module c_hydraulic fracture geomechanics
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MBDCI
Module C: Hydraulic Fracture Module C: Hydraulic Fracture Behavior: Assumptions and Behavior: Assumptions and
RealityReality
LACPEC – 2007Short Course on Petroleum Rock Mechanics
Maurice B. DusseaultUniversity of Waterloo
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Hydraulic Fracturing UsesHydraulic Fracturing Uses To enhance well productivity (drainage area)
Propped fractures in reservoirs, geothermal well fracs, access to naturally fractured zones ....
Introduce thermal energy (steam fractures) Stress measurements (step-rate tests,
Minifrac™LOT, XLOT) For massive solid oilfield waste (NOW)
injection (SFI) Drill cuttings annular reinjection Acidizing, for “choking” rates, other uses Deep biosolids injection (Los Angeles – 2008)
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E.g.: Choking ProductionE.g.: Choking Production
Poor recovery from lower sand bodies
Propped fracture chokes off the high-k zone, allowing a larger production proportion from lower zones, increasing recovery ratios
high k sand body
medium k sand
shales
medium k sand
medium k sand
Used in the North Sea by Statoil to choke production from the higher k upper layers to get higher overall RF
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Hydraulic fracturing produces more oil, but not all are happy
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HF HF
HF involves lithostratigraphic model, HF model, operations design and execution, monitoring and post-analysis
Depths, properties, initial stresses, etc…
In situ stresses
growth
Courtesy Natchiq Corp
Pressures vs time
Operations design
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Conventional AssumptionsConventional Assumptions
Fractures propagate as a planar surface through a solid, linear elastic material
The material is assumed to have an intrinsic resistance to fracture (eg: KIC)
The far-field stresses stay constant, and the material properties as well
Fractures are approximately symmetric Other similar assumptions are common,
and these assumptions are used in developing models that are used in analysis
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E.g.: E.g.: FracturesFractures are Symmetric are Symmetric
saltdome
gasoil
sulphur
fracture
A A´
salt domeFractures reflect the local stress field, and tend to elongate asymmetrically
Clearly, not all fractures are symmetric or in the same orientation! Local stress fields are important!
salt
Close wells
More distant wells
Section A-A′
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Typical Model AttributesTypical Model Attributes
Rock behaves as a Linear-Elastic material
Fracture orientation remains constant Constant fracture tip toughness (KIC)
controls propagation Mode I (opening mode) fracture only, no
shear of rock occurs Bleed-off using a 1-D flow model = ƒ(1/t) Fluid buoyancy effects often ignored Constant permeability assumed Simplifications are necessary for
modeling, but they must be robust!
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e.g. Rock Stiffness is Constante.g. Rock Stiffness is Constant
Effective stress - σ′
Stif
fnes
s -
E
assumption
reality
Sandstones are granular media…These materials display E = ƒ(σ′)High φ sandstones are strongly non-linearThis affects predictions, behavior
E = Stiffness (Young’s Modulus or Bulk Modulus)
Be aware of assumptions; make sure they are reasonable
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Impact of Modeling AssumptionsImpact of Modeling Assumptions
In soft, weak sandstones, the various assumptions made in fracture modeling lead to a number of problemsLength in SWR* is greatly over-predictedAperture predictions are invalidPredicted injection pressures rise with timeFracture orientation is constant Fractures are truly horizontalThere is no associated formation shearing Non-linear bleed-off ignored (L, t)
And so on…
Be aware of assumptions; make sure they are reasonable
*Soft, Weak Rock
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So What Do We Do??So What Do We Do?? We behave as responsible engineers:
Recognize that models are simplificationsLearn more about stresses, geomechanicsCalibrate models in real field casesUnderstand that production changes stressesTake measurements when it is feasible
Design on “expected” behavior, but…Expect the unexpectedLearn from the data for your cases, and,Understand the physics behind fracturing
This is what engineering is all about
Be aware of assumptions; make sure they are reasonable
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Behavior of Hydraulically Behavior of Hydraulically Induced FracturesInduced Fractures
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Fracture Growth is Complex!Fracture Growth is Complex!
Pay
Pay
“Perfect” fracture
Multiple fracturesdipping from vertical
T-shaped fractures
Twisting fractures
Out-of-zone
growth
Poor fluid diversion
Upward fracture growth
Horizontal fractures
?
?
?
? ?
?
?
Pinnacle Tech. Ltd.
Fracture models cannot predict highly complex behavior
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Controls Controls on on Fracture DirectionFracture Direction
In situ stresses are the major control!!! Fractures propagate normal to 3
Local fracture propagation direction may be affected by joints, fractures, bedding, but for short distances only
Stresses may also be changed by production and injection processes! By massive injection processes (+p)By thermal effects (T)By production (depletion) effects (-p)By solid waste injection (V)
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Local Fabric and FracturingLocal Fabric and Fracturing
3
3 Joint system in the rock
Locally, fracture follows fabric;
globally, fractures follow stress fields
Local stress field around the borehole (10 D max)
In strong, jointed rock (carbonates), HF locally follows the joints, but at a large scale, the regional stresses dominate…
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Goals and RealityGoals and Reality
What we getWhat we want
Pay zone
500 ft
Or Or
1200 ft 450 ft
Design → Implement → Monitor → Analyze → Learn
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Multiple Zone StimulationMultiple Zone Stimulation
What we getWhat we want
Pay zone
Pay zone
Pay zone
Understanding HF will help us design stimulations
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Why Vertical Fractures RiseWhy Vertical Fractures Rise Fracture fluid gradient is almost always
less than the 3 gradient = excess p is generated at the top of the fracture
Rise rate can be affected by fluid density
Rise rate can be affected by leak-off rates (more leak-off = less rise)
Rise rate can be affected by in situ stresses and stiffness of overlying strata
Rock strength is largely irrelevant in stopping large vertical fractures rising!!
