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SPE 54356 Drilling Fluid Interaction and Shale Strength

SPE 54356
Shale Stability: Drilling Fluid Interaction and Shale Strength
Manohar Lal, SPE, BP Amoco
Copyright 1999, Society of Petroleum Engineers Inc.
This paper was prepared for presentation at the 1999 SPE Latin American and Caribbean
Petroleum Engineering Conference held in Caracas, Venezuela, 21–23 April 1999.
This paper was selected for presentation by an SPE Program Committee following review of
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presented, have not been reviewed by the Society of Petroleum Engineers and are subject to
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at
SPE meetings are subject to publication review by Editorial Committees of the Society of
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This paper presents main results of a shale stability study,
related to the understanding of shale/ fluid interaction
mechanisms, and discusses shale strength correlation. The
major shale/ fluid interaction mechanisms: Capillary, osmosis,
hydraulic, swelling and pressure diffusion, and recent
experimental results are discussed. Factors affecting the shale
strength are discussed, and a sonic compressional velocity-log
based correlation for strength is proposed. Recommendations
for modeling and improving shale stability are described,
based on the current understanding of shale stability.
Shales make up over 75% of the drilled formations, and over
70% of the borehole problems are related to shale instability.
The oil and gas industry still continues to fight borehole
problems. The problems include hole collapse, tight hole,
stuck pipe, poor hole cleaning, hole enlargement, plastic flow,
fracturing, lost circulation, well control. Most of the drilling
problems that drive up the drilling costs are related to wellbore
stability. These problems are mainly caused by the imbalance
created between the rock stress and strength when a hole is
drilled. The stress-strength imbalance comes about as rock is
removed from the hole, replaced with drilling fluid, and the
drilled formations are exposed to drilling fluids.1
While drilling, shale becomes unstable when the effective
state of the stress near the drilled hole exceeds the strength of
the hole. A complicating factor that distinguishes shale from
other rocks is its sensitivity to certain drilling constituents,
particularly water. Shale stability is affected by properties of
both shale (e.g. mineralogy, porosity) and of the drilling fluid
contacting it (e.g. wettability, density, salinity and ionic
concentration). The existence and creation of fissures,
fractures and weak bedding planes can also destabilize shale as
drilling fluid penetrates them. Drilling fluids can cause shale
instability by altering pore pressure or effective stress-state
and the shale strength through shale/fluid interaction. Shale
stability is also a time-dependent problem in that changes in
the stress-state and strength usually take place over a period of
time. This requires better understanding of the mechanisms
causing shale instability to select proper drilling fluid and
prevent shale instability.
The basic shale stability problem can be stated as follows:
Shale with certain properties (including strength) normally lies
buried at depth. It is subjected to in situ stresses and pore
pressure, with equilibrium established between the stress and
strength. When drilled, native shale is exposed suddenly to the
altered stress environment and foreign drilling fluid. The
balance between the stress and shale strength is disturbed due
to the following reasons:
• Stresses are altered at and near the bore-hole walls as
shale is replaced by the drilling fluid (of certain density)
in the hole.
Interaction of drilling fluid with shale alters its strength as
well as pore pressure adjacent to the borehole wall. Shale
strength normally decreases and pore pressure increases as
fluid enters the shale.
When the altered stresses exceed the strength, shale
becomes unstable, causing various stability related problems.
To prevent shale instability, one needs to restore the balance
between the new stress and strength environment.
Factors that influence the effective stress are wellbore
pressure, shale pore pressure, far away in situ stresses,
trajectory and hole angle, etc. The effective stress at any point
on or near the borehole is generally described in terms of three
principal components. A radial stress component that acts
along the radius of the wellbore, hoop stress acting around the
circumference of the wellbore (tangential), axial stress acting
parallel to the well path, and additional shear stress
To prevent shear failure, the shear stress -state, obtained
from the difference between the stress components (hoop usually largest and radial stress - smallest), should not go
above the shear strength failure envelope. To prevent tensile
failure causing fracturing, hoop stress should not decrease to
the point that it becomes tensile and exceeds the tensile
strength of the rock.
The controllable parameters that influence the stress-state
are drilling fluid, mud weight, well trajectory, and drilling/
tripping practices. For example, radial stress increases with
mud weight (wellbore pressure) and hoop stress decreases with
mud weight causing mechanical stability problem. The near
wellbore pore pressure and strength are adversely affected by
drilling fluid/shale interaction as shale is left exposed to
drilling fluid (chemical stability problem).
Mechanical stability problem can be prevented by restoring
the stress-strength balance through adjustment of mud weight
and effective circulation density (ECD) through drilling/
tripping practices, and trajectory control. The chemical
stability problem, on the other hand, is time dependent unlike
mechanical instability, which occurs as soon as we drill new
formations. Chemical instability can be prevented through
selection of proper drilling fluid, suitable mud additives to
minimize/delay the fluid/shale interaction, and by reducing
shale exposure time. Selection of proper mud with suitable
additives can even generate fluid flow from shale into the
wellbore, reducing near wellbore pore pressure and preventing
shale strength reduction.
