advances in geomechanics

1

Determination of the State of Stress With Applications to Wellbore Stability and

Fracture Flow in Reservoirs

Mark ZobackProfessor of Geophysics

Stanford University

E xploration Appraisal D evelopment H arvest Abandonment

Geomechanical Model

Time

Production

Wellbore StabilityPore Pressure Prediction

Sand Production Prediction

Compaction

Depletion

SubsidenceCasing Shear

Fault Seal/ Fracture Permeability

Fracture Stimulation/ RefracCoupled Reservoir Simulation

Geomechanics Through the Life of a Field

Middle East and Caspian Sea

Last Update: 1/10/09

Wellbore Stability

Fracture Permeability

Fault Seal

Pore Pressure

Sand Production

Stress Direction

LEGEND

GMIDubai

Topics

How to Determine the State of Stress in Oil and Gas Wells (and How Not To)

Wellbore Stability Applications Fluid Flow in Fractured Reservoirs

3D/4D Geomechanics

Get the Stress Right!

Sv – OverburdenSHmax – Maximum horizontal

principal stressShmin – Minimum horizontal

principal stress

Sv

Shmin SHmax

Principal Stresses at Depth

7

UCSPp

Pp – Pore PressureUCS – Rock Strength (from logs)Fractures and Faults (from Image

Logs, Seismic, etc.)

Additional Components of a Geomechanical Model

Developing a Comprehensive Geomechanical Model

Vertical stress Sv z0( )= ρ g dz0

z0

∫Shmin ⇐ LOT, XLOT, minifracLeast principal

stress

SHmax magnitude ⇐ modeling wellbore failures

Max. Horizontal Stress

Pore pressure Pp ⇐ Measure, sonic, seismic

StressOrientation Orientation of Wellbore failures

Parameter Data

Rock Strength Lab, Logs, Modeling well failure Faults/Bedding

Planes Wellbore Imaging

Compressional and Tensile Wellbore Failures

UBI Well A FMI Well B

Well A

Borehole Wall Stresses for a Particular Trajectory

Breakouts in Deviated Wells

55º/235º

100º/280º

SHmax azimuth 145°

vertical well

100º/280º

well inclined 70° at an azimuth of 280

°

tangential stress

Stereo Plot for Deviated Wells

Easy and functional display of wellbore stability or risk for wells of any orientation.

Wellbore Failure Orientation in Deviated Wells

Pre-Salt, Brazil - SHMax Azimuth?

Wellbore Failures – South America


Geomechanical Model

Time

Production



Compaction

Depletion





Similar Diagrams for Nahr Umr Shale

Don’t Calculate Stress From Poisson’s Ratio

However...•Observations indicate that the horizontal stresses are not equal,

•Model doesn't explain SH > Sh > Sv,

•Global tectonic activity indicates that the crust is not tectonically relaxed

SH - Pp ~ (Sv - Pp)α ν−ν

1

Lateral Constraint (horizontal strain = zero)

•Sv applied instantaneously•No other sources of stress exist•No horizontal strain (Bilateral Constraint)•Material is elastic, homogeneous and isotropic from the time Sv is applied to the present

Assumptions:

Utilizing an Effective Poisson’s Ratio and Adding Tectonic Stress Does Not Make Model Correct

Don’t Calculate Stress from Poisson’s Ratio!

Topics



3D/4D Geomechanics

The Key to Wellbore Stability is Controlling the Width of Failure Zones

Design for Variations in StrengthIncrease Mud Weight as Needed

Pore Pressure

Frac Gradient

“CollapsePressure”

Tendency for Breakout Initiation for Different Stress Regimes

3 km Depth, Hydrostatic Pp

Mud Weight Needed to Maintain 30º BreakoutsNormal Strike-Slip Reverse

Stress States Same as Previous SlideMedium Strong Rock UCS = 7250 psi

Example - Stability of Uncased Multi-Laterals

Key Questions:

• Is it possible to leave short sections (~15’), of laterals uncased near the parent well?

• Will such intervals be stable as the reservoir is produced?

• Could producing too fast exacerbate sand production and stability problems?