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Why Fractures RiseWhy Fractures Rise
Fracture fluid has a density of < ~1.2
The gradient of lateral stress (dh/dz) is much more than this value
Thus, there is an extra driving pressure at top
Deficiency in driving pressure at bottom
Fracture tends to rise
pressure (stress)lateral
stress
positivedrivingforce
injectionpoint
verticalfracture
injection point
stress gradient is typically
17-23 kPa/m
fracture fluidgradient is
10-13 kPa/m
pressure and stressare about the sameat the injection point
fluid pressure
3
pressure deficiency
E.g.: 30 m high, Δp = (21 – 11) x 30 m = 300 kPa!
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Fractures Rise Out of ZoneFractures Rise Out of Zone
injectionwellbore
reservoir
shale overburden
t1
t2
t3
t4
perforations
E2
E1
If there is no difference in Δσ3, fractures tend to rise
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““Horizontal” FracturesHorizontal” Fractures These tend to occur at shallow depth, in
heated or large V cases, in high tectonic stress cases (3 = v, thrust regime)
Tend to climb away from injection point Tend to be highly asymmetric in shape Propagation of a shear band well in
advance of the parting fracture plane is common
Shallow rising fractures tend to “pan-out” under stiff, competent strata (eg: cemented zones, shale interface)
Almost impossible to numerically model in a physically rigorous manner
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““Horizontal” Fractures in SWR*Horizontal” Fractures in SWR*
Horizontal fractures do not grow 3
least principal stress = v
boreholeinjection
fractures tend to rise gently in this case
pinj > v
*SWR = Soft, weak rock such as unconsolidated sandstones
fracturepans-outunder shale3
asymmetric geometry
“Horizontal” fracture behavior remains poorly understood
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Different Stresses in StrataDifferent Stresses in Strata
Often, fractures do not rise out of the zone, they stay in the zone and propagate laterally. Why?
This usually means that σ3 (= σhmin) in the upper zone is larger than in the lower zone
This forms a barrier to upward propagationThe larger the contrast, the better the barrier
Under this condition, it is easier to grow laterally than to grow upward, because of the stress barrier at the top of the zone
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Blunting Upward GrowthBlunting Upward Growth
stress
hmin v
High lateral stress “blunts” vertical growth
Fracture grows in the zone of
lower hmin
depth
This is the “ideal” fracture, only attained when higher stresses in the overburden blunts fracture rise
Key!!
Is this common? Yes – relaxed basins, offshore, …
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Natural Natural hminhmin (P (PFF) Variations) Variations
stress
hmin
depth
v
salt
hydrostatic po
Pore pressure distribution
limestone
shale
sandstone
shale
shale
(po is undefined in salt beds)
depth
hmin
zv
z
Absolute stress values Stress gradient plot
Frac gradient, PF, is fracture pressure/depth = hmin/z
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GoM CaseGoM Case
In the GoM, it is typical that the shales have higher lateral stresses than the sands
In other words, PF (shales) > PF (sands) This provides a “stress barrier” to upward
propagation of hydraulic fractures It is the common case in all gravitational
basins, also common in normal fault basins However, this may not apply at great depth
Shales have undergone diagenesis, σ changes…Lateral stresses in shales now lower than sands
Also, not in tectonic basins, near salt…
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Lower Overburden Lower Overburden 33 Case Case
stress
depth
hmin
Fracture retreat
Initial fracture growth phase
Preferential propagation in the zone of lower hmin
v
Normal case
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Case of Low Overburden PCase of Low Overburden PFF
In this case, for tectonic reasons or diagenetic alterations:The overlying cap rocks (shales or siltstones)
have a lower PF than the reservoir rocks
It doesn’t matter if the overlying rocks are impermeable (shale), strong (limestone) or of low porosity (anhydrite):
Fractures will tend to rise through them, rather than propagate laterally
In some parts of the world, deep gas fractures can rise 4000 m to the sea floor!
