Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE Latin American and CaribbeanPetroleum Engineering Conference held in Caracas, Venezuela, 21–23 April 1999.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractThis paper presents main results of a shale stability study,related to the understanding of shale/ fluid interactionmechanisms, and discusses shale strength correlation. Themajor shale/ fluid interaction mechanisms: Capillary, osmosis,hydraulic, swelling and pressure diffusion, and recentexperimental results are discussed. Factors affecting the shalestrength are discussed, and a sonic compressional velocity-logbased correlation for strength is proposed. Recommendationsfor modeling and improving shale stability are described,based on the current understanding of shale stability.

IntroductionShales make up over 75% of the drilled formations, and over70% of the borehole problems are related to shale instability.The oil and gas industry still continues to fight boreholeproblems. The problems include hole collapse, tight hole,stuck pipe, poor hole cleaning, hole enlargement, plastic flow,fracturing, lost circulation, well control. Most of the drillingproblems that drive up the drilling costs are related to wellborestability. These problems are mainly caused by the imbalancecreated between the rock stress and strength when a hole isdrilled. The stress-strength imbalance comes about as rock isremoved from the hole, replaced with drilling fluid, and thedrilled formations are exposed to drilling fluids.1

While drilling, shale becomes unstable when the effectivestate of the stress near the drilled hole exceeds the strength ofthe hole. A complicating factor that distinguishes shale fromother rocks is its sensitivity to certain drilling constituents,particularly water. Shale stability is affected by properties ofboth shale (e.g. mineralogy, porosity) and of the drilling fluidcontacting it (e.g. wettability, density, salinity and ionic

concentration). The existence and creation of fissures,fractures and weak bedding planes can also destabilize shale asdrilling fluid penetrates them. Drilling fluids can cause shaleinstability by altering pore pressure or effective stress-stateand the shale strength through shale/fluid interaction. Shalestability is also a time-dependent problem in that changes inthe stress-state and strength usually take place over a period oftime. This requires better understanding of the mechanismscausing shale instability to select proper drilling fluid andprevent shale instability.

The basic shale stability problem can be stated as follows:Shale with certain properties (including strength) normally liesburied at depth. It is subjected to in situ stresses and porepressure, with equilibrium established between the stress andstrength. When drilled, native shale is exposed suddenly to thealtered stress environment and foreign drilling fluid. Thebalance between the stress and shale strength is disturbed dueto 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 aswell as pore pressure adjacent to the borehole wall. Shalestrength normally decreases and pore pressure increases asfluid enters the shale.

When the altered stresses exceed the strength, shalebecomes unstable, causing various stability related problems.To prevent shale instability, one needs to restore the balancebetween the new stress and strength environment.

Factors that influence the effective stress are wellborepressure, shale pore pressure, far away in situ stresses,trajectory and hole angle, etc. The effective stress at any pointon or near the borehole is generally described in terms of threeprincipal components. A radial stress component that actsalong the radius of the wellbore, hoop stress acting around thecircumference of the wellbore (tangential), axial stress actingparallel to the well path, and additional shear stresscomponents.

To prevent shear failure, the shear stress -state, obtainedfrom the difference between the stress components (hoop -usually largest and radial stress - smallest), should not goabove the shear strength failure envelope. To prevent tensilefailure causing fracturing, hoop stress should not decrease to

SPE 54356

Shale Stability: Drilling Fluid Interaction and Shale StrengthManohar Lal, SPE, BP Amoco

2 M. LAL SPE 54356

the point that it becomes tensile and exceeds the tensilestrength of the rock.

The controllable parameters that influence the stress-stateare drilling fluid, mud weight, well trajectory, and drilling/tripping practices. For example, radial stress increases withmud weight (wellbore pressure) and hoop stress decreases withmud weight causing mechanical stability problem. The nearwellbore pore pressure and strength are adversely affected bydrilling fluid/shale interaction as shale is left exposed todrilling fluid (chemical stability problem).

Mechanical stability problem can be prevented by restoringthe stress-strength balance through adjustment of mud weightand effective circulation density (ECD) through drilling/tripping practices, and trajectory control. The chemicalstability problem, on the other hand, is time dependent unlikemechanical instability, which occurs as soon as we drill newformations. Chemical instability can be prevented throughselection of proper drilling fluid, suitable mud additives tominimize/delay the fluid/shale interaction, and by reducingshale exposure time. Selection of proper mud with suitableadditives can even generate fluid flow from shale into thewellbore, reducing near wellbore pore pressure and preventingshale strength reduction.

Understanding Subsurface ShaleThe term shale is normally used for the entire class of fine-grained sedimentary rocks that contain substantial amount ofclay minerals. Sedimentologists find shale hard to work withsince shale is fine grained, lacks well-known sedimentarystructure (so useful in sandstones), and readily applicable toolsand models are not available to study shale.2 Thedistinguishing features of shale (of interest to oil industry) areits 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 largestnumber of pores having 10 nm diameter), and large differencein the coefficient of thermal expansion between water and theshale matrix constituents. To understand drilling fluidinteraction with shale, one must start from basic properties ofin situ shale (e.g. pre-existing water in shale, mineralogy,porosity), and then analyze the impact of changes in stressenvironment on the properties of shale.

