Pinnacle/Halliburton Hydraulic Fracture Diagnostics and Reservoir

Transcription

Pinnacle/Halliburton
Hydraulic Fracture Diagnostics and
Reservoir Diagnostics
Eric Davis
May 2009
Agenda
•About the Purchase
•Pinnacle Overview
•Fracture Diagnostics
– Whyy Map?
p
– Microseismic & Tilt Mapping
– Examples
•Reservoir Diagnostics
•Background Materials
Why are we here today?
Halliburton has acquired Pinnacle
assets, including Fracture
Diagnostics and Reservoir
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
Significant
ifi t iinvestment
t
t iin N
North
th America
A
i
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
Agenda
– Whyy Map?
p
– Examples
•Halliburton – Pinnacle Synergies Additional
Pinnacle Technologies
• Founded in 1992
• >160 employees today
• Offices in Houston,
Houston San Francisco,
Francisco Bakersfield,
Bakersfield
Denver, Midland, OKC, Calgary, Beijing
• Provided services to all major producers and service
companies
• Over 200 technical papers published
• 2 R & D 100 awards
• 2 Meritorious Engineering awards
• Over 11,000 stages mapped
Pinnacle – Leader in Mapping Technologies
D l
Development
t
Hardware
1992
1995
1996
1997
1998
1999
2000
2001
2002
2004
2005
2006
2007
2008
Software
Surface tilt analysis
Surface tilt series 5000
R&D 100 award
DH Tilt 1st Gen
Harts Eng Award
DH Tilt 2nd Gen
TW Tilt (3rd Gen)
DH tilt analysis
Reservoir
R
i
Monitoring
analysis
FracproPT
Harts Eng Award
Microseismic
Microseismic
GPS
G
S
InSAR
InSAR/GPS
Hybrid tools
DTS
WellTracker
Surface tilt Denali
Pinnacle – Leader in Mapping Experience
12000
To
otal Number o
of Jobs Mappe
ed to Date
>11,000
WellTracker
TWT/TWM
TWM
10000
MSM
TWT
8000
DHT
STM
6000
4000
2000
0
Pi
Pinnacle
l
* Estimates
B*
C*
D*
Company
E*
F*
G*
Revenue by Product Line
25 50% growth
25-50%
gro th
$ in Millions
55
50
45
40
Software
Engineering
G T h/T l Sales
GeoTech/Tool
S l
Reservoir Monitoring
Frac Mapping
3.4
3.7
1.9
8.6
35
2.4
30
25
1.4
3.1
0.4
2.8
20
15
10
1.2
1.9
0.1
19
1.9
1.6
3.4
0.6
2.6
2.9
0.8
4
31.8
23.8
18.8
14.2
5
8.9
0
2003
2004
2005
2006
2007
Top 15 Customers
•
•
•
•
•
•
•
•
EOG
Ch
ChevronTexaco
T
Talisman
EnCana
Chesapeake
Antero
Shell
PetroCanada
•
•
•
•
•
•
•
Devon
Q i k il
Quicksilver
Rimrock
Samson
Aera
Plains
ConocoPhillips
Agenda
– Whyy Map?
p
– Examples
We Know Everything About Our Fracs Except . . .
Poor fluid
diversion
Upward fracture
growth
th
Out-of-zone
growth
T-shaped
p
fractures
Twisting
g
fractures
Perfectly confined frac
Horizontal
fractures
Multiple fractures
dipping
pp g from vertical
How Can Fracture Mapping Provide Value?
• Determine Azimuth
– Optimize well location to maximize recovery
– Optimize horizontal well azimuth for best fracture geometry
• Determine Fracture Height
g
– Optimize perforating strategy
– Reduce out of zone growth, potentially increase half-length
• Determine Fracture Half-Length
– Optimize
O ti i F
Frac St
Stage volume
l
• Determine Fracture Coverage in Horizontal wells
– Optimize Completion Design,
Design Stage size
size, spacing etc
etc.
