Stress Path Evolution during Fluid Injection into Geological Formations

Abstract:

Safe injection of a fluid, like carbon dioxide (CO₂), into geological formations is an essential part of CO₂ storage and enhanced oil recovery (EOR) projects. Injection causes pressure changes inside the reservoir, thus changing effective and total stresses inside and outside of the reservoir. These changes can bring the reservoir and/or its surroundings to failure conditions. The existence of faults and weak zones increases the likelihood of failure in rock masses depending on the amount of the injection-induced changes and the formation properties. This paper discusses the stress changes in different reservoir and injection conditions. To do so, an in-house numerical code (MDEM) was used. Analysis indicates that the pressure buildup can significantly change the total and effective stresses. Also, the presence of a fault can influence the stress changes at the fault vicinity, both in the cap rock and the upper portion of the reservoir depending on the fault properties and the in situ stress regime. Simulation results show that the upper portion of the reservoir and the cap rock experience a greater decrease in the mean effective stresses and a greater increase in the deviatoric stress in the footwall of the fault in reverse faulting stress regime. This means that the presence of faults can bring some parts of the reservoir and the cap rock to a more unstable condition. But this does not necessary mean that the fault is unstable itself. Analysis indicates that due to injection, i.e., unloading of the reservoir, faults can deform elastically and the pore pressure difference between the reservoir and the cap rock and/or underlying layer leads to different stress changes compared to the reservoir center.

Introduction

Fluid injection operations related to geo-energies are becoming more frequent. Geo-energies aim at significantly reducing carbon dioxide (CO₂) emissions to the atmosphere to mitigate climate change. In particular, carbon capture and storage (CCS) has been proposed as one of the most feasible options in the short-term to reduce CO₂ emissions (IEA, 2010). Nevertheless, the cost of CCS may hinder the deployment of CCS projects. Thus, giving an additional value to CO₂ injection through its utilization to obtain an economic benefit will motivate CO₂ storage in the subsurface. An option of carbon capture, utilization and storage (CCUS) is enhanced oil recovery using CO₂ (CO₂-EOR), as it has been done at Weyburn, Canada, since 2000 (Verdon et al., 2011).

Most of the research involving geomechanics related to geologic carbon storage considers extensive aquifers without including faults (e.g., Gor et al., 2013; Vilarrasa, 2014; Goodarzi et al., 2015). However, the pressure perturbation cone will extend over large distances (up to hundreds of km) for the duration of CO₂ injection, which is planned to last over several decades (Birkholzer et al., 2009; Vilarrasa and Carrera, 2015). Thus, faults present in the far-field will be affected by injection. Additionally, the available storage formations will not always be extensive and injection may have to be done in reservoirs limited by faults (Castelletto et al., 2013), like at Snøhvit, Norway (Hansen et al., 2013). Furthermore, mature oil reservoirs for CO₂-EOR are usually compartimentalized, so the assumption of extensive formation may not be applicable.