Martin E. Chenevert

A study of wellbore stability in shales including poroelastic, chemical, and thermal effects

Abstract This paper presents the development of a model for determining wellbore stability for oil and gas drilling operations. The effects of mechanical forces and poroelasticity on shale behavior are included, as well as chemical and thermal effects. Chemical effects are caused by the imbalance between the water activity in the drilling mud and the shale water activity. The magnitude of this contribution depends on the effectiveness of the mud/shale system to perform as a semipermeable membrane. Experimental results show that osmotic pressures develop inside shales when they are exposed to different drilling fluids. This osmotic pressure is treated as an equivalent hydraulic potential, and is then added to the hydraulic wellbore and pore pressure as time progresses. Thermal diffusion inside the drilled formation induces additional pore pressure and rock stress changes and consequently affects shale stability. Thermal effects are important because thermal diffusion into shale formations occurs more quickly than hydraulic diffusion and thereby dominates pore pressure changes during early time. Rock temperature and pore pressure are coupled for most porous media studies; however, we have found that they can be partially decoupled for shale formations by assuming that convective heat transfer is negligible. The partially decoupled temperature and pore pressure effects can therefore be solved analytically under appropriate initial and boundary conditions. Experimental data for shale strength alteration, which occurs when shales are exposed to different fluids, are also included for the determination of cohesion strength decay. Pore pressure, collapse stress, and critical mud weights are variables investigated for determining poroelastic, chemical, and thermal effects on shale stability. The most important factors, which affect wellbore stability, are clearly identified.

Stability of Highly Inclined Boreholes (includes associated papers 18596 and 18736 )

Hole inclination produces alterations in the stress state around the borehole and in the physical properties of the rock. Depending on specific conditions, such effects may lead to collapse of the borehole or a reduction in the fracture-initiation pressure. This paper shows how to determine such effects through the application of stress analysis and rock mechanics.

The role of osmotic effects in fluid flow through shales

A transient flux model for fluid loss from the wellbore into shales during drilling has been developed. The model takes into account the coupled flow of water and ions due to hydraulic, osmotic, and electrical potential gradients imposed on the formation. Solute concentration profiles and hydraulic pressure propagation are calculated as a function of time and the flux of water and ions are obtained for various drilling conditions. The model provides a method to quantify interactions between drilling fluid and shales and constitutes a useful tool for formulating drilling fluids. It assists in the establishment of proper bottomhole hydraulic and osmotic drilling fluid pressures so as to minimize flow into or out of shales, which could result in wellbore instability problems.

Chemical and thermal effects on wellbore stability of shale formations

The model presented in Chapter 2 is compared with experimental data presented by Ewy and Stankovich [2000]. It is shown that the relative magnitude of the hydraulic conductivity of the shale (KI), the membrane efficiency of the shale (KII), and the effective diffusion coefficient of solute (Deff) all have an influence on the net pore pressure behavior of a shale exposed to a drilling mud. After the model has been calibrated with one set of experimental data, excellent predictions under other operating conditions can be made. Good agreement with experimental data is obtained for such predictions.

Decreasing Water Invasion Into Atoka Shale Using Nonmodified Silica Nanoparticles

This paper (SPE 146979) was accepted for presentation at the SPE Annual Technical Conference and Exhibition, Denver, 30 October–2 November 2011, and revised for publication. Original manuscript received for review 21 June 2011. Revised manuscript received for review 6 December 2011. Paper peer approved 21 December 2011. Summary Fluid penetration from water-based muds into shale formations results in swelling and subsequent wellbore instability. Particles in conventional drilling fluids are too large to seal the nano-sized pore throats of shales and to build an effective mudcake on the shale surface and reduce fluid invasion. This paper presents laboratory data showing the positive effect of adding commercially available, inexpensive, nonmodified silica nanoparticles (NP) (particle sizes vary from 5 to 22 nm) to water-based drilling muds and their effect on water invasion into shale. Six brands of commercial and nonmodified nanoparticles were tested and screened by running a three-step pressure penetration (PP) test (brine, base mud, nanoparticle mud). Two types of common water-based muds, a bentonite mud and a low-solids mud (LSM), in contact with Atoka shale were studied with and without the addition of 10 wt% nanoparticles. We found that a large reduction in shale permeability was observed when using the muds to which the nonmodified nanoparticles had been added. For the bentonite muds, the permeability of Atoka shale decreased by 57.72 to 99.33%, and, for the LSMs, the permeability of Atoka shale decreased by 45.67 to 87.63%. Higher plastic viscosity (PV) and lower yield point (YP) and fluid loss (FL) of the nanoparticle muds compared with base muds were also observed. We also found that nanoparticles varying in size from 7 to 15 nm and a concentration of 10 wt% are shown to be effective at reducing shale permeability, thereby reducing the interaction between Atoka shale and a waterbased drilling fluid. This study shows for the first time that it is possible to formulate water-based muds using inexpensive nonmodified and commercially available silica nanoparticles and that these muds significantly reduce the invasion of water into the shale. The addition of silica nanoparticles to water-based muds may offer a powerful and economical solution when dealing with wellbore-stability problems in troublesome shale formations.

