Current Practices in Oil and Gas Stimulation
Enhanced Geothermal Systems
Current Techniques Used for Stimulation Oil and Gas Wells
• Hydraulic Fracturing• Acid Fracturing• Propped Fracturing
• Matrix Stimulation• Acidizing (HCl, Acetic, Formic)• Non-reactive Formation Damage Systems
• Cavity Completions
• Mechanical• Under-reaming• Fishbones
• Thermal Shock (Water Injectors)
Question• How do you stimulate a geothermal wells which
consists of a very low permeability, very hard, very hot rock completed with large open holes or slotted liners.Very Low Permeability – We are currently successfully
stimulating naturally fractured shales which have perm’s in the 50 to 300 nanodarcy range.Very Hard – We currently stimulate rock which have
modulus as high at 10e6 psi. I have personally stimulated naturally fractured granite in Vietnam.Large Open Holes or Slotted Liners – We currently
complete wells with 9 inch casing (Bohai Bay) and 10,000 ft slotted liners (Alpine)
The main issue seems to be temperature.
Current Techniques Used for Stimulation Oil and Gas Wells• Hydraulic Fracturing
• Acid Fracturing• Propped Fracturing
• Matrix Stimulation• Acidizing (HCl, Acetic, Formic)• Non-reactive Formation Damage Systems
• Cavity Completions
• Mechanical• Under-reaming• Fishbones
?
Hydraulic Fracturing
Basic Physics – Lumped Pseudo 3D Model
E
HPw Net
2
netP fnH
4/1
2
4
4
4
'
'
O
Ic
O
NetH
K
E
LQ
H
EP
Viscous Tip
HwHSTHC
TQL
PPPP
P
24
HfnH
Basic Frac Fluid Composition
• Water Based• Polymer
• Crosslinker
• pH Buffer
• Clay Control
• Breaker
• Surfactants
• Biocide
• Fluid Loss Control
Gelled Oil
Base Oil
Phosphate Ester Polymer
Crosslinker
Activator
Breaker
Materials -- FluidsFluid “Recipe”
• Base Fluid (Water or Oil) (1 cp)• Clay Control (2% KCl)
• Gelling Agent (10’s of cp)a) Guar Gum b) HPGc) CMHPG d) HEC• Bactericide
(protect fluid, NOT formation)
• pH Buffer (aid in mixing)
• Breaker
Oil Based Frac Fluids
Dimethyldioctadecylammonium chloride
An example of a permanently charged cationic quaternary amine surfactant
-
-
+
+
HydrophilicHead
HydrophobicTail
Non-ionic
Anionic
Cationic
Zwitterion
Aqueoussolution
Hydrophilichead
Hydrophobictail
Micelle
Structure of Visco-Elastic Thickners
Increase ConcentrationAbove CMC
Rod Like Micelle
Increase Concentration
Increase Concentration above C*
Three-dimensional gel microstructure from transmission electron
micrographs.
