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
 
 

2.3.1 Induced seismicity

Induced seismicity may be related to the injection of CO2 into deep aquifers (Sminchak et al., 2002) and (depleted) hydrocarbon fields. Generally, induced seismicity has long been recognised as a part of human activities such as oil and gas production, dam building, geothermal energy production, mining, quarrying and underground gas storage. The study of induced seismicity has been going on for more than 50 years with two main drivers: (a) the risk, damage and public concern caused by ground motion and (b) the potential to monitor subsurface processes via the induced seismicity. Therefore, induced seismicity is recognised as a potential issue affecting geological storage of CO2, both as a hazard and as a reservoir monitoring tool. Regarding the potential hazard, there is a significant technical knowledge base referring to seismicity induced from human activities. One important distinction can be made between 'triggered' seismicity and true 'induced' seismicity. 'Triggered' seismicity includes those events that would have occurred naturally at some point in the future but were triggered by human activity, while 'induced' seismicity comprises those events entirely caused by human activity. It is important for CO2 storage projects to develop a uniform general approach to the induced seismicity hazard. Additional investigations will be needed to improve the understanding and estimation of the potential induced seismicity hazard at any individual site (Myer and Daley, 2011). These investigations may include a structural study of the area, historical seismicity, evaluation of the critical fluid pressure for failure and pre-injection seismic monitoring of the area to define "zero-state" seismicity (Holloway, 2001; Chang, 2007).

Injection of CO2 into porous rocks at pressures higher than formation pressures can induce fracturing and fault activation. This may pose two kinds of risks (Benson et al., 2005):

  • brittle failure and associated microseismicity induced by overpressurisation can create or enhance fracture permeability (secondary permeability), thus providing pathways for unwanted CO2 migration.
  • fault activation may induce earthquakes.

An understanding of the structural geology, lithology and hydrology of the CO2 storage site is critical to determining if injection will induce seismic events (Sminchak et al., 2002).

Mechanisms and processes

A conceptual model of possible processes potentially involved in triggering seismic activity by underground injection wells is given in Fig. 2-10.

Fig. 2-10: conceptual figure illustrating potential processes involved in seismic activity possibly induced by underground <span class=

Fig. 2-10: Conceptual figure illustrating potential processes involved in seismic activity possibly induced by underground injection wells (Sminchak et al., 2002).

During the process of CO2 injection at a storage site, in-situ stresses will be modified by pore pressure increases, creating a potential for seismic events due to slippage upon pre-existing discontinuities or due to creation of new fractures (Myer and Daley, 2011). The greatest risk for induced seismicity will probably arise from slip on pre-existing faults and fractures. Other processes involved in the triggering of seismic activity may include transfer of stress to a weaker fault, hydraulic fracture, mineral precipitation along a fault, density-driven stress loading etc. Processes involving faults are described and discussed in more detail in Section 2.4.

In terms of stress equation, deep well injection reduces both the principal and confining pressure in the injection formation while keeping the differential pressure constant, moving the system toward failure (cf. Fig. 2-11). Hence, injection pressures need to be monitored to determine if the changes in pressure may trigger fracture. Geological formations with low permeability and low porosity require higher injection pressures and are thus more susceptible to induced seismicity.

In addition, mineral precipitation by geochemical interactions between CO2, formation water and reservoir rocks has the potential to significantly decrease formation porosity and permeability. These changes may result in unexpected (local) pressure build-up and formation faulting or fracturing.

Fig. 2-11: Diagram illustrating how <span class=Fig. 2-11: Diagram illustrating how injection pressures (P) reduce the effective confining and axial strength of a rock formation. injection pressure counteracts confining and axial pressures, reducing the strength of the rock and causing fracture or faulting (Sminchak et al., 2002).

Formation pressure may also influence the stress-strain system. At very high injection pressures, rocks may fracture in a process termed 'hydraulic fracturing'. Hydraulic fracturing occurs when the injection pressure exceeds the intergranular strength of the rock, creating or expanding fractures which may trigger seismic activity.

In addition, the density contrast between formation water and injected CO2 may produce a density-driven flow as the lighter, injected fluids migrate upward. Given the large volumes of fluid involved in CO2 storage operations, the impact of the density contrasts could be capable of influencing stress conditions at depth, thereby causing seismic events (Sminchak et al., 2002).

Risks and potential impacts

Injection activities may affect a formation far beyond the location of the deep injection well(s). Sometimes, seismic events may occur after injection activities are stopped. In addition, earthquakes may be induced in formations well below the injection formation. In conclusion, induced microseismicity must be viewed as a manifestation of wider geomechanical deformation (Verdon, 2010) which must be taken into account for risk.

Generally, the intensity of induced seismicity related to CO2 injection is low (Environmental Potection Agency, 2008; Pagnier et al., 2009). The vast majority of induced seismic events does not release enough energy to be felt by people on the surface and the energy from these events can be used for monitoring of process in the reservoir (Myer and Daley, 2011). However, they may be precursors to larger events (Mamyer and Daley, 2011). Moderate earthquakes (e.g. of magnitude of 5.1 and 5.2) have already been reported in relation to fluid injection activity (Sminchak et al., 2002). None of these, however, were connected with injection of CO2. The risk of inducing seismicity might be increased when CO2 is injected into a reservoir in tectonically active regions with high density of active faults (Damen et al., 2006).

The risks of induced seismicity can be addressed from a technical perspective through a combination of site characterisation, engineering design, operational procedures and monitoring (Myer and Daley, 2011). In particular, the risk of induced seismicity caused by CO2 storage operation can be minimised by controlling the injection pressure (Damen et al., 2006; Price and Smith, 2008). Regulatory limits are imposed on injection pressures to avoid significant injection-induced seismicity.

In the early stage of site characterisation, data on the general fault and fracture network geometry in the area will be derived from existing data sources such as wells and seismic surveys. The ideal data set is one from a microseismic network established specifically for each CO2 storage project (Myer and Daley, 2011; Chalaturnyk and Gunter, 2005; Benson et al., 2005).