Summary Different choke-management strategies have been adopted by operators in the field; however, no general method exists for systematically selecting an optimum choke-management strategy. In this study, we propose a general method for the selection of bean-up duration and bean-up strategy (choke management) that will maximize well productivity by minimizing formation damage, reducing sand production, and reducing the impact of multiphase-flow effects. Strategies of stepwise bottomhole-pressure (BHP) adjustments are compared by use of the principle of superposition and the analytical solution of the transient radial-diffusion equation for vertical wells operating under different choke settings. The optimum choke-management strategy is based on the anticipated formation-damage mechanisms. For example, if fines migration and sand production are a concern, then minimizing the wellbore pressure gradients is the primary criterion for the selection of the optimum choke-management strategy. Using the analytical solution and simulation results, we conclude that for relatively short bean-up durations (i.e., infinite-acting behavior), the pressure-gradient reduction at the wellbore varies logarithmically with increasing bean-up duration. Choke-management strategies appear to have similar performance as far as no more than 70% of the drawdown is applied during the initial 20% of the overall bean-up duration. For longer durations (i.e., when the presence of the no-flow boundary is felt), the optimum strategy depends on both reservoir properties and radial extent. For the case of square drainage area, a plot suggesting the optimum strategy with respect to dimensionless duration is presented. Positive skin and multiphase flow near the wellbore negatively affect the performance of bean-up strategies. For vertical wells producing from multiple layers, bean-up strategies should be selected with respect to the effective horizontal permeability, ultimately yielding the greatest pressure-gradient reduction in the low-permeability zones. The proposed method enables engineers to select the optimum choke-management strategy with respect to bean-up duration and formation properties. The duration of the bean-up process is drawdown dependent, thus further research is encouraged in determining the maximum allowable pressure gradient to curtail sand production.
Different choke management strategies have been adopted by operators in the field. However, no general method exists for systematically selecting an optimum choke management strategy. In this study, we propose a general method for the selection of bean-up duration and bean-up strategy (choke management), that will maximize well productivity by minimizing formation damage, reducing sand production and reducing the impact of multiphase flow effects. Strategies of stepwise bottom-hole pressure (BHP) adjustments are compared using the principle of superposition and the analytical solution of the diffusivity equation for vertical wells operating under different choke settings. The optimum choke management strategy is based on the anticipated formation damage mechanisms. For example, if fines migration and sand production are a concern, then minimizing the near wellbore pressure gradients is the primary criterion for the selection of the optimum choke management strategy. Results indicate that the selection of the optimum strategy (sequence of choke settings) is independent of the drawdown and depends primarily on the duration of the ramp-up period. Among the 251 strategies evaluated, three of them consistently appear to be the optimum. We further refine strategies using a single parameter, incorporated in a dimensionless expression of BHP as a function of time. From simulation results, we conclude that for relatively short bean-up durations (i.e., infinite acting behavior), the pressure gradient reduction at the wellbore varies logarithmically with time. Choke management strategies appear to have similar performance as far as no more than 70% of the drawdown is applied during the initial 20% of the overall bean-up duration. For longer durations (i.e., when the presence of the no-flow boundary is felt), the optimum strategy depends on both reservoir properties and radial extent. For the case of square drainage area, a plot suggesting the optimum strategy with respect to dimensionless duration is presented. Positive skin and multiphase flow near the wellbore, negatively affect the performance of bean-up strategies. For vertical wells producing from multiple layers, bean-up strategies should be selected with respect to the effective horizontal permeability, ultimately yielding the greatest pressure gradient reduction in the low permeability zones. The proposed method enables engineers to select the optimum choke management strategy with respect to bean-up duration and formation properties. The duration of the bean-up process is drawdown dependent thus further research is encouraged in determining the maximum allowable pressure gradient in order to curtail sand production.
When a well is brought on production, the selection of an optimum choke management strategy is aimed towards maximizing well productivity and minimizing the risk of typical wellbore failures during the early life of a well. In this study, a quantitative method is presented for the selection of a choke management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. For example, in unconventional resources, an improper choke management strategy may trigger the back flow of excessive amounts of proppant, resulting in fracture closure and possible wellbore damage and loss of production. In frac-packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage resulting in impaired production and possibly sand production, requiring excessive and costly workovers. It is shown that in hydraulically fractured wells, choke management strategies should aim towards minimizing pressure gradients along the fracture, thus making proppant flowback and potential reduction/loss of fracture conductivity or its connectivity to the wellbore less likely to occur, for a given set of formation properties and closure stress. Choke management strategies are compared for a wide range of formation and fracture properties including fluid properties, matrix permeability, fracture conductivity and fracture length. Results indicate that in unconventional formations (k<0.01md) there is a unique choke management strategy, which consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed. In frac-packs and high-rate water packs, completion failure may occur due to excessive fluid velocities along the frac-pack or exaggerated pore pressure gradients at the completion sandface. Choke management strategies are compared for a wide range of formation and completion properties. Results indicate that in frac-packs and high-rate water packs, the selection of the optimum choke management strategy is similar to that of open-hole completions, with bean-up operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering bean-up operations during completion design. The results of this study provide, for the first time, a clear methodology for selecting choke management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties.
Summary In this study, a quantitative method is presented for the selection of a choke-management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. In unconventional resources, an improper choke-management strategy may trigger proppant crushing or the flowback of proppant, resulting in fracture closure and loss of production. In frac packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage, resulting in impaired production and sand production and requiring excessive and costly workovers. Choke-management strategies should aim to minimize near-wellbore pressure gradients along the fracture, thus making proppant flowback and loss of fracture conductivity or connectivity with the wellbore less likely to occur. Choke-management strategies are compared for a wide range of formation and fracture properties, including fluid properties, matrix permeability, fracture conductivity, and fracture length. Results indicate that in unconventional formations (k < 0.01 md) there is a unique choke-management strategy that consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed. In frac packs and high-rate water packs, completion failure may occur because of excessive fluid velocities along the frac pack or exaggerated pore-pressure gradients at the completion sandface. Results indicate that the selection of the optimal choke-management strategy is similar to that of openhole completions, with beanup operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering beanup operations during completion design. The results of this study provide, for the first time, a clear methodology for selecting choke-management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties. A general framework for beanup operations is defined and then used to compare beanup strategies for hydraulically fractured and frac-pack completions. It is hoped that this paper will contribute a theoretical foundation to the current diverse operator practices.
Choke management strategies vary significantly among operators and no rigorous methodology exists for properly selecting choke sizes when constraints are placed on completions, wellbores and fluid pressures and velocities. Bringing a well on production too fast may significantly compromise productivity or even result in completion failure with particularly severe implications in offshore developments. Examples of constraints placed on bean-up strategies include, limiting the maximum drawdown to minimize the risk of sanding or proppant crushing. This paper presents a methodology for translating such constraints to the required choke sizes and durations i.e. a specific bean-up strategy that will respect the constraints placed on the system. In this study, we propose a coupled wellbore-reservoir model that performs dynamic nodal analysis using integrated models for surface facilities, wellbore and reservoir simulators and allows an operator to select choke sizes as a function of time. Illustrative examples of the method are shown for a conventional and an unconventional well. Results indicate that the choke schedule strongly depends on both the reservoir and wellbore properties. As a result, empirical and general guidelines should not be used across the board. Instead a quantitative analysis is recommended for a given set of surface, wellbore and reservoir properties to ensure a successful ramp-up. This study provides an integrated and systematic approach for selecting choke sizes for oil and gas wells.
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