Pinnacle/Halliburton Hydraulic Fracture Diagnostics and Reservoir

Pinnacle/HalliburtonHydraulic Fracture Diagnostics and Hydraulic Fracture Diagnostics and

Reservoir Diagnostics

Eric Davis

May 2009

Agenda•About the Purchase •Pinnacle Overview•Fracture Diagnostics

– Why Map?y p– Microseismic & Tilt Mapping– Examples

•Reservoir Diagnostics•Background Materials

Why are we here today?Halliburton has acquired Pinnacle assets, including Fracture assets, including Fracture Diagnostics and Reservoir Monitoring Services.Monitoring Services.

Software, consulting services and

Applied Geomechanics remain with

Carbo Ceramics.

3

How will Pinnacle be managed?• Retain Pinnacle brand, culture and

business model

• Retain existing management team

Si ifi t i t t i N th A i • Significant investment in North America and international business growth

• Invest in current and future human capital

• Accelerate development of synergetic technologies and workflows in collaboration with other product services lines within Pinnacle and Halliburton

4



•Reservoir Diagnostics•Halliburton – Pinnacle Synergies Additional •Background Materials

Pinnacle Technologies• Founded in 1992• >160 employees today• Offices in Houston San Francisco Bakersfield Offices in Houston, San Francisco, Bakersfield,

Denver, Midland, OKC, Calgary, Beijing• Provided services to all major producers and service

companiescompanies• Over 200 technical papers published• 2 R & D 100 awards• 2 Meritorious Engineering awards• 2 Meritorious Engineering awards• Over 11,000 stages mapped

Pinnacle – Leader in Mapping TechnologiesD l tDevelopment

19921995

SoftwareHardwareSurface tilt analysis

Surface tilt series 50001995199619971998

Surface tilt series 5000R&D 100 award

R i

DH Tilt 1st GenHarts Eng Award

DH tilt analysis

199819992000 TW Tilt (3rd Gen)

Harts Eng Award

FracproPT

Reservoir Monitoring analysis

DH Tilt 2nd Gen

200120022004

Harts Eng Award

Microseismic

Microseismic

G S200520062007

GPSInSAR

Hybrid toolsDTS

Surface tilt Denali

WellTracker

InSAR/GPS

2008 Surface tilt Denali

Pinnacle – Leader in Mapping ExperiencePinnacle Leader in Mapping Experience12000

WellTracker>11,000

10000

ed to

Dat

e TWT/TWMTWMMSMTWT

6000

8000

of J

obs

Map

pe DHTSTM

4000

otal

Num

ber

o

0

2000

Pi l B* C* D* E* F* G*

To

* Estimates

Pinnacle B* C* D* E* F* G*Company

Revenue by Product Line$ in Millions 25 50% gro th$ in Millions

3.450

55

SoftwareEngineeringG T h/T l S l

25-50% growth

8.6

1.93.7

35

40

45 GeoTech/Tool SalesReservoir MonitoringFrac Mapping

40.8

3.4

2.9

1.6

2.4

25

30

35

23.8

31.8

1 9

2.8

2.6

0.1

0.4

0.6

1.9

3.1

1.2

1.4

10

15

20

8.914.2

18.81.90.1

0

5

10

2003 2004 2005 2006 2007

Top 15 Customers

• EOGCh T

• DevonQ i k il• ChevronTexaco

• Talisman• Quicksilver• Rimrock

• EnCana• Chesapeake

• Samson• Aera

• Antero• Shell

• Plains• ConocoPhillipsShell

• PetroCanadaConocoPhillips




We Know Everything About Our Fracs Except . . .

Out-of-zonegrowth

Poor fluiddiversion

TwistingT-shapedUpward fractureth

Perfectly confined frac

gfractures

pfracturesgrowth

Horizontalfractures

Multiple fracturesdipping from verticalpp g

How Can Fracture Mapping Provide Value? • Determine Azimuth

– Optimize well location to maximize recoveryOptimize well location to maximize recovery– Optimize horizontal well azimuth for best fracture geometry

• Determine Fracture Heightg– Optimize perforating strategy– Reduce out of zone growth, potentially increase half-length

• Determine Fracture Half-Length– Optimize well location to maximize recovery

O ti i F St l– Optimize Frac Stage volume• Determine Fracture Coverage in Horizontal wells

Optimize Completion Design Stage size spacing etc – Optimize Completion Design, Stage size, spacing etc.

