Coupled Flow and Deformation Modeling of Carbon Dioxide Migration

Jul 1, 2013 - National Energy Technology Laboratory Regional University Alliance (NETL-RUA) and Department of Civil and Environmental. Engineering ...
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Coupled Flow and Deformation Modeling of Carbon Dioxide Migration in the Presence of a Caprock Fracture during Injection Hema J. Siriwardane,*,† Raj K. Gondle,† and Grant S. Bromhal‡ †

National Energy Technology Laboratory Regional University Alliance (NETL-RUA) and Department of Civil and Environmental Engineering, West Virginia University, Morgantown, West Virginia 26506-6103, United States ‡ National Energy Technology Laboratory (NETL), United States Department of Energy, Post Office Box 880, Morgantown, West Virginia 26507-0880, United States ABSTRACT: Understanding the transport of carbon dioxide (CO2) during long-term CO2 injection into a typical geologic reservoir, such as a saline aquifer, could be complicated because of changes in geochemical, hydrogeological, and hydromechanical behavior. While the caprock layer overlying the target aquifer is intended to provide a tight, impermeable seal in securing injected CO2, the presence of geologic uncertainties, such as a caprock fracture or fault, may provide a channel for CO2 leakage. There could also be a possibility of the activation of a new or existing dormant fault or fracture, which could act as a leakage pathway. Such a leakage event during CO2 injection may lead to a different pressure and ground response over a period of time. In the present study, multiphase fluid flow simulations in porous media coupled with geomechanics were used to investigate the overburden geologic response and plume behavior during CO2 injection in the presence of a hypothetical permeable fractured zone in a caprock, existing or activated. Both single-phase and multiphase fluid flow simulations were performed. The CO2 migration through an existing fractured zone leads to changes in the fluid pressure in the overburden geologic layers and could have a significant impact on ground deformation behavior. Results of the study show that pressure signatures and displacement patterns are significantly different in the presence of a fractured zone in the caprock layer. The variation in pressure and displacement signatures because of the presence of a fractured zone in the caprock at different locations may be useful in identifying the presence of a fault/fractured zone in the caprock. The pressure signatures can also serve as a mechanism to identify the activation of leakage pathways through the caprock during CO2 injection. Pressure response and ground deformation behavior from sequestration modeling could be useful in the development of smart technologies to monitor safe CO2 storage and understand CO2 transport, with limited field instrumentation.

1. INTRODUCTION Anthropogenic greenhouse gases, mainly carbon dioxide (CO2), have dramatically increased because of fuel combustion and are believed to be a major source for global warming. Geological reservoirs that act as natural resources to extract natural gas and oil are believed to have great potential for storage of anthropogenic CO2.1−4 Also, injection of CO2 into some geologic reservoirs could result in enhanced oil recovery or enhanced gas production.3,5 Geologic formations, such as brine aquifers, have great potential to sequester substantial amounts of CO2 for permanent subsurface storage.6−12 Several worldwide projects are underway involving saline aquifers, and limited data on these projects are available in published literature.13−18 Some of the major large-scale CO2 sequestration projects include the In Salah project in Algeria,16,19,20 the Sleipner project in the North Sea,17,21 the Gorgon project in Australia,22,23 and the Snøhvit project in Norway.14 Estimated storage capacities exceeding 10 Mt have been reported in some geologic repositories planned for CO2 sequestration.14,22,23 A few modeling studies and site characterization works have been reported at field scale and basin scale to investigate the plume behavior of CO2.7,24,25 Tight, impervious caprock layers, which overlie aquifers, are the primary trap for CO2 injected in the subsurface, and their presence helps ensure low leakage risks.25,26 When CO2 is injected into a saline aquifer, geochemical changes occur with © 2013 American Chemical Society

various geological components because of dissolution and mineralization.27 Trapping mechanisms in saline/brine aquifers, which contribute to CO2 permanence, include structural, hydrodynamic, residual, ionic, and mineral trapping.11,25,28−33 Time scales associated with these trapping mechanisms can be found elsewhere.30 These geochemical changes alter the reservoir properties, and processes such as excessive dissolution or mineral precipitation may lead to CO2 leakage in the overburden formations. The unintended leakage of CO2 into overburden formations could pose a risk to groundwater quality31 and affect the geomechanical stability.32,33 Thus, the integrity of the overburden caprock plays a significant role in securing safe CO2 storage.34−36 Understanding the transport of CO2 during long-term CO2 injection into a typical geologic reservoir, such as a saline or a brine aquifer, could be complicated because of changes in geochemical, hydrogeological, and hydromechanical behavior. Research studies have used a hydrodynamic and geochemical modeling approach to investigate the long-term fate of injected CO2.31,37−39 CO2, when injected into a deep reservoir for a Special Issue: Accelerating Fossil Energy Technology Development through Integrated Computation and Experiment Received: January 31, 2013 Revised: June 21, 2013 Published: July 1, 2013 4232