Several factors affect the properties of shale buried atvarious depths. The amount and type of minerals, particularlyclay, in shale decide the affinity of shale for water. Forexample, 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). Threedifferent types of water are found associated with clays,although each clay will not contain all of the types. Inter-crystalline water is found in associated with the cationsneutralizing the charge caused by elemental substitution.Osmotic water is present as an adsorbed surface layerassociated with the charges on the clay. The swellingassociated with this type of mechanism occur when

sedimentary rocks are unloaded as occurs in drilling. Boundwater is present in the clay molecule itself as structurallybonded hydrogen and hydroxyl groups which under extremeconditions, temperatures of 600-7000 C, separate from the clayto form water.

The free water exists only within the pore space betweenthe grains. The porosity of shale is normally defined as thepercent of its total volume that water. This value is normallymeasured by drying a known volume of shale at elevatedtemperature. Porosity then is a measure of free water, osmoticwater and to a lesser extent inter-crystalline water. Chemicallybound water is not measured in this procedure. Properties ofshale and drilling fluid/shale interaction are stronglyinfluenced by the bound water and to a lesser extent by the freewater.

Some of water associated with clay can also be removedusing pressure. The majority of the loosely held osmotic watercan be removed with an overburden pressure of about 290 psi.In the inner-crystalline case, up to four layers of water may befound. The third and fourth layer can be removed with about3900 psi. Approximately, 24000 psi is required for secondmono-layer and according to various estimates,3-4 pressureover 50,000 psi is required to squeeze water in single mono-layer of clay platelets. It requires temperatures in excess of200o C to remove all bound water from clay. It is, therefore,doubtful that shale is ever completely void of water in typicaldrilling environment. Prior to drilling, the exact amount ofbound and free water in shales buried at depth, however,depends on the past compaction history.

Compaction of clay proceeds in three main stages.5 Theclays are removed from land by water and deposited inquiescent locations. Clays, at their initial state of depositionand compaction, have both high porosity and permeability;pore fluids are in communication with the seawater above;sediments consisting of hydratable clay with absorbed waterlayers prevent direct physical grain-to-grain contact. At thetime of deposition, mud water contents may be 70-90%.

In the normal compaction process as clay/shale sedimentsare buried with pore water being expelled, porosity (sonictravel time) decreases. However, any disruption of this normalcompaction and water expulsion process can lead to increasein both porosity (sonic travel time) and pore pressure.

In the first stage of compaction, free pore-water, osmoticwater and water inter-layers beyond two layers are squeezedout by the action of overburden. After a few thousand feet ofburial, the shale retains only about 30% water by volume, ofwhich 20-25% is bound interlayer water and 5-10% residualpore water. In the early stages compaction strongly depends ondepth of burial, grain size (fine-grain clays have more porositybut compact easily), deposition rate (high rate results inexcessive pore pressures and under-consolidation), claymineralogy (monmorillonitic shale contain more water thanillitic or kaolinitic shale), organic matter content, and geo-chemical factors (e.g. concentration of sodium salts affectsporosity).

SPE 54356 SHALE STABILITY: DRILLING FLUID INTERACTION AND SHALE STRENGTH 3

In the second stage of compaction, pressure is relativelyineffective for dehydration that is now achieved by heating,removing another 10 to 15% of the water. The second stagebegins at temperatures close to 100oC and diagenetic changesin clay mineralogy may also occur. The third and final stage ofcompaction and dehydration is also controlled by temperaturebut is very slow, requiring hundreds of years to reachcompletion and leaving only a few percent of water.

To sum up, the properties of drilled shale formation, whichare important for shale/fluid interaction and shale stability, aredictated by the past compaction history and the current in situstresses and temperature. For example, affinity (thirst) forwater of the shale at any depth depends on compaction/loading history, in situ stresses, clay composition, andtemperature. These factors also determine shale porosity,permeability and the amount of water squeezed out.

Shale/Fluid Interaction MechanismsAnalysis of the available experimental data (O’Brien-Goins-Simpson Associates and University of Texas, Austin, Shell andAmoco sponsored Projects)6, clearly shows that the shalestrength and the pore pressure near the bore-hole are indeedaffected by fluid/shale interaction. Basic results confirmed bythis 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

shale• 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 certaindensity replaces shale in the hole. Mechanical stabilityproblem caused by various factors is fairly wellunderstood, and stability analysis tools are available.8

2. Fractured shale - Fluid penetration into fissures andfractures and weak bedding planes

3. Capillary pressure, pC, as drilling fluid contacts nativepore fluid at narrow pore throat interface.

4. Osmosis (and ionic diffusion) occurring between drillingfluid and shale native pore fluid (with different wateractivities/ ion concentrations) across a semi-permeablemembrane (with certain membrane efficiency) due toosmotic pressure (or chemical potential), PM.