Understanding Subsurface Shale
The term shale is normally used for the entire class of finegrained sedimentary rocks that contain substantial amount of
clay minerals. Sedimentologists find shale hard to work with
since shale is fine grained, lacks well-known sedimentary
structure (so useful in sandstones), and readily applicable tools
and models are not available to study shale.2
distinguishing features of shale (of interest to oil industry) are
its clay content, low permeability (independent of porosity)
due to poor pore connectivity through narrow pore throats
(typical pore diameters range 3 nm-100 nm with largest
number of pores having 10 nm diameter), and large difference
in the coefficient of thermal expansion between water and the
shale matrix constituents. To understand drilling fluid
interaction with shale, one must start from basic properties of
in situ shale (e.g. pre-existing water in shale, mineralogy,
porosity), and then analyze the impact of changes in stress
environment on the properties of shale.
Several factors affect the properties of shale buried at
various depths. The amount and type of minerals, particularly
clay, in shale decide the affinity of shale for water. For
example, shale with more smectite (surface area - 750 m2/gm)
has more affinity for water (adsorbs more water) than illite
(surface area - 80 m2/gm) or kaolinite (25 m2/gm). Three
different types of water are found associated with clays,
although each clay will not contain all of the types. Intercrystalline water is found in associated with the cations
neutralizing the charge caused by elemental substitution.
Osmotic water is present as an adsorbed surface layer
associated with the charges on the clay. The swelling
associated with this type of mechanism occur when
SPE 54356
sedimentary rocks are unloaded as occurs in drilling. Bound
water is present in the clay molecule itself as structurally
bonded hydrogen and hydroxyl groups which under extreme
conditions, temperatures of 600-7000 C, separate from the clay
to form water.
The free water exists only within the pore space between
the grains. The porosity of shale is normally defined as the
percent of its total volume that water. This value is normally
measured by drying a known volume of shale at elevated
temperature. Porosity then is a measure of free water, osmotic
water and to a lesser extent inter-crystalline water. Chemically
bound water is not measured in this procedure. Properties of
shale and drilling fluid/shale interaction are strongly
influenced by the bound water and to a lesser extent by the free
Some of water associated with clay can also be removed
using pressure. The majority of the loosely held osmotic water
can be removed with an overburden pressure of about 290 psi.
In the inner-crystalline case, up to four layers of water may be
found. The third and fourth layer can be removed with about
3900 psi. Approximately, 24000 psi is required for second
mono-layer and according to various estimates,3-4 pressure
over 50,000 psi is required to squeeze water in single monolayer of clay platelets. It requires temperatures in excess of
200o C to remove all bound water from clay. It is, therefore,
doubtful that shale is ever completely void of water in typical
drilling environment. Prior to drilling, the exact amount of
bound and free water in shales buried at depth, however,
depends on the past compaction history.
Compaction of clay proceeds in three main stages.5 The
clays are removed from land by water and deposited in
quiescent locations. Clays, at their initial state of deposition
and compaction, have both high porosity and permeability;
pore fluids are in communication with the seawater above;
sediments consisting of hydratable clay with absorbed water
layers prevent direct physical grain-to-grain contact. At the
time of deposition, mud water contents may be 70-90%.
In the normal compaction process as clay/shale sediments
are buried with pore water being expelled, porosity (sonic
travel time) decreases. However, any disruption of this normal
compaction and water expulsion process can lead to increase
in both porosity (sonic travel time) and pore pressure.
In the first stage of compaction, free pore-water, osmotic
water and water inter-layers beyond two layers are squeezed
out by the action of overburden. After a few thousand feet of
burial, the shale retains only about 30% water by volume, of
which 20-25% is bound interlayer water and 5-10% residual
pore water. In the early stages compaction strongly depends on
depth of burial, grain size (fine-grain clays have more porosity
but compact easily), deposition rate (high rate results in
excessive pore pressures and under-consolidation), clay
mineralogy (monmorillonitic shale contain more water than
illitic or kaolinitic shale), organic matter content, and geochemical factors (e.g. concentration of sodium salts affects
SPE 54356
In the second stage of compaction, pressure is relatively
ineffective for dehydration that is now achieved by heating,
removing another 10 to 15% of the water. The second stage
begins at temperatures close to 100oC and diagenetic changes
in clay mineralogy may also occur. The third and final stage of
compaction and dehydration is also controlled by temperature
but is very slow, requiring hundreds of years to reach
completion and leaving only a few percent of water.
To sum up, the properties of drilled shale formation, which
are important for shale/fluid interaction and shale stability, are
dictated by the past compaction history and the current in situ
stresses and temperature. For example, affinity (thirst) for
water of the shale at any depth depends on compaction/
loading history, in situ stresses, clay composition, and
temperature. These factors also determine shale porosity,
permeability and the amount of water squeezed out.
Shale/Fluid Interaction Mechanisms
Analysis of the available experimental data (O’Brien-GoinsSimpson Associates and University of Texas, Austin, Shell and
Amoco sponsored Projects)6, clearly shows that the shale
strength and the pore pressure near the bore-hole are indeed
affected by fluid/shale interaction. Basic results confirmed by
this analysis can be summarized as follows:
• Activity imbalance causes fluid flow into/or out of shale
• Different drilling fluids and additives affect the amount of
fluid flow in or out of shale
• Differential pressure or overbalance causes fluid flow into
• Fluid flow into shale results in swelling pressure
• The moisture content affects shale strength. Moisture
content relates to sonic velocity.