R
Reservoir
i Monitoring
M it i
Surface Tilt Mapping
• Measure Azimuth and Approximate
Fluid Distribution in Horizontal
Laterals
Distributed Temperature Sensing
Microseismic Mapping
• Deployed On Fiber-optic Wireline
in Treatment or Offset Well
• Measure Frac Height, Length And
Azimuth In Real
Real-time
time
• Calibrate Frac Models
• Deployed On Casing or Tubing
• Measure Frac Height/Distribution
and Production Response
D
Downhole
h l Tilt Mapping
M
i
• Deployed Single-Conductor
Wireline in Treatment or Offset
Well
• Measure Frac Height, Length
Fracture Diagnostic Technologies
Will Determine
May Determine
Can Not Determine
GROUP DIAGNOSTIC
MAIN LIMITATIONS
Net Pressure Analysis
Modeling assumptions from reservoir description
Well Testing
Need accurate permeability and pressure
Production Analysis
Need accurate permeability and pressure
Radioactive Tracers
Depth of investigation 1'-2'
Temperature Logging
Thermal conductivity of rock layers skews results
HIT
Sensitive to i.d. changes
g in tubulars
Production Logging
Only determines which zones contribute to production
Borehole Image Logging
Run only in open hole– information at wellbore only
Downhole Video
Mostly cased hole– info about which perfs contribute
Caliper Logging
Open hole, results depend on borehole quality
Resolution decreases with depth
DH Offset Tilt Mapping
Resolution decreases with offset well distance
May not work in all formations
Treatment Well Tiltmeters
Frac length must be calculated from height and width
ABILITY TO ESTIMATE
g
– Optimize
O ti i F
Frac St
Stage volume
l
Design Stage size
size, spacing etc
etc.
Main Project Objective
Determine Far-Field
Far Field Frac Azimuth Using Microseismic Mapping
GM 11-36
GM 431-35
Keyy Wells with
Borehole Image Logs
9/2/2005
1.27
251,471
GM 541-35
GM 12-35
GM 411-36
GM 331-35
GM 341-35
DRILLING_ORDER : 2
COMPLETION_GROUP : 1
GM 312-35
DRILLING_ORDER : 5
GM 311-36
9/23/2005
1.46
261,983
GM 22-35
GM 342-35
DRILLING_ORDER : 3
COMPLETION_GROUP
COMPLETION
GROUP : 1
MSM Observation Well
GM 332-35
GM 422-35
35
GM 432-35
DOE 2-M-35
DRILLING_ORDER : 4
5/2/1995
1.42
1,005,697
GM 322-35
GM 423-35
GM 511
511-36
36
10/31/2006
DRILLING_ORDER : 1
DOE 1-M-35
GM 42-35
12/6/1993
2.06
1,626,797
8/21/2000
0.86
482,253
GM 442-35
DRILLING_ORDER : 6
GM 433-35
GM 343-35
DRILLING_ORDER : 10
DRILLING_ORDER : 7
GM 33-35
33 35
GM 443-35
443 35
4/20/2002
1.03
441,298
DRILLING_ORDER : 9
GM 323-35
GM 312-3
DRILLING_ORDER : 8
GM 239-36
GM 543-35
GM 333-35
DRILLING_ORDER : 12
DRILLING_ORDER : 11
GM 413-36
GM 43-35
GM 613-35
GM 23-35
5/1/2002
1.22
520,199
8/17/2006
1.05
GV 19-36
19 36
TW 8
GM 643-35
11/11/1989
1.79
8/10/1
1,254,461
21,6
M 414-35
GM 424-35
2/22/2005
1.32
219,862
226
35
PETRA 11/17/2006 1:18:10 PM
0 GM
9/8/2006
1.05
GM 34-35
513-36
FEET
460
Surface Tilt Map View – All Stages
13297000
Wellheads
Note: Frac lengths and dips are not
drawn to scale in this view.
Wellbores
Perforation Locations
Fracture Azimuth, Stage 1
13296000
No
orthing (feet)
13295000
SJU 27-5 #906
13294000
SJU 27-5 #910
SJU 27-5 #912
13293000
SJU 27-5 #908
SJU 27-5 #911
13292000
SJU 27-5 #909
13291000
939000
940000
941000
942000
Easting (feet)
943000
944000
Where Should I Drill My Next Well?