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Can Fractures Drop?Can Fractures Drop?
stress
depth
hmin v
Only limited downward growth potential exists in real cases
Fracture grows in the zone of
lower hmin
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Dropping FracturesDropping Fractures
May occur in zones of stress reversion (see sections on Stresses in the Earth)
May occur in massively depleted zones May occur if the fracture fluid is
extremely dense (e.g. a borate brine workover fluid) Because the p gradient > σhmin gradient
Only in these cases can one expect that fractures will have a significant downward component
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Induced Changes in Stress FieldsInduced Changes in Stress Fields
Near-field stresses are altered by fracture
fracture tip3 3
pprimary fracture secondary fracture
dilated zone
high pressure zonep > (original)3
a pressure increasecauses the stresses to increase as well
View from above of vertical fracturing
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Fracture Direction ChangesFracture Direction Changes
A fracture pushes the rock apart, so the fracture pressures are higher than 3
As the fracture L grows, the fracture aperture also grows; this increases the stress normal to the fracture
Near the well, it now becomes easiest to propagate in a different direction
This is done deliberately in Frac & Pack Also, the injection plane may flip back
and forth between the two directions This has been measured in real frac
jobs…
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Lessons from Nature…Lessons from Nature…
Dikes, ring dikes, sills, etc., are all hydraulic fractures
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Orientation Changes in NatureOrientation Changes in Nature
major ring-dike
minor arctuate ring-dike swarms
pre-ring-dikeradial dykes
en-echelon
older dikes
principal stress
stock
original minimum
3
3
Stress changes takeplace during vulcanism
Dikes propagate to the σ3 direction
First event – radial dikes and stock, then cooling, shrinkageSecond injection event: ring dikes, because σ3 now radial
minimum stress direction becomes
radial after shrinkage
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Rick Dike Complex, ScotlandRick Dike Complex, Scotland
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Spanish Peaks, ColoradoSpanish Peaks, Colorado
Curvilinear dike means a curvilinear σ3 stress field existed at the time of injection
σ3
σ3
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Sequence of Events…Sequence of Events…
Initially, stock is emplaced with radial dikes (hydraulic fractures) generated because of reduced , highr
Vulcanism stops, rock cooks, country rock is altered (porosity decreases), shrinkage, etc. leads to lowered r
The new generation of dikes propagate normal to 3, which is now radial (r)
Thus, the arctuate ring dikes cut across the older radial dikes!
Proof of stress changes in nature
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Spanish Peaks – Dike PatternSpanish Peaks – Dike Pattern
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Spanish Peaks – Stress ModelingSpanish Peaks – Stress Modeling
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Fracture Orientation ChangesFracture Orientation Changes
Courtesy Pinnacle Technologies
Limited further growth of N80°E fracture
Wellbore
Fracture geometry after first 2/3 of main treatment
vertical frac
Probable fracture geometry at end of pumping
Creation of new vertical frac to
original vertical frac
horizontal frac
Tiltmeter data during fracturing confirms multiple orientations and flipping of growth plane
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Depletion and FracturesDepletion and Fractures
The well-known depletion effect changes the total stresses in the well influence region
Not all wells are depleted evenly There are other effects associated with:
Proximity of no-flow boundariesLithological differences (stratification)Reservoir heterogeneity, plus k with pCompaction and stress redistribution
Combined, these give an “uncertainty” as to fracture direction after the depletion of a field
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Depletion Effect HeterogeneityDepletion Effect Heterogeneity
source: SPE 29625 by Wright et al.
p pp
h v p X
1
1 21
Original fracture orientation, virgin reservoir conditions
Fracture orientation in a mature field with infill wells, altered p, refracs…
hmin
initial
Local effects have overridden initial
stress orientations
production
injection
(X is a “fudge” factor)
Depletion is never uniform; it alters the local stress fields, in this case, the orientation looks close to random!
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Depletion and PressurizationDepletion and Pressurization
Suppose in situ stresses are similar (±5-8%) If fractures originally horizontal, 3 = v
Depletion can reduce hmin to below v
This means refracs will be vertical!
If fractures originally vertical, hmin = 3
Pressurization can increase h to above v
This means fracs may become “horizontal” during an injection process! (Especially heating)
Be careful, p can change frac orientations! Re-determine your fracture directions in
wells if this is critical to the process
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Increase in Increase in 33 OrientationOrientationpBD, breakdown pressure
Bo
ttom
Ho
le P
ress
ure
Time (or V if constant injection rate used)
Sudden propagation
3
3
Large-scale stress change with continued injection
Increase in σ3
Pressure-induced volume change + aperture effects change stresses in the region around the fracture plane.
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Fractures and StressesFractures and Stresses
Different stresses (hmin) and entry port distributions change fracture disposition
low closure stress
high closure stress
Point source
Unrestricted entry Distributed limited entry
Multiple points, limited entry
Courtesy Pinnacle Technologies
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Multiple Zone FracturingMultiple Zone Fracturing
Frac fluids will tend to only enter upper zone where the lateral stresses are lowest
A point-source fracture may grow up, not down, making things worse…
To achieve a more uniform distribution:Measure stresses to get an idea of contrastsUse perforation strategy (size and spacing)
to give more entry capacity in lower zonesThe upper zone is “choked back”Design must be based on rate and viscosity
calculations to achieve best results
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Can We Fracture Loose Sand?Can We Fracture Loose Sand?
Some suppose that this is not possible because the sand will just collapse
Actually, you can do this easily in the lab The walls stay perfectly intact because of
the seepage force This arises from Δp/Δl (Same process as
mud support forces in borehole stability.) It acts outward (in the direction of the
pressure gradient) and supports the fracture walls as long as there is flow
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Fracture in a SandFracture in a Sand
This is a fracture created by injecting a viscous plaster
To create a fracture in sand, inj. rate > leak-off rate
This “forces” a fracture to open to accommodate the fluid
However, is it a shear process before a tensile parting process?