The instability and shale/fluid interaction mechanisms,
coming into play as drilling fluid contacts the shale formation,
can be summarized as follows.7-8
1. Mechanical stress changes as the drilling fluid of certain
density replaces shale in the hole. Mechanical stability
problem caused by various factors is fairly well
understood, and stability analysis tools are available.8
2. Fractured shale - Fluid penetration into fissures and
fractures and weak bedding planes
3. Capillary pressure, pC, as drilling fluid contacts native
pore fluid at narrow pore throat interface.
4. Osmosis (and ionic diffusion) occurring between drilling
fluid and shale native pore fluid (with different water
activities/ ion concentrations) across a semi-permeable
membrane (with certain membrane efficiency) due to
osmotic pressure (or chemical potential), PM.
5. Hydraulic (Advection), ph, causing fluid transport under
net hydraulic pressure gradient because of the hydraulic
6. Swelling/Hydration pressure, ps, caused by interaction of
moisture with clay-size charged particles.
7. Pressure diffusion and pressure changes near the wellbore
(with time) as drilling fluid compresses the pore fluid and
diffuses a pressure front into the formation.
Fluid penetration in fractured shale and weak bedding
planes can play a dominant role in shale instability, as
large block of fractured shale fall into the hole. Several
papers have been written on this phenomenon.9 In
Norway Valhall field, this phenomenon is suspected to be
one of the major causes of shale instability. Preventive
measures include use of effective sealing agents for
fractures, e.g. graded CaCO3, high viscosity for low shear
rates, and lower ECD.
Capillary phenomenon also is now fairly well understood,
and an interesting exposition is given in a recent paper.10
Increasing the capillary pressure for water-wet shale has been
successfully exploited to prevent invasion of drilling fluid into
shale through use of oil base and synthetic mud using esters,
poly-alpha-olefin and other organic low-polar fluids for
drilling shale. The capillary pressure is given by
pC = 2γ cosθ/r .................................................................(1)
where, γ is interfacial tension, θ is contact angle between the
drilling fluid and native pore fluid interface, and r is the pore
When drilling water-wet shale with oil base mud, the
capillary pressure developed at oil/pore-water contact is large
because of the large interfacial tension and extremely small
shale pore radius. It prevents entry of the oil into shale since
the hydraulic overbalance pressure, ph (=Pw-po), is lower than
the capillary threshold pressure, pC. In such a case, advection
(and pressure diffusion) cannot occur. However, osmosis and
ionic diffusion phenomena can still occur under favorable
conditions. Capillary pressure thus modifies ph and the net
hydraulic driving pressure ph‘is given as follows:
0 < pC < ph
ph ′ = p h − p C ,
p h ′ = 0,
pC > p h
Capillary pressures for low permeability water-wet shales
can be very high (about 15 MPa for average pore throat radius
of 10nm). This is one of the key factors in successful use of oil
base muds or synthetic muds using esters, poly-alpha-olefin
and other organic low-polar fluids.
Osmotically induced hydraulic pressure or differential
chemical potential, PM, developed across a semi-permeable
membrane is given by 10-12,
PM = - ηPπ = - η (RT/V)ln(Ash/Am)..................................(3)
where, η is membrane efficiency, Pπ is the theoretical
maximum osmotic pressure for ideal membrane (η=1), R is the
gas constant, T is the absolute temperature, V is the molar
volume of liquid, and Am, Ash are the water activities of mud
and shale pore fluid, respectively.
Various expressions have been obtained for the membrane
efficiency in terms of parameters that are difficult to measure.
Two such expression are:11
η = 1 − ( a − rs ) 2 / ( a − rw ) 2
η = 1 − νs / ν w
where, ‘a’ is pore radius, rs is solute radius, rw is water
molecule radius, and νs and νw are the velocities of solute and
water, respectively.
From non-equilibrium thermodynamics principles,
assuming slow process near equilibrium and single nonelectrolyte solute, the linear relations between the pressure and
flow can be written as 11-12
Jv ∆x = Lpph – Lp η Pπ......................................................(5)
Js ∆x = Cs(1- η)Jv+ ωPπ....................................................(6)
Jv =JwVw + JsVs................................................................(7)
where Eqn. 5 simply states that the fluid flux Jv into shale is
the superposition of fluxes due to hydraulic pressure gradient
ph (advection) and due to osmotically induced pressure, PM
(=η Pπ), related through the hydraulic permeability coefficient
Lp. The coefficient Lp is related to the shale permeability, k,
and filtrate viscosity, µ, as Lp= k/µ. Eq. 6 describes the net salt
flux Js into the shale. Eq. 7 simply expresses the mass balance
in terms of the water and salt flux and partial molar volumes of
these components. Note that for perfect membrane, η =1, since
only water can flow across the membrane, Js=0 and thus ω =0.
Hydraulic (Advection), ph, is implicitly included in Eq. 5.
If the test fluid is the same as shale pore fluid (which implies
equal activity and Pπ =0 - no osmosis), Eq. 5 reduces to the
familiar Darcy’s law which gives volume flow as:
Jv ∆x = Lp ph...................................................................(8)
where as Lp= k/µ.; k denotes shale permeability and µ denotes
viscosity. Such an experiment was performed by van Oort to
characterize the permeability of shale and estimate Lp.