• Azimuth Changes Around Basin
800
700
– Microseismic Monitoring Of 3
Stages
g In Each Of 2 Well Pairs
500
400
South-North (ft)
300
200
100
RU-1
Gel fracs
0
-100
-200
RU-3
Observation
well
-300
-400
-500
GV-2
Gel fracs
South-Nortth (ft)
-600
-700
-800
600
0
500
0
400
0
300
0
200
0
0
100
0
-100
0
-200
0
-300
0
-400
0
-500
0
-600
0
-700
0
-800
0
-900
0
-1000
0
-1200
0
-900
-1100
0
1600
1500
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
-100
-200
-300
-400
-500
-600
-700
-800
-900
-1000
RU-2
Waterfracs
600
West-East (ft)
GV 3
GV-3
Observation
well
GV-1
Waterfracs
Grand Valley
Field
Parachute
Field
-1600
0
-1500
0
-1400
0
-1300
0
-1200
0
-1100
0
-1000
0
-900
0
-800
0
-700
0
-600
0
-500
0
-400
0
-300
0
-200
0
-100
0
0
100
0
200
0
300
0
400
0
500
0
600
0
700
0
800
0
900
0
1000
0
Colorado
River
Rulison
Field
PARACHUTE
West-East (ft)
SPE 95637 (Williams)
2
Mesaverde Gas Wells 0
Wasatch Gas Wells Scale - Miles
g
– Optimize
O ti i F
Frac St
Stage volume
l
Design Stage size
size, spacing etc
etc.
Did the Frac Stay in Zone ?
5300
142 22
142-22
GR
5400
5500
Stage 6
• Why can’t I pump into
zone 2
Stage 5
• Why does zone 3 not
produce well
5600
5700
5900
Stage 4
6000
6100
6200
Stage 3
6300
Stage
g 2
6400
6500
Stage 1
6600
Distance Along Fracture (ft)
700
600
500
400
300
200
100
0
-100
-200
-300
-500
-600
-400
Viewing angle varies by stage to show maximum.
6700
-700
Depth (ft)
5800
g
– Optimize
O ti i F
Frac St
Stage volume
l
Design Stage size
size, spacing etc
etc.
Model Calibration for J Sand in the DJ Basin, CO
(SPE 96080)
Uncalibrated
Model Calibration the J Sand in the DJ Basin, CO
(SPE 96080)
Uncalibrated
Long confined
fracture based on
microseismic
mapping
Calibrated
g
– Optimize
O ti i F
Frac St
Stage volume
l
Design Stage size
size, spacing etc
etc.
Horizontal Drilling
• Larger Area of Contact with
Wellbore
• Minimize Fracture Height
Growth
• Less Environmental Impact
(fewer surface sites)
Issues for Horizontal Well Fracturing
g
• Optimizing wellbore trajectory & reservoir drainage
requires knowledge of fracture geometry
• Wellbore
W llb Trajectory
T j t
– high,
hi h low,
l
transverse,
t
longitudinal?
l
it di l?
• Interval Coverage (fracture height & payzone)
• Wellbore Coverage (along the lateral)
• Diversion & Staging
– OH,
OH OH packers,
packers CH
CH, perf balls
balls, plug & perf
perf, etc
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 Wells
• Barnett
B
tt Shale
Sh l Longitudinal
L
it di l
3000
– Gel Frac Versus High Rate Waterfrac
(Refrac)
– Increased stimulated volume
Perforations
2500
2000
Observation Well 1
3000
South-No
orth (ft)
2500
Northing (f
ft) (ft)
South-Nor
rth
2000
1500
1500
1000
500
Observation
Well
Observation
Well
1 1
0
1000
Observation Well 2
-500
500
Perforations
-1000
-1000
0
-1000
-1000
0
500
1000
West-East (ft)
Observation Well 2
Observation Well 2
-500
-500
SPE 95568 (Devon)
-500
0
500
1000
Easting (ft)(ft)
West-East
1500
2000
2500
1500
2000
2500
Agenda
– Whyy Map?