5. Hydraulic (Advection), ph, causing fluid transport undernet hydraulic pressure gradient because of the hydraulicgradient.

6. Swelling/Hydration pressure, ps, caused by interaction ofmoisture 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.8. Fluid penetration in fractured shale and weak bedding

planes can play a dominant role in shale instability, aslarge block of fractured shale fall into the hole. Severalpapers have been written on this phenomenon.9 InNorway Valhall field, this phenomenon is suspected to beone of the major causes of shale instability. Preventivemeasures include use of effective sealing agents forfractures, e.g. graded CaCO3, high viscosity for low shearrates, 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 beensuccessfully exploited to prevent invasion of drilling fluid intoshale through use of oil base and synthetic mud using esters,poly-alpha-olefin and other organic low-polar fluids fordrilling shale. The capillary pressure is given by

pC = 2γ cosθ/r .................................................................(1)

where, γ is interfacial tension, θ is contact angle between thedrilling fluid and native pore fluid interface, and r is the poreradius.

When drilling water-wet shale with oil base mud, thecapillary pressure developed at oil/pore-water contact is largebecause of the large interfacial tension and extremely smallshale pore radius. It prevents entry of the oil into shale sincethe hydraulic overbalance pressure, ph (=Pw-po), is lower thanthe capillary threshold pressure, pC. In such a case, advection(and pressure diffusion) cannot occur. However, osmosis andionic diffusion phenomena can still occur under favorableconditions. Capillary pressure thus modifies ph and the nethydraulic driving pressure ph‘is given as follows:

ph′ = − < <′ = >

p p p p

p p p

h C C h

h C h

,

,

0

0..................................(2)

Capillary pressures for low permeability water-wet shalescan be very high (about 15 MPa for average pore throat radiusof 10nm). This is one of the key factors in successful use of oilbase muds or synthetic muds using esters, poly-alpha-olefinand other organic low-polar fluids.

Osmotically induced hydraulic pressure or differentialchemical potential, PM, developed across a semi-permeablemembrane is given by 10-12,

PM = - ηPπ = - η (RT/V)ln(Ash/Am)..................................(3)

where, η is membrane efficiency, Pπ is the theoreticalmaximum osmotic pressure for ideal membrane (η=1), R is thegas constant, T is the absolute temperature, V is the molar

4 M. LAL SPE 54356

volume of liquid, and Am, Ash are the water activities of mudand shale pore fluid, respectively.

Various expressions have been obtained for the membraneefficiency in terms of parameters that are difficult to measure.Two such expression are:11

ηη ν ν

= − − −= −

1

1

2 2( ) / ( )

/

a r a rs w

s w

.............................................(4)

where, ‘a’ is pore radius, rs is solute radius, rw is watermolecule radius, and νs and νw are the velocities of solute andwater, respectively.

From non-equilibrium thermodynamics principles,assuming slow process near equilibrium and single non-electrolyte solute, the linear relations between the pressure andflow 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 isthe superposition of fluxes due to hydraulic pressure gradientph (advection) and due to osmotically induced pressure, PM

(=η Pπ), related through the hydraulic permeability coefficientLp. The coefficient Lp is related to the shale permeability, k,and filtrate viscosity, µ, as Lp= k/µ. Eq. 6 describes the net saltflux Js into the shale. Eq. 7 simply expresses the mass balancein terms of the water and salt flux and partial molar volumes ofthese components. Note that for perfect membrane, η =1, sinceonly 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 impliesequal activity and Pπ =0 - no osmosis), Eq. 5 reduces to thefamiliar Darcy’s law which gives volume flow as:

Jv ∆x = Lp ph...................................................................(8)

where as Lp= k/µ.; k denotes shale permeability and µ denotesviscosity. Such an experiment was performed by van Oort tocharacterize the permeability of shale and estimate Lp.

As stated earlier, a recent study on osmotic and hydrauliceffects was conducted at O’Brien-Goins-Simpson &Associates, Inc. as part of the work sponsored by the GasResearch Institute (GRI). General conclusions from the studycan be summarized as follows:• Increased hydraulic potential can increase the amount of

transport of water into shales and reduce rock strength

(with exposure time). Increasing the mud weight may thusworsen a stability problem (over time) rather than curingit.

• In hydrocarbon-based fluids, water transport into shalesmay be controlled through the activity of the internalphase relative to the shale.

• Water-based fluids require a much lower activity than theshale to control water transport. Even then the effectivestrength may be reduced.

Swelling pressure and swelling behavior of shales isdirectly related to the type and amount of clay minerals in agiven shale. Two types of swelling observed in clays are:a) Innercrystalline swelling (IS) - caused by hydration of the

exchangeable cations of the dry clayb) Osmotic swelling (OS) - caused by large difference in the

ionic concentrations close to the clay surfaces and in thepore water.