’ ’
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Origin of the Seepage ForceOrigin of the Seepage Force
pf
p - pf
F
flow direction
gradient direction
F = force
s = shape factor
A = grain area
p = drop in p
F = sAp
A
This is a model of one grain of sand
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Seepage Force in FracturingSeepage Force in Fracturing
Pressure drop creates a force on each grain in the fracture wall
Force is proportional to the product of gradient, cross-section, and grain width
It is a genuine body-force, like gravity, and acts outward from the fracture face
Force acts in the direction of gradient This is why a fracture in an
unconsolidated sand can be generated without a KIC
An important factor in soft, weak rocks Shearing processes must be taking place!
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Hydrodynamic Forces Hydrodynamic Forces
The hydrodynamic force on grains
Seepage force
F Awp/l= =
p p-p
The pressure gradientleads to an outwardseepage force whichkeeps grains in place,permitting creation ofa fracture in a sand
p-p
F
fractureflow
porous flowp
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**high shear stress zone
high p area, H > v
low-k shale stratum
low-k shale stratum
high-kreservoir
**slip can occur in front of a fracture parting plane
Low-Angle ShearingLow-Angle Shearing
fracture
planeH
v
H > v
Low-angle shearing happens in many thermal projects
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Fracturing and ShearFracturing and Shear
Fracture injection (thermal or non-thermal) can lead to shearingPore pressures are > σ3, so there is no effective
stress; hence frictional strength = very low This is most serious in the case of
“horizontal” fractures (v = 3) Shearing is in the form of a low-angle thrust
fault mechanism Shear planes concentrate along the bottom
of strong, stiff beds (cemented streaks) Many examples in Alberta (CSS steam inj.)
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Fractures and Casing ShearFractures and Casing Shear
A B C
3
1
injectionwell
oilsands
silty bed
fractureplane
lean oilsands
Ver
tical
exa
gger
atio
n =
x2
to x
3
A: early shear, occurring at the base of a shale bedB: later shear, at the top of the formationC: well showing some distortion, not failed yet
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Do Fractures Initiate Suddenly?Do Fractures Initiate Suddenly?
In intact rock, yes, because the value of is the highest at the borehole wall
However, in many cases, can be reduced in a zone near the well
In this case, the fracture initiates well before breakthrough
It grows slowly and gives a non-linear response
When it passes the peak , it then “shoots” out suddenly
The p-t response is quite non-linear
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Non-Linear ResponseNon-Linear Responseb
otto
mh
ole
pre
ssu
re
virgin reservoir pore pressurep
o
fracture initiation occurs very early
stable fracture propagation
breakthrough
propagation
non-linear responsetime (constant pumping rate)
Fracture is initiated and grows well before it breaks through and extends
This is usually the case in weak rocks like tar sands…
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Rock Stiffness EffectsRock Stiffness Effects
Rock stiffness (E) affects aperture: high E, low aperture; low E, large aperture
Aperture affects hydraulic pressure distribution in the fracture (low aperture = higher losses)
Therefore, high E impedes propagation in that stratum, low E enhances propagation
Some rocks can deform plastically (UCS, chalk, coal, high dirty sands ...)
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Effects of Stiffness (E)Effects of Stiffness (E)
stiffer stratum
softer stratum
A'
A
Section A-A'
3
Stiffness controls fracture aperture: wider in lower E rocks
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Formation Stiffness EffectsFormation Stiffness Effects
Soft reservoir
Stiff overburden
Low “E”
High “E”
stress
depth
hmin
If stresses are not a factor, fractures will tend to be blunted in stiffer strata, propagating laterally more easily than vertically
A stiff caprock can blunt upward growth
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Rock Stiffness EffectsRock Stiffness Effects
Stiff reservoir rock
Softer overburden
Low “E”
High “E” Fractures that propagate into a less stiff rock will tend to extend preferentially in that material, other things being equal.