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estimate the maximum injection pressures that can be sustained without causing any fault activation or caprock failure during large-scale CO2 injection.50,51 Fluid flow along such fault zones, caprock damage zones, and fracture regions is discussed elsewhere.42,45,48,49,52,53 Changes in subsurface fluid pressures affect ground displacements and pore fluid flow. Surface deformations are obtained over a large area and are based on instrumentation near the ground surface. The redundancy in measurements of fluid pressure and surface displacements is desirable to identify the locations of potential leakage pathways. A coupled hydrogeological and hydromechancial modeling study has been reported, which helps in understanding the response of pore pressure and surface uplift when a fault is activated during CO2 injection.42,49 The usage of ground monitoring tools, such as tiltmeters and InSAR, was reported at a few pilot storage sites to monitor ground displacements and gain insight into CO2 migration.17,47,49 High-precision surface and subsurface instruments, such as tiltmeters, can be used in measuring surface uplift or subsidence in the sub-millimeter range. Use of such technologies (tiltmeters or InSAR) has become common in the oil and gas industries for real-time monitoring of fluid flow and overburden response. At a field site, measurements of pressure and ground displacements coupled with comprehensive geomechanical modeling can be used to detect a potential fracture and gain insight into the monitoring of CO2 storage. The spacing and density of monitoring units, such as tiltmeters, are functions of monitoring depth. It is important to consider the overall monitoring array and any voids in the monitoring array when a monitoring network is customized for a specific project site. The size and location of leakage pathways may be detected by selecting multiple monitoring points combined with the geophysical characterization of the underlying geologic media. Coupled fluid flow and geomechanic modeling together with limited measurements of fluid pressures and surface displacements have the potential to identify the presence of a fracture or activation of dormant fracture/fault during CO2 injection. A comparison of computed and measured ground uplift at field storage sites can also be found elsewhere.47,49 Such research work provides a greater insight into the future of safe sequestration options. However, details of fluid pressure changes in the presence of a fracture or damage zone in the caprock layer are limited in the published literature. In the presence of a pre-existing fracture or when a new fracture or an existing dormant fault becomes activated during CO2 injection, the fluid pressure in the overburden formations can change depending upon the fracture location. These changes in fluid pressures over a period of time could also serve as an indicator for possible overburden leakage. The reservoir and overburden geomechancial properties may have an influence on the CO2 transport and overburden ground response. Advanced modeling methods have been developed, and a significant amount of work has been performed by researchers to understand caprock integrity and the fate of injected CO2.7,16,18,24,25,42,45,47−50,54 The success of commercial-scale CO2 sequestration projects requires development of monitoring techniques (pressure and displacement measurements) and modeling approaches to investigate CO2 migration in the reservoir and its influence on the overlying geologic media. The ability to detect the activation of a pre-existing dormant fault in the caprock seal during CO2 injection, which could act as a conduit for CO2 leakage, would be essential. The detection of an existing fracture or fault being activated during CO2

