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Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results. The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis. The final development option to be chosen depends on a traditional NPV analysis.
Waterflooding can lead to substantial incremental oil production. Implementation of water injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection induced fractures extending into the caprock. If this risk is seen as "Intolerable" in an As Low As Reasonable Practicable (ALARP) analysis a decision may be made to not proceed with the project., In this study we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes and fracture propagation in the sand and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Monte-Carlo simulations considering a set of modelling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters where the risk of fracture height growth was acceptable. Our simulations also allowed us to identify important factors that impact caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk of the caprock integrity is reduced. This requires introducing a limit for the Bottom Hole Pressure (BHP) including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parametrisation of the model, sampling from the distribution of parameters and distance-based Generalized Sensitivity Analysis (dGSA) as well as probabilistic representation of the results. The dGSA can be used to determine which parameter has a strong impact on the BHP and hence the project and should be measured if warranted by a Value of Information analysis. The final development option to be chosen depends on a traditional NPV analysis.
Summary Waterflooding can lead to substantial incremental oil production. Implementation of water-injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as the inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection-induced fractures extending into the caprock. If this risk is seen as “intolerable” in an as-low-as-reasonably-practicable (ALARP) analysis, a decision might be made not to proceed with the project. In this study, we evaluated caprock integrity by conducting simulations of long-term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes, and fracture propagation in the sandstone and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Latin hypercube sampling considering a set of modeling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters in which the risk of fracture-height growth was acceptable. Our simulations also allowed us to identify important factors that affect caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk to the caprock integrity is reduced. This requires introducing a limit for the bottomhole pressure (BHP), including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parameterization of the model, sampling from the distribution of parameters- and distance-based generalized sensitivity analysis (dGSA) as well as probabilistic representation of the results. The results indicate that the time to reach the BHP limit varies substantially, dependent on the chosen development scenario. Injection of water (1000 m3/d), with total suspended-solids content ranging from 0.1 to 0.5 ppm by volume (ppmv) and particle size from 1 to 5 µm, into long horizontal wells (2000 m) results in injection times of more than 10,000 days even for the P10 percentile. However, injection of poor-quality water (injection rate 600 m3/d, well length 600 m), with total suspended-solids content ranging from 0.5 to 5 ppmv and particle size from 10 to 30 µm, leads to the BHP limit of 10 (P10) to 740 (P90) days. The dGSA can be used to determine which parameter has a stronger impact on the BHP and, hence, on the project, and should be measured if warranted by a value-of-information analysis. In the case reported here, dGSA showed that the filter-cake permeability has a big impact on the results and, hence, will be determined by laboratory measurements. The final development option to be chosen depends on a traditional net-present-value analysis.
Carbon capture and underground gas storage technologies have been an area of significant focus in oil and gas industry over the past few decades. They reduce the carbon footprint of oilfield activities and have a critical role in the energy transition efforts by the industry. This study focuses on conducting a thorough review of literature related to latest advances in carbon capture and underground gas storage methods including real-field applications of these technologies. The future potential of these technologies in enabling the oil and gas industry to achieve its ESG goals are also discussed. This chapter examines carbon capture and underground gas storage (CCS) technologies and summarizes various types of CCS techniques such as post-combustion, pre-combustion, and oxyfuel combustion. It describes the important operational principles, efficient methods of technology deployment, and best practices to ensure positive project economics. Additionally, the use of the CCS as a method to enable enhanced oil recovery (EOR) in the oil and gas industry, as well as application areas and challenges faced in the use of CCS in oilfield operations, are discussed. The latest advances in this technology from a global perspective and the future potential of CCS as a critical driver in helping achieve sustainability goals for the oil and gas industry are summarized. Critical factors related to the application of the CCS, including the key decision variables to be considered while implementing projects that uses these technologies are provided to be used as a guideline in decision making. Examples of the use of these technologies to improve the sustainability of oil and gas production operations are provided, as well as the benefits, drawbacks, and challenges in scaling up the use of these technologies in fields are discussed in detail. This study closes the gap in the literature by providing a comprehensive overview of the current status of the CCS technologies and guidelines for their implementation in oil and gas fields. It serves as a single source of information to the oil and gas industry, while laying out relevant data and information related to the CCS technologies, highlighting the latest advances in their application and the future of these technologies from a global perspective.
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