Quantitative prediction of swelling pressure of shale in terms of all chemical (compositional) and mechanical factors is complex because native shale compositions are complex and are not known in detail. Physical and chemical interactions do occur between the shale constituents and fluids. A physico-chemical model that incorporates the mechanics and chemistry of shale/drilling fluid interaction under conditions of elevated temperature and pressure is developed. The model is based on the total pressure concept and on thermodynamics to predict shale swelling pressures. A small-scale laboratory arrangement that includes an innovative resting procedure under downhole conditions is developed for validating the model. The model and the experimental apparatus are used to determine the effects of wellbore pressure, confining pressure, temperature and drilling fluid composition on the swelling behavior of shales.
Swelling rates were measured on two different shale samples utilizing five aqueous solutions, four drilling fluids and mineral oil, at temperatures ranging from 75 °F to 225 °F and pressures ranging from 2500 to 7500 psi. The model predictions agreed with the experimental data to ±10%. Increases in net overburden pressure reduced shale hydration while increases in wellbore pressure increased shale hydration. The two shale samples tested responded differently to various fluids for the range of temperatures and pressures studied. The use of drilling fluids containing pure glycerol or KCl-polymer reduced shale hydration significantly. Temperatures above I50 °F caused steep increase in swelling rates. Ion analysis of the tested shales exhibited series of cation exchange reactions between the shales ond the test fluids which indicates that shales are not inert semipermeable membranes as previously believed. This study provides a greatly improved understanding of shale/drilling fluid interaction and is useful for drilling fluid design optimization and total drilling costs minimization.
Maintenance of a stable wellbore is of primary importance during drilling of oil and gas wells and can be troublesome. Wellbore instability is a well established problem which results in substantial yearly expenditure for the petroleum drilling industry. Shales make up over 75% of drilled formations and cause over 90% of wellbore instability problems.
Wellbore instability may result from chemical reactions between reactive shales and drilling fluids, from unfavorable mechanical stresses within the rock, or from a combination of lbese two processes. Related factors affecting the overall behavior of shales while drilling are temperature, time in open bole, depth, and length of the open-bole interval. These factols influence the chemical and physical processes. The chemical aspects include types of minerals and fluids, the amount of each mineral and fluid, and the type of adsorbed cations present- The mechanical factors include temperature and confining, wellbore and pore pressures.
When a shale is contacted by fluids, many physico-chemical processes such as alteration of porosity and permeability as well as cation exchange reactions occur. Wellbore stability is dependent on the cumulative effect of all these factors as they effect shale swelling. Therefore, the desired approach is to develop a generalized wellbore stability model that incorporates the governing chemical and mechanical factors.
Many important contributions1–7 have been made that provide us with model components for predicting swelling displacements or stresses.