long period of time could not only lead to geochemical changes that influence caprock integrity but also change fluid pressures and overburden deformations. While the caprock layer with a very low permeability and high capillary entry pressure to CO2 can ensure effectively permanent storage, the presence of geologic uncertainties, such as a fracture or fault in the caprock, may provide a channel for CO2 leakage.1,34,36,40 Several modeling efforts have been made to investigate CO2 migration and to evaluate the long-term storage potential in the presence of a hypothetical fracture/fault in the overburden strata.19,31,34,41 The presence of a caprock fracture can lead to different CO2 plume behavior during the CO2 injection and post-injection periods, and it may be possible to exploit these differences to help early detection of leaking CO2. The fluid pressure in the reservoir and surrounding layers increases when CO2 is injected into a target reservoir. These pressure increases cause changes in effective stresses and vertical displacements in the overburden. These responses could be significantly different in the presence of a permeable fracture in the caprock. Coupled flow and geomechanical modeling of CO 2 sequestration in saline aquifers was also carried out by a few researchers to investigate geomechanical issues related to the caprock (such as changes in fracture permeability because of caprock failure) and to investigate injection-induced overburden geologic response (such as ground deformations) during geologic storage.20,42−45 In addition to coupled hydromechanical modeling of CO2 storage, field monitoring studies have been carried out at potential storage sites to measure ground deformations.16,42,43,46,47 A monitoring array of high-precision tiltmeters or InSAR technology can be used in the field to measure ground deformations with a precision in the sub-millimeter range.47 In previous studies reported at the In Salah CO2 storage project site,42,46 the magnitudes and patterns of observed InSAR ground uplifts coupled with geomechanical modeling provided a great insight to the flow behavior. Development and advancement of coupled hydrogeological and hydromechanical simulators are increasing because of the growing interest in coupled thermo-hydromechanical processes.42−44,46 During large CO2 storage operations, there may also be a possibility of developing a new caprock fracture or activating a pre-existing dormant fracture/fault in the overlying caprock layers. These leakage scenarios can be caused by geologic imperfections or changes in fluid pressure resulting from CO2 injection. In a similar study,44 coupled reservoir and geomechanical simulations were carried out to investigate the potential for tensile and shear failure as a result of injection of CO2 in a multi-layered geological model. Results show that the potential for shear failure along a pre-existing dormant fracture was higher than the potential for tensile failure.44 Also, it was reported that an initial stress regime plays a significant role on the potential of mechanical failure (type and orientation of failure).44 The opening and closure of caprock fractures can also be predicted by different modeling approaches to reduce the potential risk of CO2 leakage.45 Limited studies have been reported in the published literature with reference to fault activation and fracture growth during fluid injection and CO2 storage activities.16,18,42,48−52 Possible modeling approaches for simulating a fault zone are described elsewhere.48 Advanced modeling techniques can be used to predict the fracture growth and permeability evolution during fault activation by allowing fluid flow in the fault or fracture zones.45,48,49 Coupled fluid flow and geomechanical fault slip analyses can also be used to 4233

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where ϕ is the porosity and εv is the volumetric strain. Because the pore volume and bulk volume are accounted for and change with time in deformable porous media, the updated porosity and volumetric strain are used in the constitutive equations of CMG-GEM. However, in a conventional flow simulator, the bulk volume is assumed to remain constant, ignoring volumetric strain. The mathematical equations of reservoir flow corresponding to mass conservation and energy conservation are presented below in eqs 2 and 3, respectively.56,58 In these equations, the reservoir porosity (ϕ*) is a function of true porosity (ϕ) and volumetric strain (εv). Permeability is a function of reservoir porosity (ϕ*)

injection can act as an early warning system, so that storage site operations can be modified before leaking CO2 reaches a sensitive receptor, such as a groundwater aquifer. The pressure signatures and displacement patterns may vary depending upon the number of caprock fractures/faults and their respective locations in the overburden formations. Numerical modeling work and ground monitoring tools can be useful in identifying the presence of geologic features, such as a caprock fracture or activation of an existing dormant fault, that could potentially lead to CO2 leakage. The objective of the study presented in this paper was to investigate the possibility of detection of a geologic feature, such as a caprock fracture or an activation of a pre-existing dormant fault, during CO2 injection using numerical models. In this study, pressure signatures and changes in ground deformation patterns were investigated to explore their use in detecting a caprock fracture. Several hypothetical scenarios of fractures in the caprock layer were considered to investigate the influence of a caprock fracture, fracture location, and fracture permeability on pressure and overburden geologic response. The present paper describes the modeling results for different hypothetical scenarios that could help develop monitoring systems to detect a leakage pathway in the caprock.

