1, 2
1 Geological Survey of South Australia, Department of the Premier and Cabinet
2 School of Physical Sciences, The University of Adelaide
Download this article as a PDF (0.8 MB); cite as MESA Journal 85, pages 4–7
Introduction
Figure 1 Schematic diagram depicting an EGS setup. Fluids are pumped at depth of typically around 4 km under high pressure to cause an enhanced fracture network susceptible to fluid flow. Once a permeable fractured network is established the heated fluids are pumped back to the surface through a second borehole to generate electricity from a power plant. Used fluids are then recycled to hot rocks at depth. (Courtesy of the United States Department of Energy 2008)
Hydraulic stimulation, also referred to as hydraulic fracturing or fracking, is a geoengineering application in which fluids or supercritical fluids are pumped to depths of several hundred metres to several kilometres to enhance the connectivity of the pores within the rock matrix (Gérard et al. 2006). The enhanced connectivity, or permeability, of the medium has the effect of enabling a more efficient fluid or gas flow through the matrix. This enhancement of subsurface permeability forms the basis for enhanced geothermal systems (EGS), as well as tight shale gas and coal-seam gas plays. While the Australian geothermal industry is largely dormant at this point, the investments made over the last decade still provide important insights into the geoengineering challenges surrounding EGS and holds learnings for other applications of hydraulic stimulation technology.
In EGS, a cool fluid is pumped under high pressure to depths of several kilometres where temperatures can rise up to 200 °C (Peacock et al. 2012a). A second borehole closes the loop and pumps the hot fluids back up to the surface, at which point the thermal energy of the fluids can be used for heating, direct use applications or electricity generation if the temperature is sufficiently high (Fig. 1). In gas plays, the high-pressure fluids establish an enhanced fracture network. After the enhancement, the fluids are then extracted leaving behind pathways for the formation-bound gas to escape via the enhanced permeability pathways into the well.
Monitoring the distribution of the connected fluid-filled fracture network remains at the forefront of scientific study. Commonly, microseismic deployments are used to map fracture opening due to the injected high-pressure fluids. The seismicity in a reservoir is therefore a proxy for establishing enhanced permeability (Phillips et al. 2002).
Over the last seven years, the University of Adelaide established one of the world’s biggest research hubs for field-based electromagnetic geophysics, with particular focus on magnetotellurics (MT) experiments for fluid injection monitoring, which was supported by Renewables SA and the South Australian Government. This article summarises the recent advances in monitoring fluid injections at depth using electromagnetic geophysics, with particular focus on South Australia. A more comprehensive in-depth review has just been published by Thiel (2017) focusing on global efforts in using electromagnetic geophysics for monitoring of hydraulic stimulation. This review paper was presented as a keynote address at the 23rd Electromagnetic Induction Workshop in Chiang Mai, Thailand, 2016.
Motivation for novel monitoring methods
While microseismic methods are the industry standard and achieve a high resolution of mapping microseisms (typically recorded in the range from magnitude –2 to 3 on a Richter scale for EGS injections), they are not directly sensitive to the injected fluids themselves, but to the movement of fractures opening under the high injection-induced pressure in the formation. For this reason, the University of Adelaide began a research program in 2010 to test surface MT measurements for monitoring temporal changes in the surface electromagnetic field due to fluid movement at depth. This approach not only maps the distribution of stimulated fractures, but demonstrates that they are connected and open to the transmission of fluid.
South Australian enhanced geothermal systems
Figure 2 Location of the SAHFA, and Paralana and Habanero EGS sites used to test MT monitoring of hydraulic stimulation.
South Australia does not have the tectonic setting for conventional geothermal energy resources where hot near-surface fluids due to volcanic activity can be tapped for electricity generation. However, anomalously high temperatures occur at depths of several kilometres within the South Australian Heat Flow Anomaly (SAHFA), a roughly north–south corridor along the Flinders Ranges and adjacent basins extending north to the Cooper Basin (Fig. 2; Neumann, Sandiford and Foden 2000). Over the last decade, several South Australian companies explored the possibility of utilising these high temperatures for EGS electricity generation. These systems require prior permeability enhancement using a hydraulic stimulation approach. Hydraulic stimulation in EGS typically occurs deep beneath the surface at depths of around 4 km. Within the SAHFA, temperatures at 4 km depth can reach to around 200 °C. This temperature is required to achieve economic viability for electricity generation. Two companies have drilled into hot basement rocks of the SAHFA to test the viability of geothermal electricity generation – Geodynamics Limited at the Habanero EGS site and Petratherm Limited at the Paralana EGS site (Fig. 2). It is around these two geothermal sites, the University of Adelaide initially trialled surface MT deployments to study the effectiveness of MT to monitor fluid movement at depth during injection of the hydraulic stimulation.
The Paralana EGS site was the first monitoring experiment using MT worldwide and generated a number of field and theoretical studies (Albaric et al. 2014; Alexander, Thiel and Peacock 2012; MacFarlane et al. 2014; Peacock et al. 2012, 2013; Rosas-Carbajal et al. 2015). The high heat flow (~126 mW/m2) near the Paralana EGS site is attributed to elevated uranium and thorium concentrations in the Proterozoic Mount Painter Inlier basement rocks (Cull 1982; Brugger et al. 2005). The Paralana EGS is ~10 km east of the Flinders Ranges in the Frome Embayment near the Beverley uranium mine.