It may be noted that the osmosis, discussed earlier, wasconcerned with ionic concentration or water activitydifferences 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 theformation of first water layer, up to 16000 psi for second, andup to 4000 for the third and fourth layers for puremontmorillonite in the Wyoming bentonite). The swellingstresses resulting from osmotic swelling (OS), on the otherhand, are relatively small and usually do not exceed 300 psi.13

Complete understanding of physico-chemical reactionsbetween clays and water requires a detail discussion of thestructure of compacted clay, namely the arrangement of clayparticles at the atomic level and the electrical forces betweenthe adjacent particles. The electrical forces act only near theparticle surface and mostly result from discontinuity at or nearthe surface, they become particularly significant and dominatethe mass forces (such particles are called colloidal - 1micron -1 millimicron (10A) size range) for clays since they have largesurface area per unit mass. Several excellent papers13 areavailable which attempt to describe various aspects of thiscomplex phenomenon.

A simple explanation, which may suffice for this report, isgiven as follows. First the electrical forces: van der Waalsforces (secondary valence forces) between units of clay arisefrom electrical moments existing within units, which aresimilar to force acting between two short bar magnets. Sincethere are more attractive positions than repulsive, the net effectof such forces is attraction. These forces exist in clays becauseof the nonsymmetrical distribution of electrons in the silicatecrystals, which act as a large number of dipoles. They canattract other dipoles like water molecules, which arepermanent dipoles due to nonsymmetrical configuration of thewater molecules and position of the atoms in the molecule.The hydrogen bond linkage between water molecules occurs aseach hydrogen atom, attracted by the oxygen in neighboringwater molecule, links its water molecule to others.

Furthermore, clay particles carry a net negative charge

SPE 54356 SHALE STABILITY: DRILLING FLUID INTERACTION AND SHALE STRENGTH 5

(mainly caused by isomorphous substitution - e.g. substitutionof bivalent Mg for trivalent Al). This net negative charge isbalanced by exchangeable cations, clustered at the clay surfaceto neutralize the particles. When the dry clay particle is placedin water the cations swarm around the clay surface particles,forming a double layer with certain electrical potential thatvary with characteristics of the dispersion medium (accordingto Gouy-Chapman theory). Because of the net negative charge,adjacent clay particles repel each other as they approach eachother 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 thetotal potential energy reduces when adjacent particlesapproach each other, they flocculate (form aggregates), but if itincreases they disperse or move apart.

Confining discussion to clay-water reaction, the clay-waterattractive force consists of two main components: attraction ofdipolar water to the electrically charged clay particles andattraction of the dipolar water to the cation in the double layer- the cations in turn are attracted to the clay. Based on relativemagnitude of force between water and clay (large near butbecoming weak away from the colloidal surface), water can becategorized into three types: adsorbed - strongly held by clay;double layer - all the water attracted to clay anywhere in thedouble layer; and free water which is not attracted to clay atall.

For illustration, let us look at two clay minerals:montmorollinite and kaolinite. For both minerals, the forcerequired to pull the adsorbed water off the mineral surface isextremely high (varying from 100 for outside to 10,000atmospheres for the closest molecules). The adsorbed anddouble layer water on kaolinite are thicker than onmontmorillonite because of the high charge density onkaolinite (about twice). However, the amount of adsorbedwater expressed, as a percentage of mineral weight is muchgreater on montmorillonite since its specific surface is greater.The controversy regarding particle mineral-to-mineral contactin clay is not yet settled. According to one concept, cohesionin a natural clay is due to “water bonds”20. Compaction andany other stress changes on clay minerals in shale also affectthe clay structure and thus water-clay interaction.

Swelling experiments indicate that the swelling follows adiffusion type of law, and the cumulative water flux into theshale, Q, time t, sorptivity S, the change in equilibrium voidratio (liquid to solid volume ratio) ∆e, and diffusivity, D, arerelated as follows 14:

Q = S.t 0.5

S = ∆e.(2D)0.5...................................................................(9)

The linear dependence of S on the change in equilibriumvoid ratio on swelling implied in the above equation isobserved experimentally. Diffusivity for Pierre shale inferredfrom experiments is about 9x10-10 m2s-1 at 20o C. D depends

on the nature of bound cations, and commonly used polymersappear to have little effect on its value. The low values of Dfor typical shales may also explain why many shales becomeunstable 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 alarge fraction of the clay cations must be replaced before thiseffect is significant, and the action of KCl is largely osmoticsince on the time scale of the swelling experiments little ionexchange with clay has taken place.

Atmospheric swelling and saturation experiments onSpeeton shale core were also sponsored by the GRI at theUniversity of Texas, Austin. An interesting conclusion fromthis study was that the activities of the shale-fluid system,nature of the ions, ionic concentration, hydrated ionic diameterand valency of the generated cations influence the ultimateswelling response of shale. The results of the study indicatethat water activity differential is not the only mechanism ofwater transportation into shale matrix under atmosphericconditions. The Electro-chemical forces associated withnegatively charged clay surfaces and ionic exchange maytransport water into shale matrix even in the presence of lowactivity salt solutions. In summary, swelling phenomenon inshales can be explained in terms of clay-water reaction, andwater has significant effect on the properties of clays.