⎛ k ⎞ ∂ (ϕ*ρf ) − Δ⎜ρf [∇p − ρf b]⎟ = Q f ∂t ⎝ μ ⎠

⎤ ⎡ k ∂ [ϕ*ρf Uf + (1 − ϕ*)ρr Ur] + ∇⎢ −ρf (∇p − ρf b)Hf ⎥ ⎦ ⎣ ∂t μ + ∇ (κ ∇ T ) = Q h

(3)

where ϕ* is the reservoir porosity and k is the updated permeability. It was assumed that permeability is proportional to the cube of porosity based on the Kozeny−Carman model.57 The relationship is given below

2. COUPLED MULTIPHASE FLUID FLOW AND DEFORMATION ANALYSES The constitutive equations related to mathematical formulations of multiphase fluid flow in a deformable reservoir can be found elsewhere.32,55,56 An advanced compositional and greenhouse gas simulator known as “CMG-GEM” was used to model multiphase fluid flow, which is based on a finite difference approach.57 CMG-GEM is a commercially available software package developed by Computer Modeling Group.57 Geomechanics module of CMG-GEM was used with an iterative coupling method, with the objective to model coupled multiphase fluid flow and deformation analyses.56 In a conventional reservoir simulator, deformations of the porous media are not considered. Governing equations in a conventional reservoir simulator correspond to mass conservation, energy conservation, Darcy’s law, and the equation of state of fluids involved. The mathematical details of coupled flowdeformation analyses in GEM are separated out for reservoir flow and geomechanics.58 Variables, such as displacement, stress, and strain, are influenced by geomechanics, and flow variables, such as pressure and temperature, are influenced by flow equations.58 Because the modeling work uses an iterative approach to couple geomechanics with reservoir flow, flow variables are primarily computed in a compositional simulator and later sent to GEM’s finite-element-based geomechanics module to compute displacement, stress, and strain. CMGGEM was used to perform geomechanical calculations. Porosity changes caused by deformations are estimated in each time step based on the geomechanical response and are sent to compute new porosity in the flow simulator for the next time step.58 The computation model (constructed in CMG-GEM) used in this study is based on coupled fluid flow and deformations. Mathematical details of multiphase and single-phase fluid flow in porous media can be found elsewhere.59 In a deformable porous media, the conservation of fluid can be presented as56 ⎤ ⎡ k ∂ [ϕρf (1 − εv )] − ∇⎢ρf (∇p − ρf b)⎥ = Q f ⎦ ⎣ μ ∂t

(2)

⎛ ϕ ⎞3 ⎛ 1 − ϕ 0 ⎞ 2 k = ⎟ ⎜ 0⎟ ⎜ k0 ⎝ϕ ⎠ ⎝ 1 − ϕ ⎠

(4)

where k0 and ϕ0 are the initial permeability and porosity, respectively. The constitutive equation for the stress−strain relationship can be written as60 ⎛ 2G ⎞ ⎟ε δ + α pδ σij = 2Gεij + ⎜K − kk ij ij ⎝ 3 ⎠

(5)

where G is the shear modulus, K is the bulk modulus, α is a poroelastic constant, and p is the pore fluid pressure. The effective stress in the porous media can be expressed as σ ′ij = σij − αpδij

(6)

where σ′ij is the effective stress tensor, α is the poroelastic constant, p is the pore fluid pressure, and δij is the Kronecker delta. Numerical details of the model used in this study are presented below.

3. NUMERICAL METHODOLOGY In this study, finite difference and finite element methods were used to determine changes in fluid pressure and overburden deformations caused by CO2 injection at a hypothetical injection site. Figure 1 shows the schematic of a multi-layered geologic profile considered in this study with a pre-existing fractured zone or dormant fracture in the caprock, which may become activated as a result of fluid injection. The schematic consists of five geologic layers, including the overburden strata, the monitoring layer, the caprock (or seal), the target aquifer where CO2 injection is planned, and the underburden rock. Similar stratified systems were used in the published literature44,48 to investigate caprock integrity and fault reactivation during geologic sequestration of CO2. A highly permeable overburden monitoring layer (a highly permeable region similar to the target reservoir) immediately above the tight, impervious caprock layer was considered to investigate the immediate pressure response caused by the changes in fluid flow. Table 1 shows the geomechanical properties of the five layers used in the modeling study. A similar range of geomechanical properties can be found elsewhere.44,48 Single-phase and multiphase

