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3D Seismic Profiles of U S Shale 3D Seismic Profiles of U.S. Shale Plays -- An AAPG E-Symposiumy y p

David PaddockSchlumbergerSchlumberger

Rick Lewis and Jessie Cryer Schlumberger DCS Data Services (Petrophysics)Rick Lewis and Jessie Cryer, Schlumberger DCS Data Services (Petrophysics)Colin Sayers and Roberto Suarez-Rivera, Schlumberger DCS GeomechanicsJohn Young and Pat Kist, Schlumberger WesternGecoDavid Paddock and Lei Zhang Schlumberger DCS Reservoir Seismic ServicesDavid Paddock and Lei Zhang, Schlumberger DCS Reservoir Seismic ServicesBrian Toelle and Ron Martin, Schlumberger DCS Consulting ServicesJoel Le Calvez, Schlumberger DCS StimMAP Microseismic

Treasure Map

Gammon Excello/MulkyNew Albany

BakkenAntrim

Caney &Woodford

NiobraraGammon Excello/Mulky

GreenRiver

Monterey Devonian/OhioMarcellus

McClure

Cane CreekFloyd &

ConasaguaPalo Duro

Lewis &Mancos

Barnett Fayetteville

Palo Duro

Barnett &Woodford

Haynesville

Woodford

Woodford

Eagle Ford

Introduction

Motivation– Gas shales and their economics

• 30% or fewer of wells are profitable• 50% of Barnett perfs have no flow (typical?)• 70% of flow from 30% of perfs• 70% of flow from 30% of perfs• Is it possible to perf less and drill less. To attain the same profitability from

15% of the forward-looking capital investment?

Challenges for gas shales– Identify sweetspots, optimize drilling, and optimize completions

Disciplines: Petrophysics, geomechanics. Support from seismic. The goal: Prediction of success. It’s achievable.g Most operators only use seismic for well design and hazard avoidance

Organic Rich Shales: Siltstones and Marls

Barnett Woodford Caney/FayettevilleTypical

• A solution for each. Plus details of stress, open fractures, structure, and overburden

Barnett Woodford Caney/FayettevilleTypical

Kerogen

Gas-filled porosity

Shale by Shale: Characteristics and seismic solutions

Siltstones: Fayetteville and Barnett– Little carbonate– Azimuthal stress anisotropyAzimuthal stress anisotropy– Add structure: Woodford– Add structure and open fractures: Marcellus

Sweetspot identification: Prestack inversion or multicomponent analysis for Sweetspot identification: Prestack inversion or multicomponent analysis for Poisson’s ratio, Vp/Vs, and Mu-Rho

Drilling: Avoid faults through better fault imaging. Optimize horizontal azimuth through prediction of maximum stress azimuth through curvature or azimuthal through prediction of maximum stress azimuth through curvature or azimuthal anisitropy analysis. Optimize well path through use of structure and stratigraphy.

Completions: Vertical stress prediction. Poisson’s ratio, Young’s modulus, and Mu-Rho cubes.Rho cubes.

Woodford: Depth imaging necessary if using azimuthal anisotropy. Marcellus: FractureMAP (and other patented techniques) for identifying open

fractures (and their direction)fractures (and their direction).


Not a gas shale: The Bakken Formation– Mixed clastic/carbonate middle member– Better production where thin– Pore pressure important– Fractures important (open?)– Lithology and rock quality important

Resolution is king Middle Bakken is below conventional seismic resolution even with high cut Resolution is king. Middle Bakken is below conventional seismic resolution, even with high cut frequencies of 75 Hertz.

Sweetspots: – Rock quality: Prestack inversion or multicomponent analysis for the prediction of porosity and Rock quality: Prestack inversion or multicomponent analysis for the prediction of porosity and

lithology– Fracturing: Infer from thickness and curvature. Measure with seismic azimuthal velocity

analysis, AVO Az and Ampl Az, but need depth imaging to do so. – Pore Pressure: Integrated seismic velocity analysis with well logs information– Pore Pressure: Integrated seismic velocity analysis with well logs information

Drilling: Avoid faults through better fault imaging. Optimize horizontal azimuth through prediction of maximum stress anisotropy through curvature or azimuthal anisitropy analysis; also predict good and bad geobodies. Optimize well path through use of structure.

