Page 204 - Fundamentals of Gas Shale Reservoirs

184 GEOMECHANICS OF GAS SHALES

8.4.3 Time‐Dependent Instability peak strength is reduced as much as 50% due to reac­
tion with deionized water. Mud filtrate leak‐off causes
Wellbore instability‐related problems in shale formations pore pressure increase with time, reducing the effec­
have plagued the petroleum industry for many years. More tive confining pressure in the near wellbore region and
than 90% of drilling‐related problems are associated with thus making the rock prone to failure. Horsrud et al.
shale formation instability which costs up to 1 million USD (1998a) presented data that show a 28% reduction in
annually (Bol et al., 1992; Mody and Hale, 1993). It is well peak strength for triaxially loaded silty claystone
established that time‐dependent processes are responsible which was exposed to fresh water for five days.
for instability and failures in the wellbores drilled in shale Amanullah et al. (1994) noted a UCS decrease of up to
formations. Time‐dependency in wellbore stability analysis 70% for tertiary mudrock upon saturation with oil‐
is a result of the coupled phenomena of pore fluid diffusion and water‐based muds of varying chemistry and water.
and formation stress variation. This coupled diffusion– The oil‐based mud had the least effect while water
deformation phenomenon is explained on the basis of the showed the most significant effect (68%). In addition
theory of poroelasticity. Cost‐effective and successful dril­ to the strength and stiffness reduction, increasing
ling requires that the drilling fluid pressure be maintained rock–fluid interactions leads to a decrease in brittle­
within a tight mud weight window dictated by the stress and ness of mudrock.
pressure analyses around the wellbore. The time‐dependent
nature of the stress and pore pressure variation around the Oil‐based mud mitigates the problem of drilling in shale
wellbore results in the mud weight window varying with formations since penetration into the shale pore space gener­
time. The gradient of temperature between the drilling mud ally does not occur. This is due to high capillary entry
and the rock formation is also an important issue in wellbore pressure for the nonaqueous fluid phase and good osmotic
stability analyses. The temperature gradient will signifi­ membrane which enables the salt content of the water phase
cantly affect the time‐dependent stresses and pore pressure to prevent osmotic transfer of water into the shale.
distributions around the wellbore. In addition, mud salinity Although nonaqueous fluids minimize the unfavorable
and formation exposure time need to be considered while shale/mud interactions, thus improving wellbore stability,
drilling in chemically reactive formations such as shale, environmental concerns restrict their use. Thus, many studies
using water‐based mud. In fact, In addition to the thermal have been conducted on preventing pore pressure build up
diffusion process, there are at least four other major mecha­ around the wellbore caused by the shale–water mud‐based
nisms which can contribute to time‐dependent wellbore interaction (Ewy and Stankovich, 2000; Schlemmer et al.,
stability in shale formations (Russell et al., 2008):
2002; Tare et al., 2000). Chenevret (1969) introduced the
concept of water activity which has been applied in the sta­
1. Pore pressure difference due to underbalanced/over­ bility analysis extensively (Sherwood, 1993; Van Oort, 1997;
balanced conditions. Van Oort et al., 1996; Yew et al., 1989). Biot‐like analysis
2. Pore pressure changes due to osmotic effect. This is and model‐based water activity have also been proposed
one of the main shale instability mechanisms which (Yew et al., 1989). Assuming water advection to be negli­
occur when water‐based drilling fluid is injected into gible, a simplified model was developed by replacing the
the pore space of shale. Pore pressure raises the near pore pressure with chemical potential utilizing the Biot
wellbore pore pressure and reduces the true overbal­ poroelastic model (Yu et al., 2002). These models were too
ance leading to wellbore instability. The pressure pen­ simplified to be used to simulate the swelling problem of
etration cannot be prevented with standard filtration shale (Frydman and Fontoura, 2001). For instance, some of
additives, since the shale pores are extremely small these models consider shale as a perfect ion exchange mem­
and shale permeability is very low and thus filter cake brane (Bol et al., 1992; Sherwood, 1993; Sherwood and
does not develop on shale intervals. Bailey, 1994; Yew et al., 1989) and others do not take the
3. Swelling induced stress as the ions in the solvent pore pressure advection around the bore hole into account
become part of the shale skeleton component when the (Yu et al., 1989). Although these newly developed models
shale is subject to deformation restriction. allow time‐dependent pressure and stress changes to be cal­
4. Formation strength reduction as a result of entering of culated (Ghasemi and Diek, 2001), most of these studies are
the ions in the original structure of shales. The strength restricted within the poroelastic domain with exceptions and
of shale formations exposed in a borehole is expected simplifications. Several investigators have also used the non­
to decrease with time due to physical–chemical alter­ equilibrium thermodynamic approach in the treatment of the
ation caused by native pore water and mud filtrate transport process in shales (Mody and Hale, 1993; Sherwood,
chemistry (McLellan and Hawkes, 1995). Remvik and 1993). Nonequilibrium thermodynamics allow the incorpo­
Skalle (1993) showed that Young’s modulus of shale ration of cross effects between different phenomena, such as
from the North Sea is reduced by 20–60% and the flux of a solution with different ionic species caused by the