As stated earlier, a recent study on osmotic and hydraulic
effects was conducted at O’Brien-Goins-Simpson &
Associates, Inc. as part of the work sponsored by the Gas
Research Institute (GRI). General conclusions from the study
can be summarized as follows:
• Increased hydraulic potential can increase the amount of
transport of water into shales and reduce rock strength
SPE 54356
(with exposure time). Increasing the mud weight may thus
worsen a stability problem (over time) rather than curing
• In hydrocarbon-based fluids, water transport into shales
may be controlled through the activity of the internal
phase relative to the shale.
• Water-based fluids require a much lower activity than the
shale to control water transport. Even then the effective
strength may be reduced.
Swelling pressure and swelling behavior of shales is
directly related to the type and amount of clay minerals in a
given shale. Two types of swelling observed in clays are:
a) Innercrystalline swelling (IS) - caused by hydration of the
exchangeable cations of the dry clay
b) Osmotic swelling (OS) - caused by large difference in the
ionic concentrations close to the clay surfaces and in the
pore water.
It may be noted that the osmosis, discussed earlier, was
concerned with ionic concentration or water activity
differences between the drilling fluid and the pore water.
The swelling stress due to inner-crystalline swelling (IS)
can be very large (approximately up to 58000 psi for the
formation of first water layer, up to 16000 psi for second, and
up to 4000 for the third and fourth layers for pure
montmorillonite in the Wyoming bentonite). The swelling
stresses resulting from osmotic swelling (OS), on the other
hand, are relatively small and usually do not exceed 300 psi.13
Complete understanding of physico-chemical reactions
between clays and water requires a detail discussion of the
structure of compacted clay, namely the arrangement of clay
particles at the atomic level and the electrical forces between
the adjacent particles. The electrical forces act only near the
particle surface and mostly result from discontinuity at or near
the surface, they become particularly significant and dominate
the mass forces (such particles are called colloidal - 1micron 1 millimicron (10A) size range) for clays since they have large
surface area per unit mass. Several excellent papers13 are
available which attempt to describe various aspects of this
complex phenomenon.
A simple explanation, which may suffice for this report, is
given as follows. First the electrical forces: van der Waals
forces (secondary valence forces) between units of clay arise
from electrical moments existing within units, which are
similar to force acting between two short bar magnets. Since
there are more attractive positions than repulsive, the net effect
of such forces is attraction. These forces exist in clays because
of the nonsymmetrical distribution of electrons in the silicate
crystals, which act as a large number of dipoles. They can
attract other dipoles like water molecules, which are
permanent dipoles due to nonsymmetrical configuration of the
water molecules and position of the atoms in the molecule.
The hydrogen bond linkage between water molecules occurs as
each hydrogen atom, attracted by the oxygen in neighboring
water molecule, links its water molecule to others.
Furthermore, clay particles carry a net negative charge
SPE 54356
(mainly caused by isomorphous substitution - e.g. substitution
of bivalent Mg for trivalent Al). This net negative charge is
balanced by exchangeable cations, clustered at the clay surface
to neutralize the particles. When the dry clay particle is placed
in water the cations swarm around the clay surface particles,
forming a double layer with certain electrical potential that
vary with characteristics of the dispersion medium (according
to Gouy-Chapman theory). Because of the net negative charge,
adjacent clay particles repel each other as they approach each
other close enough for the double layers to overlap.
Combining this with the secondary valence attractive forces,
equations for total potential energy have been developed. If the
total potential energy reduces when adjacent particles
approach each other, they flocculate (form aggregates), but if it
increases they disperse or move apart.
Confining discussion to clay-water reaction, the clay-water
attractive force consists of two main components: attraction of
dipolar water to the electrically charged clay particles and
attraction of the dipolar water to the cation in the double layer
- the cations in turn are attracted to the clay. Based on relative
magnitude of force between water and clay (large near but
becoming weak away from the colloidal surface), water can be
categorized into three types: adsorbed - strongly held by clay;
double layer - all the water attracted to clay anywhere in the
double layer; and free water which is not attracted to clay at
For illustration, let us look at two clay minerals:
montmorollinite and kaolinite. For both minerals, the force
required to pull the adsorbed water off the mineral surface is
extremely high (varying from 100 for outside to 10,000
atmospheres for the closest molecules). The adsorbed and
double layer water on kaolinite are thicker than on
montmorillonite because of the high charge density on
kaolinite (about twice). However, the amount of adsorbed
water expressed, as a percentage of mineral weight is much
greater on montmorillonite since its specific surface is greater.
The controversy regarding particle mineral-to-mineral contact
in clay is not yet settled. According to one concept, cohesion
in a natural clay is due to “water bonds”20. Compaction and
any other stress changes on clay minerals in shale also affect
the clay structure and thus water-clay interaction.
Swelling experiments indicate that the swelling follows a
diffusion type of law, and the cumulative water flux into the
shale, Q, time t, sorptivity S, the change in equilibrium void
ratio (liquid to solid volume ratio) ∆e, and diffusivity, D, are
related as follows 14:
Q = S.t 0.5
S = ∆e.(2D)0.5...................................................................(9)
The linear dependence of S on the change in equilibrium
void ratio on swelling implied in the above equation is
observed experimentally. Diffusivity for Pierre shale inferred
from experiments is about 9x10-10 m2s-1 at 20o C. D depends
on the nature of bound cations, and commonly used polymers
appear to have little effect on its value. The low values of D
for typical shales may also explain why many shales become
unstable after several weeks.