Nisslert, R. et.al. Journal of Microscopy. (2006)
Friction Reducers (Synthetic Polymers)
Polyacrylic acid(PAAc)
Polyacrylamide(PAAm)
Hydrolyzed Polyacrylamide(PHPA)
AcrylamidoMethylPropaneSulfonate
(AMPS)
Comparison of Friction Pressure for FR, 10# Guar and 2% KCl
1
10
100
1000
10000
0 10 20 30 40 50 60 70 80 90 100
Fric
tio
n in
psi
/10
0 f
t
Pump Rate in BPM
Poly. (4.5" Tubulars 10#/1000 gal Guar Linear Gel) Poly. (4.5" Tubulars KCl Water)
Poly. (4.5" Tubulars 2gpt FR)
Subject to hydrolysis at high temperatures
Consequence of using straight water
• High Friction
• Small Net Pressure resulting in a Narrow Frac Width
4/1
2
4
4
4
'
'
O
Ic
O
NetH
K
E
LQ
H
EP
Enter 1 to 5 Rate/Pressure Data Pairs
dP
/dL
0.2
01
.05
.02
05
02
00
Rate0.20 1.0 5.0 20 50 200
Choose Friction:
Sea Water 4.778
Enter 1 to 5 Rate/Pressure Data Pairs
Rate
(BPM)
dP/dL
(psi/100ft) a b
5.0 0.41 0.024 1.772
10.0 1.40 0.020 1.838
15.0 2.95 0.027 1.740
100.0 80.00 0.041 1.644
200.0 250.00 0.041 1.644
Slurry Friction Factor 0.50
Overall FluidFriction Factor
1.0000
Fluid Initially in Wellbore
Friction in psi/100 feet of9” casing
E
HPw Net
2
Dimensionless Fracture Conductivity
f
CD
f
k w
k xF
Proppant Types
Ceramic
Resin Coated
Sand
Each of these is available in several sizes and types
Quality and performance are variable
New “Microsphere” Materials
Softening Point = 1200°CUniaxial Compressive Strength = 60,000 psi
Natural Fractures Outcrops
Ithaca Shale Outcrop showing theGeneseo Gas Shale Eagle Ford Shale Outcrop
West of Del Rio, TXJPT – May 2015 Confidential
Critical Bridging Diameter
Deeprop™ 1000• D50 = 25µ *3 = 75µ = 0.0029 inches
Deeprop™ 200• D50 = 5µ *3 = 15µ = 0.0006 inches
Confidential
Deeprop™ 600• D50 = 10µ *3 = 30µ = 0.0012 inches
Deeprop™ 400• D50 = 8µ *3 = 24µ = 0.0009 inches
100 Mesh• D50 = 177µ *3 = 531µ = 0.02 inches
Silica Flour• D50 = 37µ *3 = 111µ = 0.004 inches
40/60 Mesh• D50 = 297µ *3 = 891µ = 0.035 inches
20/40 Mesh• D50 = 595µ *3 = 1785µ = 0.07 inches
DP™-1000
Deeprop™ 10000.25 lb/ft2
Confidential
Fayetteville
Conductivity compared to 100 mesh
Confidential
0.01
0.1
1
10
100
1000
2000 3000 4000 5000 6000 7000 8000 9000 10000
Co
nd
uct
ivit
y (m
d/f
t)
Fracture Closure Stress (psi)
2 lb/ft2 White 100 Mesh 2 lb/ft2 Deeproptm 1000 2 lb/ft2 Deeproptm 600 2 lb/ft2 Deeproptm 400 2 lb/ft2 Deeproptm 200
2% KCl Water250 degF
Confidential
Width vs Stress@ 2 lb/ft2
0.1
0.12
0.14
0.16
0.18
0.2
0.22
0.24
0.26
0 2000 4000 6000 8000 10000 12000
Frac
ture
wid
th in
inch
es
Fracture Closure Stress
Deeproptm-1000 Deeproptm-600 Deeproptm-400 Deeproptm-200 100 Mesh
Cumulative Weight Percent Larger Than (micron) Uniformity Coefficientd10 d25 d40 d50 d60 d75 d90
Pre-Test 70 43 26 19 13 7 1.6 16.3Post-Test 79 40 24 18 12 7 1.8 13.3
Pre- and Post-Test Deeprop™ 1000 Particle Size
Barnett Shale Example Design
TVDft
7600
7800
8000
8200
8400
GR API0 15075.00
NPOR V/V0.30 -0.100.1000
DPOR V/V0.30 -0.100.1000
Perforations
Confidential
Conductivity at Stress
psi
Reservoir Pressure, Pres 5200
Overburden, OB 8610
Tectonics, T 0
Closure Pressure, _CL 6337
Bottomhole Flowing Pressure, BHFP 1000
Propped Width Stress, _width 200
Proppant Stress, _p 5537
0.01
0.1
1
10
2000 3000 4000 5000 6000 7000 8000 9000 10000