p
– Examples
Pi
Pinnacle
l Reservoir
R
i M
Monitoring
it i
Main Focus Areas
•
•
•
•
Any Heavy Oil Steam EOR Field
Any Long Term Waste Injection Project
Carbon Capture and Sequestration (CCS) Projects
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
Cost effective long term monitoring for waste injections
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 Deformation
Surface Microseismic
Tilt, GPS, InSAR
Special (Rare) Applications
Downhole Microseismic
Downhole (Deformation) Tilt
Offset
and Active Well (Injector or Producer)
Offset and Active Well (Injector
or Producer)
Near Wellbore Monitoring
VSP Acquisition
Fib Optic
Fiber
OAcquisition
ti Temperature
T
t
and
dP
Pressure
Crosswell Seismic
Reservoir Monitoring Technologies
Direct Fracture Diagnostic Techniques
Principle of Tilt Fracture Mapping
Hydraulic
y
fracture
induces a characteristic
deformation pattern
Fracture-induced
surface trough
Induced tilt reflects
the geometry and
orientation
i t ti off created
t d
hydraulic fracture
pick-up electrodes
Fracture
gas bubble
conductive liquid
excitation electrode
glass case
Downhole tiltmeters
In offset well
Surface Tilt Tool Sensitivity
Tiltmeter Data from a Quiet Site
250
Full Moon on 6/20/97
New Moon on 7/4/97
Tilt (Nanorradians)
200
150
100
50
0
06/14/97
06/19/97
06/24/97
X
gas bubble
excitation electrode
07/04/97
07/09/97
Date
pick-up electrodes
conductive liquid
06/29/97
glass case
Y
NanoRadian Resolution
07/14/97
Surface Tilt Tool Sensitivity
Earthquake Response
San Salvador
13-Jan 10:33 (CST)
7.6 Magnitude
India
25-Jan 21:16 (CST)
7.8 Magnitude
Surface Mapping
Tilt Mapping
Off Well Mapping
Offset
Fracture Dimensions
Well Spacing
Model Calibration
Fracture Orientation
Horizontal Wells
Well Placement
Long-term reservoir monitoring
Active (Injection) Well Mapping
Fracture Height
Model Calibration
Critical Wells
Downhole Mapping
Tilt Examples
Surface Tiltmeter/GPS Mapping
Mapped Cement Squeeze
Event depth and error bounds computed
Cement squeeze
performed at 345’.
Suspect upward
channel
Tilt Examples
Obtaining Data From an Offset Observation Well
• Fiber optic wireline and 7
conductor
• 6-20
6 20 Levels,
L l 3C
Componentt Sensors
S
• Mechanically Coupled
• Can be deployed under pressure
SAGD Steam Flood Example
Tiltmeter/Strain-Microseismic
Presentation Room 217D Monday @ 11:05
High Precision Differential GPS
3-D displacement
Sensitivity:
1-½ mm vertical displacement
½ mm lateral displacement
InSAR Technology
Interferometric Synthetic Aperture
Radar
“spaceborne
spaceborne radar
radar”
Sensitivity: Can be sub-centimeter
displacement under right conditions
InSAR Applications
Steam Induced Oil field
heave San Joaquin
heave.
Valley, CA. 2005.
InSalah Algeria
Pinnacle
Monitoring Program
•
•
•
•
•
4 year InSAR historical study
2 year acquisition of RSAT2 Ultra Fine SAR data
Surface Tiltmeter Array over KB-501 injector
Field wide DGPS array
Reservoir level volumetric & strain studies
●
●
●
●
●
● ●
2007/12/8
2008/2/16
2008/3/22
2008/5/31
●
2006/12/23
2007/3/3
●
2006/7/1
●
2006/2/11
●
2005/9/24
●
2005/6/11
2004/7/31
2004/10/9
2004/12/18
2005/2/26
In Salah
Surface
Deformation
Time Series
from
2004/7/31
to
2008/5/31
/ /
●
SWP Carbon Sequestration
San Juan Basin, New Mexico
Pinnacle
Site Location
Pump Canyon
CO2 Sequestration
San Juan Basin, NM
Sec 32 / T31N, R8W
Field Installation
Site Location
GPS Reference
Pump Canyon
CO2 Sequestration
GPS Remote
Injection Well
Production Wells
Tiltmeter Sites
(36)
Injection/Production from section 32 & surrounding
Producers in
section 32
Producers
immediately
surrounding
section 32
Pre-CO2 Injection: < 7/30/2008
Pinnacle Technologies Injector
Stage 1 SJ04.ptx
Serial #:7725
X Tilt
Y Tilt
-10
-10
-15
~ 2 month
settling time for
many tiltmeter
instruments.
