State-of-the-Art of Monitoring Methods to evaluate Storage Site Performance

 
1. INTRODUCTION
 
2. MONITORING TECHNIQUES
 
3. MONITORING CONCEPTS – STATUS QUO
 
4. SETTING UP A SITE-SPECIFIC MONITORING PLAN
 
5. CONCLUSIONS AND RECOMMENDATIONS
 
6. REFERENCES
 
 
2.1 CO2 plume migration in the storage reservoir
 
2.2 Surface uplift
 
2.3 Induced seismicity and mechanical reaction of overburden
 
2.4 Faults
 
2.5 Abandoned wells
 
2.6 Overlying and adjacent aquifers
 
2.7 Freshwater aquifers
 
2.8 Near surface eco-compartments
 
 
2.3.1 Induced seismicity
 
» 2.3.2 Passive seismic monitoring
 
2.3.3 Mechanical reaction of overburden
 
 

2.3.2 Passive seismic monitoring

Passive seismic monitoring provides a different kind of information to controlled-source seismic techniques. In passive seismic monitoring recording is continuous and information can be analysed in near real time. This technique can only image areas between locations where microseismic events occur and receivers are located. Passive seismic monitoring is an excellent technique for identifying geomechanical deformation induced by injection (Verdon et al., 2010). In addition, passive seismics can be used to monitor the formations above the reservoir for evidence of CO2 migration through the caprock and to assess fracture propagation.

Microseismic monitoring has been employed for about 40 years to measure down-hole processes. Microseismic events can be monitored with geophysical instrumentation such as accelerometer, hydrophone or geophone arrays. For example, microseismic surveys are regularly used to monitor hydrofracturing in commercial oil fields, as well as to track flow fronts and pressure waves during water injection. These technologies are rooted in earthquake seismology and thus, the basic theoretical underpinnings are clearly known. Microseismic monitoring provides an image of fractures by detecting microseismicity (micro-earthquakes) triggered by shear slippage.

Fig. 2-12: The permanent array in the CO2CRC Otway project <span class=

Fig. 2-12: The permanent array in the CO2CRC Otway project well (sensors installed in Naylor-1 monitoring wellbore) for downhole passive seismic monitoring (Causebrook, 2010; Daley et al., 2009).

The location of the microseismic events is obtained, e.g. using a down-hole receiver array that is positioned at depth in a second (monitoring) well near the injection well (Streit and Siggins, 2004; Fig. 2‑12). This way, very small seismic events, commonly between M -4 and 0, can be measured. In cases where suitable offset monitoring Wellbores are not available, microseismic mapping can be performed in the injection well. However, the seismic waves attenuate in the rock environment, and it is therefore often difficult to detect events that are more than 800 m away. Furthermore, some fluid-rock systems may not produce any acoustic signal.

Passive seismic monitoring should be performed before injection activities start to obtain baseline conditions. The frequency of seismic activity compared to previous seismic trends may be examined to reveal changes introduced by the injection practices. The magnitude of the seismic events is another line of evidence to link earthquakes to injection.

Detection of induced seismic activity and operational control

Passive seismic monitoring is an important part of assessing induced seismic activity from an injection well (Sminchak et al., 2002) and to mitigate the risks of induced seismic activity (Sminchak and Gupta, 2003). Various methods exist to locate microseismic event hypocentres based on the energy recorded at the geophones in order to delineate fracture geometries and to reveal fracture activation and fluid-flow paths (Rutledge et al., 2004; Streit and Siggins, 2004). Depending on the frequency of seismic activity at the injection site, months to years of monitoring may be required to achieve an adequate depiction of baseline seismic conditions prior to injection. This may involve the installation of several subsurface seismic sensors around the proposed injection site.

Recording of microseismic events in monitoring wells of CO2 storage sites can be used to provide real-time control to keep injection pressures below the levels that induce seismicity. Once microseismic recording arrays (geophones) have been installed, the costs of maintenance, operation and data processing are small in comparison with controlled-source seismic techniques (Verdon, 2010; Verdon et al., 2010). This is an important consideration for CCS where a site may need to be monitored long after injection has ceased and the field shut in (verdon et al., 2010).

Microseismic monitoring for reservoir characterisation

The microseismic monitoring has a potential for reservoir characterisation. The magnitudes of seismic events are such that they cannot usually be detected at the surface. The Richter magnitude of induced events is typically between +2 and -2 in crystalline rocks and it ranges from -2 to -4 in sedimentary rocks (Streit and siggins, 2004). During injection, the seismic event locations image the growth of fractures from the injection site, both laterally and above the injection point. By tracking the event locations, one may track potential areas of failure, and thereby stress changes. Since seismic velocities vary according to the density of material, the density contrast between formation waters and injected CO2 may also provide evidence of the extent of the injected fluid (Benson et al., 2005; Sminchak et al., 2002). Geophones should be installed in (abandoned) boreholes to provide an early warning of leakage.

The waves from microseismic events recorded on downhole geophones have travelled through only reservoir and caprock materials and wave propagation effects, such as anisotropy, can be used to make inferences about the properties of these rocks and materials. Analysis of shear wave splitting can be performed on recorded microseismic events (Verdon, 2010). S-wave splitting is particularly useful, as it allows the direct measurement of anisotropy, which may indicate the presence of sedimentary layering or aligned fractures.

Microseismic arrays have been installed at the Aneth oil field CCS-EOR pilot site, Utah (Zhou et al., 2010), and recently at the In Salah CCS site, Algeria (Mathieson et al., 2010; Verdon et al., 2011). In 2003 in the Weyburn CO2-enhanced oil recovery (CO2-eor) project (see 3.3.2), a downhole recording array of 8 triaxial 20-Hz geophones was installed in a disused borehole above the reservoir within 50 m of a planned new vertical CO2 injection well to monitor microseismicity (Verdon, 2010; Verdon et al., 2011; Verdon et al., 2010). The array has detected microseismicity and events have been located using automated location algorithms. 86 microseismic events have been located over five years of monitoring, representing a low rate of microseismicity and indicating that the reservoir is undergoing little deformation and that the CO2 is generally moving through the reservoir aseismically (Fig. 2-13). Microseismicity rates correlate with periods of elevated CO2 injection rates.

Fig. 2-13: Histogramme of located microseismic events from August 2003 to January 2008 at Weyburn <span class=

Fig. 2-13: Histogramme of located microseismic events from August 2003 to January 2008 at Weyburn CO2 injection project. Also shown are the monthly injection volumes for the WAG (water-alternating-gas) injection program in nearby vertical well. The grey shaded areas indicate periods when the passive array (geophones) was not recording (Verdon et al., 2010).