INTRODUCTION
Shale or Clay swelling has been long known as one of
the major causes for formation damage in hydrocarbon reservoirs. In
conventional hydrocarbon production, most of the clay related problems occur in
the near well region, and are associated with well operations (drilling,
completion, workover, etc.). Krueger has
provided an excellent review on this subject. In enhanced oil recovery (EOR),
the potential for formation
damage to occur is in many instances much greater
because incompatible injection fluids often cause clay swelling or fines
migration and thus impair the formation permeability. Even formations which do
not contain smectite can have smectite-related formation damage because
smectite clays can be synthesized through mineral/fluid reactions during
thermal recovery . The formation of smectite was responsible for the reduction
in porosity, permeability, and oil recovery rate at the Great Plain Pilot
Project, Cold Lake . It was also partly responsible for the low steam sweep at
the Ipiatik Heavy Oil Pilot, Cold Lake .
Coreflood experiments have been used to characterize
the effect of clay swelling on reservoir quality . In the coreflood
experiments, a decrease in permeability (or an increase in injection pressure)
is used as a measure of formation damage. However, a fair amount of core, which
is not always available, is required to run coreflood experiments. In addition,
coreflood experiments can be expensive.
Shale Clay swelling affects not only reservoir
quality but also many aspects of drilling operations in conventional oil
production and in enhanced oil recovery. Swelling clays include two groups of
layer silicate: smectites and vermiculites.
Two types of
clay swelling are identified: crystalline swelling and osmotic swelling.
Osmotic swelling is the major cause for permeability reduction due to smectites
in hydrocarbon reservoirs.
Problems caused by shales in petroleum activities
are not new. At the beginning of the 1950s, many soil mechanics experts tried
to find out more about the swelling of clays, which are important for
maintaining wellbore stability during drilling, especially in water-sensitive
shale and clay formations. The rocks within these types of formations absorb
the fluid used in drilling, which causes them and may lead to a wellbore
collapse. The swelling of clays and the problems that may so arise have been
reviewed in the literature (Durand et al., 1995a,b; Van Oort, 1997; Zhou et
al., 1995).
Shales or clay are known to make up above 70% of the
drilled formations, and over 70% of the borehole problems are all associated
with shale instability. The petroleum industry are continually fighting
borehole problems. The problems usually involve well collapse, tight hole,
stuck pipe, poor hole cleaning, hole enlargement, plastic flow, fracturing,
lost circulation, well control. Most of the drilling problems that do increase
the drilling costs are most times related to wellbore instability. These problems
are mainly caused by the imbalance created between the rock stress and strength
when a hole is drilled. The stress-strength imbalance results when cuttings are
removed from the hole, replaced with drilling fluid, and the drilled formations
are exposed to drilling fluids. 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
differentiates shale from other rocks is its predisposition 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 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.As
fluid enters the shale, its strength decreases while pore pressure increases.
When the altered stresses exceed the strength, shale
becomes unstable, resulting to various stability related problems. To prevent
shale instability, it is important 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 borehole angle, etc. The effective stress at any point on or
near the borehole is generally described in terms of three principal
components,namely;
·
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 components.
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 , and readily applicable tools
and models are not available to study shale.The important features of shale in
the 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.
1.
Intercrystalline water is found in
associated with the cations neutralizing the charge caused by elemental
substitution.
2.
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 sedimentary rocks are
unloaded as occurs in drilling.
3.
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 within 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
water. 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 porosity). 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 100 0C 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
complete and having only a few percent of water left. To sum up, the properties
of drilled shale formation, which are important for shale/fluid interaction and
shale stability, are determined by the past compaction history and the current stresses
and temperature. For example, affinity for water of the shale at any depth
depends on compaction/ loading history, 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) purely explains that the shale strength and the pore
pressure near the bore-hole are indeed affected by fluid versus shale
interaction. Basic results confirmed by this explanation 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.
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.
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 gradient.
6.
welling/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.
8.
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. A lot of works have been written on this
phenomenon. 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.
9.