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Figure 1. Multi-layered geologic profile of a hypothetical CO2 injection site. fluid flow modeling coupled with geomechanical effects were performed to simulate water and CO2 injection. A vertical injection in the center of the target reservoir at a differential injection pressure of 6.89 MPa (1000 psi) was used. A reservoir temperature of 107 °F was used. Hypothetical fractures were simulated at 100, 500, and 1000 m away from the injection source, and only one fracture zone was assumed to be active at any given period of time. The grid block sizes in the current model were selected to have a refined grid network near the injection and fault/fracture zone. A fault or fractured zone in the caprock layer was modeled by assuming an equivalent set of continuum solid elements. Geomechanical properties were assumed on the basis of those reported in the published literature,44,48 and no thermal effects were considered in the coupled flow and geomechanical analyses performed in this study. In our study, we used a dual-permeability model, because of its capability for simulating a fracture. It has been reported that dual-permeability models are used for saline aquifers.45 While we used a dual-permeability model, all of the fracture grid blocks (except one remote grid block) were nulled out to simulate a single-porosity system. This numerical procedure is discussed in the literature.45 In our case, the fluid communication between grid blocks is through the matrix. Three-dimensional coupled multiphase flow and displacement models (73 × 51 × 22 grid blocks) were constructed with hypothetical fracture zones in the caprock layer and can be seen in panels a and b of Figure 2. The grid block sizes were selected to have a refined grid network near the injection and fault/fracture zone. The fault/fracture zone was modeled by assuming an equivalent set of continuum solid elements. In the multiphase system, water and CO2 were selected as individual components and the dual-permeability method was used to simulate caprock fracture. Water is a default component in CMGGEM; however, the water saturation can be controlled. In a singlephase flow system, water was used as the only component to model fluid injection. The relative permeability curves were idealized for simplicity. In a single-phase flow system, water was used as the only component to model fluid injection. However, in the multiphase flow analyses, CO2 was used as an injection component in the

Figure 2. Multiphase fluid flow model. presence of water. Figure 3 shows the relative permeability curves used when CO2 was used as an injection fluid. The relative permeability

Figure 3. Relative permeability curves used in the study. curves used in this study fall in the similar range identified for different rock formations.61−63 The grid block volumes of boundary elements in the monitoring, reservoir, and caprock layers were modified with large volume multipliers to model the infinitely large lateral extent of these layers for the fluid flow model. The monitoring layer is bound by the caprock layer and the overburden layer, both of which have lowpermeability values compared to the monitoring layer. Table 1 shows the permeability values used in the study. In the geomechanic model, the outside boundary of the model was fixed. The ground surface was allowed to move freely.

Table 1. Geometric Details and Material Properties Assumed in the Modeling Study material property

overburden strata

monitoring layer

caprock seal

caprock fracture

target aquifer

underburden rock

layer thickness (m) grid top (m) grid block size, x direction (m) grid block size, y direction (m) grid block size, z direction (m) hydrostatic gradient (kPa/m) stress gradient (kPa/m) rock density (kN/m3) elastic modulus (kN/m2) Poisson’s ratio permeability porosity (fraction)

750 0 20−750 20−1000 250 9.8 22.62 22.16 5 × 106 0.3 0.1 mD 0.02

100 750 20−750 20−1000 50 9.8 22.62 22.16 5 × 106 0.3 100 mD 0.1

150 850 20−750 20−1000 75 9.8 22.62 22.16 5 × 106 0.3 1 nD 0.005

150 850 20 20−1000 75 9.8 22.62 22.16 5 × 106 0.3 100 mD 0.1

100 1000 20−750 20−1000 25 9.8 22.62 22.16 5 × 106 0.3 100 mD 0.1

1900 1100 20−750 20−1000 150200 9.8 22.62 22.16 5 × 106 0.3 0.1 μD 0.02

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4. INFLUENCE OF A CAPROCK FRACTURE ON THE PORE PRESSURE RESPONSE To investigate the influence of a fractured zone in the caprock, a permeable, linear feature was included in the caprock layer at 500 m away from the injection source, as shown in Figure 2. The width of the fractured zone was assumed to be 20 m, and the thickness of the fractured zone was assumed to be 150 m. The fractured zone is extended throughout the model in the length direction. The results presented in this section correspond to constant injection of CO2 for a period of 5 years with the inclusion of geomechanics. Figure 4 shows the

Figure 5. Pressure changes (kPa) caused by injection of CO2 with and without a simulated fractured zone in the caprock layer.

the fluid pressure in the overburden geologic layers and could have a significant impact on ground deformation behavior. A variation of pressure distribution in different layers in the presence of a simulated caprock fracture is shown in Figure 6. The pressure increase in the monitoring layer and other overburden layers above the permeable fracture helps in identifying the location of a caprock fracture.