Conversely, propagation into soft strata is easier…
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Permeability EffectsPermeability Effects
High k stratum generates massive blunting Propagation potential reduced if a new
high-k stratum encountered (loss of hydraulic E)
In extremely low-k strata (shales), no bleed-off, distant propagation, high p generated
Bleed-off changes with time as the pressure gradients change with inflow
Fluid-loss control agents can be used wisely
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Blunting in a High-k ZoneBlunting in a High-k Zone
High k stratum
Low k stratum
Low k stratum
A
A
Section A-A
Fracture retreats after high k zone intersected
“Blunting” through high k zone effect
Fluid flow
Fracture before intersection
Higher k, higher leak-off, more blunting…
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Rock Strength EffectsRock Strength Effects
Rocks are jointed, fissures, bedded, flawed Fracture will “find” these flaws immediately Resistance of such materials to propagation
is minimal with a a large fracture length If strength is correlated to another property
(k, E, 3), it may “appear” to be important In general, strength (fracture toughness) is
largely irrelevant for large fracs
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Local Fabric and FractureLocal Fabric and Fracture
3
3 Joint system in the rock
Locally, fracture follows fabric;
globally, fractures follow stress
The strength of the intact rock is not relevant in this case
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Monitoring FracturesMonitoring Fractures
Precision real-time tilt monitoring (<3000m) Microseismic monitoring using geophones at
depth relatively near the fracture site Pressure-time response in the injection well Impedance tests in a propped fracture Borehole geophysical logging (T, tracers) Other methods are problematic at best
Implies a “poorer” method of monitoring
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Hydraulic Fracture MappingHydraulic Fracture Mapping
Characteristic deformation pattern makes it easy to distinguish fracture dip, horizontal and vertical fractures Gradual “bulging”
of earth’s surface for horizontal fractures
Trough along fracture azimuth for vertical fractures
Dipping fracture yields very asymmetrical bulges
Dip = 80°Maximum Displacement:
0.00045 inches
Dip =90°Maximum Displacement:
0.00026 inches
Dip = 0°Maximum Displacement:
0.0020 inches
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Tiltmeter Fracture MappingTiltmeter Fracture Mapping
Tilts measured Mathematical sol’n If depth > 3 km,
tilt measurements are quite difficult
One solution is use of borehole tiltmeters
Mapping has recently been achieved at > 3km
De
pth
S urface tiltm eters
D ow nhole tiltm eters in o ffse t w e ll
F racture
Courtesy Pinnacle Technologies
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Fracture and Tilt VectorsFracture and Tilt Vectors
1000 feet
Measured Tilt -- 250 nanoradians
Theoretical Tilt -- 250 nanoradians
Frac: Vertical Azimuth: N39°E Dip: 87° W Depth: 2300 ft
North
Tiltmeter Site
1000 feet
Measured Tilt -- 500 nanoradians
Theoretical Tilt -- 500 nanoradians
Frac: Horizontal Azimuth: N/A Dip: 6° N Depth: 2900 ft
North
Tiltmeter Site
Wellhead
Courtesy Pinnacle Technologies
Vertical
Horizontal
Azimuth
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Reality and Tilt ModelingReality and Tilt Modeling
Actual fracturedimensions
Estimated fracturedimensions
Inversion of tilt data is based on relatively simple and symmetric source functions.
It is nevertheless quite powerful in giving orientation and size of fractures.
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Lessons LearnedLessons Learned
HF behavior is complex, but understandable Stress fields dominate fracture propagation
behavior, strength is almost irrelevant Almost all fractures rise, except when there is
a stress barrier Permeability, stiffness, etc. are important
second-order effects Fractures change directions over time! Monitoring fracture behavior is feasible Geomechanics concepts are essential for HF
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Additional Materials on Hydraulic Additional Materials on Hydraulic Fracture BehaviorFracture Behavior
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Volume Change EffectsVolume Change Effects
+V has an effect similar to +T +V can occur through fluid injection
and through injection of a slurry -V occurs during depletion, or during
solids production (Cold Heavy Oil Production with Sand for example)
Stress changes large enough to change the fracture orientations happen regularly with injection or production volume changes
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p Gradientsp Gradients
p
d
p
p
p
d
A
A
B
B
low k
high k
very slow flow
rapid flow
High pressure liquid injection
shale
sandstone
shale
High gradients across the fracture wall support the sand
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Pressure GradientsPressure Gradients
In a fracture, assume that p ~ constant At the advancing fracture tip, we always
have very high local pressure gradients On the flanks, near the injection point, p
gradients become flatter with time +p (p increase) involves , hence
+V, therefore the total stresses should increase
Thus, facture gradients will increase with continued injection if there are no additional effects (e.g. thermal effects…)
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Poroelastic EffectPoroelastic Effect
+p causes +3, leads to higher inj. pressure
fracture
pressured region
3 3
Δp
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Some Thermal Aspects of Some Thermal Aspects of Hydraulic FracturingHydraulic Fracturing
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Thermal EffectsThermal Effects
The large-scale vertical stress is governed by the force of gravity and the free surface
-T decreases h = vertical fracs with time
+T increases h = horizontal fracs All thermal processes, in the absence of
other effects, eventually lead to the generation of “horizontal” fracturing
CO2 fracs lead to easier and fatter fracs because of the thermal cooling
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T GradientsT Gradients
T
d
T
T
T
d
A
A
B
B
low k
high k
conductive heat flow
convective heat flow
Hot fluid injection
shale
sandstone
shale
steep Tgradients
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Temperature GradientsTemperature Gradients
In permeable rocks and high injection rates, heat transfer is convective (advective)
Steep t-gradients are maintained for long t In adjacent low-k rocks, it is conductive Gradients flatten out toward steady state V differences lead to regions where 3 > p,
others where 3 < p (frac condition) Thus, fracture gradients and orientations
evolve with thermal processes
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Heat and Stress FieldsHeat and Stress Fields
Near-field stresses are altered by fracture
fracture tip3 3
T
primary fracture
secondary fracture
heated zone
high pressure zonep > (original)3
Temperature increasecauses stresses to
increase near fracture
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Thermal FracturingThermal Fracturing
Clearly, large T alters stress fields Heating leads to horizontal fracs (v 3)
Cooling leads to vertical fracs (hmin 3) We can do some interesting things:
Multiple +T fracs in horizontal wellsMultiple –T fracs in geothermal wellsZonal control using cooling fracs Heating to restrict fracture (increase pfrac)Cooling encourages borehole wall fracs Other processes as well
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Hot Fluids Hot Fluids OrientationOrientation
pBD, breakdown pressure
Bo
ttom
Ho
le P
ress
ure
Time (or V if constant injection rate used)
Sudden propagation
3]initial 3]farfield
Large-scale stress change with continued heating
v
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CSS - First Cycle ResponsesCSS - First Cycle Responses
pressure
time
original v (= ·z)
initial hmin (= 3)
A
B C
A: pBD, usually > v
B: p falls off
C: p rises with V
D: fluid losses?