Pressure diffusion phenomenon concerns the pressurechange with time near the wellbore as the drilling fluid atwellbore pressure, Pw, in conjunction with the osmoticpressure, PM, etc. suddenly contacts and compresses the porefluid at the wellbore wall (which was at pressure, po, beforedrilling). The pressure away from the wall varies with timeuntil a steady-state pressure distribution between near and far-away pore pressure is established. This pressure diffusion canbe compared in a way to the pressure surge when a pipesuddenly moves in a wellbore compressing the drilling fluid,which is analyzed as transient wave propagation instead ofdiffusion phenomenon. Various expressions and numericalsimulations for pressure diffusion have been used to study thisphenomenon 15-16. The basic point of these studies can beillustrated with the help of Fig. 1.

If a drilling fluid cannot penetrate shale at all (e.g. perfectoil base mud for a given shale), the pore pressure near thewellbore wall is the virgin pore pressure po (ignoring the effectof stress changes) at the time drilling fluid comes in contactwith shale (t=0) and remains the same for t>0. However, whenthe mud is such that it interacts with shale, the drilling fluid atwellbore pressure Pw will diffuse through shale. The pressurenear the wall in the pores will increase from po with time. Howfast this pore pressure in the vicinity of the borehole increasesdepends upon the permeability of shale, its elastic propertiesand other boundary conditions. In general, lower thepermeability, more time it takes for pressure to increase andtend to equalize with Pw, thus losing pressure support for theformation. Depending on permeability, it may take anywhere

6 M. LAL SPE 54356

from a few hours to a number of days before the pressure nearthe wellbore approaches the wellbore pressure, losing pressuresupport, reducing effective stresses and bringing the rock tounstable situation. This could be an explanation for thedelayed failure of exposed shale sections, often experienced inthe field.

Shale Strength CorrelationFor stability analysis, an important input parameter needed isthe formation strength, which is usually characterized bycohesive strength S0, and friction angle φ . These parametersare traditionally determined from different rock mechanicalcore tests based on a number of different core plugs from thesame depth. The test results from several plugs are thencombined to provide these strength properties from this depth.

Regarding rock strength, it is far easier to make rock grainsslide past one another than it is to crush them. Consequently,when rocks fail in compression, they are actually failing inshear, as a result of inter-granular slip. Their resistance toshear, i.e. shear strength, is due to a combination of cohesionand friction between the rock grains.

The amount of cohesion is represented by a parameterknown as the cohesive strength S0, while inter-granular frictionis defined by the internal friction angle φ. For a layer of rocksubjected to an effective compressive stress σ and a shearstress 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 totalcompressive stress s and pore pressure p as follows:

σ = s - p..........................................................................(11)

For complex stress states, such as exist at the wall of awellbore, a number of different failure criteria have beenproposed for generalizing Eq. 10. However, all the criteria arerelated to the parameters S0 and φ.

For example, the Mohr-Coulomb6,8 shear failure criterioncan be written as:

(σ1-σ3)2 = So cosφ +

(σ1+σ3)2 sinφ..................................(12)

Where, (σ1-σ3)/2 is the Mohr Coulomb shear strengthparameter, and (σ1+σ3)/2 is the average effective stress, andσ1, σ3 are the maximum and minimum effective compressivestresses, respectively.

The Drucker-Prager Criterion is defined in terms of the twogeneralized stresses, the mean effective stress:

I1 = (σ1 + σ2 + σ3 )/3......................................................(13)

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 triaxialstrength tests, in which cylindrical samples of rock are firstsubjected to a hydrostatic confining pressure, and an axial loadis then applied until the rock fails. These tests are performedat several different confining pressures, and the results areplotted as a series of Mohr’s circles, as shown in Fig. 2. Forlinear failure criterion, the line that envelops the family ofcircles has a slope equal to tanφ, and an intercept equal to S0.

Intuitively, we know that rock strength tends to increasewith compaction. Consequently, this suggests that S0 and φcan 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 basispresents more of a challenge. It clearly is not feasible to dothis with laboratory strength tests. As an alternative, it isdesirable to develop relationships for computing S0 and φ fromwire-line data. Therefore, rock strength correlation actuallyrefers to relation with wire-line log data for determining thecohesive strength and friction angle.

A more fundamental look at shale physics was taken togain better insight into which factors need to be included instrength correlation. Three factors were considered6:• clay mineralogy• clay content• compaction.

