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Abstract
Ohio River Valley is considered a potential site for CO2 storage since it is in close proximity to large CO2 emitters in the area. In a CO2 storage project, the temperature of the injected CO2 is usually considerably lower than the formation temperature. The heat transfer between the injected fluid and rock has to be investigated in order to test the viability of the target formation to act as an effective storage unit and to optimize the storage process.

A coupled flow, geomechanical and heat transfer model for the potential injection zone and surrounding formations has been developed. All the modeling focuses on a single well performance and considers induced fracturing for both isothermal and thermal injection conditions. The induced thermal effects of CO2 injection on stresses, displacements, fracture pressure and propagation are investigated. Possibility of shear failure in the caprock resulting from heat transfer between reservoir and the overburden layers is also examined.

Displacements will be smaller for the thermal model compared to isothermal model. In the thermal case, the total minimum stress at the wellbore decreases with time and falls below the injection pressure quite early during injection. Therefore, fracturing occurs at considerably lower pressure for the thermal model. The coupled thermal and dynamic fracture model shows that thermal effects of injection could increase the speed of fracture propagation in the storage layer depending on the injection rate. These phenomena are dependent primarily on the difference between the injection and reservoir temperature.

An optimization algorithm for injection temperature is discussed based on limiting the maximum fracture length and minimizing the risk of leakage from thermal effects of CO2 storage while improving the injection capacity.

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 thermal effects will help prevent the unexpected leakage in storage projects. The methodology developed will play an important role in process optimization for maximizing the injection capacity while maintaining the safety of storage.

Introduction
Ohio River Valley, located adjacent to the Mountaineer power plant in New Haven, West Virginia, is considered for saline aquifer geological storage of CO2. This valley is in a relatively stable, intraplate tectonic setting and the regional stress state is in strike slip to reverse faulting regime with the maximum stress oriented northeast to east-northeast. (Lucier et al, 2006).

Based on current sequestration pilot projects and enhanced oil recovery efforts, evidence suggests that geologic sequestration is a technically viable means to significantly reduce anthropogenic emissions of CO2 (Solomon, 2006; Preston et al., 2005; Wright, 2007) Once CO2 is injected, the pressure and temperature of the formation is affected by the mass and heat transfer between the injected and in place fluid. These changes have geomechanical consequences on stresses, displacements, fracture pressure and its propagation. Since injected induced geomechanical effects could lead to formation or reactivation of fracture network, rock shear failure and fault movements which could potentially provide pathways for CO2 leakage, geomechanical modeling plays a very important role in risk assessment of geological storage of CO2.