Exchange of the natural bound cation (Na+, Ca2+, Mg2+)
by K+ can lead to a clay fraction with lower swelling tendency.
The experimental results, however, seem to indicate that a
large fraction of the clay cations must be replaced before this
effect is significant, and the action of KCl is largely osmotic
since on the time scale of the swelling experiments little ion
exchange with clay has taken place.
Atmospheric swelling and saturation experiments on
Speeton shale core were also sponsored by the GRI at the
University of Texas, Austin. An interesting conclusion from
this study was that the activities of the shale-fluid system,
nature of the ions, ionic concentration, hydrated ionic diameter
and valency of the generated cations influence the ultimate
swelling response of shale. The results of the study indicate
that water activity differential is not the only mechanism of
water transportation into shale matrix under atmospheric
conditions. The Electro-chemical forces associated with
negatively charged clay surfaces and ionic exchange may
transport water into shale matrix even in the presence of low
activity salt solutions. In summary, swelling phenomenon in
shales can be explained in terms of clay-water reaction, and
water has significant effect on the properties of clays.
Pressure diffusion phenomenon concerns the pressure
change with time near the wellbore as the drilling fluid at
wellbore pressure, Pw, in conjunction with the osmotic
pressure, PM, etc. suddenly contacts and compresses the pore
fluid at the wellbore wall (which was at pressure, po, before
drilling). The pressure away from the wall varies with time
until a steady-state pressure distribution between near and faraway pore pressure is established. This pressure diffusion can
be compared in a way to the pressure surge when a pipe
suddenly moves in a wellbore compressing the drilling fluid,
which is analyzed as transient wave propagation instead of
diffusion phenomenon. Various expressions and numerical
simulations for pressure diffusion have been used to study this
phenomenon 15-16. The basic point of these studies can be
illustrated with the help of Fig. 1.
If a drilling fluid cannot penetrate shale at all (e.g. perfect
oil base mud for a given shale), the pore pressure near the
wellbore wall is the virgin pore pressure po (ignoring the effect
of stress changes) at the time drilling fluid comes in contact
with shale (t=0) and remains the same for t>0. However, when
the mud is such that it interacts with shale, the drilling fluid at
wellbore pressure Pw will diffuse through shale. The pressure
near the wall in the pores will increase from po with time. How
fast this pore pressure in the vicinity of the borehole increases
depends upon the permeability of shale, its elastic properties
and other boundary conditions. In general, lower the
permeability, more time it takes for pressure to increase and
tend to equalize with Pw, thus losing pressure support for the
formation. Depending on permeability, it may take anywhere
from a few hours to a number of days before the pressure near
the wellbore approaches the wellbore pressure, losing pressure
support, reducing effective stresses and bringing the rock to
unstable situation. This could be an explanation for the
delayed failure of exposed shale sections, often experienced in
the field.
Shale Strength Correlation
For stability analysis, an important input parameter needed is
the formation strength, which is usually characterized by
cohesive strength S0, and friction angle φ . These parameters
are traditionally determined from different rock mechanical
core tests based on a number of different core plugs from the
same depth. The test results from several plugs are then
combined to provide these strength properties from this depth.
Regarding rock strength, it is far easier to make rock grains
slide past one another than it is to crush them. Consequently,
when rocks fail in compression, they are actually failing in
shear, as a result of inter-granular slip. Their resistance to
shear, i.e. shear strength, is due to a combination of cohesion
and friction between the rock grains.
The amount of cohesion is represented by a parameter
known as the cohesive strength S0, while inter-granular friction
is defined by the internal friction angle φ. For a layer of rock
subjected to an effective compressive stress σ and a shear
stress τ, the shear failure criterion can be written simply as:
τ = S0 + σ tan φ..............................................................(10)
Where, the effective compressive stress σ is related to the total
compressive stress s and pore pressure p as follows:
σ = s - p..........................................................................(11)
For complex stress states, such as exist at the wall of a
wellbore, a number of different failure criteria have been
proposed for generalizing Eq. 10. However, all the criteria are
related to the parameters S0 and φ.
For example, the Mohr-Coulomb6,8 shear failure criterion
can be written as:
= So cosφ +
Where, (σ1-σ3)/2 is the Mohr Coulomb shear strength
parameter, and (σ1+σ3)/2 is the average effective stress, and
σ1, σ3 are the maximum and minimum effective compressive
stresses, respectively.
The Drucker-Prager Criterion is defined in terms of the two
generalized stresses, the mean effective stress:
I1 = (σ1 + σ2 + σ3 )/3......................................................(13)
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and an equivalent shear stress parameter √J2, where
√J2 =
((σ1-σ2)2+(σ1-σ3)2+(σ2-σ3)2)/6 .........................(14)
and σ2 is the intermediate effective compressive stress.
The Drucker-Prager Criterion is8:
√J2 = m I1 + τo ..............................................................(15)
where, in terms of So and φ:
m = 2√3 sin φ /(3-sin φ)..............................................(16a)
τo = 2√3 So cos φ /(3-sin φ)...............................................(16b)
S0 and φ can be determined from laboratory triaxial
strength tests, in which cylindrical samples of rock are first
subjected to a hydrostatic confining pressure, and an axial load
is then applied until the rock fails. These tests are performed
at several different confining pressures, and the results are
plotted as a series of Mohr’s circles, as shown in Fig. 2. For
linear failure criterion, the line that envelops the family of
circles has a slope equal to tanφ, and an intercept equal to S0.