The main conclusion from the study, based on severalexternal 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 importanceregarding their effect on shale strength. The degree ofcompaction (characterized by water content, porosity, sonicvelocity, 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 SHALE STABILITY: DRILLING FLUID INTERACTION AND SHALE STRENGTH 7

• densityThe shale strength correlations, developed by the author,

were tied only to compressional sonic velocity in shales. Therelations were developed using an extensive shale database.The following relations for friction angle, φ (degrees) , andcohesive strength, So (MPa), were developed as a function ofcompressional 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 computedfrom both laboratory measured and sonic log-derivedvelocities (reported for different core depths in North Sea),along with the measured strength data. Both estimates arefairly good, which show that this correlation is applicable withsonic log derived velocities.

The sonic correlation was also found to be fairlysatisfactory for formations other than shale. The estimatedcohesive strength and friction angle parameter represent localvalues at the in situ stress conditions reflected in the sonic logmeasurements. For sands, Gassman Correction for gas needs tobe applied, or nearby shale points needs to be picked as inpore 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 shaleand alters the salinity of native pore fluid through shale/fluidinteraction. Smectitic shales have a lower tolerance to drillingfluid invasion, and will tend to fail easier than formations inwhich kaolinite and/or illite are the only clay types present.The effect of clay mineralogy on strength can be important ifthe drilling process severely disturbs a formation from itsnatural state. In those cases, as discussed below, smectiticformations will be more susceptible to failure.

The strength of all geologic materials depends upon theeffective confining. Therefore, if shale/drilling fluidinteraction raises the pore pressure in the near wellbore region,the drop in effective confining pressure will make the holemore susceptible to failure. However, with smectites, drillingcan introduce two additional destabilizing effects.

As discussed earlier, confining pressures in the vicinity of500 psi are necessary to keep liquid water from getting inbetween smectite platelets. The two-to-three layers of waterthat remain are more competent than liquid water, and appearto allow smectite platelets to act like thicker, strongerparticles. This effect can be reduced or lost if the effectiveconfining pressure drops to values low enough to permit liquidwater to penetrate between the platelets.

Salinity can also cause smectite platelets to behave likethicker 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 asignificant drop in the strength of smectitic formations.

To summarize, smectitic formations are highly susceptibleto the effects of drilling fluid/shale interaction. Fluid invasionnot only reduces friction and interlocking between smectitegrains, it can also reduce the competency of the grainsthemselves. The impact of clay mineralogy on strength (andstability) can thus become quite significant on drilling, when aforeign drilling fluid contacts in situ smectitic shale and altersthe salinity of native pore fluid through shale/fluid interaction.Smectitic shales have a lower tolerance to drilling fluidinvasion, and will tend to fail easier than formations in whichkaolinite and/or illite are the only clay types present.

Finally, the effects of drilling fluid/shale interaction mustbe kept in mind when using offset well log data. Wireline logreadings may not reflect true in situ pore pressure and rockproperties if the near wellbore region has been invaded by thedrilling fluid and undergone hydration. Hydration raises thelocal pore pressure and weakens the rock.

Improving Shale StabilityThus far, we have seen that there are several mechanismswhich cause or affect shale/fluid interaction. There is anintense effort under way in the oil industry to get a betterunderstanding of each of these mechanisms. The stakes arehigh in that understanding and quantification of each of thesephenomena is critical for designing benign drilling fluidswhich would stabilize shales. Rapid progress is being madeand more results will become available in the near future. Thecurrent understanding of various mechanisms responsible forshale/fluid interaction indicate certain basic principles forimproving shale stability.

Based on current understanding of various shale/fluidinteraction mechanisms, we can discuss some generalprinciples for improving shale stability. The main objective toimprove shale stability is to prevent, minimize, delay or use toour advantage the interaction of the drilling fluid with shale.As our understanding of the various interaction mechanismsimproves, so will the mud systems designed to improve shalestability.

We can list the following means of improving shalestability corresponding to various mechanisms contributing toshale/fluid interaction:• For fractured shale stability, use effective sealing agents,

thixotropic drilling fluid (high viscosity for low shearrates), and lower mud weight /ECD. This would minimizefluid penetration into fractures.

• Increase the capillary pressure, pC(>ph’) to prevent fluidentry into shale pore throats. Eq. 1 suggests thatincreasing interfacial tension and contact angle θ canincrease the capillary pressure for given shale pore throatradii. Increasing capillary pressure through γ and θ forwater-wet shales has been successfully exploited throughuse of oil base muds or synthetic muds using esters, poly-

8 M. LAL SPE 54356

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 wellborepore pressure through pressure diffusion or transmittal andfluid transport into (or out of) the shale. The near wellborepore pressure, pn, can be expressed in terms of the originalvirgin 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 discussedabove, or making osmotic pressure PM equal to (or less than)zero by matching (or making drilling fluid activity, Am, lowerthan) shale water activity, Ash. If the activity of the mud ishigher than that of the shale, we need to reduce membraneefficiency as much as possible. However, when drilling fluidactivity is made lower than shales, resulting in negativeosmotic pressure and causing pore fluid to flow out of shaleinto the wellbore, the membrane efficiency needs to beincreased.

