**2. Construction of the flow, thermal and geomechanical model**

A coupled flow, thermal, and geomechanical model has been developed in order to study the thermo-elastic and poro-elastic response of the injection and surrounding layer to increasing of pressure and reduction of temperature after CO2 injection. Ohio River valley is located in a relatively stable, intraplate tectonic setting and the regional stress state is in strike slip faulting regime with the maximum stress oriented northeast to east-northeast [7].

This study used the fluid and rock mechanical properties provided by Lucier et al. [8]. The stratigraphic sequence of the geological layers in the study area and the relative location of the potential injection layer, Rose Run Sandstone (RRS) at the Mountaineer site is shown in Figure 1. RRS has an average thickness of 30 m and is extended from 2355-2385 m. The direction of maximum and minimum horizontal stresses is reported to be in N47E(±13) and N43W (±13) respectively [8]. All the models in this study are aligned along these directions, in order to avoid having initial non-zero value of shear stresses in principal stress directions.

Our results show that shortly after injection, the induced expansion in caprock lead to slight increase of total stresses (poroelasticity) which will reduce the chance of shear failure. However as soon as total minimum stress in the caprock decreases due to thermal diffusion between the reservoir and caprock, thermoelasticity dominates and the chance of shear failure increases in

Incorporation of thermal effects in modeling of CO2 injection is significant for understanding the dynamics of induced fracturing in storage operations. Our work shows that the injection capacity with cold CO2 injection could be significantly lower than expected, and it may be impractical to avoid induced fracture development. In risk assessment studies inclusion of the

Past storage pilot projects and enhanced oil recovery efforts have shown that, geologic sequestration of CO2 is a technically viable means of reducing anthropogenic emission of CO2 from accumulating in the atmosphere [1,2,3]. Security of storage is one of the most important concerns with the long term injection of CO2 in underground formations. Injection of CO2 induces stress and pore pressure changes which could eventually lead to the formation or reactivation of fracture networks and/or shear failure which could potentially provide pathways for CO2 leakage through previously impermeable rocks [4]. Therefore geomechan‐ ical modeling plays a very important role in risk assessment of geological storage of CO2.

In order to determine whether the induced stress changes compromises the ability of the formation to act as an effective storage unit, a geomechanical assessment of the formation integrity must be carried out. In our previous work, we have studied the dynamic propagation of fracture in the Rose Run sandstone reservoir in Ohio River valley under isothermal [5] and thermal condition [6] for injection above fracture pressure. In this paper, the thermal effect of injection on the possibility of tensile and shear failure in the reservoir and caprock are studied for injection below fracture pressure. This study utilized a fully coupled reservoir flow and geomechanical model which allows accounting for poroelastic and thermoelastic effects and

To examine the possibility of shear failure in the caprock, Mohr-Coloumb Criteria was used.

A coupled flow, thermal, and geomechanical model has been developed in order to study the thermo-elastic and poro-elastic response of the injection and surrounding layer to increasing of pressure and reduction of temperature after CO2 injection. Ohio River valley is located in a relatively stable, intraplate tectonic setting and the regional stress state is in strike slip faulting

**2. Construction of the flow, thermal and geomechanical model**

regime with the maximum stress oriented northeast to east-northeast [7].

thermal effects will help prevent the unexpected leakage in storage projects.

the caprock.

946 Effective and Sustainable Hydraulic Fracturing

**1. Introduction**

can model static and/or dynamic fractures.

**Figure 1.** Generalized stratigraphy of the study area at the Mountaineer site. The well location and the general stratig‐ raphy intersected by well is illustrated in the picture. The black box shows the boundaries of the area of previous work by Lucier et al., [8], Modified from [9]