Figure 4. CO2 migration with and without a simulated fractured zone in the caprock.

CO2 transport in the reservoir and overburden layers as a result of injection of CO2 with and without the presence of a simulated fractured zone at the end of a 5 year injection period. The injected CO2 leaks through the caprock and escapes into the overlying monitoring layer when a fractured zone is present in the caprock. The changes in fluid pressure were computed, and CO2 remains as a supercritical fluid in the overburden monitoring zone and reservoir layer. Fluid properties were determined internally in the computer code depending upon the pressure and temperature of the CO2 fluid. The injection of CO2 causes the reservoir pressure to increase with time, and the pressure increase in the monitoring layer is significant in the presence of a breach in the caprock. Moreover, the pressure distribution is nearly centered around the fracture location. Figure 5 shows the computed pressure changes in the reservoir and overburden layers caused by the injection of CO2. The CO2 migration through an existing fracture leads to changes in

Figure 6. Variation of the pore pressure (kPa) in different layers in the presence of a caprock fracture. 4236

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5. INFLUENCE OF A CAPROCK FRACTURE ON THE GROUND RESPONSE Figure 7 shows the computed vertical displacements (ground uplift) caused by injection of CO2 in the presence and absence

Figure 8. Changes in displacement (m) pattern in the presence of a simulated caprock fracture.

layer, a hypothetical fractured zone at 100, 500, and 1000 m away from the injection source was considered. Only one fractured zone was assumed to be active at any given period of time. The pressure response was observed at two separate monitoring points in the monitoring layer for different fracture locations in the caprock layer. The first monitoring point is located right above the fractured zone in the monitoring layer, and the second monitoring point represents the point right above the injection point in the monitoring layer. The first monitoring point is located at 100, 500, or 1000 m away from the injection source, to correspond to the locations of the fractures in the caprock. The second monitoring point is at the same place for all cases, regardless of the fracture location. The changes in pressure signatures at these monitoring locations can help identify the location of a fracture in the caprock layer. 6.1. Influence of the Fracture Location on Fluid Pressure Response. Figure 9 shows the changes in pressure response in the monitoring layer as a result of injection of CO2 when fractures are located at different positions in the caprock layer. The pressure distribution is symmetric about the fracture;

Figure 7. Vertical displacements (m) caused by injection of CO2 with and without a simulated fractured zone in the caprock layer.

of a simulated fractured zone in the caprock layer (fractured zone was simulated 500 m away from injection point). Ground deformations computed were comparatively smaller, and the surface deformation pattern was symmetric when no fracture was present. In the presence of a caprock fracture, surface displacements were non-circular (non-symmetric) and show an increase in the magnitudes of the vertical displacements. The increase in surface displacements may be because of the pressure increase in the monitoring and overburden layers. Also, the displacement patterns are centered nearer the fractured zone, which will be helpful in identifying the location of a caprock fracture. Magnitudes of ground displacements shown in Figure 7 are high because of assumed high permeability values of the fractured zone in the caprock layer. Figure 8 shows the influence of permeability of a fractured zone in the caprock on ground movements. The equivalent permeability of the fractured zone was varied in the range of 0.01−100 mD. Results from the figure show that the permeability of a fractured zone in the caprock layer has a significant influence on the magnitudes of vertical ground deformations. Vertical ground displacements were small when the permeability value of the fractured zone was assumed to be low.

6. INFLUENCE OF FRACTURE LOCATIONS ON PRESSURE AND GROUND RESPONSE The current paper also studies the influence of the fracture location on the pressure response and ground deformations. To study the influence of various fracture locations in the caprock

Figure 9. Pressure distribution (kPa) in the monitoring layer. 4237

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therefore, the centerline of the pressure distribution is an indication of the fracture location. Figure 10 shows the

Figure 12. Pressure changes in the monitoring layer caused by CO2 injection.