Capillary
phenomenon also is now fairly well understood, and an
interesting exposition is given in a recent paper. 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 radius. 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:
ph
= ph – pc, 0<pc<ph..................................(2)
ph=0,
pc>ph
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:
η
= 1-(a-rs)2 /(a-rw)2.............................................(4a)
η
= 1-vs /vw..........................................................
(4b)
In this, ‘a’ = pore radius, rs=solute radius, rw = water
molecule radius, and νs and νw are the velocities of solute and water,
respectively. According to non-equilibrium thermodynamics principles, assuming
slow process near equilibrium and single non electrolyte 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)
Equation. 5 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
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 indicates 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 stability. 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 increased. 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.
·
Reduce the rate of fluid transportion
and rate of pressure diffusion. 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, however, control parameters that
enable us to reduce the fluid transportion 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
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 checked and maintained, the 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.
References
Lal et al. Amoco Wellbore Stability
Team, “Amoco Wellbore Stability Drilling Handbook,” 1996.
Potter, E. P, Maynard, J. B.,
Pryer, W. A.: Sedimentology of Shale, Springer-Verlag, N. Y., 1984.
Mody, F. K. and Hale, A. H.: “A
borehole Stability Model to Couple the Mechanics and Chemistry of Drilling
Fluid Shale Interaction, SPE/IADC 25728, Proc. 1993 SPE/IADC Drilling
Conference, Amsterdam, Feb. 23-25, 1993.
van Olphin, H.: “Compaction of Clay
Sediments in the Range of Molecular Particle Distances, Clays and Clay
Minerals,” Proc. Eleventh National Conference on Clays and Clay Minerals,
Ottawa, Ontario, Canada, August 13-17 (1962).
Burst, J. F.: “Diagensis of Gulf Coast Clayey
Sediments and Its Possible Relation to Petroleum Migration,” Amer. Assn. Pet.
Geol. Bull., 53, pp.73-93, 1969.
Lal, M., Kristiansen, T., Deem, C.
and Bowers, G. “Shale Stability: Drilling Fluid/ Shale Interaction Study and
Shale Strength Correlations,” Amoco Report F96-P-99, 963480010 ART
Lal, M. and Deem, C., “Shale
Stability: Drilling Fluid/Shale Interaction - State of the Art Report,”
F95-P-117, 953420005-TUL, December 7, 1995.
Amoco Wellbore Stability Team,
“State of the Art in Wellbore Stability,” F94-P-60, June 20, 1994.
Santarelli, F., Dardeau, C., and Zurdo, C.:
“Drilling through highly fractured formations: A problem, a Model, and a Cure,”
paper SPE 24592 presented at the 1992 Annual Technical Conference &
Exhibition, Washington, D.C., Oct. 4-7
Forsans, T.
M. and Schmitt, L., “Capillary Forces: The Neglected Factor in shale
Instability Studies?” SPE Paper 28058 presented at the 1994 SPE/ISRM Rock
Mechanics in Petroleum 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.
Fritz, S. J.
“Ideality of Clay Membranes in Osmotic Processes: A review,”: Clays and Clay
Minerals, Vol. 34(2), 1986, pp. 214223.
Madsen, F. T. and Muller, V.: “The Swelling Behavior
of Clays,” Applied Clay Science, Vol. 4, 1989, pp. 143-156. 14. Bailey, L.,
Denis, J. H., Maitland, G. C.: “Drilling Fluids and 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.
Horsrud, P, Holt, R. M., Sonstebo, E.: “Time
Dependent Borehole Stability: Laboratory Studies and Numerical Simulation of
Different Mechanisms in Shale,” paper SPE 28060 presented at the 1994 SPE/ISRM
Rock Mechanics in Petroleum Engineering Conference, Delft, 29-31
Gazaniol, D.,
Forsans, T., Boisson, M. J. F. and Plau, J. M.: “Wellbore Failure Mechanisms in
Shales: Prediction and Prevention,” JPT, July 1995, pp. 5890595
please like us or share in facebook
