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Borehole instability

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Borehole instability is the undesirable condition of an openhole interval that does not maintain its gauge size and shape and/or its structural integrity. This articles discusses the causes, types, effects, and possible prevention of borehole instability.


The causes can be grouped into the following categories:

  • Mechanical failure caused by in-situ stresses
  • Erosion caused by fluid circulation
  • Chemical caused by interaction of borehole fluid with the formation

Types and associated problems

There are four different types of borehole instabilities:

  • Hole closure or narrowing
  • Hole enlargement or washouts
  • Fracturing
  • Collapse

Fig. 1 illustrates hole-instability problems.

Hole closure

Hole closure is a narrowing time-dependent process of borehole instability. It sometimes is referred to as creep under the overburden pressure, and it generally occurs in plastic-flowing shale and salt sections. Problems associated with hole closure are:

  • Increase in torque and drag
  • Increase in potential pipe sticking
  • Increase in the difficulty of casings landing

Hole enlargement

Hole enlargements are commonly called washouts because the hole becomes undesirably larger than intended. Hole enlargements are generally caused by:

  • Hydraulic erosion
  • Mechanical abrasion caused by drillstring
  • Inherently sloughing shale

The problems associated with hole enlargement are:

  • Increase in cementing difficulty
  • Increase in potential hole deviation
  • Increase in hydraulic requirements for effective hole cleaning
  • Increase in potential problems during logging operations


Fracturing occurs when the wellbore drilling-fluid pressure exceeds the formation-fracture pressure. The associated problems are lost circulation and possible kick occurrence.


Borehole collapse occurs when the drilling-fluid pressure is too low to maintain the structural integrity of the drilled hole. The associated problems are pipe sticking and possible loss of well.

Principles of borehole instability

Before drilling, the rock strength at some depth is in equilibrium with the in-situ rock stresses (effective overburden stress, effective horizontal confining stresses). While a hole is being drilled, however, the balance between the rock strength and the in-situ stresses is disturbed. In addition, foreign fluids are introduced, and an interaction process begins between the formation and borehole fluids. The result is a potential hole-instability problem. Although a vast amount of research has resulted in many borehole-stability simulation models, all share the same shortcoming of uncertainty in the input data needed to run the analysis. Such data include:

  • In-situ stresses
  • Pore pressure
  • Rock mechanical properties
  • Formation and drilling-fluids chemistry

Mechanical rock-failure mechanisms

Mechanical borehole failure occurs when the stresses acting on the rock exceed the compressive or the tensile strength of the rock. Compressive failure is caused by shear stresses as a result of low mud weight, while tensile failure is caused by normal stresses as a result of excessive mud weight.

The failure criteria that are used to predict hole-instability problems are the maximum-normal-stress criterion for tensile failure and the maximum strain energy of distortion criterion for compressive failure. In the maximum-normal-stress criterion, failure is said to occur when, under the action of combined stresses, one of the acting principal stresses reaches the failure value of the rock tensile strength. In the maximum of energy of distortion criterion, failure is said to occur when, under the action of combined stresses, the energy of distortion reaches the same energy of failure of the rock under pure tension.

Shale instability

Shales make up the majority of drilled formations, and cause most wellbore-instability problems, ranging from washout to complete collapse of the hole. Shales are fine-grained sedimentary rocks composed of clay, silt, and, in some cases, fine sand. Shale types range from clay-rich gumbo (relatively weak) to shaly siltstone (highly cemented), and have in common the characteristics of extremely low permeability and a high proportion of clay minerals. More than 75% of drilled formations worldwide are shale formations. The drilling cost attributed to shale-instability problems is reported to be in excess of one-half billion U.S dollars per year. The cause of shale instability is two-fold: mechanical (stress change vs. shale strength environment) and chemical (shale/fluid interaction—capillary pressure, osmotic pressure, pressure diffusion, borehole-fluid invasion into shale).

Mechanical instability

As stated previously, mechanical rock instability can occur because the in-situ stress state of equilibrium has been disturbed after drilling. The mud in use with a certain density may not bring the altered stresses to the original state, therefore, shale may become mechanically unstable.

Chemical instability

Chemical-induced shale instability is caused by the drilling-fluid/shale interaction, which alters shale mechanical strength as well as the shale pore pressure in the vicinity of the borehole walls. The mechanisms that contribute to this problem include:

  • Capillary pressure
  • Osmotic pressure
  • Pressure diffusion in the vicinity of the borehole walls
  • Borehole-fluid invasion into the shale when drilling overbalanced

Capillary pressure

During drilling, the mud in the borehole contacts the native pore fluid in the shale through the pore-throat interface. This results in the development of capillary pressure, pcap , which is expressed as


where σ is the interfacial tension, ϴ is the contact angle between the two fluids, and r is the pore-throat radius. To prevent borehole fluids from entering the shale and stabilizing it, an increase in capillary pressure is required, which can be achieved with oil-based or other organic low-polar mud systems.