Chemical–mechanical wellbore instability model for shales: accounting for solute diffusion

Abstract A model that combines chemical effects with mechanical effects and provides a quantitative tool for evaluating wellbore stability is presented. In the past, wellbore stability models have introduced chemical effects by adding an osmotic potential modified by a membrane efficiency to the pressure acting at the wellbore wall [Fonseca, C.F., 2000. Chemical–mechanical modeling of wellbore instability in shales. Proceeding of ETCE 2000 and OMAE 2000 Joint Conference: Energy for the New Millenium, Feb. 14–17, 2000, New Orleans, LA.]. In this paper, an entirely different approach is adopted. The fluxes of water and ions into and out of the shale are accounted for. The pressure profiles obtained using our model differ significantly from the error function decline in pressure that is predicted by earlier models. As a consequence of this near wellbore pore pressure profile, wellbore failure can now occur inside the shale not just at the wellbore wall (as predicted by earlier models). The onset of instability now depends not only on the activity of the water but also on the properties of the solutes.

Permeability and Effective Pore Pressure of Shales

Laboratory-derived permeability and pore-pressure data obtained for Wellington and Pierre Shales are used to describe swelling pressure, and spalling types of wellbore instability. Tests showed that increased pore pressures can lead to wellbore failure. The laboratory pore-pressure information developed displays a time-dependent swelling process followed by a Darcy type of flow. A «total aqueous chemical potential » concept is presented that describes the driving potentials that operate during both phases of flow. Experimental methods are presented to determine the «storage » of water shale during the swelling phase and the permeabilities with steady-state-flow and transient-flow techniques

The ion-selective membrane behavior of native shales

Experiments were conducted to evaluate the membrane character of native shale samples by measuring the electrochemical potential across the shale membrane. Results suggest that the composition of the interstitial pore fluid in the shale plays a determining role on the establishment of the electrochemical potential and that, in some cases, the behavior of the shales is close to the expected behavior of a perfect cation-selective membrane. Shales with intermediate electrochemical potentials appear to be more sensitive to water-based fluids than shales that are closer to perfect membranes (high electrochemical potential). A model to simulate the transport of water and ions through shales was developed. Hydraulic pressure, concentration, and electric potential gradients are the driving forces for the flow of water and solute between two solutions separated by the shale. The reflection coefficient and the modified diffusion potential are calculated from the model and are used to characterize the membrane behavior of shales. A sensitivity study on the various model parameters was conducted. Results show that the membrane efficiency of the shale is strongly affected by the concentration of the interstitial fluid, the separation distance between the platelets and the type of ions in the membrane. The higher the ion concentration and the interplatelet spacing, the lower the efficiency. Results obtained using the model produce reflection coefficients that are consistent with experimental data. The model provides excellent insight into the physical mechanisms responsible for the membrane behavior of shales and a way to conduct sensitivity studies on the important model parameters. The membrane efficiencies obtained from the model may be used in wellbore stability simulators to account for chemical interactions between shales and water-based drilling fluids.

Control of Shale Swelling Pressures Using Inhibitive Water-Base Muds

Over the years wellbore stability in shales has been achieved using oil base muds, however water base muds still plague the industry. Up until now it was not obvious what mechanisms were in operation during such shale/water base mud interactions. The research reported herein discusses the development of swelling pressures when water base muds are in contact with a troublesome North Sea shale. A mechanistic theory is presented that focuses on increases in total pore pressures that are reflected in swelling pressures. The results obtained showed that different mud filtrates produce swelling or shrinking pressures that are related to the type of salt present and its ionic concentration. Fluids tested included deionized water and solutions of CaCl 2 , Potassium Formate, Glycerol, Methyl Glucoside and NaCl/Methyl Glucoside. The range of swelling pressures measured were from +2800 psi (swelling) to -1400 psi (shrinkage). In addition to swelling pressures, the compressive strength of the shales was also measured under downhole insitu stress and conditions after the chemical interactions were complete. Strength reductions as high as 35% were measured for certain fluid systems.

Wellbore stress distribution produced by moisture adsorption

Evaluation of the stress distribution produced by moisture adsorption around a wellbore by applying the mechanics of deformable solids. The process of moisture adsorption is governed by a diffusion equation, and the equations governing moisture-induced stresses around the hole, are similar to those used in thermoelasticity theory. A computational method is developed for calculating the stress distribution around the hole, and an experimental procedure for obtaining the material constants needed in the computation (adsorption characteristics, moisture-induced modulus change of the material) is presented.