The symmetry of the pressure distribution above the fracture location is clearly seen in this figure. Therefore, the variation in the pore pressure signals in the monitoring layer could be useful in determining the location of faults/fracture zones in the caprock. 6.2. Influence of the Fracture Location on Ground Response. Figure 13 shows the influence of the fracture

Figure 10. Pressure changes in the monitoring layer right above the caprock fracture caused by CO2 injection.

influence of the fracture location at a monitoring point right above the caprock fracture in the monitoring layer. In addition to the symmetry (Figure 9), the magnitudes shown in Figure 10 are different for different fracture locations. Figure 11 shows the

Figure 11. Pressure changes in the monitoring layer right above the injection point caused by CO2 injection.

Figure 13. Surface displacements caused by CO2 injection.

change in fluid pressure at a monitoring point located right above the injection point in the monitoring layer. Results show similar trends for different fracture locations; however, the pore pressure in the monitoring layer is higher if the fracture zone is located closer to the injection source. The pressure changes over a period of time as a result of fluid flow, and the magnitude of the pressure increase is related to the injection pressure. In the current study, a limited number of monitoring points were selected to identify the location of a caprock fracture and to demonstrate fluid pressure changes at various locations with respect to distance. It was observed that the farther the monitoring point is from the injection source, the greater the magnitudes of pressure signals are reduced. Figure 12 shows the distribution of pressure in the monitoring layer for different fracture locations. A pressure increase in the monitoring layer for the no-fracture case is insignificant, as shown in Figure 12.

location on surface displacements. Results show larger magnitudes of ground deformations when a fractured zone in the caprock layer is located closer to the injection source. The variation in displacement signals as a result of the presence of fractures at different locations could also be helpful in identifying the presence of a fault/fracture zone in the caprock. In addition to these, the deformation pattern at the ground surface can also serve as a monitoring mechanism to identify and locate a potential fracture, as shown in Figure 14. Such ground deformations can also be monitored in the field by the use of high-precision ground monitoring tools, such as tiltmeters and InSAR, over a large area covering the injection zone. More details of ground monitoring tools and their applications can be found elsewhere.17,47 6.3. Influence of the Fracture Location on Pressure and Ground Response Using Single-Phase Fluid Flow. Figures 15−18 show similar behavior in the pressure response 4238

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Figure 16. Pressure changes in the monitoring layer right above the injection point in a single-phase model.

Figure 14. Displacement patterns caused by CO2 injection.

Figure 17. Pressure changes in the monitoring layer in a single-phase model.

Figure 15. Pressure changes in the monitoring layer right above the caprock fracture in a single-phase model.

and ground deformations when single-phase coupled flow and geomechanical analyses were performed by injecting water into a water-saturated reservoir. Both Figures 15 and 16 are for single-phase fluid flow models. Figure 15 shows the fluid pressure changes in the monitoring layer right above the fractured zone in the caprock layer. Figures 10 and 15 are similar, except for the magnitudes. In both cases, single-phase (i.e., water injection) and multiphase (i.e., CO2 injection) fluid flow models, the fluid was injected with a constant bottomhole pressure. Our results show that computed pressure in the case of single-phase fluid flow is lower than the computed pressure in the multiphase fluid flow. For the case of single-phase fluid flow, the amount of fluid injection is low, because of the high viscosity of water compared to CO2. For the case of multiphase

Figure 18. Surface displacements (ground uplift) in a single-phase model.

fluid flow, the computed volume of CO2 is significantly larger (approximately 5 times more) because of the low viscosity. Figure 16 shows the fluid pressure changes in the monitoring layer right above the injection point. The figures are similar but 4239

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different in magnitudes. Magnitudes of pressure increase in geomechanical cases for both the single-phase and multiphase coupled fluid flow models are lower compared to the cases without geomechanics. Patterns of surface displacements and pore pressure are distinctly different with different fracture locations. Therefore, changes in pore pressure and surface deformation at various monitoring points in the monitoring region could be used as a monitoring tool in identifying the location of a fracture that could serve as a leakage pathway during underground injection. A possible leakage scenario through an abandoned well has been discussed in a recent study.7,64 While the numerical values are different for singlephase and multiphase fluid flow models, the signature pattern in both models shows noticeable differences when a fracture is active.