Intuitively, we know that rock strength tends to increase
with compaction. Consequently, this suggests that S0 and φ
can be tied to compaction-dependent wire-line measurements,
such as porosity, density, and sonic velocity.
However, determining S0 and φ on a foot-by-foot basis
presents more of a challenge. It clearly is not feasible to do
this with laboratory strength tests. As an alternative, it is
desirable to develop relationships for computing S0 and φ from
wire-line data. Therefore, rock strength correlation actually
refers to relation with wire-line log data for determining the
cohesive strength and friction angle.
A more fundamental look at shale physics was taken to
gain better insight into which factors need to be included in
strength correlation. Three factors were considered6:
• clay mineralogy
• clay content
• compaction.
The main conclusion from the study, based on several
external and internal data sources, appears to be as follows.
Under in situ stress and native pore fluid salinity conditions,
clay mineralogy and contents are of secondary importance
regarding their effect on shale strength. The degree of
compaction (characterized by water content, porosity, sonic
velocity, etc.) appears to be the dominant factor. Thus,
strength can be tied to any of the following related parameters:
• water content
• porosity
• sonic velocity
SPE 54356
The shale strength correlations, developed by the author,
were tied only to compressional sonic velocity in shales. The
relations were developed using an extensive shale database.
The following relations for friction angle, φ (degrees) , and
cohesive strength, So (MPa), were developed as a function of
compressional sonic velocity Vp (km/sec):
sin φ = (Vp - 1)/( Vp + 1)
So = 5(Vp-1)/√Vp , or
= 10 tanφ.......................................................................(17)
Fig. 3 plots the velocity based strength estimates computed
from both laboratory measured and sonic log-derived
velocities (reported for different core depths in North Sea),
along with the measured strength data. Both estimates are
fairly good, which show that this correlation is applicable with
sonic log derived velocities.
The sonic correlation was also found to be fairly
satisfactory for formations other than shale. The estimated
cohesive strength and friction angle parameter represent local
values at the in situ stress conditions reflected in the sonic log
measurements. For sands, Gassman Correction for gas needs to
be applied, or nearby shale points needs to be picked as in
pore pressure estimation.
The impact of clay mineralogy and contents on strength
(and stability) can become quite significant while drilling,
when a foreign drilling fluid contacts in situ smectitic shale
and alters the salinity of native pore fluid through shale/fluid
interaction. Smectitic shales have a lower tolerance to drilling
fluid invasion, and will tend to fail easier than formations in
which kaolinite and/or illite are the only clay types present.
The effect of clay mineralogy on strength can be important if
the drilling process severely disturbs a formation from its
natural state. In those cases, as discussed below, smectitic
formations will be more susceptible to failure.
The strength of all geologic materials depends upon the
effective confining.
Therefore, if shale/drilling fluid
interaction raises the pore pressure in the near wellbore region,
the drop in effective confining pressure will make the hole
more susceptible to failure. However, with smectites, drilling
can introduce two additional destabilizing effects.
As discussed earlier, confining pressures in the vicinity of
500 psi are necessary to keep liquid water from getting in
between smectite platelets. The two-to-three layers of water
that remain are more competent than liquid water, and appear
to allow smectite platelets to act like thicker, stronger
particles. This effect can be reduced or lost if the effective
confining pressure drops to values low enough to permit liquid
water to penetrate between the platelets.
Salinity can also cause smectite platelets to behave like
thicker particles. However, as reported earlier this effect is not
permanent. A drop in salinity can cause a loss in strength.
Therefore, a high activity (low salinity) mud could cause a
significant drop in the strength of smectitic formations.
To summarize, smectitic formations are highly susceptible
to the effects of drilling fluid/shale interaction. Fluid invasion
not only reduces friction and interlocking between smectite
grains, it can also reduce the competency of the grains
themselves. The impact of clay mineralogy on strength (and
stability) can thus become quite significant on drilling, when a
foreign drilling fluid contacts in situ smectitic shale and alters
the salinity of native pore fluid through shale/fluid interaction.
Smectitic shales have a lower tolerance to drilling fluid
invasion, and will tend to fail easier than formations in which
kaolinite and/or illite are the only clay types present.
Finally, the effects of drilling fluid/shale interaction must
be kept in mind when using offset well log data. Wireline log
readings may not reflect true in situ pore pressure and rock
properties if the near wellbore region has been invaded by the
drilling fluid and undergone hydration. Hydration raises the
local pore pressure and weakens the rock.
Improving Shale Stability
Thus far, we have seen that there are several mechanisms
which cause or affect shale/fluid interaction. There is an
intense effort under way in the oil industry to get a better
understanding of each of these mechanisms. The stakes are
high in that understanding and quantification of each of these
phenomena is critical for designing benign drilling fluids
which would stabilize shales. Rapid progress is being made
and more results will become available in the near future. The
current understanding of various mechanisms responsible for
shale/fluid interaction indicate certain basic principles for
improving shale stability.
Based on current understanding of various shale/fluid
interaction mechanisms, we can discuss some general
principles for improving shale stability. The main objective to
improve shale stability is to prevent, minimize, delay or use to
our advantage the interaction of the drilling fluid with shale.