Co
nd
uct
ivit
y (m
d/f
t)
Fracture Closure Stress (psi)
2% KCl Water250 degF
4.5 md/ft
0.08 md/ft
2 lb ft2 Deeprop™ 200 2 lb ft2 Deeprop™ 1000
Confidential
Pump Schedule/Frac Geometry
Well ID: Untitled
Blessed Downhole Pump Schedule Surface Pump Schedule
Wellbore Volume (M-Gal) 8.36 Wellbore Volume to Include As Pad (M-Gal) 0.00 Wellbore Fluid
1 25.000 25.000 0.00 0.00 70.00 0.000000 0.0 8.503 8.5 Slick Water 100 Mesh Sand 250F 80-100
2 25.000 24.446 0.50 0.50 70.00 0.000000 12.2 8.503 17.0 Slick Water 100 Mesh Sand 250F 80-100
3 25.000 23.917 1.00 1.00 70.00 0.000000 23.9 8.503 25.5 Slick Water 100 Mesh Sand 250F 80-100
4 50.000 47.833 1.00 1.00 70.00 0.000000 47.8 17.007 42.5 Slick Water Ottawa Sand, 250 F, Long Term 40-70
5 25.000 23.409 1.50 1.50 70.00 0.000000 35.1 8.503 51.0 Slick Water Ottawa Sand, 250 F, Long Term 40-70
6 25.000 22.923 2.00 2.00 70.00 0.000000 45.8 8.503 59.5 Slick Water Ottawa Sand, 250 F, Long Term 40-70
Stage
SlurryVolume(M-Gal)
FluidVolume(M-Gal) Start End
Rate(BPM)
FinesConc. (Vol
Fraction)Proppant(M-Lbs)
Pump Time(min)
Cum Time(min) Fluid Type Proppant Type
Proppant Conc(PPG)
Flush 50.000 46.819 0.00 0.00 60.00 0.000000 0.0 0.000 59.5 Slick Water
175.000 167.528 Average (PPG) 0.94 164.80 59.522
Schedule
Design_2 w50' frac spacing
Constant PPG Steps
Fluid Ramp
Slurry Ramp
Flow Back Rate (BPM) 0.000
Start Pump Time (YYYY/MM/DD HH:MM:SS
TVDft
7600
7800
8000
8200
8400
GR API0 15075.00
NPOR V/V0.30 -0.100.1000
DPOR V/V0.30 -0.100.1000
951 ft
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:1.33 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.005
0.008
0.012
0.016
0.020
0.024
0.028
0.032
0.036
0.040
in
Time
1.3300 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:25.93 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.010
0.018
0.027
0.036
0.045
0.054
0.063
0.072
0.081
0.090
in
Time
25.9300 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:35.50 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.010
0.018
0.027
0.036
0.045
0.054
0.063
0.072
0.081
0.090
in
Time
35.5000 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:42.30 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.010
0.018
0.027
0.036
0.045
0.054
0.063
0.072
0.081
0.090
in
Time
42.3000 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:54.26 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.009
0.016
0.024
0.032
0.040
0.048
0.056
0.064
0.072
0.080
in
Time
54.2600 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:59.52 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.008
0.014
0.021
0.028
0.035
0.042
0.049
0.056
0.063
0.070
in
Time
59.5200 Play Speed
7500.0
8539.5
8206.8
End of Job
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:63.21 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.008
0.014
0.021
0.028
0.035
0.042
0.049
0.056
0.063
0.070
in
Time
63.2100 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:79.68 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.007
0.012
0.018
0.024
0.030
0.036
0.042
0.048
0.054
0.060
in
Time
79.6800 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:105.18 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.006
0.010
0.015
0.020
0.025
0.030
0.035
0.040
0.045
0.050
in