-15
-20
-20
-30
-25
-35
-30
microradians
microradians
-25
-40
-35
35
Settling
S
ttli llasts
t
until June,
2008
-45
-40
-50
-45
4/26
0:00
5/3
0:00
5/10
0:00
microradianss
Extracted Tilt Signals:
X Tilt
70
65
60
55
50
45
40
35
30
25
20
15
10
5
0
-5
-10
4/20
0:00
5/17
0:00
5/24
0:00
5/31
6/7
6/14
6/21
6/28
7/5
0:00
0:00
0:00
0:00
0:00
0:00
(GMT-07:00)
Arizona Injector
Pinnacle
Technologies
Stage 1 Y:SJ27.ptx
X: -40.310 microradians
-28.395 microradians
S i l #:7755
Serial
# 7755
7/12
0:00
7/19
0:00
7/26
0:00
Y Tilt
resulted in …
75
70
65
60
55
50
45
40
35
30
25
20
15
10
5
4/27
0:00
5/4
0:00
5/11
0:00
5/18
0:00
5/25
0:00
6/1
6/8
6/15
6/22
0:00
0:00
0:00
0:00
(GMT-07:00) Arizona
X: 76.655 microradians
6/29
0:00
Y: 66.718 microradians
7/6
0:00
7/13
0:00
7/20
0:00
7/27
0:00
microradianss
-55
4/19
0:00
Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08
Stage 1 SJ15.ptx
Serial #:7760
Detrended
Y Tilt
1.2
1.2
1.0
1.0
0.8
0.8
06
0.6
06
0.6
0.4
0.4
0.2
0.2
0.0
0.0
-0.2
-0.2
-0.4
04
-0.4
04
-0.6
-0.6
-0.8
6/20
0:00
microradians
microradians
X Tilt
-0.8
6/27
0:00
7/4
0:00
7/11
0:00
7/18
0:00
7/25
8/1
8/8
0:00
0:00
0:00
(GMT-07:00) Arizona
X: 3.184 microradians
8/15
0:00
8/22
0:00
8/29
0:00
Stage 1 SJ16.ptx
Serial #:7857
X Tilt
9/5
0:00
Detrended
Y Tilt
0.6
1.4
1.2
0.4
1.0
microradians
0.6
0.0
0.4
0.2
-0.2
0.0
-0.4
-0.2
-0.4
-0.6
-0.6
-0.8
6/27
0:00
7/4
0:00
7/11
0:00
7/18
0:00
7/25
8/1
8/8
0:00
0:00
0:00
(GMT-07:00) Arizona
X: -2.272 microradians
8/15
0:00
8/22
0:00
8/29
0:00
9/5
0:00
microradians
0.8
0.2
-0.8
6/20
0:00
Long-term
change in tilt
response
observed
b
d after
ft
injection
initiation
This change is
observed at
several
tiltmeter sites
Period 2: CO2 Injection Ramp-up – 7/30/08 – 9/9/08
Reservoir 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: < 7/30/2008
C l cycle
Color
l
(blue to red)
represents
p
2.3
cm (1.0 inch) of
slant-range
change.
