Thermal Contribution in Fault Stability Assessment During Fluid Injection: Improvement of the Analytical Probabilistic Approach of an In-House Tool
Authors: Petroselli S. , Stiz A. , Brignoli M. , Monaco S. , Marton F. , Grilli D. , Facchi G. L. D. , Bottazzi F. , Mantica S. 
Published: August 2024

Among the geomechanical aspects associated to the fluid injection in a reservoir, the effective stress reduction due to a cold fluid may be critical for the fault stability. To account for this aspect, Eni has implemented the thermal contribution in the in-house SAFE tool used for the fault stability assessment associated to injection projects. The validation of this feature has been carried out using Perkins and Gonzales (1984) model as a benchmark, considering a hypothetical vertical fault at a certain distance from the injection well, and oriented perpendicularly to the minimum horizontal stress direction. The results in terms of stress have been compared to a 2D Finite Element Abaqus simulation of the same case, previously validated with the benchmark. Finally, the unfavorable impact of the thermal aspect when a fluid colder than the rock mass is injected in a formation has been analyzed through a synthetic case.

1. INTRODUCTION

One of the most critical challenges related to the actual problem of global climate change is to find an environmentally and economical solution to immediately reduce greenhouse gases emissions, particularly the carbon dioxide (CO2). To this aim, CO2 capture and storage (CCS) in deep geologic formations, such as depleted oil and gas reservoirs or deep saline aquifers, will have a crucial role in reducing gas emissions. To implement CCS on the scale needed to make noticeable changes, geological media suitable for gas storage must have sufficient capacity and injectivity, and a comprehensive understanding of their hydrologic-geochemical-geomechanical is needed to ensure the confinement for the lateral or vertical migration of CO2 to the surface (Rutqvist, 2012).

The importance of geomechanics associated to carbon storage started to be recognized in the 2000s, when studies of actual CO2 injection sites have shown that significant geomechanical changes may indeed occur, depending on the injection conditions and the site-specific properties (Rutqvist et al., 2010). Among all known phenomena related to fluid injection, rock integrity and fault stability are key factors to be evaluated for reservoir development. Fault reactivation and associated induced seismicity have been observed in many water injection projects in the US, where the earthquake rate increase, since 2001, is due to the injection of water resulting from hydraulic fracturing operations in nearby disposal wells. High CO2 injection pressures can induce fluid driven fractures as well, triggering displacements along pre-existing faults and generating seismic events (Ellsworth, 2013). Moreover, the injection of a fluid with different temperature than the formation temperature leads to a thermal effect on the geomechanical integrity, adding a stress variation that could alter the fault resistance. More specifically, once the fluid is injected, rock usually cools down in the area around the well. In this condition, within the cooled zone, horizontal earth tension decreases as a result of the formation rock contracting (Perkins & Gonzales, 1984; Kim & Hosseini, 2017).