Comparison of Mud Pressures Predicted with Different Constitutive Models in Anisotropic Shale Rocks

Depleted oil and gas fields are good targets for gas storage both in offshore and onshore environments. Carbon capture and sequestration (CCS) must repurpose existing rigs to drill new wells cost-effectively. The integrity of the well is crucial for successful carbon dioxide sequestration. During the drilling phase, well integrity involves preventing not uniform wellbore wall geometry induced by local rock failures and ensuring that cave-ins and washouts do not occur. The post-drilling experience in depleted fields can undoubtedly help selecting mud pressures to avoid instability when drilling new wells. The cap of most depleted fields is composed of shale rock that often exhibits variation in strength properties along and across the lamination planes and has been responsible for the major source of instability [Carey & Torsæter, 2019; Mehrabian et al., 2019]. The mechanical properties of shale at significant depths are hard to ascertain [Steiger & Leung, 1992]. Although laboratory tests provide accurate assessments, retrieving cores from deep wells is challenging due to potential alterations during retrieval and specimen preparation. Shale cores can undergo changes in pressure, temperature, and oxidation state as they are brought to the surface, which can affect their properties [Basu et al., 2020]. Cores retrieved from wells may be limited and damaged, making it difficult to obtain reliable mechanical property data directly from them [Josh et al., 2012]. Alternatively, mechanical properties can be obtained from laboratory tests conducted on outcropping formations similar to those found in the subsurface [Risnes, 2001]. Mechanical properties at depth are often inferred indirectly using correlations with log data and microscopic models [Abousleiman et al., 2007, Woehrl et al., 2010]. These correlations are empirical equations used to establish continuous profiles of elastic constants and strength parameters (Mandal et al. 2021]. Empirical relationships derived from log data are typically valid within specific geological settings, reflecting the conditions of the region where they were established. Additionally, the transverse isotropy of shale, a common characteristic in many formations, is often not specifically addressed in indirect approaches. This can lead to challenges in accurately characterizing the mechanical behavior of shale formations, particularly in situations where transverse isotropy significantly influences rock behavior. The low permeability of saturated shale rock indeed has implications for wellbore stability, especially immediately after drilling. When drilling through shale formations, the drilling process can disturb the equilibrium of pore fluid pressure within the rock, leading to undrained conditions in the short term. The undrained pore fluid pressure evolution can enhance plasticity around the wellbore [Asaka & Holt 2021; Vales et al. 2004; Aoki et al., 1993; Holt et al. 2014; Detournay & Atkinson, 2000; Deangeli & Marchelli, 2022; Tran et al., 2022]. All the previous considerations evidenced the difficulty and uncertainties related to the prediction of mud pressures in wellbore drilled in transversely isotropic shales. To reduce uncertainties on mud pressure prediction, there is the need of properly investigate the mechanical response of anisotropic shales during drilling operations. By integrating multiple models, engineers can gain a deeper understanding of the complex interactions between different factors influencing shale behavior. This enables them to anticipate potential challenges and hazards during drilling and wellbore operations, leading to more proactive risk mitigation strategies.