R i M it iSurface Tilt Mapping• Measure Azimuth and Approximate

Fluid Distribution in Horizontal Laterals

Reservoir Monitoring

Microseismic Mapping

Laterals

Distributed Temperature Sensing• Deployed On Casing or Tubing

• Deployed On Fiber-optic Wireline in Treatment or Offset Well

• Measure Frac Height, Length And Azimuth In Real-time

• Measure Frac Height/Distribution and Production Response

Azimuth In Real time• Calibrate Frac Models

D h l Tilt M iDownhole Tilt Mapping• Deployed Single-Conductor

Wireline in Treatment or Offset WellWell

• Measure Frac Height, Length• Calibrate Frac Models

Fracture Diagnostic TechnologiesABILITY TO ESTIMATEWill Determine ABILITY TO ESTIMATEWill Determine ABILITY TO ESTIMATEWill Determine

GROUP DIAGNOSTIC

ABILITY TO ESTIMATEWill Determine

May Determine

Can Not Determine

MAIN LIMITATIONSGROUP DIAGNOSTIC


May Determine

Can Not Determine

MAIN LIMITATIONSGROUP DIAGNOSTIC


May Determine

Can Not Determine

MAIN LIMITATIONS

Net Pressure Analysis

Well Testing

Production Analysis

GROUP DIAGNOSTIC MAIN LIMITATIONS

Modeling assumptions from reservoir description

Need accurate permeability and pressure



Well Testing

Production Analysis






Well Testing

Production Analysis





Radioactive Tracers

Temperature Logging

HIT

Production Analysis

Depth of investigation 1'-2'

Thermal conductivity of rock layers skews results

Sensitive to i.d. changes in tubulars


Radioactive Tracers

Temperature Logging

HIT

Production Analysis





Radioactive Tracers

Temperature Logging

HIT

Production Analysis





Production Logging

Borehole Image Logging

Downhole Video

g

Only determines which zones contribute to production

Run only in open hole– information at wellbore only

Mostly cased hole– info about which perfs contribute

Production Logging


Downhole Video

g




Production Logging


Downhole Video

g




Surface Tilt Mapping

DH Offset Tilt Mapping

Caliper Logging Open hole, results depend on borehole quality

Resolution decreases with depth

Resolution decreases with offset well distance












Treatment Well Tiltmeters

May not work in all formations

Frac length must be calculated from height and width















Main Project ObjectiveDetermine Far Field Frac Azimuth Using Microseismic MappingDetermine Far-Field Frac Azimuth Using Microseismic Mapping

GM 11-36

9/2/20051.27

251,471GM 541-35

GM 431-35

Key Wells with

GM 22-35

DRILLING_ORDER : 3COMPLETION GROUP : 1

GM 311-36

9/23/20051.46

261,983

GM 341-35

DRILLING_ORDER : 5COMPLETION_GROUP : 1

GM 331-35


GM 342-35

10/31/2006

GM 312-35

GM 12-35GM 411-36

GM 511-36

yBorehole Image Logs

35COMPLETION_GROUP : 1

GM 42-35

8/21/2000

DOE 1-M-35

12/6/19932.06

1,626,797

DOE 2-M-35

5/2/19951.42

GM 312-3GM 332-35


10/31/2006DRILLING_ORDER : 1

COMPLETION_GROUP : 1

GM 422-35

GM 432-35

DRILLING_ORDER : 4COMPLETION GROUP : 1

GM 511 36

MSM Observation Well

35GM 33 35

8/21/20000.86

482,2531,005,697

GM 343-35


GM 322-35

GM 423-35 GM 433-35


_

GM 443 35

GM 442-35


GM 23-35

GM 239-36

GM 33-35

4/20/20021.03

441,298

GM 43-35

5/1/2002 GV 19 36

GM 333-35


GM 323-35

GM 443-35


GM 543-35

DRILLING_ORDER : 12COMPLETION_GROUP : 3 GM 413-36

GM 613-35

8/17/20061.05

5/1/20021.22

520,199GV 19-36

11/11/19891.79

1,254,461

TW 8

8/10/121,6

226 35GM 34-35

M 414-35

2/22/20051.32

219,862

GM 643-35

GM 424-35

9/8/20061.05

GM 513-36

FEET

0 460

PETRA 11/17/2006 1:18:10 PM

Surface Tilt Map View – All StagesSurface Tilt Map View – All Stages13297000

13296000

13297000Wellheads

Wellbores

Perforation Locations

Fracture Azimuth, Stage 1


Note: Frac lengths and dips are not drawn to scale in this view.

13295000



SJU 27-5 #906

13294000

orth

ing

(fee

t)

SJU 27-5 #912SJU 27-5 #910

13293000

No

SJU 27-5 #911

SJU 27-5 #909

SJU 27-5 #908

13292000

13291000939000 940000 941000 942000 943000 944000

Easting (feet)

Where Should I Drill My Next Well?• Azimuth Changes Around Basin 800• Azimuth Changes Around Basin

– Microseismic Monitoring Of 3 Stages In Each Of 2 Well Pairs

200300400500600700 RU-2

Waterfracs

g

12001300140015001600

-300-200-100

0100200

Sout

h-N

orth

(ft)

RU-3Observation

RU-1Gel fracs

400500600700800900

10001100

th (f

t)

GV-2Gel fracs

-900-800-700-600-500-400

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

well

-300-200-100

0100200300400

Sout

h-N

ort

GV-3

-120

0

-110

0

-100

0

-900

-800

-700

-600

-500

-400

-300

-200

-100 0

100

200

300

400

500

600

West-East (ft)