Osmotic pressure

When the energy level or activity in shale pore fluid, as, is different from the activity in drilling mud, am , water movement can occur in either direction across a semipermeable membrane as a result of the development of osmotic pressure, pos , or chemical potential, μc . To prevent or reduce water movement across this semipermeable membrane that has certain efficiency, Em, the activities need to be equalized or, at least, their differentials minimized. If am is lower than as, it is suggested to increase Em and vice versa. The mud activity can be reduced by adding electrolytes that can be brought about through the use of mud systems such as:

  • Seawater
  • Saturated-salt/polymer
  • KCl/NaCl/polymer
  • Lime/gypsum

Pressure diffusion

Pressure diffusion is a phenomenon of pressure change near the borehole walls that occurs over time. This pressure change is caused by the compression of the native pore fluid by the borehole-fluid pressure, pwfl, and the osmotic pressure, pos.

Borehole fluid invasion into shale

In conventional drilling, a positive differential pressure (the difference between the borehole-fluid pressure and the pore-fluid pressure) is always maintained. As a result, borehole fluid is forced to flow into the formation (fluid-loss phenomenon), which may cause chemical interaction that can lead to shale instabilities. To mitigate this problem, an increase of mud viscosity or, in extreme cases, gilsonite is used to seal off microfractures.

Use of drilling fluid

Drilling overbalanced through a shale formation with a water-based fluid (WBF) allows drilling-fluid pressure to penetrate the formation. Because of the saturation and low permeability of the formation, the penetration of a small volume of mud filtrate into the formation causes a considerable increase in pore-fluid pressure near the wellbore wall. The increase in pore-fluid pressure reduces the effective mud support, which can cause instability. Several polymer WBF systems have made shale-inhibition gains on oil-based fluids (OBFs) and synthetic-based fluids (SBFs) through the use of powerful inhibitors and encapsulators that help prevent shale hydration and dispersion.

Wellbore-stability analysis

Several models in the literature address wellbore-stability analysis.[1] These include very-simple to very-complex models such as:

  • Linear elastic
  • Nonlinear
  • Elastoplastic
  • Purely mechanical
  • Physicochemical

Regardless of the model, the data needed includes:

  • Rock properties (Poisson ratio, strength, modulus of elasticity)
  • In-situ stresses (overburden, horizontal)
  • Pore-fluid pressure and chemistry
  • Mud properties and chemistry

Other than the mud data, the data are often compounded with problems of availability and/or uncertainties. However, sensitivity analysis can be conducted by assuming data for the many variables to establish safety windows for mud selection and design.

Borehole-instability prevention

Total prevention of borehole instability is unrealistic, because restoring the physical and chemical in-situ conditions of the rock is impossible. However, the drilling engineer can mitigate the problems of borehole instabilities by adhering to good field practices. These practices include:

  • Proper mud-weight selection and maintenance
  • Use of proper hydraulics to control the equivalent circulating density (ECD)
  • Proper hole-trajectory selection
  • Use of borehole fluid compatible with the formation being drilled

Additional field practices that should be followed are:

  • Minimizing time spent in open hole
  • Using offset-well data (use of the learning curve)
  • Monitoring trend changes (torque, circulating pressure, drag, fill-in during tripping)
  • Collaborating and sharing information


αm = activity in drilling mud, dimensionless
αs = activity in shale pore fluid, dimensionless
Ac = area of contact, L2 , in.2
Dh = diameter of the hole, L, in.
Dop = outside diameter of the pipe, L, in.
Em = efficiency, dimensionless
f = coefficient of friction, dimensionless
Fl = lateral force, F, lbf
Fp = pull force, F, lbf
hmc = mudcake thickness, L, in.
Lep = length of the permeable zone, L, in.
pcap = capillary pressure, F/L2, psi
pff = formation-fluid pressure, F/L2, psi
pm = mud pressure, F/L2, psi
pos = osmotic pressure, F/L2, psi
r = pore-throat radius, L, in.
T = tension in the drillstring just above the key-seat area, F, lbf
Δp = differential pressure, F/L2 , psi
Δλαf = additional mud weight caused by friction pressure loss in annulus, F/L3, lbm/gal
Δλs = additional mud weight caused by surge pressure, F/L3, lbm/gal
ϴ = contact angle between the two fluids, degrees
ϴdl = abrupt change in hole angle, degrees
λeq = equivalent mud circulating density, F/L3, lbm/gal
λfrac = formation-pressure fracture gradient in equivalent mud weight, F/L3, lbm/gal
λmh = static mud weight, F/L3, lbm/gal
μc = chemical potential, dimensionless
σ = interfacial tension, F/L, lbf/in.


  1. McLean, M.R. and Addis, M.A. 1990. Wellbore Stability Analysis: A Review of Current Methods of Analysis and Their Field Application. Presented at the SPE/IADC Drilling Conference, Houston, Texas, 27 February-2 March. SPE-19941-MS.

See also

Drilling problems


PEH:Drilling Problems and Solutions

Noteworthy papers in OnePetro

1. Aadnoy, B.S. 1988. Modeling of the Stability of Highly Inclined Boreholes in Anisotropic Rock Formations (includes associated papers 19213 and 19886 ). SPE Drill Eng 3 (3): 259-268. SPE-16526-PA.

2. Hale, A.H., Mody, F.K., and Salisbury, D.P. 1993. The Influence of Chemical Potential on Wellbore Stability. SPE Drill & Compl 8 (3): 207-216. SPE-23885-PA.

External links