No characteristic
“bull-eye”
patterns
observed within
this imagery. We
will continue to
look at this to
better constrain
any background
signal
Additionally …
Preliminary InSAR
observations hint that
there is negligible
deformation prior to
CO2 injection period
September 21, 2007
–
August 4, 2008
Surface Deformation Monitoring Technologies
Synthetic Aperture
Radar Interferometry (InSAR)
Global Positioning System
(GPS)
Description
Compares the
C
h phase
h
change
h
bbetween reflected
fl
d
radar pulses recorded at two different
times from space borne satellites
Directly
Di
l measures surface
f
ddeformation
f
i using
i a
network of surface receivers and a
constellation of satellites
Directly
Di
l measures surface
f
ddeformation
f
i (Til
(Tilt
or 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
Key
Strengths



Broad spatial coverage
No ground instrumentation required
Monthly monitoring capabilities




Tiltmeters

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 Pressure
Fiber Optic Gauge and Carrier
Gauge
g Carrier
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 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 p
power
Stable Temperatures – ideal for electronics and batteries
(constant ~60°F)
Eventually will house most of our reservoir monitoring
equipment
q p
–
–
–
–
Sealed
Pipe
10” PVC
Pipe
Ground
Level
5-15 ft
FOP and DTS
RM Computers
GPS
MSM - Future
FOP
DTS
FOP
DTS
Pinnacle SILO Instrumentation
Davidson Fiber Optic Pressure Surface
Interrogator
SensorTran DTS Surface Interrogator,
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,
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”
small temperature variations
Identify water or gas breakthrough
Behind pipe channels
Adding a single pressure point adds significantly to the analysis
Activities Monitored
–
–
–
–
Cementing
C
ti (depends
(d
d off rig
i requirements)
i
t )
Stimulations/Chemical Injection/Profile Modification
Flowbacks
Long-term production and injection
Typical Deployment Casing
Surface Casing
Production
Casing
Cross-coupling Protectors,
every other joint
Tubing
Fiber Optic Cable
Bottom Hole
Gauge Carrier
TD: 6,5
• Need Oriented
Perforating
• Can map cmtg,
frac, flowbacks
• StimWatch
• Ongoing
production
• Single Press
Typical Deployment Tubing
•
•
Surface Casing
Cross-coupling Protectors,
every other joint
Production
C i
Casing
Tubing
Fiber Optic Cable
Tubing Tail 2-3/8”, 4.6 ppf, K-55
EUE tubing extended 75-100’
below the bottom perforation
Bottom Hole
Gauge Carrier
TD: 6,
•
•
•
•
No Perforating
g Issue
Lower Cost, daylight
operations
Requires annular BOP
Can not map cmtg,
frac, flowbacks
Ongoing production
Single Pressure
Pinnacle Reporting
DTS Viewer of Data
Advanced Processing
Virtual Production Log
Questions?
THANK YOU
Agenda
• About the Buyout
• Who is Pinnacle
• Halliburton – Pinnacle Synergies
• Fracture Diagnostics
– Microseismic Mapping
– Tilt Mapping
• Why Map?
• Additional Background Materials
• Deployed On Fiber-optic Wireline
• Mechanically Clamped To
Wellbore
• Measure Frac Height, Length And
Azimuth In Real-time
Microseisms
• What Is It?
