The development of unconventional shale gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18 to 24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical-flow simulation model to simulate these production conditions. This model mimics the impact of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural fracture permeability as well as reduction in hydraulic fracture conductivity due to proppant crushing, deformation, embedment, and fracture-face creep. Matrix permeability evolutions, considering the conflicting effects of non-Darcy flow, and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic fracture planar geometries are then obtained using a finite element method (FEM) scheme. A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial gas cumulative production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher and higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic fracture conductivity. The results conclude that ignoring impacts of any of the above phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale gas reservoirs can yield substantially higher ultimate recovery. The model is fully versatile and allows modeling and characterization of all profoundly different (on a petrophysical level) shale gas formations as well as proppant materials utilized for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic fracture design, for fine-tuning production history matching, and, especially, as a predictive tool for pressure drawdown management.

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Summary The development of unconventional shale-gas formations in North America with horizontal multifractured wells is mature enough to identify production malpractices and abnormal productivity declines generally observed within 18–24 months of initial production. The primary objective of this study is to address all known causes of these productivity declines and to develop a fully coupled geomechanical/flow simulation model to simulate these production conditions. This model mimics the effect of depletion-induced in-situ stress variations on short-term and long-term productivity by taking into account several phenomena, such as stress-dependent matrix and natural-fracture permeability as well as reduction in hydraulic-fracture conductivity caused by proppant crushing, deformation, embedment, and fracture-face creep. Matrix-permeability evolutions, considering the conflicting effects of non-Darcy flow and compaction, have also been accounted for in this model. Numerical solutions for simplified hydraulic-fracture planar geometries are then obtained by use of a finite-element-method scheme. A synthetic case was defined to investigate the effects of each individual phenomenon on short-term and long-term production. Results show that the combined effects of permeability alterations in matrix and natural fractures as well as conductivity losses in hydraulic fractures may result in substantial cumulative-gas-production loss. The model also reproduces familiar field-observed trends, with lower long-term production corresponding to higher drawdowns. This behavior is attributed to the stress-dependent evolution of reservoir permeability and hydraulic-fracture conductivity. The results show that ignoring the effects of any of the previous phenomena results in overestimation of ultimate recovery. Furthermore, it is shown that proper management of pressure drawdown and the penalty for lower initial production rates in unconventional shale-gas reservoirs can yield substantially higher ultimate recovery. The model is fully versatile and allows modeling and characterization of all widely differing (on a petrophysical level) shale-gas formations as well as proppant materials used for the stimulation treatments. This integrated model can be used for optimization of key parameters during the hydraulic-fracture design, for fine tuning production history matching, and especially as a predictive tool for pressure-drawdown management.

Poststimulation operations on multistage hydraulically stimulated horizontal wells producing from conventional and unconventional reservoirs have a major impact on long-term well performance. Most common types of poststimulation services on such wells include plug drillout (PDO) operations and well flowback (WFB) operations. During these operations, the hydraulic fracture system experiences major changes in pressure and flowrate, which may affect the well's long-term productivity. Among the many mechanisms responsible for decrease in well productivity, we highlight 1) the risk of losing the connection between the wellbore and hydraulic fracture system because of the development of an unpropped area; 2) rock destabilization, and 3) the risk of scaling and precipitation. In this paper, we describe an integrated engineering and operations workflow for optimizing poststimulation operations on horizontal wells by controlling the productive fracture system evolution during the poststimulation period. The approach is based on applying the secure operating envelope (SOE) concept, which provides a set of operating parameters that ensure preservation of the connection between the hydraulic fractures and wellbore. The SOE is defined for each individual well, using a combination of geomechanical and multiphase transport modeling. It accounts for reservoir properties, well completion, and fracture treatment parameters. High-resolution, real-time monitoring of well performance and active control of bottomhole conditions through choke management ensure the well is operated within the SOE. The production objectives combined with the evolution of the SOE enable an overall strategy for poststimulation operations. The paper outlines how the SOE is constructed. Applications of the proposed approach on horizontal oil and gas wells in unconventional reservoirs in North America are reported, both during well flowback and plug drillout operations. Using the SOE during well flowback helps to predict and avoid a decrease in well production performance caused by excessive proppant flowback which results in creation of near-wellbore pinch points inside hydraulic fractures. Additionally, plug drillout was identified as a critical operation, during which the proppant pack can be destabilized. The associated risk was strongly reduced by applying the SOE concept in combination with high-resolution monitoring. Based on data obtained from more than 50 operated wells, we conclude that the proposed methodology, including application of geomechanical modeling to poststimulation operations, brings significant opportunities for optimization of well performance and securing long-term well productivity.

Scale deposits are a common problem in oil and gas wells and can have detrimental effects on well production. Depending on the severity, scaling can stop production entirely as scale forms anywhere in the well production system, including the formation, perforations, casing or tubular, and in or on the artificial lift equipment. There are several chemical and mechanical methods for removing scale deposits. However, to prevent scale deposition, the only solution is chemical inhibitors injected into the formation. The typical production system includes artificially lifted, stimulated wells (propped hydraulic fractures) placed in reservoirs where pressure maintenance is achieved by water flooding. The artificial lifting is typically accomplished through use of electric submersible pumps (ESPs). In reservoirs where produced fluids exhibit scaling tendencies, ESP run life is significantly shortened by scale formation on the pump elements restricting rotation. By treating the formation with chemical inhibitors, the life of the ESP can be extended. In this paper we provide approaches for improving a compatibility of a novel hydraulic fracturing fluid (used in Russia) and scale inhibitor. A 3-year campaign to combine scale inhibition with the hydraulic propped fracture effectively increased the average run life of ESPs in the Mayskoe and Snezhnoe oil fields.