Grand Valley

-1000-900-800-700-600-500-400

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

GV 3Observation well

GV-1Waterfracs River

Colorado

Grand Valley Field

Parachute Field Rulison

Field

-160

0-1

500

-140

0-1

300

-120

0-1

100

-100

0-9

00-8

00-7

00-6

00-5

00-4

00-3

00-2

00-1

00 010

020

030

040

050

060

070

080

090

010

00

West-East (ft)PARACHUTE

0 2Scale - Miles

Mesaverde Gas WellsWasatch Gas Wells

SPE 95637 (Williams)







Did the Frac Stay in Zone ?5300

142 22 GR

• Why can’t I pump into zone 2

5400

5500

5600

142-22 GR

Stage 6

• Why does zone 3 not produce well

5600

5700

5800

Stage 5

5900

6000

6100

Dep

th (f

t)

Stage 4

6200

6300

6400Stage 2

Stage 3

6400

6500

6600

g

Stage 1

6700

-700

-600

-500

-400

-300

-200

-100 0

100

200

300

400

500

600

700

Distance Along Fracture (ft)

Viewing angle varies by stage to show maximum.







Model Calibration for J Sand in the DJ Basin, CO(SPE 96080)(SPE 96080)

Uncalibrated

Model Calibration the J Sand in the DJ Basin, CO(SPE 96080)(SPE 96080)

UncalibratedLong confined fracture based on fracture based on microseismic mapping

Calibrated







Horizontal Drilling

• Larger Area of Contact with Wellbore

• Minimize Fracture Height GrowthGrowth

• Less Environmental Impact (fewer surface sites)

Issues for Horizontal Well Fracturing g• Optimizing wellbore trajectory & reservoir drainage

requires knowledge of fracture geometryW llb T j t hi h l t l it di l?• Wellbore Trajectory – high, low, transverse, longitudinal?

• Interval Coverage (fracture height & payzone)Wellbore Coverage (along the lateral)• Wellbore Coverage (along the lateral)

• Diversion & Staging– OH OH packers CH perf balls plug & perf etc– OH, OH packers, CH, perf balls, plug & perf, etc.

• Fracture Execution & Complexity– Perforating, wellbore clean-out, initiation, to cement or not

Minimize Complexity, Good Communication to the Formation & Optimum Interval/Lateral

Coverage

Microseismic in Horizontal WellsB tt Sh l L it di l• Barnett Shale Longitudinal

– Gel Frac Versus High Rate Waterfrac (Refrac)

– Increased stimulated volume2500

3000Perforations

2500

3000

2500

3000

1000

1500

2000

orth

(ft)

Observation Well 1

1500

2000

ft)

Observation Well 11500

2000

rth

(ft)

Observation Well 10

500

1000

Sout

h-N

o500

1000

Nor

thin

g (f

Perforations500

1000

Sout

h-N

or

-1000

-500

0

Observation Well 2

-500

0

Observation Well 2-500

0Observation Well 2

-1000-1000 -500 0 500 1000 1500 2000 2500

West-East (ft)

SPE 95568 (Devon)-1000

-1000 -500 0 500 1000 1500 2000 2500

Easting (ft)

-1000-1000 -500 0 500 1000 1500 2000 2500

West-East (ft)

SPE 95568 (Devon)

Agenda•About the Purchase•Pinnacle Overview•Fracture Diagnostics



Pi l R i M it iPinnacle Reservoir Monitoring

Main Focus Areas• Any Heavy Oil Steam EOR Field • Any Long Term Waste Injection Project• Any Long Term Waste Injection Project• Carbon Capture and Sequestration (CCS) Projects• Any well where pressure / temperature monitoring is • Any well where pressure / temperature monitoring is

desired

• Future: Monitoring of large offshore projects

How Can Reservoir Monitoring Provide Value? • Risk avoidance in steam EOR fields• Steam program optimization• Steam program optimization• Cost effective long term monitoring for waste injections• Cost savings through virtual production or injection logs • Cost savings through virtual production or injection logs

from fiber optic solutions.• Identification of fluid movement over time

– Is that a sealing fault?– Where are my drill cuttings going?– Is my CO2 staying in zone?

Surface DeformationTilt, GPS, InSAR

Surface MicroseismicSpecial (Rare) Applications

Downhole (Deformation) TiltDownhole MicroseismicOffset and Active Well (Injector or Producer)Offset and Active Well (Injector or Producer)

VSP AcquisitionNear Wellbore MonitoringFib O ti T t d PCrosswell Seismic AcquisitionFiber Optic Temperature and Pressure

Reservoir Monitoring TechnologiesReservoir Monitoring Technologies

Direct Fracture Diagnostic TechniquesPrinciple of Tilt Fracture Mapping

Hydraulic fracture Fracture-induced

surface troughyinduces a characteristic

deformation pattern

Induced tilt reflects the geometry and

i t ti f t d orientation of created hydraulic fracture

Fracture Downhole tiltmetersIn offset well

gas bubble

pick-up electrodes

glass caseexcitation electrodeconductive liquid

Surface Tilt Tool SensitivityTiltmeter Data from a Quiet Site

200

250Full Moon on 6/20/97

New Moon on 7/4/97

150

radi

ans)