The developed element of symmetry model that covers 8000x8000x2575 m of study area, has 50x50x9 grid block in x, y and z directions respectively. The injection well is located at the top left corner of this model. RRS was gridded into three layers with 5, 10 and 15 m thickness. The adjacent Beekmanton Caprock was refined into 3 layers (10, 50 and 126 m) to capture and predict the potential growth of fracture through this layer (and the resulting possibility for CO2 leakage). The horizontal and vertical permeability of the caprock layers in the model are given as 2E-10 and 1E-10 md resepectively. Average properties of 5%, 20 md and 10 md for porosity, horizontal and vertical permeability were given to the injection layer. These values are the probability averages of the given property distributions for Rose Run sandstone formation [8]. The initial pressure and temperature of the RRS is 26000 kPa and 63.1 C. The fluid flow is modeled by two-phase flow with dissolution of CO2 in water. Van Genutchen function with an irreducible gas saturation of 0.05, an irreducible liquid saturation of 0.2 and an exponent of 0.457 was used to generate relative permeability data [10].

mechanism for containment of fractures to the target zone. This initial stress contrast is very critical when considering fracture propagation in the reservoir layer for enhancing injectivity while avoiding the risk of fracture growth through upper caprock layers. As mentioned before, since the temperature of injected CO2 (at approximately 30 deg C) is smaller than the formation temperature (at 60 deg C), thermal effects of injection on fluid flow and geomechanics must be included in the model. This coupling is achieved by solving the energy balance equation within the fluid flow model, and including the thermoelasticity term in the geomechanical

Thermal Effects on Shear Fracturing and Injectivity During CO2 Storage

http://dx.doi.org/10.5772/56311

949

0 20 40 60 80 100

Pressure(Mpa) Minimum Stress(Mpa) Vertical Stress(Mpa) Maximum Stress(Mpa)

The average thermal properties for the rock, as well as injected and in-place fluids used for

The boundary condition for the fluid flow model is that there is no flow across the boundary of the model. The constraints for the geomechanical model are as follows. The right and left sides of the model are fixed in the x-direction so there would be no displacement in the xdirection. The front and back sides of the model are fixed in Y direction. The bottom side of the model is fixed in vertical direction and the top of the model is free to move in all directions. Stresses were initialized according to data in Fig. 2. All injections are done through a single

Volumetric Thermal Expansion Coefficient (1/deg K) 5.4E-6 2.1E-4 3.003E-3 Heat Capacity(Kj/Kg deg K) 0.9 4.182 0.84 Thermal Conductivity(W/ m deg K) 2.34 0.65 0.084

**Rock Water CO2**

model (included in the constitutive model of the rock).

Caprock (Beekmantown Dolomite) Reservoir (RRS)

**Figure 2.** Initial pressure, horizontal and vertical stress profile in Ohio River Valley [8]

this study are listed in Table 2 [8,11-14].

**Table 2.** Thermal properties of fluids and rock

vertical well with constant injection rate.

The mechanical properties and initial stress profile is required to be added to the geomechan‐ ical model and coupled with the flow model in order to be able to study the mutual effect of pressure and stresses and the resulting effect on fracture propagation and injectivity. The mechanical properties for this model are listed in Table 1. The listed value with the exception of grain Modulus are all extracted directly from Lucier et al. paper [8]. Grain modulus was back- calculated from the given Biot constants and Young's Modulus. The Biot constant *α* is important for computing the effects of pressure changes on stress. At the Mountaineer site, Lucier et al. estimated *α* to be very low - in the range of 0.03 to 0.2. In this analysis, a mean value of 0.11 was used to calculate the poroelastic effects. The formation rock density is assumed to be 2500 kg/m3 [8].


**Table 1.** Rock Mechanical properties of the coupled model

The initial pressure, horizontal and vertical stress profile for different depths in Ohio River Valley is shown in Figure 2. It is important to note that the horizontal stresses are lower in RRS (the injection layer) than in the surrounding layers. This is a common behavior due to generally having larger Poisson's ratio for the surrounding layers than the reservoir. In many situations the stresses in caprock (low permeability rock) are larger than in the reservoir (permeable formations), because of differences in Poisson's ratio, material properties, stress history and other factors. This is well documented in hydraulic fracturing literature and is the primary mechanism for containment of fractures to the target zone. This initial stress contrast is very critical when considering fracture propagation in the reservoir layer for enhancing injectivity while avoiding the risk of fracture growth through upper caprock layers. As mentioned before, since the temperature of injected CO2 (at approximately 30 deg C) is smaller than the formation temperature (at 60 deg C), thermal effects of injection on fluid flow and geomechanics must be included in the model. This coupling is achieved by solving the energy balance equation within the fluid flow model, and including the thermoelasticity term in the geomechanical model (included in the constitutive model of the rock).