Completions: Pore pressure and vertical stress prediction. Poisson’s ratio, Young’s modulus, Mu-Rho, and pore pressure cubes.


Marls: Haynesville and Eagle Ford Formations– Carbonate rich (Haynesville regional)

Little / no azimuthal stress anisotropy– Little / no azimuthal stress anisotropy– Small faults known to be an annoyance in the Haynesville

Sweetspot identification: Much more complicated that siltstones. p pOptimize carbonate/clastic ratio. Pre-stack inversion or multicomponent analysis for Vcarbonate, Vshale, and porosity. Pore pressure may be important.pressure may be important.

Drilling: – Avoid faults through better fault imaging.

O ti i ll th th h f i i f t t– Optimize well path through use of seismic for structure. Completions: Pore pressure and vertical stress prediction. Poisson’s

ratio, Young’s modulus, Mu-Rho, and pore pressure cubes.ratio, Young s modulus, Mu Rho, and pore pressure cubes. Haynesville: Detailed attention to structure and fault delineation

Technical Content

Sweetspot identification Drilling Optimization Drilling Optimization Completions Support Predicting Success Cost / Benefit Cost / Benefit Conclusions Review

Sweetspot Identification: Porosity and superior fracture stimulations

Porosity– Lithology alone in silty shales (Marcellus Fayetteville etc )Lithology alone in silty shales (Marcellus, Fayetteville, etc.)

• More siliceous zones and areas are– More porous– More permeable– More brittle

More complicated in marls– More complicated in marls• Rock physics driven by lithology, which has little to do with

porosity Both are important for successporosity. Both are important for success.

Superior Fracture Stimulations (later)

Core: Scratch test scale to log scaleThe laminated texture of TGS reservoirs

lt i i ti f t i l

g

results in variations of material properties that differ primarily along the vertical direction (across beds).

The resulting material propertiesThe resulting material properties (petrophysical and mechanical) are best characterized using anisotropic medium models (e.g., transverse isotropic or

th t i )orthotropic).

The implication of anisotropy is that material properties are different in the vertical direction (perpendicular tovertical direction (perpendicular to bedding) and horizontal direction (parallel to bedding), and that these vary strongly with orientation to beddingbedding.

Log-scale heterogeneity (colors) obtained via n-dimensional l t l i f lcluster analysis of logs.

Reservoir Facies: Micrographs to Logsese o ac es c og ap s to ogs

Clay Rich (Non-reservoir):Mixed siliceous/argillaceous Clay Rich (Non reservoir):Mixed siliceous/argillaceous(Reservoir)

Calcite Rich (Non reservoir): Silica Rich (Reservoir)Silica Rich (Reservoir)

Conventional Seismic DataMigrated Conventional Seismic

Target

+ -

Sweetspot IdentificationPoisson’s Ratio from Prestack Inversion

p

Target

Low High

Conventional seismic versus rock physics inversionAcoustic ImpedanceAcoustic Impedance Poisson’s RatioPoisson’s Ratio

Low HighLow HighLow HighLow Highgg


Porosity– Lithology alone in silty shales (Marcellus Fayetteville etc )Lithology alone in silty shales (Marcellus, Fayetteville, etc.)

• More siliceous zones and areas are– More porous– More permeable– More brittle

More complicated in marls– More complicated in marls• Rock physics driven by lithology, which has little to do with

porosity Really would like to have bothporosity. Really would like to have both.

Superior Fracture Stimulations (later)

Sweetspot Identification: Porosity in marls

Rock physics driven by lithology, which has little to do with porosityp y– Success driven by both lithology and porosity– Petrophysical approach

• Measurement: Compare multiple measurements to discern lithology, porosity and kerogen

• Neural network: Compare simpler and more limited well log • Neural network: Compare simpler and more limited well log measurements to core