100

Tilt

(Nan

or

50

006/14/97 06/19/97 06/24/97 06/29/97 07/04/97 07/09/97 07/14/97

Datepick-up electrodes

X Y NanoRadian Resolution

glass case

gas bubble

excitation electrodeconductive liquid

NanoRadian Resolution

Surface Tilt Tool SensitivityEarthquake Response

San Salvador13-Jan 10:33 (CST)7.6 Magnitude

India25-Jan 21:16 (CST)7.8 Magnitude

Tilt MappingOff

Surface Mapping Downhole Mapping

Offset Well MappingFracture DimensionsWell SpacingModel Calibration

Fracture OrientationHorizontal WellsWell PlacementLong-term reservoir monitoring

Active (Injection) Well MappingFracture HeightModel CalibrationCritical Wells

Tilt Examples

Surface Tiltmeter/GPS Mapping Mapped Cement Squeeze

Event depth and error bounds computed

Cement squeeze performed at 345’. Suspect upward Suspect upward channel

Tilt Examples

Microseismic Mapping Obtaining Data From an Offset Observation Well

• Fiber optic wireline and 7 conductor6 20 L l 3 C t S• 6-20 Levels, 3 Component Sensors

• Mechanically Coupled• Can be deployed under pressure

SAGD Steam Flood ExampleTiltmeter/Strain-Microseismic

Presentation Room 217D Monday @ 11:05

High Precision Differential GPS3-D displacement

Sensitivity:3-D displacement

Sensitivity:Sensitivity:1-½ mm vertical displacement

½ mm lateral displacement

Sensitivity:1-½ mm vertical displacement

½ mm lateral displacement

Pinnacle TechnologiesInSAR Technology

Interferometric Synthetic Aperture Radar

“spaceborne radar”

Interferometric Synthetic Aperture Radar

“spaceborne radar”spaceborne radarSensitivity: Can be sub-centimeter

displacement under right conditions

spaceborne radarSensitivity: Can be sub-centimeter

displacement under right conditions

InSAR Applications

Steam Induced Oil field heave San Joaquin heave. San Joaquin Valley, CA. 2005.

InSalah Algeria

Pinnacle

Monitoring Program• 4 year InSAR historical study• 2 year acquisition of RSAT2 Ultra Fine SAR data • 2 year acquisition of RSAT2 Ultra Fine SAR data • Surface Tiltmeter Array over KB-501 injector• Field wide DGPS array• Field wide DGPS array• Reservoir level volumetric & strain studies

In SalahIn SalahSurfaceSurface

DeformationDeformationTime SeriesTime Series

from from 2004/7/312004/7/31

toto/ // /2008/5/312008/5/31

● ● ● ● ● ● ● ● ● ● ● ● ●

2004

/7/3

120

04/7

/31

2004

/10/

920

04/1

0/9

2004

/12/

1820

04/1

2/18

2005

/2/2

620

05/2

/26

2005

/6/1

120

05/6

/11

2005

/9/2

420

05/9

/24

2006

/2/1

120

06/2

/11

2006

/7/1

2006

/7/1

2006

/12/

2320

06/1

2/23

2007

/3/3

2007

/3/3

2007

/12/

820

07/1

2/8

2008

/2/1

620

08/2

/16

2008

/3/2

220

08/3

/22

2008

/5/3

120

08/5

/31

SWP Carbon SequestrationSWP Carbon SequestrationSan Juan Basin, New Mexico

Pinnacle

Site LocationSite Location

Pump CanyonCO2 Sequestration

San Juan Basin, NM

Sec 32 / T31N, R8WSec 32 / T31N, R8W

Field Installation

Site LocationSite Location

GPS Reference

GPS Remote

Pump CanyonCO2 Sequestration

Injection Well

Production Wells

Tiltmeter Sites (36)

Injection/Production from section 32 & surroundingInjection/Production from section 32 & surrounding

Producers in section 32section 32

ProducersProducers immediately surrounding section 32section 32

Pre-CO2 Injection: < 7/30/2008Pre-CO2 Injection: < 7/30/2008

~ 2 month settling time for-20

-15

-10

X Tilt

-15

-10

Y Tilt

Pinnacle Technologies InjectorStage 1 SJ04.ptx

Serial #:7725

settling time for many tiltmeter instruments.

S ttli l t-40

-35

-30

-25

mic

rora

dian

s

-35

-30

-25

-20

mic

rora

dian

s

Settling lasts until June,

20084/190:00

4/260:00

5/30:00

5/100:00

5/170:00

5/240:00

5/310:00

6/70:00

6/140:00

6/210:00

6/280:00

7/50:00

7/120:00

7/190:00

7/260:00

-55

-50

-45

-45

-40

35

Extracted Tilt Signals: X: -40.310 microradians Y: -28.395 microradians(GMT-07:00) Arizona

X Tilt Y Tilt


S i l # 7755

resulted in …

40455055606570

X Tilt

s 5055

60

65

7075

Y Tilt

s

Serial #:7755

510152025303540

mic

rora

dian

s

20

2530

35

40

45

mic

rora

dian

s

4/200:00

4/270:00

5/40:00

5/110:00

5/180:00

5/250:00

6/10:00

6/80:00

6/150:00

6/220:00

6/290:00

7/60:00

7/130:00

7/200:00

7/270:00

-10-50

5

10

15

Extracted Tilt Signals: X: 76.655 microradians Y: 66.718 microradians(GMT-07:00) Arizona

Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08

0 6

0.8

1.0

1.2

X Tilt

0 6

0.8

1.0

1.2

Y Tilt


Serial #:7760

Detrended

Long-term change in tilt

response b d ft0 4

-0.2

0.0

0.2

0.4

0.6

mic

rora

dian

s

0 4

-0.2

0.0

0.2

0.4

0.6

mic

rora

dian

s

observed after injection initiation

6/200:00

6/270:00

7/40:00

7/110:00

7/180:00

7/250:00

8/10:00

8/80:00

8/150:00

8/220:00

8/290:00

9/50:00

-0.8

-0.6

-0.4

-0.8

-0.6

-0.4

Extracted Tilt Signals: X: 3.184 microradians Y: 3.467 microradians(GMT-07:00) Arizona

This change is observed at

several tiltmeter sites

0.2

0.4

0.6

X Tilt

0.8

1.0

1.2

1.4

Y Tilt


Serial #:7857

Detrended

tiltmeter sites

-0.4

-0.2

0.0

mic

rora

dian

s

-0.2

0.0

0.2

0.4

0.6

mic

rora

dian

s

6/200:00

6/270:00

7/40:00

7/110:00

7/180:00

7/250:00

8/10:00

8/80:00

8/150:00

8/220:00

8/290:00

9/50:00

-0.8

-0.6

-0.8

-0.6

-0.4

Extracted Tilt Signals: X: -2.272 microradians Y: 3.514 microradians(GMT-07:00) Arizona

Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08Reservoir Strain Computation

Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08Reservoir Strain Computation

• Small volumetric changes calculated

• Theoretical / actual tilt correlation is poor

Reservoir strain from surface tilt

Surface deformation from reservoir strain

Pre-CO2 Injection: < 7/30/2008Pre-CO2 Injection: < 7/30/2008

C l l

Additionally …

Color cycle

(blue to red)

represents 2.3

Preliminary InSAR observations hint that

pcm (1.0 inch) of

slant-range change.

observations hint that there is negligible

deformation prior to CO2 injection period

No characteristic “bull-eye”

September 21, 2007 –

patterns observed within this imagery. We will continue to

August 4, 2008will continue to look at this to

better constrain any background

signal

Pinnacle TechnologiesSurface Deformation Monitoring Technologies

Synthetic Aperture Global Positioning System TiltmetersRadar Interferometry (InSAR) (GPS) Tiltmeters

C h h h b fl d Di l f d f i i Di l f d f i (TilDescription

Compares the phase change between reflected radar pulses recorded at two different times from space borne satellites

Directly measures surface deformation using a network of surface receivers and a constellation of satellites

Directly measures surface deformation (Tiltor gradient of displacement) using an array of tools

Sensitivity Sub-centimeter displacement 1.5 mm (0.06 inches) of vertical displacement 0.005 mm (0.0002 inches) of vertical displacement

Measures extremely small

KeyStrengths

Broad spatial coverage No ground instrumentation required Monthly monitoring capabilities

Operates continuously Operable in most weather conditions 3-D displacement monitoring Absolute elevation measurements

Measures extremely small movements

Operates continuously Uses very little power Measurements not influenced by

weather

Fiber Optic PressureFiber Optic Pressure

Fiber Optic Gauge and Carrier

Gauge Carrierg

Pinnacle SILO Enclosure• Similar to our proven Surface Tilt Sites (over 15 years of

experience)• Installed 5 - 20 ft below the earth’s surface with single 10”-

diameter PVC pipe10” PVCPipe

Sealed Pipe

• Drilled with Rat-hole drilling unit, same as conductor pipe or dead-man anchors

• Eliminates need for doghouse and climate control equipment and associated power

Ground Level

p• Stable Temperatures – ideal for electronics and batteries

(constant ~60°F)• Eventually will house most of our reservoir monitoring

equipment 5-15 ftq p– FOP and DTS– RM Computers– GPS – MSM - Future

5-15 ft

FOP

DTS

FOP

FOP DTS

Pinnacle SILO Instrumentation

Davidson Fiber Optic Pressure Surface SensorTran DTS Surface Interrogator Davidson Fiber Optic Pressure Surface Interrogator

SensorTran DTS Surface Interrogator, Proprietary to Pinnacle

What Can You Do With DTS and Pressure Data

Viewer DTS Data– Identify “large” temperature anomalies– Identify water or gas breakthrough– Behind pipe channels– Identify top of cement washouts and voids– Identify top of cement, washouts and voids– Isolation failure (flappers)– Tubular or packer failures

Pressure Data– Initial Reservoir Pressure (Bottom zone)– Overall bottomhole pressure history (flowing and SI)– PTA

Virtual Production Log– Production/injection splits by zone– Analyze “small” temperature variationsAnalyze small temperature variations– Identify water or gas breakthrough– Behind pipe channels– Adding a single pressure point adds significantly to the analysis