– A Microseism Is Literally A Micro-Earthquake. Microseisms
That Occur During
g Hydraulic
y
Fracturing
g Are Caused By:
y
• Changes In Stress And Pressure As A Result Of The Treatment
• By Movement Along Induced Fracture Planes Where Hindered By
Irregularities
Leakoff:
Increased Pore
Pressure Reduces
Net Stress On Natural
Fractures (Less Friction)
Pfrac
Fracture
Irregularities
May Stick & Slip As
F t Propagates
Fracture
P
t
Shear Added
To Favorably
T
F
bl
Oriented Natural
Fractures
Crack Tip
NATURAL FRACTURES
Receiver Arrays – OYO Geospace System
• DS 250
• DS 150
• Fiber Optic Wireline
– Fast Telemetry
DS 250
• Large Number Of Receivers
– 32 Maximum Per Well
• High Sampling Rates
Vertical Up
V
– 4,000
4 000 S
Samples
l P
Per S
Second
d
Clamp Arm
In Back
H2
DS 150
Tri-Axial Sensors (Geophones)
H1
Microseismic Wireline Deployment & Set-up
Obser ation Well
Observation
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)
– Perforation Timing
• Receiver Orientation
– Perforations Or String Shots
Distance
Elevation
Direction
• Known Locations
• Surveys
– Surface Survey (Well-to-well)
• Pinnacle Checks With GPS
– Deviation Surveys
• Monitor & Frac Wells
Accuracy
Perforation Timing
g Measurements
• Perforations Or String Shots Are Required to
Determine 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 For
Measuring The Timing Pulse On The Firing Line
• Velocity Can Be Determined
– Firing Time
– Arrival Times
– Distances (Requires Survey Data)
Sample Rate & Errors
40
• Monte Carlo Analysis Of Errors
• Arrivals +/- 2 Sample Points
– 50 Realizations For Each Case
– Layered Cases For Realistic Behavior
• Error Increases Almost Linearlyy With Slower Sampling
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
– Depth Errors
• 1/4 msec = 4 ft
• 1 msec = 18 ft
1/4 msec Sampling
Distribution
Of Events
For 50
Realizations
Receiver Locations
One Stand
dard Deviation (ft)
– Sampled
S
l d FFrom A T
Triangular
i
l Di
Distribution
t ib ti
35
Depth
Distance
30
Pinnacle
25
20
15
10
5
0
0
0.5
1
1.5
2
Sample Rate (msec)
1 msec Sampling
Distribution
Of Events
For 50
Realizations
Receiver Locations
2.5
Sample Rate & Errors
– Errors Can Be Much Greater & Can Cause
Interpretation Problems
• Notice The “Bend” In The Locations, Particularly
For 1 msec Sampling
– Depth Errors
• 1/4 msec = 10 ft
• 1 msec = 45 ft
– Note The Complex Distribution For 2 msec
Sampling In The Inset
1/4 msec Sampling
Distribution
Of Events
Receiver Locations
100
One Stand
dard Deviation (ft)
• The Previous Case Where The Array Is
St ddli A ZZone IIs Th
Straddling
The Best
B tC
Case
• Consider A Case Where The Array Is Above The
Zone And The Event Is Near The Bottom
120
Depth
Distance
80
Pinnacle
2-msec
Results
60
40
20
0
0
0.5
1
1.5
2
Sample Rate (msec)
1 msec Sampling
Distribution
Of Events
Receiver Locations
2.5
Comparison Of Accuracy
• Pinnacle
Dep
pth
– Depth: 8 ft
– Distance: 5 ft
7000
Pinnacle: 12 Receivers @ ¼ msec
7500
7000
Depth
Actual Data
7500
• Comp. B
Dep
pth
– Depth: 57 ft
– Distance: 24 ft
7000
8 Receivers @ 1 msec
7500
-2000
-1500
-1000
-500
0
East
500
1000
1500
2000
– Microseismic Events Usually Have Most
Energy In The 200 – 700 Hz Range
– Best To Have A Flat Response Over The
Range Of Interest
Acceleration Response
e (V/g)
• OYO OMNI 2400 & SLB GAC
– Most Systems Use OMNI 2400 15 Hz
Geophones
– SLB Uses The GAC Sensor
• Using Published Response Curves For
Each Sensor
• The Response To Velocity Is Shown In
The Lower Curve
– The OMNI 2400 Geophone Response Is
Flat Above About 20 Hz (Out To ~1200
1200
Hz)
• Response To Acceleration Shown At Top
– The GAC Response Is Flat From ~5 –
200 Hz
• Other Important Points:
10
1
01
0.1
GAC
Dual OMNI2400
Single OMNI2400
0.01
1
10
100
1000
Frequency (Hz)