Calibrated Rock Strength Log

• Triaxial tests in laboratory

• Relate strength to P-wave modulus

• Use ∆T and density to compute UCS

• Caution - should not be used in hydrocarbon zones

0 5 1 0 1 5 2 09 5 0 0

9 6 0 0

9 7 0 0

9 8 0 0

9 9 0 0

1 0 0 0 0

C o , K p s i

Wellbore Stability Plot

S H m a x

N

S

W E

More stable

Less stable

Req

uire

d St

reng

th

Req

uire

d m

ud w

eigh

tB

reak

out W

idth

Lower hemisphere stereographic projection of well orientation

Well XDrilled at 335 degrees,maximum deviation 108 degrees.Successfully drilled and completed

-920

0'

-920

0'

-9400'

-9600'

-9600'

-9400'

-9200'

-9200

'

-9400'-9600'

-920

0'-9000'

-9600'

-9400'

-9200'

-9200'

-9600

'

-940

0'

-940

0'

-9600'-9400'

-980

0'

-960

0'

-940

0'

-940

0'

-980

0'

-960

0'

-940

0'

-920

0'

-960

0'

-980

0'

-9200'

-900

0'-9

000'

-9400'

-9600'

-960

0'

-9800

'

-9700

'

-9800'

Trading Bay Fault

G-1 5 RD

M-3 1

K-2 6

DOLLY VARDEN

GRAYLING

KING SALMON

STEELHEAD

MONOPOD

Previously Unknown Drilling Experience

Well YDrilled at 31 degrees,deviation 88 degrees.Wellbore collapsed in open-hole section

Moderate Drawdown / Damage

Pore pressure distribution during drawdown

• Decreased pressure drop

• Damage zone less important

Moderate Drawdown / No Damage

Smaller pressure drop

Lower stress at wellbore

→Relatively more stable

→Total BO’s ~ 100o

6 0 0 0

4 0 0 0

8 0 0 0

2 0 0 0

0

1 0 0 0 0

Uni

axia

l com

pres

sive

stre

ngth

[psi

]

Rapid Drawdown / Damage

• Large pressure drop near the well

• Exacerbated by damage zone

Pore pressure distribution during drawdown

Rapid Drawdown / Damage

Large pressure drop

Increased stress at wellbore

→Unstable well

→Total BO’s > 180o

6 0 0 0

4 0 0 0

8 0 0 0

2 0 0 0

0

1 0 0 0 0

Strength required to prevent failure is too high → excessive breakouts

Uni

axia

l com

pres

sive

stre

ngth

[psi

]

PG-2

abandoned

Side track

Example 2• Severe wellbore instabilities in

the Fortune Bay shale led toabandonment of original PG-2well and required drilling a side track

• The side track was completedsuccessfully by switching to oilbased mud and raising the mudweight to 12 ppg in the FortuneBay shale.

Objective for future wells• Optimization of wellbore stability

in deviated and horizontal wells• Feasibility of drilling highly

deviated wells with a maximummud weight of ~11.5 ppg

Orientation of SHmax

World stress map data superimposed with mean SHmax orientation (red arrow) derived from 4-arm caliper and UBI breakout analysis in vertical wells of the Terra Nova field

Hibernia

Terra Nova

St. John’s

Newfoundland

Pore Pressure and Stress in the Terra Nova Field

0 200 400 600 800 10000

500

1000

1500

2000

2500

3000

3500

4000

Pp[bara]

Pp[bara]

Hydrost. [bara]

Sv [bara]

Test Pres.[bara]

Pressure/Stress [bar]

LOT (C-09)

LOT (C-23)

X-LOT (GIG-3)X-LOT (PG-2)

Pp water wet sand

Pp oil wet sand

Hydrostatic

Overburden

FITLOT

X-LOT

Sv = 0.0848*SSTVD 1.117

Shmin = -15.889 + 0.19416*SSTVD

Pp = 0.098*SSTV

SS

TVD

[m]

Breakouts from UBI log in PG-2

• Total breakout length: 32 m

• Mean breakout width: 40° (±11°)

0 90 180 270 3603800

3850

3900

3950

4000

4050

4100

4150

4200Azimuth (deg)

Width (deg)

Azimuth [deg]

no data

no data

Breakout azimuth

Breakout width

Low er FBS

E sand

ED shale

Dc sandDb shale

Da sand

D congl.UC2 sand

LC2 shale

LC2 sand

C2C1 shale

C1 sand

C1B shale

B sand

B Rank shaleRankin Mbr.