Reduction of drilling fluid activity, Am, is at the heart ofmost inhibitive muds 14. This reduction is brought about byadding electrolytes: seawater bentonite muds, saturated salt-polymer (xanthan, guar), KCl or NaCl-polymer (PHPA,xanthan), fresh water calcium treated muds (lime, gypsum). Anew type of drilling fluid based on a substituted sugar, methylgluocide, is currently being looked at because of its ability toform low activity muds with high membrane efficiency. Thedispersed water phase in oil base muds is treated to adjust theactivity, 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 notknown and varies with depth and mineralogy. We can,nevertheless, control parameters that enable us to reduce thefluid transport and pressure diffusion rates by increasing thefluid viscosity and reducing the permeability of shales.Regarding the viscosity increase, the problem is to find solutesthat increase the fluid viscosity significantly and yet can passthrough the narrow shale pore space to maintain high viscosity.Most mud polymers are too large to enter shale but some lowmolecular weight polymers might achieve the desired results.

As regards reducing permeability, one solution is to formpermeability barrier at shale surface or within micro-fractures.Oil base mud achieves this as water is made to diffuse throughcontinuous oil phase to reach the shale. Silicate and ALPLEXmuds, for example, attempt to reduce the permeability.

Cationic polymers, which are strongly adsorbing, can also actin the same way. In the extreme, shale formation could becompletely isolated by creating an impermeable hydrophobicseal, using asphaltine derivatives like gilsonite. Use of chargedemulsifiers for binding the oil droplets of oil-in-wateremulsions to the clay surface and organophilic clays in oil basemuds 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 iscurrently underway to formulate drilling fluids containingcesium, Ce+ for stabilizing the shale. While this fluid would bevery expensive to formulate, increased stability and rate ofpenetration could compensate for this cost.• Preserve mechanical integrity of the shale cuttings.

As damage control, certain measures can be taken to limitthe dispersion of cuttings or spallings by binding the clayparticles together, if shale failure or erosion is initiated.Polymers that can reduce shale disintegration must adsorbonto clay platelet surface and have high enough energy toresists mechanical or hydraulic forces pulling them apart.PHPA and strongly adsorbing cationic polymers andcomponents like polyglycerol can limit the dispersion ofshale cuttings or spallings in the well. To achieve similarresults within the shale formation, polymer must be able todiffuse into the bulk shale, requiring short flexible chains.

Future work on shale stability and understandingshale/fluid interaction is bound to lead to better means tostabilize shales and design of environmentally acceptableeffective mud systems. As new additives for drilling fluids arestudied to stabilize shales, major challenge would be to makethem compatible with preserving other desirable mudproperties such as, rheology, drilled solids compatibility anddrilling rates.

Finally, even if we could design the best mud system forshale formations, continuous monitoring and control of drillingmuds are critical elements for successful drilling. The mudcomposition continually changes as it circulates and interactswith formations and drilled solids. Unless concentrations ofvarious mud additives are continually monitored (as opposedto the current practice of periodically monitoring justrheological and simple properties) and maintained, the desiredresults could not be achieved. The development andintroduction of improved monitoring techniques for chemicalmeasurements should proceed simultaneously with thedevelopment of more effective mud systems for shale stability,based on improved understanding of shale/fluid interaction.

ConclusionsThe above discussion gives an indication of the experimentalactivity and progress in shale stability projects, sponsored byoil and gas industry. However, understanding of the shale/fluidinteraction mechanisms is not yet complete to effectivelycontrol the shale instability problem. The ongoingdevelopments and data from numerous active industry

SPE 54356 SHALE STABILITY: DRILLING FLUID INTERACTION AND SHALE STRENGTH 9

sponsored shale stability projects, hopefully, will provideanswers to the remaining questions. Then only, one candevelop models that can quantify the impact of shale/fluidinteraction on the stress- strength of the shale and the time-dependent effects.

In view of the shale instability costs, it is imperative tounderstand shale behavior and its interaction with differentfluids. Completely satisfactory answers to questions such as:which drilling fluid to use for drilling a particular shale, orhow long can we keep the hole exposed to a particular fluidwithout causing shale instability, can be given only after suchan understanding. The quantification of the impact of fluidinvasion on effective stresses and shale strength near thewellbore is critical for shale stability analysis models. Simpleand realistic shale testing procedures and shale/ fluidinteraction testing procedures are required in order to achievepractical assessments of wellbore instability risks. Efforts todevelop predictive models and to develop more effective fluidsfor drilling shales, based on improved understanding ofshale/fluid interaction mechanisms must continue.

AcknowledgementsThe author would like to thank Glenn Bowers,Tron Kristiansen and Calvin Deem for their valuable help anddiscussions. Their contributions and help in several wellborestability projects, related to shale/fluid interaction, are alsogratefully acknowledged.

