A debate rages as to whether abandoned oil and gas wells have to be sealed to prevent methane leakage – a potent greenhouse gas – or whether the valuable infrastructure can be repurposed for environmental benefit. One viable solution is to repurpose such wells for the recovery of low-grade geothermal energy and simultaneously produce a revenue stream, staunch fugitive emissions and maintain workforce engagement. This avoids the major upfront costs of drilling and significant risks of non-transmissive reservoirs that remain major obstacles in the development of geothermal energy. Regions of extensive hydrocarbon exploration are often close to market and with significant geothermal gradients. Repurposing must accommodate local energy demand, potential markets, existing infrastructure and technical challenges. So far, most studies have been scattered or focused on the viability of converting a specific oilfield. This work integrates the accomplishments and key challenges faced from projects that converted hydrocarbon production in geothermal renewable energy and establish guidelines to assist future projects. Conversion strategies are discussed for open-loop systems with co-production and enhanced geothermal systems and for true closed-loop systems. Five key challenges relate to well selection, data availability, underground infrastructure, well integrity and regulatory factors. Potential challenges in inspection and preparation of these wells in terms of well integrity and productivity with possible remedies are also discussed. Pilot projects and feasibility studies that have been performed worldwide confirm the viability of this concept but at low efficiency, paving the way for future innovations in this area.

Hydrocarbon exploration and exploitation may occur in challenging environments, which require innovative solutions to lower the costs and risks of operations. SMPs are finding an increasing number of applications in the upstream oil & gas industry, where they respond dynamically to changes in downhole temperature. This article will provide readers with a review of the fundamentals of oil & gas operations, including drilling, completion and stimulation of wells, and a comprehensive coverage of design and testing of SMPs for each operation.

Proper zonal isolation is key to ensure optimum injection and production and it is highly dependent on the cement bond to the casing and the formation. Yet, in most wells, cement evaluation logs are not run. This work will describe a workflow to address the lack of cement evaluation data by creating synthetic logs to aid wellbore integrity analysis. Synthetic logs can be a reliable and cost-effective alternative to predicting the cement bond than running log tools in every well during a drilling campaign, and, with further development, has the potential to be used for well design. A machine learning framework based on Gaussian process regression (GPR) was chosen in the development of this procedure because it can assess uncertainty of the cement bond through estimation of error and confidence interval. GPR also require less training samples than conventional machine learning techniques. In this work CBL data was used for training and the model was validated through comparison with data from a different well in the same field. The results shows that the predicted case correlated very well with the base case, with some curves overlaying even in the poor bond sections. Initial assumptions given by the covariance function help capture not only the general trend relationship but also localized variations, which play a major role in the way a fracture propagates in the annulus. Additionally, the uncertainty assessment provided by this framework can assist risk management by determining worst case scenarios and potential fluid migration paths in the annulus.

Methane leakage due to compromised wellbore cement integrity may result in operational complications and environmental contaminations in oil and gas wells. In this work, the problem of fluid-driven fracture propagation at the cement interfaces is revisited by a thorough and comprehensive consideration of the non-uniform cement bonding to the formation along the wellbore. While previous works were mainly focused on discharge without attention to mechanical failure or mechanical failure without ties to seepage rate; here, we couple these two analyses to provide a practical aspect of this approach. As revealed by cement evaluation logs, the quality of the cement behind the casing varies and may include flaws in the form of channels or pockets of mud residuals. A novel methodology, initiated with laboratory-scale cement bonding properties using the push-out test, is introduced to estimate the cohesive properties of the cement interface, considering mud removal and mud residuals in the rock. Then, the measured cohesive properties are applied to a field-scale numerical model with an embedded cohesive layer between cement and formation to evaluate the susceptibility of the wellbore to develop cement debonding. The excessive fluid pressure at the casing shoe is assumed to be the source for the fracture initiation. The proposed numerical model has been tested against actual sustained casing pressure (SCP) field tests for validation purposes. This model may estimate the geometry of leakage pathways and predict leakage flowrate within acceptable ranges. The effect of several key factors in the development of SCP due to the cement debonding is investigated. The results show that the early stage of SCP buildup is controlled by the cohesive properties of the cement interfaces (i.e., cement properties), but the cohesive properties have minor effects on the stabilized pressure. The method proposed herein presents a method to evaluate the cement bond quantitatively to be further integrated into cement design.