Jean

ne d

’Arc

Res

ervo

ir

Fortu

neB

ayS

hale


Lc2 shale within theJeanne d’Arc reservoir

C1 sand within theJeanne d’Arc reservoir

Isotropic compressive failure

N

S

EW

Breakouts from EMS 6-arm caliper log in PG-2

Fortune Bay shaleJeanne d’Arc reservoir

The difference in failure behavior between the Fortune Bay shale and the Jeanne d’Arc reservoir is similar to the UBI images

Anisotropic failureIsotropic failure


Lowermost Fortune Bay shale

Anisotropic compressive failure

Modeling anisotropic breakouts in the Fortune Bay shale with the given in situ stress state

Anisotropic failure

MW = 10.5 ppg

Isotropic failure

Anisotropic failure

MW = 12 ppg

Observed

Bedding plane properties:• dip = 8° (from core data)• Azi = 23° (from core data)• S0 = 4.8 MPa (from lab data)

• µs = 0.21 (from lab data)

Result: The in situ stress tensorderived in this study and thebedding plane propertiesmeasured in the lab canaccount for the anisotropicbreakouts seen in the FortuneBay shale

Predicting stability in theFortune Bay shale for well GIG-3

MW = 12 ppgwBO = 75°

Assuming anisotropic behavior• There exists a steep stability gradient for deviations between 25° and 45 °• Well PG-2 is oriented less favorably in the current stress field• Well GIG-3 is oriented more favorably in the current stress field• Severe stability problems can be avoided for GIG-3 with a maximum mud weight of 11.5 ppg if deviation < 30 °

C0 = 55 MPa

Graben structure at base of reservoir

PG-2

abandoned

successful

GIG-3

successful

Business impact• Petro-Canada successfully drilled well

GIG-3 through the Fortune Bay Shaleby limiting deviation to 27° andmud weights to 10.5 ppg – 11 ppg

• Petro-Canada avoided costly stabilityproblems by following GMI’srecommendations for this well

Topics



3D/4D Geomechanics

Characterizing Hydraulically-Permeable Fractures and Faults

But which ones control fluid flow and how do we take advantage of this?

Hydraulically Conductive Fractures are Shear Faults Active (or Activated) in the Current Stress Field

From Townend andZoback (2001)

Active Faults Maintain Permeability Through Time

Faulting is key to maintaining permeability

Ito and Zoback (2000)

Temperature Anomalies andPermeable Faults in the KTB Borehole

Zoback and Townend (2001)

High Stress, Critically-Stressed CrustDuctile Lower Crust and Upper Mantle

Is This Model Quantitatively Correct?

Mechanical Lithosphere

Zoback, Townend and Grollimund (2002)

Broad-Scale Stresses and Distributed Seismicity

Gas Leakage Along Faults

Active Strike-Slip Faults Conduct Fluids

~5cm/yr

Examples -Critically-Stressed Faults in Damage Zones

Fault Damage Zones and Directional Permeability

Damagezone

Preferential flow along the faults from interference and tracer test

Strong Directional Flow Near Dormant Normal Faults

Current Strike-Slip Stress State

Stratigraphic Permeability Model

Paul, Zoback and Hennings (2009)

Permeability Model Does Not Match Pressure Data in

Producers or Injectors

Need For a Better Model to Match Reservoir Flow

No Wells Directly in Damage ZonesDynamic Rupture Propagation to Calculate Damage Zones

Depth ~2700m

Origin point of rupture

0 2000m

N

0 5 0 1 0 0 1 5 0 2 0 0 2 5 0 3 0 0- 1

- 0 . 5

0

0 . 5

1

1 . 5x 1 0 8

d i s t a n c e f r o m r u p t u r e f r o n t ( m )

stre

ss m

agni

tude

(Pa)

s x xs x y

s y y

s z ys z x

s z zS 1

S 2

S 3

o c t s h e a rt o t a l o c t s h e a r

Damage zone

Rock strength

Cross Section View Along Strike of Normal Fault

Fault Plane

Horizontal Plane

Damage Intensity

Calculated Damage Zone Width

At reservoir depths from100 simulations:Mean of DZ width ~50-90m

2km

Simulation 1

Simulation 3

Simulation 2

Simulation 4 Vermilye and Scholz (1998)

Pro

cess

Zon

e W

idth

, mFault Zone Length, m

Utilizing the Dynamic Rupture Model to Predict Width of

Damage Zone and Anisotropic Permeability

Damage Zone Model Matches Pressure Data in

Producers and InjectorsBaseModel

ImprovedModel

Breakout Orientation Fluctuations Due to Fault Slip

Shamir and Zoback (1992)


Geomechanical Model

Time

Production



Compaction

Depletion





advances in geomechanics

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