Time
105.1800 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:215.38 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.004
0.006
0.009
0.012
0.015
0.018
0.021
0.024
0.027
0.030
in
Time
215.3800 Play Speed
7500.0
8539.5
8206.8
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:59.52 Depth:8206.84Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.008
0.014
0.021
0.028
0.035
0.042
0.049
0.056
0.063
0.070
in
Time
59.5200 Play Speed
7500.0
8539.5
8206.8
0.06 in
0.05 in
0.07 in
0.03 in
0.04 in
0.02 in
0.01 in
Deeprop™ 200• D95 = 14µ *3 = 42µ = 0.0016 inches• D90 = 12µ *3 = 36µ = 0.0014 inches• D50 = 5µ *3 = 15µ = 0.0006 inches
100 Mesh• D95 = 295µ *3 = 885µ = 0.035 inches• D90 = 275µ *3 = 825µ = 0.032 inches• D50 = 177µ *3 = 531µ = 0.021 inches
End of Job
Deeprop™ 1000• D95 = 120µ *3 = 360µ = 0.014 inches• D90 = 85µ *3 = 255µ = 0.01 inches• D50 = 25µ *3 = 75µ = 0.0029 inches
Confidential
NATURAL_FRACTURE_WIDTH
NATURAL_FRACTURE_WIDTH Time:59.52 Depth:8206.84
Y
20
40
60
80
10
01
20
X200 400 600 800 1000 1200
0.001
0.008
0.014
0.021
0.028
0.035
0.042
0.049
0.056
0.063
0.070
in
Time
59.5200 Play Speed
7500.0
8539.5
8206.8
End of Job
25’
50’
75’
Confidential
Benefits at a width of 0.06 inches (1.52 mm) and a formation perm of 250 nano-darcies
2 lb ft2 Deeprop™ 200 2 lb ft2 White 100 Mesh2 lb ft2 Deeprop™ 1000
Confidential
Deeproptm 1000
Permeability (md) 0.00025
Conductivity (md-ft) 1.14
Re (ft) 100.000
Rw (ft) 0.35
Xf (ft) FCD Rw'/Xf Rw' FOI
25 182.400 0.5 13 2.72
50 91.200 0.5 25 4.08
75 60.800 0.5 38 5.77
Deeproptm 200
Permeability (md) 0.00025
Conductivity (md-ft) 0.022
Re (ft) 100.000
Rw (ft) 0.350
Xf (ft) FCD Rw'/Xf Rw' FOI
25 3.520 0.35 9 2.32
50 1.760 0.28 14 2.88
75 1.173 0.2 15 2.98
100 mesh
Permeability (md) 0.00025
Conductivity (md-ft) 22.060
Re (ft) 100.000
Rw (ft) 0.350
Xf (ft) FCD Rw'/Xf Rw' FOI
25 3529.600 0.5 13 2.72
50 1764.800 0.5 25 4.08
75 1176.533 0.5 38 5.77
1.00
2.00
3.00
4.00
5.00
6.00
7.00
0 20 40 60 80
Fold
s-o
f-In
cre
ase
Xf
Deeprop 1000 Expected Folds of Increase vs Kf and Natural Fracture Xf
0
2
4
6
8
10
12
14
0 20 40 60 80 100 120 140
Fold
s o
f In
crea
se
Natural Fracture Length (ft)
Kf in Nano-Darcies = 50 Kf in Nano-Darcies = 200 Kf in Nano-Darcies = 500
Kf in Nano-Darcies = 1000 Kf in Nano-Darcies = 1500 Kf in Nano-Darcies = 2000
Limit of 100 Mesh PenetrationIn this case
Limit of DP 1000 PenetrationIn this case
Stokes Law Settling Velocity
)(
)()(1064.6)/(
2
5
cp
SGSGftrXsftV FPP
S
Description Vs (ft/sec)
20/40 Sand 4.28
40/70 Sand 1.07
80/140 0.22
Deeprop™ -1000 (D95) 0.26
Deeprop™-1000 (D50) 0.029
Deeprop™-200 (D95) 0.0022
Deeprop™-200 (D50) 0.00029
(cps) = 1
SG of Fluid = 1
SG of Proppant = 2.6
Confidential
Completion Strategies
Re-Fracs w/DiversionTreating Long Intervals
ExampleData
Ekofisk X-04 Field ObservationBullhead acid jobs may be sub-optimal – 4 zones near heel producing 75%
Breakdown Pressures of 15 Zones
Real Time Fluid Placement Monitoring
Particulate DivertersPotential Problems
After I. Abou-Sayed, SPE Web Event“Shale Formation Re-Fracturing ……”
Diverters – ball sealers
Re-Frac Design Elements
Ball Sealers
Mechanical Diversion
Frac Sleeves
Positive DiversionExpandable Liner• +
• Positive Diversion• Allows Use of