The prerequisites for a successful EGS, which are enhanced heat flow and thick insulating sedimentary rocks to trap the heat of the granites below the cover, are present at Paralana. The pre-existing higher density of fractures at the sediment to basement contact, observed in seismic reflection profiles, is also beneficial to establish further enhancement of the fracture network post fluid injection. In July 2011 Petratherm injected 3,100 m3 of saline water into Mesoproterozoic metasedimentary rocks over a period of five days at a depth of 3,680 m within the 4,012 m deep Paralana 2 drillhole. The drillhole was cased to 3,725 m depth and perforation occurred over a height interval of 6 m (Bendall et al. 2014).
Another time-lapse MT installation occurred at the Habanero EGS in 2012 (Didana et al. 2017). It was the most developed EGS project in Australia at the time with four geothermal wells intersecting hot Carboniferous granitoids of the Big Lake Suite beneath the Cooper Basin. The Habanero EGS fractured reservoir sits about 400 m deeper than the Paralana EGS reservoir. In November 2012 Geodynamics injected 36,500 m3 over 14 days into the hot granitic reservoir at 4,077 m depth using a near-surface aquifer fluid. The target fracture zone at depth, intersected by all four geothermal wells, was a shallow WSW-dipping fracture zone of 5–6 m thickness (Bendall et al. 2014).
Magnetotelluric experiments
Figure 3 Survey layout of the broadband MT sites (triangles) across the 3.7 km deep borehole (red circle) of the Paralana EGS. Inset shows microseismic events recorded during fracking (Albaric et al. 2014). Background colour is depth to basement, and arrows denote maximum stress direction (Balfour et al. 2015). Lines show roads, seismic lines, and gas pipeline. Reprinted from Peacock et al. (2013; fig. 1) with permission from the Society of Exploration Geophysicists.
In both scenarios two types of MT deployments were undertaken to monitor the fluid injection – continuous and time lapse. Continuous deployment is limited by the number of instruments available, whereas time-lapse monitoring involves a larger array of sites that are deployed before and after the fluid injection by using the instrument pool at multiple sites, similar to a typical MT deployment. An example of the MT layout for the Paralana EGS is given in Figure 3. During the continuous deployment at Paralana, broadband MT sites were placed within a couple of kilometres radius around the borehole, measuring throughout the entire hydraulic stimulation program (Peacock et al. 2012). For the time-lapse monitoring at Paralana, 56 MT sites were deployed around the injection hole before and after the hydraulic fracturing (Peacock et al. 2013). Similarly, at the Habanero EGS site, two main profiles of 40 km length centred on the injection well were deployed for the time-lapse deployment (Didana et al. 2017).
The continuous and time-lapse deployments were designed to establish the suitability of surface MT studies for monitoring the hydraulic fracturing given that future monitoring exercises may have limited land access or instruments available. The site spacing in both types of deployment was chosen based on the variation in surface MT response changes derived from hypothetical 3D forward modelling. For all of these deployments, baseline data (defined as the MT responses prior to the injection) is compared to the MT responses during and after the fluid injection. Typically, we studied the MT responses derived from a day of time series data of the electric and magnetic field. When plotted for several consecutive days during the fluid injection, the results showed a temporal change in the responses due to the fluid injection. While the temporal changes in the response are small, they are nevertheless visible. Furthermore, the tensorial character of the MT responses allows a direction-dependent assessment of the change due to the fluid injection at depth. We found that the primary control of the connectivity enhancement at depth is controlled by the applied stress field in the study area. It preferably connects fractures perpendicular to the maximum horizontal stress direction (Didana et al. 2017).
Further monitoring studies were performed for fluid injections in hydrocarbon plays in Australia, including coal-seam gas and shale gas fluid injections (Rees et al. 2016a, 2016b; Rees, Heinson and Krieger 2016).
Conclusion
Electromagnetic monitoring of fluid injections has shown promising results across the South Australian EGS sites. Further studies were undertaken across other fluid injection scenarios in coal-seam gas and shale gas plays. Results from case studies suggest that electromagnetic monitoring is a viable tool to detect changes in electrical resistivity of the fluid reservoir at depth with surface measurements. However, the changes in the electromagnetic response functions are very small for the injections occurring at several hundred metres to a few kilometres depth and there still exist shortcomings in adequately mapping the horizontal fluid extent of the injection plume. Repeatability studies are an important part of the studies to ensure relatively noise free environments and stable baseline data.
Further petrophysical studies are needed to explain fracture development and its influence on fluid flow and relation to electrical resistivity over time within the fracture network. The percolation threshold of a fracture network plays an important role for permeability enhancement of the reservoir. At the percolation threshold, the connectedness increases in a highly non-linear fashion, and permeability and electrical conductivity are enhanced by several orders of magnitude (Kirkby and Heinson 2017; Kirkby, Heinson and Krieger 2016).
Downhole measurements would significantly improve the resolution to in situ processes during fluid injection. Modelling studies indicate a significant increase in sensitivity to target for borehole to borehole, or borehole to surface configurations (Tietze, Ritter and Veeken 2015). This would alleviate resolution of the fluid plume extent at depth.
Acknowledgements
This summary is an overview of work undertaken in recent years. Thanks go to the students at the University of Adelaide who worked on this over the years, in particular Jared Peacock who performed the pioneering analyses on the Paralana EGS. Yohannes Didana, Alison Kirkby, Jake MacFarlane, Nigel Rees, Simon Carter, Dennis Conway, Graham Heinson and many others subsequently furthered research in this field. The South Australian Centre for Geothermal Energy Research, guided by Martin Hand, supported a fellowship for me throughout the first few years of the electromagnetic monitoring research at the University of Adelaide. Australian geothermal companies Petratherm and Geodynamics allowed access to their EGS plays, making this research possible in the first place. The Habanero EGS MT work was funded through the Australian Geophysical Observatory System (AGOS) as part of AuScope. Betina Bendall provided a review of this article.
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