As our understanding of the various interaction mechanisms
improves, so will the mud systems designed to improve shale
We can list the following means of improving shale
stability corresponding to various mechanisms contributing to
shale/fluid interaction:
• For fractured shale stability, use effective sealing agents,
thixotropic drilling fluid (high viscosity for low shear
rates), and lower mud weight /ECD. This would minimize
fluid penetration into fractures.
• Increase the capillary pressure, pC(>ph’) to prevent fluid
entry into shale pore throats. Eq. 1 suggests that
increasing interfacial tension and contact angle θ can
increase the capillary pressure for given shale pore throat
radii. Increasing capillary pressure through γ and θ for
water-wet shales has been successfully exploited through
use of oil base muds or synthetic muds using esters, poly-
alpha-olefin and other organic low-polar fluids.
Reduce the total net driving force (pressure) for
shale/fluid interaction. The net effective driving force
(pressure) at t=0+ for pC<ph(=Pw-po) can be written as:
ph‘= Pw - po - pC+ PM......................................................(18)
which brings about the changes with time in the near wellbore
pore pressure through pressure diffusion or transmittal and
fluid transport into (or out of) the shale. The near wellbore
pore pressure, pn, can be expressed in terms of the original
virgin pore pressure, po, and time changes, δp(t), as:
pn = po + δp(t)............................................................... (19)
to minimize δp(t), we need to minimize ph′ , which can be
accomplished by increasing capillary pressure pc, as discussed
above, or making osmotic pressure PM equal to (or less than)
zero by matching (or making drilling fluid activity, Am, lower
than) shale water activity, Ash. If the activity of the mud is
higher than that of the shale, we need to reduce membrane
efficiency as much as possible. However, when drilling fluid
activity is made lower than shales, resulting in negative
osmotic pressure and causing pore fluid to flow out of shale
into the wellbore, the membrane efficiency needs to be
Reduction of drilling fluid activity, Am, is at the heart of
most inhibitive muds 14. This reduction is brought about by
adding electrolytes: seawater bentonite muds, saturated saltpolymer (xanthan, guar), KCl or NaCl-polymer (PHPA,
xanthan), fresh water calcium treated muds (lime, gypsum). A
new type of drilling fluid based on a substituted sugar, methyl
gluocide, is currently being looked at because of its ability to
form low activity muds with high membrane efficiency. The
dispersed water phase in oil base muds is treated to adjust the
activity, usually with CaCl2, to make activity Am<Ash.
• Slow down the rate of fluid transport and pressure
diffusion rate.
It is difficult to balance water activity of shale with mud
exactly everywhere in a well because shale activity is not
known and varies with depth and mineralogy. We can,
nevertheless, control parameters that enable us to reduce the
fluid transport and pressure diffusion rates by increasing the
fluid viscosity and reducing the permeability of shales.
Regarding the viscosity increase, the problem is to find solutes
that increase the fluid viscosity significantly and yet can pass
through the narrow shale pore space to maintain high viscosity.
Most mud polymers are too large to enter shale but some low
molecular weight polymers might achieve the desired results.
As regards reducing permeability, one solution is to form
permeability barrier at shale surface or within micro-fractures.
Oil base mud achieves this as water is made to diffuse through
continuous oil phase to reach the shale. Silicate and ALPLEX
muds, for example, attempt to reduce the permeability.
SPE 54356
Cationic polymers, which are strongly adsorbing, can also act
in the same way. In the extreme, shale formation could be
completely isolated by creating an impermeable hydrophobic
seal, using asphaltine derivatives like gilsonite. Use of charged
emulsifiers for binding the oil droplets of oil-in-water
emulsions to the clay surface and organophilic clays in oil base
muds could achieve similar results.
Although changing the clay cation with less hydratable K+
or Ca2+ can reduce intrinsic swelling, these ions lead to more
open structure and thus increase permeability. Work is
currently underway to formulate drilling fluids containing
cesium, Ce+ for stabilizing the shale. While this fluid would be
very expensive to formulate, increased stability and rate of
penetration could compensate for this cost.
• Preserve mechanical integrity of the shale cuttings.
As damage control, certain measures can be taken to limit
the dispersion of cuttings or spallings by binding the clay
particles together, if shale failure or erosion is initiated.
Polymers that can reduce shale disintegration must adsorb
onto clay platelet surface and have high enough energy to
resists mechanical or hydraulic forces pulling them apart.
PHPA and strongly adsorbing cationic polymers and
components like polyglycerol can limit the dispersion of
shale cuttings or spallings in the well. To achieve similar
results within the shale formation, polymer must be able to
diffuse into the bulk shale, requiring short flexible chains.
Future work on shale stability and understanding
shale/fluid interaction is bound to lead to better means to
stabilize shales and design of environmentally acceptable
effective mud systems. As new additives for drilling fluids are
studied to stabilize shales, major challenge would be to make
them compatible with preserving other desirable mud
properties such as, rheology, drilled solids compatibility and
drilling rates.
Finally, even if we could design the best mud system for
shale formations, continuous monitoring and control of drilling
muds are critical elements for successful drilling. The mud
composition continually changes as it circulates and interacts
with formations and drilled solids. Unless concentrations of
various mud additives are continually monitored (as opposed
to the current practice of periodically monitoring just
rheological and simple properties) and maintained, the desired
results could not be achieved. The development and
introduction of improved monitoring techniques for chemical
measurements should proceed simultaneously with the
development of more effective mud systems for shale stability,
based on improved understanding of shale/fluid interaction.