Activities MonitoredC ti (d d f i i t )– Cementing (depends of rig requirements)

– Stimulations/Chemical Injection/Profile Modification– Flowbacks– Long-term production and injection

Typical Deployment Casing

Surface Casing

Production

• Need Oriented Perforating

Tubing

Cross-coupling Protectors, every other joint

Casing • Can map cmtg, frac, flowbacks

• StimWatchFiber Optic Cable

• StimWatch• Ongoing

productionproduction• Single Press

TD: 6,5

Bottom Hole Gauge Carrier

Typical Deployment Tubing• No Perforating Issue

Surface Casing

g• Lower Cost, daylight

operations• Requires annular BOP

Cross-coupling Protectors, every other joint Production

C i

Requires annular BOP• Can not map cmtg,

frac, flowbacks• Ongoing production

Tubing

Casing • Ongoing production• Single Pressure

Fiber Optic Cable

Tubing Tail 2-3/8”, 4.6 ppf, K-55 EUE tubing extended 75-100’ below the bottom perforation

Bottom Hole

TD: 6,

Bottom Hole Gauge Carrier

Pinnacle ReportingDTS Viewer of DataDTS Viewer of Data

Advanced Processing Virtual Production Log

Questions?

THANK YOUTHANK YOU

Agenda• About the Buyout• Who is Pinnacle• Who is Pinnacle• Halliburton – Pinnacle Synergies • Fracture Diagnostics

– Microseismic Mapping– Tilt Mapping

• Why Map?• Additional Background Materials

Microseismic MappingMicroseismic Mapping• Deployed On Fiber-optic Wireline• Mechanically Clamped To

Wellbore• Measure Frac Height, Length And

Azimuth In Real-time• Calibrate Frac Models

Microseisms• What Is It?• What Is It?

– A Microseism Is Literally A Micro-Earthquake. Microseisms That Occur During Hydraulic Fracturing Are Caused By:g y g y

• Changes In Stress And Pressure As A Result Of The Treatment• By Movement Along Induced Fracture Planes Where Hindered By

IrregularitiesIrregularities

Shear AddedT F bl

Leakoff:Increased Pore

FractureIrregularities

May Stick & Slip AsF t P t

Crack Tip

To FavorablyOriented Natural

Fractures

Increased PorePressure Reduces

Net Stress On NaturalFractures (Less Friction)

Fracture Propagates

Crack TipPfrac

NATURAL FRACTURES

Receiver Arrays – OYO Geospace System• DS 250• DS 150• Fiber Optic Wireline

– Fast Telemetry• Large Number Of Receivers

DS 250

• Large Number Of Receivers– 32 Maximum Per Well

• High Sampling Rates4 000 S l P S d

Vertical UpV– 4,000 Samples Per Second V

Clamp ArmIn Back

H2 H1

Tri-Axial Sensors (Geophones)Tri-Axial Sensors (Geophones)DS 150

Microseismic Wireline Deployment & Set-up

Obser ation WellObservation Well

Treatment Well~ 3000 ft

Crane

Wireline Unit with 12-Level 3C Tool String

What Information Is Needed For Processing?• Formation Velocity

– Advanced Sonic Log (P & S Waves)Distance

– Advanced Sonic Log (P & S Waves)– Perforation Timing

• Receiver Orientation

Elevation

Receiver Orientation– Perforations Or String Shots

• Known Locations

Direction

• Surveys– Surface Survey (Well-to-well) Accuracy

• Pinnacle Checks With GPS– Deviation Surveys

• Monitor & Frac Wells

Accuracy

• Monitor & Frac Wells

Perforation Timing Measurementsg• Perforations Or String Shots Are Required to

Determine Orientation of Every Tool in ToolstringDetermine Orientation of Every Tool in Toolstring– Use For Velocity Measurements

• Requires A Precise Measurement Of Exactly When It Fired (Not When Voltage Was Increased)

• Pinnacle Has A Patent-Pending Procedure ForPinnacle Has A Patent-Pending Procedure For Measuring The Timing Pulse On The Firing Line

• Velocity Can Be Determined– Firing Time– Arrival Times– Distances (Requires Survey Data)Distances (Requires Survey Data)

Sample Rate & Errors• Monte Carlo Analysis Of Errors

S l d F A T i l Di t ib ti35

40

Depth– Sampled From A Triangular Distribution

• Arrivals +/- 2 Sample Points– 50 Realizations For Each Case– Layered Cases For Realistic Behavior

• Error Increases Almost Linearly With Slower Sampling 20

25

30

dard

Dev

iatio

n (ft

) Distance

Pinnacley p g

Rate– Effect On Depth Is Usually Greater Than Effect On

Distance– Observe The Difference In The Distribution Of The 50

Realizations For the Two Cases Below 5

10

15

One

Sta

nd

– Depth Errors• 1/4 msec = 4 ft• 1 msec = 18 ft

00 0.5 1 1.5 2 2.5

Sample Rate (msec)