NomenclatureAm = water activities of mudAsh = water activity of shaleD = diffusivityJv = fluid fluxJs = solute fluxk = shale permeability

Lp = hydraulic permeability coefficientPM = observed osmotic pressurePw = wellbore pressurePπ = theoretical osmotic

p = pore pressurepC = capillary pressureph = hydraulic pressureph

′ = net hydraulic pressureps = swelling pressureQ = cumulative water fluxR = gas constantr = pore radiusrs = solute radiusrw = water molecule radiusS = sorptivity

S0 = cohesive strengths = total compressive stressT = absolute temperaturet = time

V = molar volume

Vp = compressional sonic velocityγ = surface tensionθ = contact angleη = membrane efficiencyνs = solute velocityνw = water velocity

µ = filtrate viscosity∆e = liquid to solid volume ratioφ = internal friction angle

σ = effective compressive stressτ = shear stressσ1 = effective maximum principal stressσ2 = effective intermediate principal stress σ3 = effective minimum principle stresses

References1. Lal et al. Amoco Wellbore Stability Team, “Amoco Wellbore

Stability Drilling Handbook,” 1996.2. Potter, E. P, Maynard, J. B., Pryer, W. A.: Sedimentology of

Shale, Springer-Verlag, N. Y., 1984.3. Mody, F. K. and Hale, A. H.: “A borehole Stability Model to

Couple the Mechanics and Chemistry of Drilling Fluid ShaleInteraction, SPE/IADC 25728, Proc. 1993 SPE/IADC DrillingConference, Amsterdam, Feb. 23-25, 1993.

4. van Olphin, H.: “Compaction of Clay Sediments in the Range ofMolecular Particle Distances, Clays and Clay Minerals,” Proc.Eleventh National Conference on Clays and Clay Minerals,Ottawa, Ontario, Canada, August 13-17 (1962).

5. Burst, J. F.: “Diagensis of Gulf Coast Clayey Sediments and ItsPossible Relation to Petroleum Migration,” Amer. Assn. Pet.Geol. Bull., 53, pp.73-93, 1969.

6. Lal, M., Kristiansen, T., Deem, C. and Bowers, G. “ShaleStability: Drilling Fluid/ Shale Interaction Study and ShaleStrength Correlations,” Amoco Report F96-P-99,963480010 ART

7. Lal, M. and Deem, C., “Shale Stability: Drilling Fluid/ShaleInteraction - State of the Art Report,” F95-P-117,953420005-TUL, December 7, 1995.

8. Amoco Wellbore Stability Team, “State of the Art in WellboreStability,” F94-P-60, June 20, 1994.

9. Santarelli, F., Dardeau, C., and Zurdo, C.: “Drilling throughhighly fractured formations: A problem, a Model, and a Cure,”paper SPE 24592 presented at the 1992 Annual TechnicalConference & Exhibition, Washington, D.C., Oct. 4-7

10. Forsans, T. M. and Schmitt, L., “Capillary Forces: TheNeglected Factor in shale Instability Studies?” SPE Paper 28058presented at the 1994 SPE/ISRM Rock Mechanics in PetroleumEngineering Conference, Delft, Aug. 29-31, 1994

11. Oort, van E., Hale, A. H., Mody, F. K. and Roy, S.: “CriticalParameters in Modelling the Chemical Aspects of BoreholeStability in Shales and in designing Improved Water-BasedShale Drilling Fluids,” SPE 28309 paper presented at the SPEAnnual Conference, New Orleans, Sept. 26-28, 1994.

12. Fritz, S. J. “Ideality of Clay Membranes in Osmotic Processes:A review,”: Clays and Clay Minerals, Vol. 34(2), 1986, pp. 214-223.

13. Madsen, F. T. and Muller, V.: “The Swelling Behavior ofClays,” Applied Clay Science, Vol. 4, 1989, pp. 143-156.

14. Bailey, L., Denis, J. H., Maitland, G. C.: “Drilling Fluids and

10 M. LAL SPE 54356

Wellbore Stability – Current Performance and FutureChallenges,” in Chemicals in the Oil Industry: Developmentsand Applications, Ed. Ogden, P.H., Royal Soc of Chemistry,London, 1991, pp. 53-70.

15. Horsrud, P, Holt, R. M., Sonstebo, E.: “Time DependentBorehole Stability: Laboratory Studies and NumericalSimulation of Different Mechanisms in Shale,” paperSPE 28060 presented at the 1994 SPE/ISRM Rock Mechanicsin Petroleum Engineering Conference, Delft, 29-31

16. Gazaniol, D., Forsans, T., Boisson, M. J. F. and Plau, J. M.:“Wellbore Failure Mechanisms in Shales: Prediction andPrevention,” JPT, July 1995, pp. 5890595

SI Metric Conversion Factorsft x 3.048* E-01 = m

in. x 2.54* E+00 = cmlbm x 4.535 924 E-01 = kgpsi x 6.894 757 E+00 = kPa

* Conversion factor

Fig. 1-Pressure diffusion from wellbore wall with time.

Fig. 2-Determining cohesive strength S 0, and internal frictionangle φ from laboratory strength tests.

Fig. 3-Predicted vs measured rock strengths using lab and soniclog velocities with velocity-strength correlation.