Managing Physico-Chemical Wellbore Instability in Shales with the Chemical Potential Mechanism

Abstract

Chee P. Tan, SPE, Australian Petroleum Cooperative Research Centre, CSIRO Petroleum, Melbourne, Australia; Brian G. Richards, Geotech Research Pty Ltd, Queensland, Australia and S.S. Rahman, SPE, Australian Petroleum Cooperative Research Centre, Centre for Petroleum Engineering, U of New South Wales, Kensington, Australia Abstract This paper describes the fundamental concept and a model of the chemical potential mechanism and the associated effective mud support change as the drilling fluid interacts with the shale. By having the chemical potential of the drilling fluid to be lower than the potential of the formation, pore fluid can be induced to flow from the formation into the wellbore which will result in a reduction of the near-wellbore pore pressure. This in turn will lead to an increase in effective mud support and consequently, a more stable condition at the wellbore wall. The model was verified with laboratory experiments designed for the study of the chemical potential mechanism. The results showed that osmotic flow of pore fluid from the formation across a non-ideal semi-permeable membrane would only provide a temporary shale stabilisation mechanism. A parametric study was carried out using the verified model to demonstrate the effects of critical drilling fluid properties on time-dependent pore pressure change due to the difference between drilling fluid and formation chemical potentials and the associated wellbore (in)stability in shales for water-based muds. The model provides a fundamental basis for understanding the effects of the type, concentration and chemical properties of the salt, drilling fluid properties, and reflection coefficient of the shale on time-dependent mud support on the wellbore wall. Introduction Wellbore instability, experienced mainly in shale sections, is one of the principal causes of drilling delays and in some cases, even suspension of wells prior to reaching the target. These instabilities may be induced by either in-situ stresses that are high relative to the strength of the formations or physico-chemical interactions of the drilling fluid with the shales. The instability induced by drilling fluid-shale interactions can be managed more efficiently through a better understanding and development of a capacity to model the pore pressure change due to chemical potential difference between the drilling fluid and the shale, and subsequent wellbore (in)stability due to the interactions. Coupled chemical potential mechanism has been studied as a method of stabilising shales drilled with water-based muds. This paper describes the fundamental concept and a model of the chemical potential mechanism and the associated effective mud support change as the drilling fluid interacts with the shale. The model was verified with laboratory experiments designed for the study of the chemical potential mechanism. Analyses were carried out using the verified model to demonstrate the effects of critical drilling fluid properties on time-dependent pore pressure change due to the difference between drilling fluid and formation chemical potentials and the associated wellbore (in)stability in shales for water-based muds. Fundamental Concept of Chemical Potential Mechanism Flow of water into or out of shales is somewhat similar in mechanism to the flow of water through a semi-permeable membrane (osmosis). Osmosis is the flow of solvent (water) from a solution containing lower concentration of solute (salinity) into a solution of higher solute concentration through a membrane that is permeable to the solvent but not to the solute. The pressure required to prevent water from moving through a semi-permeable membrane from a solution of low salinity to a solution of high salinity is called osmotic pressure. The driving forces involved in solute and solvent transport through a membrane are the chemical potential gradients across the membrane. P. 107