1/4 msec Sampling 1 msec Sampling

Distribution Distribution

Receiver Locations Receiver Locations

Distribution Of Events For 50 Realizations

Distribution Of Events For 50 Realizations


100

120

Depth

Sample Rate & Errors• The Previous Case Where The Array Is

St ddli A Z I Th B t C

60

80

dard

Dev

iatio

n (ft

) DistanceStraddling A Zone Is The Best Case• Consider A Case Where The Array Is Above The

Zone And The Event Is Near The Bottom– Errors Can Be Much Greater & Can Cause

Interpretation Problems

Pinnacle2-msec Results

20

40

One

Sta

ndInterpretation Problems• Notice The “Bend” In The Locations, Particularly

For 1 msec Sampling– Depth Errors

• 1/4 msec = 10 ft

Results

00 0.5 1 1.5 2 2.5

Sample Rate (msec)

• 1 msec = 45 ft– Note The Complex Distribution For 2 msec

Sampling In The Inset

1/4 msec Sampling 1 msec Sampling


Distribution Of Events

Distribution Of Events


Comparison Of Accuracy7000

Dep

• Pinnacle– Depth: 8 ft

7500

pth

7000

Pinnacle: 12 Receivers @ ¼ msec– Distance: 5 ft

7000

7500

Depth

Actual Data

7000

Dep

• Comp. B– Depth: 57 ft

Distance: 24 ft

East-2000 -1500 -1000 -500 0 500 1000 1500 2000

7500

pth

8 Receivers @ 1 msec– Distance: 24 ft

East

10

e (V

/g)Comparison Of Sensors Used

In Microseismic Monitoring

0 1

1

tion

Res

pons

eg• OYO OMNI 2400 & SLB GAC

– Most Systems Use OMNI 2400 15 Hz Geophones

0.01

0.1

1 10 100 1000 10000

Acc

eler

a GACDual OMNI2400Single OMNI2400

Geophones– SLB Uses The GAC Sensor

• Using Published Response Curves For Each Sensor

1000

)

GACDual OMNI2400

1 10 100 1000 10000Frequency (Hz)• The Response To Velocity Is Shown In

The Lower Curve– The OMNI 2400 Geophone Response Is

Flat Above About 20 Hz (Out To ~1200 100

Res

pons

e (V

/m/s Single OMNI2400Flat Above About 20 Hz (Out To 1200

Hz)• Response To Acceleration Shown At Top

– The GAC Response Is Flat From ~5 –200 Hz

1

10Ve

loci

ty R200 Hz

• Other Important Points:– Microseismic Events Usually Have Most

Energy In The 200 – 700 Hz Range 11 10 100 1000 10000

Frequency (Hz)

– Best To Have A Flat Response Over The Range Of Interest

QC Report- Confidence Level

QC ReportEvent Magnitude vs Distance from Observation Well

• Series Of Faults2

-1.5

-1

de

Well 1Well 2; Stage AWell 2; Stage BWell 3; Stage AWell 3; Stage B

Courtesy Of BP

g

– Identified Easily From Magnitudes

– Abnormal -3

-2.5

-2

Rel

ativ

e M

agni

tu

Faults

Abnormal Propagation• Azimuth

V ti ll

-4

-3.5

0 100 200 300 400 500 600 700 800

Distance (m)

Normal Events

• VerticallyNW-SE

Azimuths

EAST 1

EAST 3

EAST 2NW-SE

Azimuths

EAST 1

EAST 3

EAST 2NW-SE

Azimuths

EAST 1

EAST 3

EAST 2 300 mJonah Field, WY

3150

3200Faults

EAST 3

EAST 6

EAST 3

EAST 6

EAST 3

EAST 63250

3300

3350

Dep

th (m

)

EAST 5 EAST 4EAST 5 EAST 4EAST 5 EAST 4

Courtesy Of BP

3400

3450-40 -20 0 20 40 60 80

Lateral Distance From Well (m)SPE 102528

QC Report - Event Uncertainty• Larger azimuthal uncertainty farther from observation well results in wider “fan” of events results in wider “fan” of events toward eastern wings of fractures• Relatively narrow band of • Relatively narrow band of events indicates absence of complex (network) growth

Pinnacle’s Microseismic Mapping Advantage• Experience

– More Than 3,800 Hydraulic Fractures Mapped Since 2001– More Than 90% Of All Microseismic Jobs Mapped Worldwide

• Dedicated People and Equipment• Superior Equipment:

– Highest Array Density With Up To 32 Tools In One Array– Highest Telemetry Rate At ¼ Ms With Fiber Optic Wireline

• Record & Analyze Much Higher Frequencies Than Other Tool Systems

B tt D t Q lit A d Hi h t P i i E t L ti D T • Better Data Quality And Highest Precision Event Location Due To: – Number Of Tools & Sample Rate

P f Ti i– Perf Timing– Stacking

Surface Tilt MappingSurface Tilt Mapping

Principle of Tilt Fracture Mapping Direct Fracture Diagnostic TechniqueDirect Fracture Diagnostic TechniqueHydraulic fracture

i d h t i ti

Frac Orientation from Surface Tilts

induces a characteristic deformation pattern

Induced tilt reflects the geometry and

orientation of created hydraulic fracture

Pick-up electrodes

Treatment Well Offset Well

Pick up electrodes

current electrode

Surface Tiltmeter Site• Installed 5 - 40 ft below the earth’s surface in

4”-diameter PVC pipeSolar Panel8”