D
“thief” zone
hmin = 3
Fracture orientation changes with rapid steam injection into low permeability tar sands, leading to “horizontal” fracs
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Pressure Rise in CSSPressure Rise in CSS
Initially, virgin 3 controls pP, but:V from the volumes injected, andV from expansion (T in rock V +),
Leads to increase in the local stresses (h )
Locally, h becomes > v (now = 3) Fractures become horizontally dominated Now, overburden + p losses govern pP
Generally, pinj 1.15 - 1.25 v
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Heat Losses - CSS 1Heat Losses - CSS 1stst Cycle Cycle If hmin << v, vertical fractures
These fractures rise substantially (f << 3)Break-through to overlying high-k zones common Irrecoverable heat loss (fractures close when p <3)
If hmin > v, “horizontal” fracturesMay exist as the natural state in shallow reservoirsMay be induced by injection and T effects
Nevertheless, these will rise to top of zoneUneven heating, loss of some of the lower resourceWith time, downward propagation occurs (slowly)
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Horizontal Well Horizontal Well T EffectsT Effects
33
v
213 3
The first vertical steam fracture increases 3, leading to initiation of a second fracture, likely farther down the casing. 3 in region 2 goes up, a third fracture starts…
+T
Eventually, hmin is no longer 3; then fractures change orientation
MBDCI
Stable Thermal FracturingStable Thermal Fracturing
Horizontal well ║ to 3 , fractures vertical
Thermal fracturing +V +3 (local)
Thus, in first fracture, pfrac as 3 (locally) After some t, easier to fracture elsewhere Frac #1 is near heel, others step toward
toe The process continues until ║ to well is no
longer 3, then frac orientations will change
New orientations are related to []initial
Fractures are stable until [] is altered
MBDCI
Cooling-Induced FracturesCooling-Induced Fractures
Water displacement front
hmin
HMAX
T front
T
T
TTo
To
Cooling shrinks the rock, stresses drop, PF drops…
MBDCI
Geothermal FracturingGeothermal Fracturing
Cold water inHot fluids out
Cross-section Large propped fracture
Massive cooling by conduction
“Daughter” fractures propagate at 90° to the
mother fracture, heat exchange becomes better.
ΔT as great as 300ºC lead to large stress changes, in this case, leading to initiation and propagation of new fractures
MBDCI
Massive Water Re-injectionMassive Water Re-injection
Water may be injected hot or after cooling
T between target stratum and H2O leads to thermoelastic stress changes
Beneficial or detrimental, depending on various factors (e.g. IOR or disposal?)
A subtle interplay exists:Conductive versus convective heat transferPermeability of strata involved is important In situ stresses in all strata are important
MBDCI
Benefits of Water Re-InjectionBenefits of Water Re-Injection
Cold water injection is common Thermoelastic shrinkage develops (TV) Stresses near the injector are reduced:
Fracture aperture increases, keff goes up Intact rock k remains about the same3 drops, and pinj may become > 3
Lower pinj needed to achieve Qinj
Less pump power needed to achieve Qinj
Injection wells perform better!
MBDCI
-T
overburden
warmreservoir
adjacent wells
HMAX < v
+ve
-vemax shear
T in the reservoir
-T
region of high shear
Cooling-Induced ShearingCooling-Induced Shearing
Cooling can also lead to casing shear (shear fracture)
MBDCI
Water Re-Injection ProblemsWater Re-Injection Problems
Mainly during water-flooding (IOR) Thermoelastic shrinkage develops
(T=V) Stresses in the flooded zone drop
Fracture aperture increases, keff goes up
Bounding rocks may reach pinj > 3 Loss of seal, excessive channeling
Conformance is impaired, efficiency lost Effect may be greatly delayed in time Effects are largely irreversible
MBDCI
Thermal Cooling Effect on SRTThermal Cooling Effect on SRT**
*Step-Rate Testpressure
rate
before injection
after injection
lowered pfrac near wellborehigher pfrac far from wellbore
pfrac
pfrac
MBDCI
Thermal Stress AlterationThermal Stress Alteration
Stresses are coupled to ΔT through ΔV calculations (thermal volume change…)
is the coefficient of thermal expansion ΔV = ΔT, is calculated for each unit
volume ΔV is then put into the & Δp model Flow problem is solved (both advection and
conduction) to get {ΔT} Conductive heat flow included, if important Now, the thermal-geomechanical model will
give stresses (from both Δp and ΔT)!
MBDCI
Parameters for Parameters for T AnalysisT Analysis
Specific heat of minerals, cm (convection)
Bulk specific heat of rock, cb (conduction)
Thermal conductivity, ij (conduction)
Hydraulic conductivity, kij (convection)
Thermal expansion coefficient (ij)
Rates of injection, Qinj
In situ stresses, ij, for all involved strata Stratigraphy, porosity, etc. ...
