Modeling of coupled fluid-flow/geomechanical processes in stress-sensitive reservoirs has shown that different reservoir conditions yield different degrees of reservoir productivity reduction. Factors affecting the productivity of stress sensitive reservoirs include reservoir permeability, initial loading, aspect ratio, mechanical and physical properties of the reservoir and its surroundings, and fluid compressibility. The effects and interaction among these factors is complex and needs to be investigated if reservoir management is to be optimized. This study applies the statistical technique factorial design to investigate systematically and efficiently the interactions and effects that the above mentioned factors have on productivity index and cumulative production. To achieve these objectives, this study applies a 3D, finite difference, fully coupled, fluid-flow/rock deformation model.1 The model considers an inner and an outer domain representing the reservoir and its surroundings, respectively. The system is treated as a poro-elastic medium consisting of a deforming solid skeleton and a moving compressible pore fluid. Non-linear elastic deformation is assumed. Results indicate that the most important variables affecting reservoir productivity and cumulative production are reservoir permeability, aspect ratio, Young's modulus of the inner domain and fluid compressibility (the effect of fluid compressibility and Young's modulus of the inner domain are of the same order). This paper provides a deep discussion on the effect of these factors on both response variables: productivity index and cumulative production. Introduction There are different factors that can influence the interaction between rock deformation and fluid flow in stress-sensitive reservoirs. Some of these factors are:mechanical properties of the reservoir and its surroundings,the "arch effect",fluid compressibility,reservoir permeability,aspect ratio, andthe initial loading (initial stress state). The interaction of these parameters and how they affect the coupling of rock deformation and fluid flow in oil reservoirs is complex. Some factors may have significant effects while other factors may exhibit negligible effects. Also, the effect of some factors may be a function of the reservoir stress state. The complex interaction of factors affecting coupled fluid-flow/geomechanical processes in oil/gas reservoirs suggests that a parametric study is a step toward a better understanding of the behavior of stress-sensitive reservoirs. Specifically, a parametric study would lead to the achievement of the following objectives:to obtain information about which parameters are needlessly considered in coupled fluid-flow/rock deformation modeling;to investigate the effects and interactions among the factors affecting coupled fluid-flow/rock deformation processes in oil/gas reservoirs, andto better understand the behavior of stress-sensitive reservoirs. The purpose of this study is to perform a parametric study of the variables affecting coupled fluid-flow/geomechanical processes in stress-sensitive oil/gas reservoirs. The factorial design technique is used to investigate the effects of six important variables affecting fluid-flow/rock deformation process. These variables are: Young's modulus of the reservoir and it's surroundings, fluid compressibility, aspect ratio, initial loading, and reservoir permeability. The response variables measuring the effect of these variables are reservoir productivity index and cumulative production. In order to estimate the response variables under different factor combinations, this study applies a fluid-flow/geomechanical model developed by Osorio et al.1 (1999). The model is a 3D finite difference, fully implicit model that simulates the physical phenomena occurring during the production from reservoirs with stress-sensitive mechanical and fluid-flow properties. The model considers two different physical domains:an inner porous domain representing the reservoir, where fluid-flow and rock deformation occurs, anda surrounding domain representing the extended stress-disturbed region caused by the reservoir depletion. The inclusion of the surrounding domain leads to a more realistic modeling of the actual reservoir geomechanical boundary conditions. The reservoir is treated as a poro-elastic system consisting of a deforming solid skeleton and a moving compressible fluid. Nonlinear elastic deformation is assumed for both the reservoir and its surroundings.

Drilling in the Appalachian basin in Pennsylvania has evolved since its inception. Operators have shifted their focus from mere wellbore delivery to delivering wells in the shortest amount of time to reduce risks and costs, as well as drive efficiency. This paper presents a case study in which offline cementing helped improve operation efficiency by reducing drilling times and provided significant cost savings. Offline cementing is not a new concept. In Q4 2015, an operator drilling in the Eagle Ford shale began the movement of their program toward offline cementing of both the surface and production casings. The operator determined that reducing flat time was crucial to create a cost savings (Hsieh 2018). When another operator began their 2018 drilling program in northeastern Pennsylvania, improving efficiencies was discussed with the service company. After quantifying the experience obtained during a previous project, the service company proposed offline cementing because of the economic benefits it could provide. The service company was able to cement both the surface and intermediate casing strings offline while the operator skidded to the next well to begin rigging up. All surface casings were drilled and cemented offline and the rig skidded back to drill for the intermediate casings, which were also cemented offline. Approximately 15 hours was saved by skidding between surface strings, and another 16 hours was saved between intermediate casings. This paper discusses the successful use of offline cementing during drilling operations in northeastern Pennsylvania. The flat time reduction achieved during this drilling program can be quantified into a cost savings of approximately USD 80,000 per well.

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