The above discussion gives an indication of the experimental
activity and progress in shale stability projects, sponsored by
oil and gas industry. However, understanding of the shale/fluid
interaction mechanisms is not yet complete to effectively
control the shale instability problem. The ongoing
developments and data from numerous active industry
SPE 54356
sponsored shale stability projects, hopefully, will provide
answers to the remaining questions. Then only, one can
develop models that can quantify the impact of shale/fluid
interaction on the stress- strength of the shale and the timedependent effects.
In view of the shale instability costs, it is imperative to
understand shale behavior and its interaction with different
fluids. Completely satisfactory answers to questions such as:
which drilling fluid to use for drilling a particular shale, or
how long can we keep the hole exposed to a particular fluid
without causing shale instability, can be given only after such
an understanding. The quantification of the impact of fluid
invasion on effective stresses and shale strength near the
wellbore is critical for shale stability analysis models. Simple
and realistic shale testing procedures and shale/ fluid
interaction testing procedures are required in order to achieve
practical assessments of wellbore instability risks. Efforts to
develop predictive models and to develop more effective fluids
for drilling shales, based on improved understanding of
shale/fluid interaction mechanisms must continue.
Vp =
γ =
θ =
νs =
νw =
µ =
∆e =
φ =
σ =
τ =
σ1 =
σ2 =
σ3 =
Am = water activities of mud
Ash = water activity of shale
D = diffusivity
Jv = fluid flux
Js = solute flux
k = shale permeability
Lp = hydraulic permeability coefficient
PM = observed osmotic pressure
Pw = wellbore pressure
Pπ = theoretical osmotic
p = pore pressure
pC = capillary pressure
ph = hydraulic pressure
ph′ = net hydraulic pressure
ps = swelling pressure
Q = cumulative water flux
R = gas constant
r = pore radius
rs = solute radius
rw = water molecule radius
S = sorptivity
S0 = cohesive strength
s = total compressive stress
T = absolute temperature
t = time
V = molar volume
help and
are also
compressional sonic velocity
surface tension
contact angle
membrane efficiency
solute velocity
water velocity
filtrate viscosity
liquid to solid volume ratio
internal friction angle
effective compressive stress
shear stress
effective maximum principal stress
effective intermediate principal stress
effective minimum principle stresses
The author would like to thank Glenn
Tron Kristiansen and Calvin Deem for their valuable
discussions. Their contributions and help in several
stability projects, related to shale/fluid interaction,
gratefully acknowledged.
Lal et al. Amoco Wellbore Stability Team, “Amoco Wellbore
Stability Drilling Handbook,” 1996.
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Shale, Springer-Verlag, N. Y., 1984.
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Couple the Mechanics and Chemistry of Drilling Fluid Shale
Interaction, SPE/IADC 25728, Proc. 1993 SPE/IADC Drilling
Conference, Amsterdam, Feb. 23-25, 1993.
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Molecular Particle Distances, Clays and Clay Minerals,” Proc.
Eleventh National Conference on Clays and Clay Minerals,
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Stability: Drilling Fluid/ Shale Interaction Study and Shale
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Lal, M. and Deem, C., “Shale Stability: Drilling Fluid/Shale
Interaction - State of the Art Report,” F95-P-117,
953420005-TUL, December 7, 1995.
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Stability,” F94-P-60, June 20, 1994.
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paper SPE 24592 presented at the 1992 Annual Technical
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Neglected Factor in shale Instability Studies?” SPE Paper 28058
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Engineering Conference, Delft, Aug. 29-31, 1994
Oort, van E., Hale, A. H., Mody, F. K. and Roy, S.: “Critical
Parameters in Modelling the Chemical Aspects of Borehole
Stability in Shales and in designing Improved Water-Based
Shale Drilling Fluids,” SPE 28309 paper presented at the SPE
Annual Conference, New Orleans, Sept. 26-28, 1994.
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Bailey, L., Denis, J. H., Maitland, G. C.: “Drilling Fluids and
SPE 54356
Wellbore Stability – Current Performance and Future
Challenges,” in Chemicals in the Oil Industry: Developments
and Applications, Ed. Ogden, P.H., Royal Soc of Chemistry,
London, 1991, pp. 53-70.
15. Horsrud, P, Holt, R. M., Sonstebo, E.: “Time Dependent
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Simulation of Different Mechanisms in Shale,” paper
SPE 28060 presented at the 1994 SPE/ISRM Rock Mechanics
in Petroleum Engineering Conference, Delft, 29-31
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“Wellbore Failure Mechanisms in Shales: Prediction and
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SI Metric Conversion Factors
ft x 3.048*
E-01 = m
in. x 2.54*
E+00 = cm
lbm x 4.535 924 E-01 = kg
psi x 6.894 757 E+00 = kPa
* Conversion factor
Fig. 1-Pressure diffusion from wellbore wall with time.
Fig. 2-Determining cohesive strength S0, and internal friction
angle φ from laboratory strength tests.
Fig. 3-Predicted vs measured rock strengths using lab and sonic
log velocities with velocity-strength correlation.