MBDCI
T by Convection or Conduction?T by Convection or Conduction?
shale
sandy shale
sandstone
shale k ~ 0
k ~ 0
low k
high k
pure conduction
pure convection
pure conduction
mixed conduction-convection
90% Tinj
radius
depth
Tinj Tinj
MBDCI
Fracture Where Fracture Where vv = = 33
p
time
pinj
pisip = v
reservoir pressure
solids injectionpinj~1.1-1.3v
4-16 hours continuous injection
This is a case of massive solids re-injection
MBDCI
Injection Rate EffectsInjection Rate Effects p in the fracture =Vt, ...) To create a short, fat fracture, use high rates
and a viscous fluid (trade-offs are vital) To create a short, thin fracture, use a low-
viscosity fluid and low rates Extremely high rates can locally change
stresses, generating locally orientated “arms” FracPack is a good example of rate effects We deliberately use high rates, high viscosity,
and heavy proppant load to get better effects
MBDCI
High Proppant ConcentrationHigh Proppant Concentrationbo
ttom
hole
pre
ssur
e
po - virgin reservoir pore pressure
time (constant pumping rate)
σhmin - least principal stress
Proppant concentration
Treatment pressuresσv - vertical stress
Frac-&-Pack is widely used to create short thick fractures
MBDCI
!
High Rate FracturesHigh Rate Fractures
proppant forced between casing and rock, sometimes called the “halo effect”, verified in 1999
fat fractures,close to hole
cement
casing
3
extrawings
Frac & pack, high rate fracs, high fracs
increases!
r increases!
MBDCI
Increase in Confining StressIncrease in Confining Stress
Y
Frac & Pack increases the confining stress, making the sand stronger and Improving arching
Shear stress
Normal stress
Shear strength of the rock
Restressing the disturbed sand also strengthens it
MBDCI
Is Lab Testing Valuable?Is Lab Testing Valuable?
There have been many large rock fracture cells built, even huge sand boxes of many cubic metres
Results from these have been of little practical value in general (although the owners of these would argue vociferously)
The complex reality in situ for fracturing is difficult to replicate in any lab
Given history to date, we must conclude that modeling and measurements are best, lab simulation is not of great use
MBDCI
Vertical Fracture Plane in a Sandbox, U. of Waterloo
MBDCI
Horizontal Fracture in a Sandbox, U. of Waterloo
MBDCI
New Completion Approaches?New Completion Approaches?
Why fracture soft, weak rocks?To increase flow to wellsTo mitigate sand production tendenciesTo introduce heat, fluids, etc.To change stress state (stress rotation)
New completions approaches with a period of solids production followed by a high-rate sand-propped fracture are quite promising
MBDCI
New Completion ApproachesNew Completion Approaches
First, produce some sand Then, re-stress with Frac-and-Pack
MBDCI
Completion in Weak SandsCompletion in Weak Sands
Produce 10-100 m3 of sand deliberatelyDilation occurs, k goes upPore throats are larger, less fines pluggingWell becomes a better actor
Then, use a high sand content fractureRe-stresses the sand near the well (stronger)Large proppant gives –ve skin on the wellLarge-diameter well effect (high k)Use resin-coated proppant to eliminate
sanding Will give a better well, fewer workovers
MBDCI
Summary of Fracturing in Soft Summary of Fracturing in Soft Weak Rocks (Unconsolidated Weak Rocks (Unconsolidated
Sandstones)Sandstones)
MBDCI
Leak-Off BehaviorLeak-Off Behavior
Assumption: Permeability is constant Fact: Permeability alterations are large
Dilation of UCSS through shear dilation
Opening of joints and fissures from effects
Fissure dilation from pressure effects Thus, leak-off predictions contentious Solution: Incorporate changes in leak-off
behavior as a function of k This turns out to be very challenging
MBDCI
Dilatancy and Dilatancy and Shearing dominates in SWR and UCSS
Dilation is a consequence ofshearing from high pressureand differential stresses
Dilation causes Vand attendant stresschanges
fracture
dilating region, high permeability
σ3 +Δσ3
shear leadsto dilation
Shear dilation is not accounted for in fracture models
MBDCI
Fracture Tip ProcessesFracture Tip Processes
Assumption: KIC governs propagation Fact: tip resistance is essentially zero in:
Poorly consolidated rocks (no tensile strength) Highly fractured cases (little tensile strength) Large hydraulic fractures (scale effect on To)
Thus, KIC = 0, and predictions are in error
Solution: Develop models where KIC is not used explicitly. (static equilibrium?)
This is being attempted now by some research groups, but it is challenging…
MBDCI
Tip Stresses in HFTip Stresses in HF
p must be higher than least principal stress for fracturing to occur
f
fracture
stress
distance
high tensile stressesat the fracture tip
verticalborehole
fracture tip fracturestrength
3
Net driving pressure pnet = pfrac - σhmin
excess (driving) pressure
MBDCI
Mode I Dominates Mode I Dominates EE Assumption: Mode I dominates ΔEnergy Fact: MS monitoring shows shear
dominates In all SWR, flanks exhibit MS Mode II activity Dilation implies shearing, so does
compaction SWR have extremely low KIC
Thus, shear processes are first-order Solution: Incorporate Mode II (bedding
slip, shear dilation, ...) into FEM models Until shear energy dissipation is
included, history matching will remain contentious
MBDCI
Shearing Near a FractureShearing Near a Fracture
Shearing occurson the flanks ofthe fracture.