– SeismicSeismic• Multiple measurements (multicomponent or AVO) to derive

Vcarbonate, Vshale, and porosityN l– No example


Porosity Superior Fracture Stimulations Superior Fracture Stimulations

– Brittleness and StressB ittl d it k h i• Brittleness and its rock physics– Completions: Young’s modulus and Poisson’s ratio– Seismic: Poisson’s ratio in siltstones. Mu-Rho in marls. Through pre-g p

stack inversion or multicomponent analysis.• Stress

Vertical Vertical trans erse anisotrop ( ertical ers s hori ontal) – Vertical: Vertical transverse anisotropy (vertical versus horizontal). Through anisotropic migration or anisotropic velocity analysis

– Azimuthal: Varies with azimuth


Superior Fracture Stimulations– Brittleness and Stress

• Brittleness and its rock physics– Completions: Young’s

modulus and Poisson’s modulus and Poisson s ratio

– Seismic: Poisson’s ratio i ilt t M Rh i in siltstones. Mu-Rho in marls. Through pre-stack inversion.

from von Lunen 2009



– Brittleness and StressSt• Stress– Vertical: Vertical transverse anisotropy

(vertical versus horizontal). Through VTI ( ) ganisotropic migration (eta for time migration; delta and epsilon for depth migration)

– Azimuthal: Varies with azimuth. Through Azimuthal: Varies with azimuth. Through curvature analysis, azimuthal anisotropy analysis, Amplitude Azim, AVO Azim, and/or 3D Mechanical Earth Modeling3D Mechanical Earth Modeling.

VTI Anisotropic Migration for a Better Structural Image and a Measurement of Stressand a Measurement of Stress

Isotropic Migration VTI Anisotropic Migration y T

ime

y Tim

e

Two W

ay

Two W

ay

Offset / Angle Offset / AngleOffset / Angle Offset / AnglePSTM Seismic Gathers



– Brittleness and StressSt• Stress– Vertical:– Azimuthal: Varies with azimuth. Through g

curvature analysis, azimuthal anisotropy analysis, Amplitude Azim, AVO Azim, and/or 3D Mechanical Earth Modeling. Not an issue 3D Mechanical Earth Modeling. Not an issue in Haynesville or Eagle Ford (?).


Curvature– Simplest azimuthal stress methodSimplest azimuthal stress method

• A good idea to tie to stress measurements in wells– See Rich and Ammerman: Changes in frac

azimuth within one well agree with changes in curvature (a Barnett example)curvature (a Barnett example)

Azimuthal anisotropy (next slide)P i i th t l h– Pre-imaging the most popular approach• Adequate for low dip and absence of

overburden velocity effectsoverburden velocity effects

Measuring Fractures with Seismicg

1000 -

y Seismic

100 -

Fre

quen

cy Seismic

10 -

. Fra

ctur

e

1 -

Cum

.

Core ImageLog

No Seismic Image

from Mattner (2002)

10 mm1 mm 0.1 m 1 m 10 m 100 m

Fractal Parameterfrom Mattner (2002)

Anisotropy—Cookie Perspective (map view)py p ( p )Source

Source Slowness Source

Receiver

Slowness or travel

time ellipseReceiver ellipse

Source

Receiver

Receiver

Anisotropy—Cookie Perspective (map view)Source

Source

py p ( p )

Source Slowness or travel

time Receiver time ellipse

Source

Receiver

Receiver

Anisotropy—Cookie Perspective (map view)Source

Source

py p ( p )

Source

Receiver

Slowness or travel

time Receiverellipse

Source

Receiver

Receiver

Post-imaging azimuthal anisotropy analysisPost imaging azimuthal anisotropy analysis

S li i 4 diff

azimuth groups in degrees4Survey split into 4 different

azimuth groups

PSTM each azimuth group with the same velocity

EXAMPLE:

1. 15 - 60

2. 60 - 105

3. 105 - 150

4. 150 - 195

1

43

2

1

2

34

Residual velocities picked post migration for each azimuth

group using a spatially continuous method

Attribute cubes produced by analyzing changes in velocity

with azimuth

Fracture Analysis from Velocities

Residual velocities applied and trim statics calculated to align horizons between azimuths

The same 3 attribute cubes are produced from the velocity and amplitude analysis:

1. Ellipticity (B)

2. Fracture Density or Percent Anisotropy

3 Fracture Orientation (phi0)

Far angle stacks produced – 18 to 36 degrees

3. Fracture Orientation (phi0)

The ellipticity and fracture orientation are defined by the following equation

f(phi) = A + B cos(2(phi – phi0)) Where A is the average value

phi0Attribute cubes produced by

analyzing changes in amplitude with azimuth

of the attribute

Fracture Density or Percent Anisotropy is the Ellipticity normalized by the following equation:

Percent Anisotropy = 2B/(A+B) * 100

Fracture Analysis from Amplitudes

Deliverables: Segy’s for each of 1,2, and 3 above for both velocity and amplitude analysis (6 total)

Azimuthal Anisotropy: Amount and Direction(Amount shown)

Map view at targetMap view at targetDisplays azimuthal variations in

anisotropyanisotropy low indicates little

fracturing and small ac u g a d s adifferential stress

high indicates higher g gfracture storage of gas, and large differential stress

Low High

Results from Ant Tracking complements analysis

Low High


Additional Azimuthal: – Take azimuthal anisotropic cube and Take azimuthal anisotropic cube and

evaluate Amplitude Azim and AVO Azim (patented).(pate ted)• Can detect multiple fracture sets having

different azimuths and whether open or closed

– 3D Mechanical Earth Modeling• Full integration of all seismic and well log

measurements, including the evaluation and simulation of the effects of blowdownand simulation of the effects of blowdown

Technical Content


Drilling optimizationg p

Staying in zone– Drill in a brittle zone or drill in

the hot Gamma Ray?• Seismic has the solution

either wayeither way– Prestack inversion or

multicomponent analysis for Poisson’s ratio (siltstones) or Poisson s ratio (siltstones) or Mu-Rho (for marlstones)

Azimuth optimization– Curvature or azimuthal velocity

analysisanalysis

Technical Content


Completions support and optimizationp pp p

Brittleness Containment Containment Stress

Hazard Avoidance Hazard Avoidance


Brittleness– Poisson’s ratio in

Poisson’s Ratio from Prestack InversionPoisson s ratio in siltstones

– Mu-Rho in marlsMu Rho in marls Containment

St ti h– Stratigraphy– Ductile – brittle – ductile– On same vertical scale

as an induced fracture



Hazard Avoidance Hazard Avoidance


Stress– Vertical velocity Vertical velocity

anisotropy helps predict fracture growthactu e g o t

– Curvature and azimuthal velocity anisotropy help y py ppredict fracture geometry / direction, which can vary widely within a single lateral



Hazard Avoidance Hazard Avoidance– Enhanced fault delineation

Fault Delineation

Shale

Shale

Shale

Fault Image Enhancement Workflowg

Fault AttributeFi l C bEd E h tEd E h t Final CubeEdge EnhancementEdge Enhancement

Seismic FaultsFaults

Fault System Analysis

Enhanced Fault Image DisplayEnhanced Fault Image Display


TargetTarget

Integration—The Bigger Picture

Acoustic Impedance

g gg• Fractogram – azimuthal stress prediction• Seismic Inversion - rock properties for sweetspot identification Acoustic Impedance

Poisson’s Ratio

Seismic Inversion rock properties for sweetspot identification• Ant Tracking - subtle fault identification• Sonic Scanner - calibration

Fractogram

Sonic Scanner Fast Shear Azimuth

Technical Content


Prediction of success (patented)Colin Sayers, Schlumberger Geomechanics

Post-drill calibration– EUR as a function of

• induced fracture area within reservoirG i l

ndex

• Gas in place• Permeability . . .

P d ill di tiEU

R In Pre-drill prediction

– EUR as a function of • Estimated stress

f (HP, MSV, Curvature)

• Estimated stress• Brittleness• PorosityPorosity• Gas in place . . .

