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

MBDCI

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)

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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!!

MBDCI

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

MBDCI

““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

MBDCI

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

MBDCI

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!

MBDCI

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

MBDCI

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.

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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!

MBDCI

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

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.)

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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

MBDCI

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…

MBDCI

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 ...)

MBDCI

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

MBDCI

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

MBDCI

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…

MBDCI

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

MBDCI

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…

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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

MBDCI

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)

MBDCI

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