10000
1000
Velocity R
Response (V/m/s)
Comparison Of Sensors Used
In Microseismic Monitoring
g
GAC
Dual OMNI2400
Single OMNI2400
100
10
1
1
10
100
Frequency (Hz)
1000
10000
QC Report- Confidence Level
QC Report
Event Magnitude
g
vs Distance from Observation Well
Courtesy Of BP
-1
• Series Of Faults
Well 1
Well 2; Stage A
Well 2; Stage B
Relative Magnitude
-1.5
– Identified Easily
From Magnitudes
– Abnormal
Propagation
Well 3; Stage A
Well 3; Stage B
2
-2
Faults
-2.5
-3
-3.5
Normal Events
-4
• Azimuth
• Vertically
V ti ll
0
100
200
300
400
500
600
700
800
Distance (m)
Jonah Field, WY
NW-SE
Azimuths
3150
EAST 2
300 m
EAST 1
Faults
3200
EAST 3
Depth (m)
3250
EAST 6
3300
3350
EAST 5
3400
EAST 4
3450
SPE 102528
-40
-20
0
20
40
Lateral Distance From Well (m)
60
80
Courtesy Of BP
QC Report - Event Uncertainty
• Larger azimuthal uncertainty
farther from observation well
results in wider “fan” of events
toward eastern wings of
fractures
• 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
• Better
B tt D
Data
t Q
Quality
lit A
And
d Hi
Highest
h tP
Precision
i i Event
E t LLocation
ti Due
D To:
T
– Number Of Tools & Sample Rate
– Perf
P f Timing
Ti i
– Stacking
Principle of Tilt Fracture Mapping
Direct Fracture Diagnostic Technique
Hydraulic fracture
i d
induces
a characteristic
h
t i ti
deformation pattern
Frac Orientation from Surface Tilts
Induced tilt reflects
the geometry and
orientation of created
hydraulic fracture
Pick-up
Pick
up electrodes
Treatment Well
current electrode
Offset Well
Surface Tiltmeter Site
• Installed 5 - 40 ft below the earth’s surface in
4”-diameter PVC pipe
• Deeper boreholes to eliminate “noise” from
surface
– Cultural noise
– Thermal induced earth surface motion
• Surface array with 16 or more tiltmeters
placed in concentric circles around the point
of injection (distance from well: 15%-75% of
injection depth)
• Tiltmeter data stored in datalogger contained
in tiltmeter
• Data collected periodically either manually or
by radio
8”
Outer
Pipe
Solar Panel
4”
Inner
Pipe
Tilt t
Tiltmeter
Cement
Sand
5 40 ft
5-40
Surface Tiltmapping
Surface Tiltmeter Fracture Mapping
• E
Example
l Of Surface
S f
Tiltmeter
Tilt t
Response
– Multi-Mode Fracturing
• Vertical Fractures And/Or
Opening Of Cleats
• Horizontal Fractures
VerticalTrough &
Uplifts
– Surface Deformation From
I di id l C
Individual
Components
t Add
Together
• Superposition
CombinedTrough On
Top Of
Uplift
Horizontal – Simple Uplift
P
Poor
Diversion
Di
i in
i a LLong U
Uncemented
t d Lateral
L t l
Surface Deformation Image
906
T t
Treatment
tW
Wellll Tilt Mapping
M i
• Deployed on single
conductor e-line
• Magnetic
M
ti d
decentralizers
t li
• Slim 1-11/16” tool diameter
• Measure frac height in realtime
• Calibrate frac models
Treatment Well Tiltmeters
• Measure Fracture Height In Vicinity Of
Wellbore
• Observe Changes
g In Height
g
– Correlate With Pressure
• Height -> Primary Result
– Complex Deformation Around Wellbore
9850


9900


Depth
h (ft)
9950
10000
10050
10100
10150
0
1000
2000
Downhole tilt (Microradians)
3000
4000
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
Geometryy and Eliminate Screenout Problems in the Bossier Sand of East Texas
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
pp
of Microseismic Mapping
pp g and Modeling
g Analysis
y to Understand Hydraulic
y
Fracture Growth
PT 2006 98219 Application
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 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
Calibration
PT 2005 77441 Integrating Fracture-Mapping Technologies to Improve Stimulations in the Barnett Shale

Pinnacle/Halliburton Hydraulic Fracture Diagnostics and Reservoir

Transcription

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