Technical Content


Cost / Benefit Analysisy

Cost of seismic (assumes 50 square mile survey)– Acquistion and processing : $200 000 per square mile Acquistion and processing : $200,000 per square mile – Seismic interpretation and analysis $10,000 per square mileTi Li Time Line– Permitting, acquisition and processing: 5 - 21 months– Ant Tracking, and inversion to rock properties: 2 months– 3D Mechanical Earth Modeling: 6 months– Average Marcellus or Haynesville: 8 – 9 months

– Typical lease term: 3 years

Cost / Benefit Analysisy

Cost of seismic– Acquistion and processing : g

$200,000 per square mile – Seismic interpretation and

analysis $10 000 per square analysis $10,000 per square mile

Benefits Benefits– Potential reduction in

completions > $10,000,000 p , ,per square mile• Assumes perfing only half the

available lateral available lateral – Needn’t drill all locations

Technical Content


Conclusions

Effective seismic gas shale workflow Prestack inversion or multicomponent analysis for the Prestack inversion or multicomponent analysis for the

delivery of Vcarbonate, Vshale, porosity, Poisson’s ratio, and/or Young’s modulus

Fault image enhancement for the identification of subtle faults that are overlooked on conventional seismic

For siltstones, curvature analysis, azimuthal velocity analysis, and/or 3D Mechanical Earth Modeling for the y , gprediction of stress, its azimuthal variation, and open fracturing

Review: Shale by Shale: Characteristics and seismic solutions

Siltstones: Fayetteville and Barnett– Little carbonate– Azimuthal stress anisotropyAzimuthal stress anisotropy– Add structure: Woodford– Add structure and open fractures: Marcellus

Sweetspot identification: Prestack inversion or multicomponent analysis for Sweetspot identification: Prestack inversion or multicomponent analysis for Poisson’s ratio, Vp/Vs, and Lambda-Mu

Drilling: Avoid faults through better fault imaging. Optimize horizontal azimuth through prediction of maximum stress azimuth through curvature or azimuthal through prediction of maximum stress azimuth through curvature or azimuthal anisitropy analysis. Optimize well path through use of structure and stratigraphy.

Completions: Vertical stress prediction. Poisson’s ratio, Young’s modulus, and Mu-Rho cubes.Rho cubes.

Woodford: Depth imaging necessary if using azimuthal anisotropy. Marcellus: FractureMAP (and other patented techniques) for identifying open

fractures (and their direction)fractures (and their direction).


Not a gas shale: The Bakken Formation– Mixed clastic/carbonate middle member– Better production where thin– Pore pressure important– Fractures important (open?)– Lithology and rock quality important

Resolution is king Middle Bakken is below conventional seismic resolution even with high cut Resolution is king. Middle Bakken is below conventional seismic resolution, even with high cut frequencies of 75 Hertz.

Sweetspots: – Rock quality: Prestack inversion or multicomponent analysis for the prediction of porosity and Rock quality: Prestack inversion or multicomponent analysis for the prediction of porosity and

lithology– Fracturing: Infer from thickness and curvature. Measure with seismic azimuthal velocity

analysis, AVO Az and Ampl Az, but need depth imaging to do so. – Pore Pressure: Integrated seismic velocity analysis with well logs information– Pore Pressure: Integrated seismic velocity analysis with well logs information

Drilling: Avoid faults through better fault imaging. Optimize horizontal azimuth through prediction of maximum stress anisotropy through curvature or azimuthal anisitropy analysis; also predict good and bad geobodies. Optimize well path through use of structure.

Completions: Pore pressure and vertical stress prediction. Poisson’s ratio, Young’s modulus, Mu-Rho, and pore pressure cubes.


Marls: Haynesville and Eagle Ford Formations– Carbonate rich (Haynesville regional)

Little / no azimuthal stress anisotropy– Little / no azimuthal stress anisotropy– Small faults known to be an annoyance in the Haynesville

Sweetspot identification: Much more complicated than siltstones. p pOptimize carbonate/clastic ratio. Pre-stack inversion or multicomponent analysis for Vcarbonate, Vshale, and porosity. Pore pressure may be important.pressure may be important.

Drilling: – Avoid faults through better fault imaging.

O ti i ll th th h f i i f t t– Optimize well path through use of seismic for structure. Completions: Pore pressure and vertical stress prediction. Poisson’s

ratio, Young’s modulus, and Mu-Rho cubes.ratio, Young s modulus, and Mu Rho cubes. Haynesville: Detailed attention to structure and fault delineation

3d seismic profiles for shale plays - · pdf file3d seismic profiles of u s shale 3d ......

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