7. MODELING OF ACTIVATION OF A PRE-EXISTING DORMANT FRACTURE DURING CO2 INJECTION Single-phase and multiphase fluid flow analyses coupled with geomechanics were performed to study the pressure and displacement signatures as a result of activation of an existing dormant fracture during CO2 injection. Activation of a caprock fracture located at 500 m away from the injection source was simulated after 120 days and 1 year. In the current study, when the fracture activation during CO2 injection is simulated, the permeability was altered manually in the fractured zone to allow fluid flow through the fault/fractured zone in the caprock layer. The fracture permeability was changed from 5 to 100 mD to simulate the activation of a dormant fracture/fault. Figure 19

Figure 20. Pressure changes as a result of fracture activation from a single-phase model.

8. SUMMARY AND CONCLUSION Understanding the transport of CO2 during long-term CO2 injection into a typical geologic reservoir, such as a saline or a brine aquifer, could be complicated because of changes in geochemical, hydrogeological, and hydromechanical behavior. CO2, when injected into a deep reservoir for a long period of time could not only lead to geochemical changes that influence caprock integrity but also change fluid pressures and overburden deformations. One of the key aspects in determining the long-term potential for carbon storage is the ability to detect and correct a CO2 leak before a significant volume escapes the subsurface. The two techniques described in this study, pressure testing in the monitoring layer and ground surface displacements, have the possibility of detecting the presence of a permeable fault/fractured zone in the caprock before any leakage occurs. In the current study, threedimensional coupled pore-fluid flow and geomechanic analyses were performed at a hypothetical injection site using numerical models. The pressure response in the overburden monitoring layer and the overburden ground response as a result of CO2 injection were investigated with and without a fracture zone in the caprock. Results of the study show that the presence of a fault/fractured zone in the caprock layer can significantly change the pressure response in the monitoring layer and the overburden ground response. The variation in pressure and displacement signatures as a result of the presence of a caprock fracture at different locations may be useful in identifying the presence of a fault/fractured zone in the caprock. Significant changes in fluid pressure as a result of CO2 injection may induce a new fracture or activate an existing dormant fault/fractured zone in the caprock. In the current study, a numerical approach was used to investigate the pressure response in an overlying monitoring layer as a result of the activation of a dormant fault/fractured zone in the caprock. Results of the study show a distinct change in the pressure signature in the monitoring layer when a fault/fractured zone in caprock is activated. These pressure signatures can serve as a mechanism to identify the activation of leakage pathways through the caprock during CO2 injection.

Figure 19. Pressure changes as a result of fracture activation during CO2 injection.

shows the pressure response as a result of activation of a preexisting dormant fracture during CO2 injection. Figure 20 shows the pressure response as a result of activation of a preexisting dormant fracture obtained from a single-phase fluid flow model. A distinct change in the pressure signature in the monitoring layer can be seen in Figures 19 and 20. Results of this study can certainly provide some input into the development of geophysical monitoring technologies to evaluate the long-term CO2 storage potential in deep brine/ saline aquifers. 4240

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REFERENCES

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Corresponding Author

*Telephone: 1-304-293-9946. E-mail: hema.siriwardane@mail. wvu.edu. Notes

Disclaimer: This project was funded by the National Energy Technology Laboratory, United States Department of Energy, an agency of the United States Government, through a support contract with URS Energy & Construction, Inc. Neither the United States Government nor any agency thereof, nor any of their employees, nor URS Energy & Construction, Inc., nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise, does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The work presented in this paper was performed with the funding provided by URS Energy & Construction, Inc. under RES Contract RES1000023 to support National Energy Technology Laboratory’s ongoing research in CO2 sequestration. Also, the authors greatly acknowledge the Computer Modeling Group (CMG) for their technical support.

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NOMENCLATURE σ′ij = effective stress tensor (Pa) δij = Kronecker delta α = poroelastic constant b = body force per unit mass of fluid (m/s2) G = shear modulus (Pa) Hf = fluid enthalphy (J/gmol) K = bulk modulus (Pa) k = updated permeability (m2) k0 = initial permeability ϕ0 = initial porosity ϕ = true porosity ϕ* = reservoir porosity p = pore fluid pressure (Pa) Qf = fluid flow rate Qh = loss or gain of heat (J) T = temperature (C) Uf = internal energy of fluid (J/gmol) Ur = internal energy of rock (J/m3) x = horizontal distance (m) z = vertical depth (m) ε = strain tensor (m/m) εv = volumetric strain (m/m) κ = hardening parameter μ = fluid viscosity (Pa s) ρf = density of fluid (kg/m3) ρr = density of solid rock (kg/m3) 4241

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