Analyses of Wellbore Instability in Drilling Through Chemically Active Fractured-Rock Formations

Abstract

Summary Numerous time-dependent wellbore-instability problems have been reported while drilling through the chemically active fractured-shale formations in the Arabian Gulf. Very often, these shales are characterized by the abundance of not only macroscale bedding planes but also networks of microscale natural fractures. The presence of fractures weakens the shale mechanically and produces higher-permeability fluid-flow paths within the low-permeability rock formation. Because of different fluid-diffusion rates between the fractures and shale matrix, there are two distinct pore-pressure fields in saturated fractured shale. Additionally, in chemically active shale formations, osmotic pressure arises because of the imbalance in mud/shale chemical activity. Practically, it is extremely complex to isolate the fractures from the matrix for analysis or to identify fracture size and fracture density. However, a first-order approach in an attempt to understand the porous fractured-shale behavior is to use dual-porosity and dual-permeability theory of poromechanics in the analytical modeling. In this study, a poromechanical inclined-wellbore solution has been derived that incorporates time dependency, a primary porosity and permeability for the matrix, a secondary porosity and permeability for the fractures, and the chemical effect. The expressions for the stresses and pressure solutions are presented and detailed in Appendix A. These analytical solutions are used to simulate an inclined-wellbore-stability problem in a fractured-shale formation, accounting also for bedding planes in some instances in addition to the microfractures. Additionally, retrieved rock samples of fractured shale were tested by use of an innovative laboratory characterization device, the Inclined Direct Shear Testing Device (IDSTD) (PoroMechanics Institute; Norman, Oklahoma; 2008). This device tests tiny shale specimens (rock volume less than 0.14 in.3) and is capable of measuring cohesion and friction angle while the sample is subjected to in-situ stresses, varying mud pressures, and mud-circulation times.

Changing the Safe Drilling Window with Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results

“…A significant advance over poroelastic modeling, porochemoelastic (PCE) modeling incorporates the effects of fluid chemistry 14,15 . In the case of IEFs having WPS levels different from the pore fluid in the wellbore wall, osmotic pressure theory of invert emulsion fluids tells us that water can pass from the drilling fluid into the rock or vice versa, depending on the differences of WPS levels in the drilling fluid and in the formation connate water.…”

Development of a new correlation to determine the static Young’s modulus

“…Young's modulus is the ratio of the stress applied on the material to strain associated with the applied stress (Chen 2011). Young's Modulus can be calculated using Hook's Law (Nguyen et al 2009) as follows:…”

Moderate Collapse in a Shale Cap of a Nearly Depleted Reservoir

“…By this time, it is hoped that the ECD to be as low as possible. Extensive studies on wellbore stability in shale have been conducted [23][24][25][26][27][28], but conventional collapse pressure in shale, which was usually referred to as ECD design, was often evaluated by assuming the wellbore is completely stable [29,30], and the recommended results were relatively conservative. In fact, some studies have showed that a certain amount of collapse can be acceptable due to the self-stabilization effect during the collapsing process, and a lower ECD than collapse pressure can be used, which may have a number of advantages, such as increasing the drilling rate, reducing formation damage, and so on [31,32].…”