OuterPipe

• Deeper boreholes to eliminate “noise” from surface

– Cultural noise4”– Thermal induced earth surface motion

• Surface array with 16 or more tiltmeters placed in concentric circles around the point 5 40 ftTilt t

4” InnerPipe

placed in concentric circles around the point of injection (distance from well: 15%-75% of injection depth)

• Tiltmeter data stored in datalogger contained

5-40 ftTiltmeter

Cement

Tiltmeter data stored in datalogger contained in tiltmeter

• Data collected periodically either manually or by radio

Sand

by radio

Surface Tiltmapping

Surface Tiltmeter Fracture MappingE l Of S f Tilt t • Example Of Surface Tiltmeter Response– Multi-Mode Fracturing

• Vertical Fractures And/Or

Vertical-Trough & Uplifts• Vertical Fractures And/Or

Opening Of Cleats• Horizontal Fractures

– Surface Deformation From I di id l C t Add

Uplifts

Individual Components Add Together

• Superposition

Combined-Trough On Trough On Top Of Uplift

Horizontal – Simple Uplift

P Di i i L U t d L t lPoor Diversion in a Long Uncemented Lateral

Surface Deformation ImageSurface Deformation Image

906

T t t W ll Tilt M iTreatment Well Tilt Mapping• Deployed on single

conductor e-lineM ti d t li• Magnetic decentralizers

• Slim 1-11/16” tool diameter• Measure frac height in real-

timetime• Calibrate frac models

Treatment Well Tiltmeters• Measure Fracture Height In Vicinity Of • Measure Fracture Height In Vicinity Of

Wellbore• Observe Changes In Heightg g

– Correlate With Pressure• Height -> Primary Result

– Complex Deformation Around Wellbore9850

9900

9850

9900

9900

9950

h (ft

)

9900

9950

h (ft

)

10000

10050

Dep

th 10000

10050

Dep

th

10100

101500 1000 2000 3000 4000

Downhole tilt (Microradians)

10100

101500 1000 2000 3000 4000

Downhole tilt (Microradians)

SPE Microseismic Mapping Papers – Last 2 Years• PT 2007 108103 Stacking Seismograms to Improve Microseismic Images • SLB 2007 106159 Real-Time Microseismic Monitoring of Hydraulic Fracture Treatment: A Tool To Improve Completion

and Reservoir Management• SLB 2006 104570 Using Induced Microseismicity to Monitor Hydraulic Fracture Treatment: A Tool to Improve Completion

Techniques and Reservoir Management• PT 2006 102801 Imaging Seismic Deformation Induced by Hydraulic Fracture Complexity• PT 2006 102690 Improving Hydraulic Fracturing Diagnostics By Joint Inversion of Downhole Microseismic and

Tiltmeter Data• PT 2006 102528 Hydraulic Fracture Diagnostics Used To Optimize Development in the Jonah Field• SLB 2006 102493 Using Microseismic Monitoring and Advanced Stimulation Technology to Understand Fracture

Geometry and Eliminate Screenout Problems in the Bossier Sand of East Texasy• PT 2006 102372 Understanding Hydraulic Fracture Growth In Tight Oil Reservoirs By Integrating Microseismic Mapping

and Fracture Modeling • PT 2006 102103 Integration of Microseismic Fracture Mapping Results with Numerical Fracture Network Production

Modeling in the Barnett Shale• PT 2006 98219 Application of Microseismic Mapping and Modeling Analysis to Understand Hydraulic Fracture Growth pp pp g g y y

Behavior• PT 2005 97994 Application of Microseismic Imaging Technology in Appalachian Basin Upper Devonian Stimulations• XOM 2005 95909 Logging Tool Enables Fracture Characterization for Enhanced Field Recovery• PT 2005 95568 Comparison of Single and Dual-Array Microseismic Mapping Techniques in the Barnett Shale• SLB 2005 95513 Automated Microseismic Event Detection and Location by Continuous Spatial MappingSLB 2005 95513 Automated Microseismic Event Detection and Location by Continuous Spatial Mapping• PT 2005 95508 Integration of Microseismic Fracture-Mapping Fracture & Production Analysis with Well-Interference

Data to Optimize Fracture Treatments in the Overton Field, East Texas• PT 2005 95337 Effect of Well Placement on Production and Frac Design in a Mature Tight Gas Field• SLB 2005 94048 Hydraulic Fracture Monitoring as a Tool to Improve Reservoir Management• PT 2005 84488 Improved Microseismic Fracture Mapping Using Perforation Timing Measurements for Velocity • PT 2005 84488 Improved Microseismic Fracture Mapping Using Perforation Timing Measurements for Velocity

Calibration• PT 2005 77441 Integrating Fracture-Mapping Technologies to Improve Stimulations in the Barnett Shale

Documents

Pinnacle/Halliburton Hydraulic Fracture Diagnostics and Reservoir