Ohio River Valley is considered a potential site for CO 2 storage since it is in close proximity to large CO 2 emitters in the area. In a CO 2 storage project, the temperature of the injected CO 2 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 CO 2 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 CO 2 storage while improving the injection capacity. Incorporation of thermal effects in modeling of CO 2 injection is significant for understanding the dynamics of induced fracturing in storage operations. Our work shows that the injection capacity with cold CO 2 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.

Ensuring long-term containment of CO2 is critical for a safe geological storage of carbon. Although Carbon Capture and Storage (CCS) is feasible in depleted hydrocarbon fields, it can pose significant risk to safety and the environment if its containment is not ensured. An integrated geomechanics workflow to evaluate caprock integrity is presented in this paper. This approach integrates reservoir simulation which typically computes variation in formation pressure and temperature with geomechanical simulation which models variation in stresses. Coupling between these two simulation modules is done iteratively until an equilibrium state between formation pressure and stress is achieved within a given tolerance. The efficiency of this approach is demonstrated through a case study of a proposed carbon storage site in Canada where an injection rate of 600 tonne/day for 25 years is planned.

The RSE-1 well operated by Total is located within the Rousse field in the southwest of France. The 43 year old, depleted gas well has undergone extensive research in order to determine its suitability for CO 2 storage. The main objective, in terms of containment, is to avoid the injected CO 2 migrating back to the atmosphere or reaching potable aquifers, either through the well or the caprock itself. Openhole data from 43 years ago consisted only of 1-arm caliper and compressional sonic data. In order to predict geomechanical effects on the formation from production or CO 2 injection, sonic shear data was acquired to compute elastic properties and the direction of maximum horizontal stresses in anisotropic zones. Breakout orientations from multi-arm/finger-calipers, corresponding to the minimum horizontal stress direction are used to improve the geomechanical analysis, especially in areas of strong stress anisotropy. This paper focuses on the acquisition of good quality stress data through casing essential for a geomechanical analysis of the caprock using sonic and cement/borehole imaging tools. Since azimuthal sonic data is very sensitive to acoustic anisotropy, the available log was processed together with directional survey data to reveal a 75m-thick stress-induced anisotropic zone in the lower part of the caprock. The fast shear azimuth, which is associated with maximum horizontal stress direction as dispersion curves show the sonic anisotropy being the result of a horizontal stress imbalance, suggested a ENE-WSW compression. Evaluation of 3-D cement imaging data showed borehole breakouts along most of the annulus. The cement thickness map is equivalent to a 36-arm caliper through casing and the computed maximum hole diameter correlates well with the 1-arm openhole caliper data acquired 43 years ago. The associated breakout direction within the zone of anisotropy was determined to vary between NNW-SSE and NNE-SSW. The fast shear azimuth computed during sonic processing is approximately perpendicular to the breakout direction acquired from the borehole images within the 75m-thick anisotropic zone. The overall NNE-SSW compression was confirmed by other well geometry data from the region. These results suggest that both measurements complement each other very well in a cased-hole environment and could be further used for geomechanical modeling.

Abstract A mechanical earth model (MEM) and wellbore stability analysis were completed for a CO 2 injection well in the Eau Claire shale where in offset wells, severe borehole enlargements were experienced. This shale serves as a caprock for the Mt. Simon injection zone in the planned CO 2 injection well and therefore, borehole enlargement had to be minimized to provide zonal isolation and containment for injection. After drilling the CO 2 injection well, a comparison was made between the predrill prediction and actual results. Borehole enlargement was experienced at depths predicted by the predrill model, but borehole enlargement severity was minimized with improved drilling practices. To determine the formation stability, an MEM was built using offset well data and was calibrated with both borehole and regional data. Multiple stress models were examined, and calibration for unconfined compressive strength (UCS) values was provided from core tests in other wells. After calibration, the data was correlated to the planned well trajectory using formation tops, and the stresses were recalculated. The largest areas of uncertainty in the predrill prediction existed in the Eau Claire shale UCS and the maximum horizontal stress magnitude. Available shale core testing for UCS was likely biased toward stronger intact samples. The principle stress ordering and magnitudes from offset well testing showed a shallow thrust fault environment with deeper strike-slip environment. Increasing mud weight to reasonable levels would not prevent shear failure in the Eau Claire shale as predicted by the models. Therefore, it was important to monitor the wellbore while drilling through the shale and mitigate borehole enlargement. For monitoring borehole enlargement, material across the shakers from the drilling process was examined for cavings. Digital pictures of the rock cuttings/cavings samples were taken before reaching the Eau Claire shale and through the interval. Mechanical vibration and backreaming were kept to a minimum across the Eau Claire shale while this section was open to minimize borehole enlargement. Introduction Geological sequestration of CO 2 is being tested on several projects as part of a collaborative effort between the U.S. Department of Energy and private backers. In one project, the target injection formation is the Mt. Simon Sandstone, a saline water-bearing formation at 6,500 ft below the surface. The predrilling estimate of Mt. Simon's thickness was 1,200 to 2,000 ft with the upper part of the formation expected to have an average of 11% porosity and a 20-mD permeability, with the lower arkose zone possibly having a permeability over 1 D. In the proposed injection well, the Eau Claire shale just above the Mt. Simon sandstone provides the geological seal for injected CO 2 . Many offset wells in the area were known to have borehole enlargement problems in Eau Claire shale. As part of the predrill planning for the injection well, an analysis was made to determine the safe mud-weight window that would prevent borehole failure. Vertical containment will be monitored in the St. Peter Sandstone just above the Eau Claire shale.