Standard CompletionProcedures
• -• Time Consuming
Costs • Operationally Complex,
Risky?• Destroys Existing
Production
Positive DiversionExpandable Liner• +
• Positive Diversion• Allows Use of
Standard CompletionProcedures
• -• Time Consuming
Costs • Operationally Complex,
Risky?• Destroys Existing
Production
MT
WY
SD
ND
MBSKAB
MT ND
Williston Basin
perfs
MGS (1990)
Post-frac temperature survey
Bakken Strata
Preliminary Micro Seismic Results
6,0
00
fe
et
10,000 feet
Well headToe
N
E
1000’
1000’
500’
500’
185° -1200’317° -1900’
60° -950’
195° -1200’
Max Stress N 65 E
Video
1
1 2 3 4
2
3
Stre
ss C
on
cen
trat
ion
Wellbore Radius
Wellbore
Figure 1 - Stress Concentration for a circular hole in a biaxial stress field
v
h
Virgin StressCondition
Stress Condition at open hole wall
1
1 2 3 4
2
3
Stre
ss C
on
cen
trat
ion
Wellbore Radius
Figure 2 - Cross sectional view of the stress concentration for a circular holein a biaxial stress field with a packer set at a pressure
equal to ½ the stress concentration created by the open hole
SetPacker
Packer Setting Pressure(Pp)
(Pp)
(Pp)
(Pp)
(Pp)
(Pp)
(Pp)
(Pp)
Virgin StressCondition
Stress Condition at open hole wall
Stress Condition With Set Packer
Ball ActivatedSlidingSleeve
Swell or MechanicalPacker
InducedHydraulicFracture
Open hole
Figure 4 – Longitudinal view of a wellbore containing multiple packer systems
with ball activated sliding sleeves with induced propped fracture treatments.
Colter 44-14H Fracture Mapping ProjectHybrid Liner Design
7" Shoe
11,805' Swell Pkr
12,436-452'
Swell Pkr
13,438-454'
Swell Pkr
14,144-160'
Swell Pkr
15,149-164'
Swell Pkr
16,143-159'
Hydraulic Pkr
17,653'
Pinned at 1,900 psi
Over Hydrostatic
Swell Pkr
17,150-165'
Hydraulic Pkr
18,669'
Pinned at 1,900 psi
Over Hydrostatic
TD
20,335'
4-1/2"
Shoe
19,974'
Press
Operated
Vent 19,700'
Pinned at
3,950 psi
Over
Hydrostatic
Sliding
Sleeve
19,156'
2.5" Ball
Sliding
Sleeve
18,180'
2.75" Ball
Sliding
Sleeve
17,425'
3.0" Ball
Encore's Branvic 11-1
Rigged with Pinnacle Technologies Seismic
Equipment
~900' to the Colter
Seismic View Window
~15,000' to 19,000'
4-1/2", 11.6#/ft, P-110 Liner w/4.0" ID
Six Perf & Plug Intervals
From 7" shoe to 17,150'
Separated with swell packers
Limestone sections
within seismic window
16,350' - 16,800'
17,010' - 17,100'
18,150' - 18,450'
18,550' - 18,820'
19,020' - 19,750'
Colter 44-14HBakken Horizontal Well Play
Fracture Mapping Project
7/10/2008
Robert Clark & Clyde Findlay II
Bakken Completions Team
500' Sleeve interval 1,000' Sleeve interval
Hydraulic Pkr
19,642'
Pinned at 2,500 psi
Over Hydrostatic
6" Hole
Sleeve Interval 1Map View
Treatment Curve Information:▬ Treating Pressure▬ Slurry Rate▬ BH Proppant Concentration
1234
Sleeve Interval
2000ft x 2000ft
Time Interval Highlighted
Events sized and colored by energy
Bottom Hole Assembly
Connector Knuckle Joint & Shear Disconnect
CentralizerBall Sub
Jet Sub
Jetting Tools
• Many different types & styles of housings and jets
• Replaceable nozzles
• Typical flowrate of 1 bbl/min per 3/16” nozzle or 0.6 bbl/min per 1/8” nozzle
• Typical sand concentration of 1ppg (100 mesh) if only hydrajetting - or just use the frac sand that is on location
Kiel’s Process
Post Frac