At the tip, parting occurs, little ΔEnergy
Shearing on fracture flanks during HF of SWR has been detected microseismically in the field.
Shear energy dominates over Mode I
σ3 = σhmin
σHMAX
MBDCI
Mode II Shear and Mode II Shear and pp
drop in lateral stressthrough production
relative fault motion
increase in σHMAX and p through injection
a: Reactivation of normal faulting
b. Reactivation of thrust faulting
MS emissions will cluster around the incipient faulting
σ3 = σhmin
σ3 = σvσ1 = σHMAX
σ1 = σv
MBDCI
Real Fracture Issues Real Fracture Issues
Rock stiffness is non-linear: E = ƒ( Poroelastic effects lead to +V and -V Many unconsolidated sandstones are
actually cohesionless; is KIC = 0?
Strength is a function of scale KIC = ƒ(L/Lo
Rock shear on flanks is a dominant source of energy expenditure (+ shear dilation)
Cohesion loss occurs during shearing, dilation and straining in general (weakening)
MBDCI
E.g.: Sands are Non-LinearE.g.: Sands are Non-Linear
Young’s modulus
(stiffness)
Effective confining stress - 3
Linear behavior: low , few fractures
Mildly non-linear: intermediate , naturally fractured strata, etc.
Highly non-linear: high unconsolidated sandstones, highly fractured reservoirs
MBDCI
Reality in Soft, Weak RocksReality in Soft, Weak Rocks
Dilation or contraction accompanies shear
Cohesion loss during shear is irreversible Fracture opening can alter local stress
fields Fractures can change their orientation Large permeability changes can occur Fracture toughness is essentially zero T and p can change fracture behavior Other factors as well…
MBDCI
**high shear stress zone
high p area, H > v
low-k shale stratum
low-k shale stratum
high-kreservoir
**slip can occur in front of a fracture parting plane
Low-Angle ShearingLow-Angle Shearing
fracture
planeH
v
H > v
Low-angle shearing happens in many thermal projects
MBDCI
Fracturing and ShearFracturing and Shear
Fracture injection (thermal or non-thermal) can lead to shearingPore pressures are > σ3, so there is no effective
stress; hence frictional strength = very low This is most serious in the case of
“horizontal” fractures (v = 3) Shearing is in the form of a low-angle thrust
fault mechanism Shear planes concentrate along the bottom
of strong, stiff beds (cemented streaks) Many examples in Alberta (CSS steam inj.)
MBDCI
Fractures and Casing ShearFractures and Casing Shear
A B C
3
1
injectionwell
oilsands
silty bed
fractureplane
lean oilsands
Ver
tical
exa
gger
atio
n =
x2
to x
3
A: early shear, occurring at the base of a shale bedB: later shear, at the top of the formationC: well showing some distortion, not failed yet
MBDCI
Soft Weak Rock Soft Weak Rock Fracturing Fracturing II
HF models work OK in stiff “elastic” rocks
They fail in the following cases:When the “limits” are pushed (V, p, T...) In near-isotropic stress fields In cases of excessive or non-linear bleed-off In soft, weak rocks (coal, PCS, Chalk...)
Most “interesting” fracture jobs are now taking place in PCS, gas sands...
MBDCI
Soft Weak Rock Soft Weak Rock Fracturing Fracturing II II
Plasticity effects include the following:Fabric collapse and contractionMassive yielding and shear dilationBlocky material slip (with fissures)
These processes change properties:Stiffness changes with dilation, cohesion
lossPermeability alterations are massiveOther effects are important
MBDCI
Soft Weak Rock Soft Weak Rock Fracturing Fracturing IIIIII
Conventional simulators have problems:Elastic response often violated (Frac-and-Pack)Bleed-off assumptions often wrong In a “no-cohesion” material, no fracture
resistance actually exists at the propagating fracture tip
Rotation of stresses around fracture is ignoredThermal advection alters stresses massively
An opinion exists in the industry that these are fatal for PCS, coal, thermal fracture modeling. For these materials, we need more physically correct models
MBDCI
Soft Weak Rock Soft Weak Rock Fracturing Fracturing IVIV
Are simple, better solutions available? Is good field data available? (probably yes) Is it necessary to go to a full FEM
approach; are analytical approximations possible?
When are “fudges” acceptable for empirical design, using existing simulators?
Can we improve our understanding of the physics involved in HF in weak materials?
MBDCI
Behavior of Soft, Weak RocksBehavior of Soft, Weak Rocks
Mechanical properties Deformation response Compressive and
tensile strength Dilation-contraction Thermal expansion
Compression and extension triaxial tests, plus a thermal cell
Transport properties Permeability vs Thermal conductivity Acoustic properties:
impedance, attenuation Effect of damage
These properties can be assessed with existing laboratory facilities
MBDCI
Fracture in Soft, Weak Rocks: Fracture in Soft, Weak Rocks: Assumptions vs RealityAssumptions vs Reality
Current attributes linear poroelastic fracture tip toughness constant orientation constant permeability isotropic properties no shear dilation other simplifications
Actual behavior, SWR non-linear behavior zero tip toughness (?) orientation changes flow properties altered anisotropy is common shearing dominates E other realities
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