**Figure 2.** Initial pressure, horizontal and vertical stress profile in Ohio River Valley [8]

The average thermal properties for the rock, as well as injected and in-place fluids used for this study are listed in Table 2 [8,11-14].


**Table 2.** Thermal properties of fluids and rock

The developed element of symmetry model that covers 8000x8000x2575 m of study area, has 50x50x9 grid block in x, y and z directions respectively. The injection well is located at the top left corner of this model. RRS was gridded into three layers with 5, 10 and 15 m thickness. The adjacent Beekmanton Caprock was refined into 3 layers (10, 50 and 126 m) to capture and predict the potential growth of fracture through this layer (and the resulting possibility for CO2 leakage). The horizontal and vertical permeability of the caprock layers in the model are given as 2E-10 and 1E-10 md resepectively. Average properties of 5%, 20 md and 10 md for porosity, horizontal and vertical permeability were given to the injection layer. These values are the probability averages of the given property distributions for Rose Run sandstone formation [8]. The initial pressure and temperature of the RRS is 26000 kPa and 63.1 C. The fluid flow is modeled by two-phase flow with dissolution of CO2 in water. Van Genutchen function with an irreducible gas saturation of 0.05, an irreducible liquid saturation of 0.2 and

The mechanical properties and initial stress profile is required to be added to the geomechan‐ ical model and coupled with the flow model in order to be able to study the mutual effect of pressure and stresses and the resulting effect on fracture propagation and injectivity. The mechanical properties for this model are listed in Table 1. The listed value with the exception of grain Modulus are all extracted directly from Lucier et al. paper [8]. Grain modulus was back- calculated from the given Biot constants and Young's Modulus. The Biot constant *α* is important for computing the effects of pressure changes on stress. At the Mountaineer site, Lucier et al. estimated *α* to be very low - in the range of 0.03 to 0.2. In this analysis, a mean value of 0.11 was used to calculate the poroelastic effects. The formation rock density is

**(kpa)**

Shale-Surface 1911 6.00E+07 0.29 5.25E+07 Limestone-1911 253 7.05E+07 0.3 6.61E+07 Dolomite-2164 186 8.96E+07 0.28 7.51E+07 Rose Run Sandstone-2350 30 8.73E+07 0.25 6.53E+07 Dolomite-2380 195 9.47E+07 0.28 8.05E+07

The initial pressure, horizontal and vertical stress profile for different depths in Ohio River Valley is shown in Figure 2. It is important to note that the horizontal stresses are lower in RRS (the injection layer) than in the surrounding layers. This is a common behavior due to generally having larger Poisson's ratio for the surrounding layers than the reservoir. In many situations the stresses in caprock (low permeability rock) are larger than in the reservoir (permeable formations), because of differences in Poisson's ratio, material properties, stress history and other factors. This is well documented in hydraulic fracturing literature and is the primary

**Poisson's Ratio**

**Grain Modulus (Kpa)**

an exponent of 0.457 was used to generate relative permeability data [10].

assumed to be 2500 kg/m3

948 Effective and Sustainable Hydraulic Fracturing

[8].

**Table 1.** Rock Mechanical properties of the coupled model

**Layer-top depth (m) Thickness (m) Young's Modulus**

The boundary condition for the fluid flow model is that there is no flow across the boundary of the model. The constraints for the geomechanical model are as follows. The right and left sides of the model are fixed in the x-direction so there would be no displacement in the xdirection. The front and back sides of the model are fixed in Y direction. The bottom side of the model is fixed in vertical direction and the top of the model is free to move in all directions. Stresses were initialized according to data in Fig. 2. All injections are done through a single vertical well with constant injection rate.
