Evaluation of Stress And Geomechanical Characteristics of Rocks At Penn West's Pembina CO-Enhanced Oil Recovery Pilot Operation

Abstract The capture and geological storage of CO2 is emerging as a viable option to reduce emissions of greenhouse gases into the atmosphere, and CO2-enhanced oil recovery (EOR) is a potential process for long-term CO2 storage. The safety of CO2 storage is critically important because decision and policy makers, regulatory agencies and the public must be assured that these operations are safe and that CO2 has been removed permanently from the atmosphere. Several pilot CO2-EOR operations in Alberta have been initiated with support from both the provincial and federal governments, among them Penn West Energy Trust's pilot in the Pembina field, located from 5- 12-048-09W5 to 10-11-048-09W5, where a multidisciplinary research program is being currently conducted. Among the subjects of investigation are the stress and geomechanical properties of the rocks, which are decisive elements in evaluating the safety of CO2 injection and storage. This paper includes an assessment of the stress regime of the Pembina oil field and a review of the relevant rock properties. Introduction One of the major issues affecting the successful capture and geological storage of CO2 is the minimization of the potential for CO2 leakage. Leakage may occur through faults and fractures, natural or induced. These potential CO2 leakage paths are controlled by geomechanical parameters, such as the in-situ stress regime, rock stiffness and rock strength, and the integrity of the wellbore seal. The Penn West Energy Trust CO2-EOR pilot is located southwest of Edmonton in the Pembina Field (Figure 1). Penn West is injecting CO2 into the Upper Cretaceous Cardium Formation sandstone at an approximate depth of 1650 m. Overlying and underlying the Cardium sandstone and conglomerate are thick sequences of Colorado Group shale. The stress and geomechanical characterization was performed on a regional scale covering the Pembina Field (Figure 1). Stress Regime Regional-scale studies of the stress regime indicate that in southern and central Alberta the vertical stress (Sv) is the largest principal stress, being greater than the maximum horizontal stress (SHmax) (Bell and Bachu, 2003). The estimation of the minimum horizontal stress (SHmin) and Sv in a well provides loose lower and upper bounds for the fracturing pressure in that well. The Sv magnitude is calculated by integrating the bulk density log from ground surface to the depth of interest. In the Pembina field there are six wells that have been analyzed for Sv (Figure 2). The trend of the Sv magnitude follows the trend of formation depth, which increases from northeast to southwest. The Sv gradient ranges between 22.2 kPa/m and 24.2 kPa/m. The minimum horizontal stress can be evaluated using a variety of tests. The most accurate method for estimating the magnitude of the SHmin is through micro-fracture testing, but mini-fracturing, leak-off tests and fracture breakdown pressures are also used (Bell, 2003; Bell & Bachu, 2003). Given that horizontal stress magnitudes tend to decrease as reservoir pressure is depleted, it is necessary to account for depletion effects when interpreting data from any of these tests.

Fetched live from OpenAlex and de-inverted. Abstracts are not stored in this database: the inverted indexes are 8.6 GB of the frame’s 9.3 GB of text, and the host has 13 GB free.