Pin-Point Fracturing in the Cooper Basin, Australia
Jim McGowen
Halliburton, Adelaide
Presentation Overview
•Overview of Cooper Basin
•The Problem: Bypassed Pay
•A Solution: Pin-Point Fracturing Technique
•Case History
• Well 3
• Well 7
•Overall Program Results
Pin-Point Overview in Cooper Basin – As of Sept 2005
25 miles
Cooper Basin• Over 600 Individual Treatments
Pumped Since 1969
• Multiple Gas Sands• 7500 – 10000 Ft
• Inter-bedded Fluvial Sand/Shale/Coal Sequences
• Avg. Gross Interval > 1500ft
• Temperatures of 250 – 400 °F
• High Stress Environment• ISIP Gradients Of 0.9 – 1.2 Psi/Ft
• Near Wellbore Pressure Loss 500 -2500 Psi
• Normally Pressured Reservoirs
• Historically Treated With 1-3 Fracs
0
10
20
30
40
50
60
70
80
90
100
Num
ber
of S
tage
s
1969
1972
1975
1978
1981
1984
1987
1990
1993
1996
1999
2002
2005
Cooper Basin - Fracture Stages
The Problem: Bypassed PayBlanket Staging
• Multiple Sands Targeted In Single Frac Stage
• 100-250 Ft Gross Interval
• Perforate All Sands
• No Control Over Fluid Entry
PLT Results
• A Study Of 92 Plt’s Showed Limited Zone Coverage When Targeting Multiple Zones
• 40% - Flow Only From Top Zone
• 80% - Flow Only From One Zone
• 0% - Flow From >2 Zones
Single Frac
A Solution : Pin-Point Fracturing
Pin-point Fracturing Utilizes Coiled Tubing To Jet Perfs While Treatment is Pumped Down The Casing/Coil Annulus
Issues
• Completion And Wellhead Must Be Able To Withstand Fracturing Pressures
• Bottom Up Completion Strategy
• Sand Plug Management Requires Circulation Under Pressure
Pin-Point Fracturing Equipment80k CTU1.75” Coil10k WellheadBOP’sNormal Frac Spread
Test Showing Hydrajetting ResultsFront Back
This was after jetting @ 2.2 bpm with linear gel and 1 ppg sand for 80 seconds. The 0.25” Jet, stand-off was 1.25” from plate.
Example Treatment Data
23/04/200512:00 12:20 12:40 13:00 13:20 13:40
23/04/214:0
Time
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000A
Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Coil Proppant Concentration (lb/gal)
A AB BC
4/20054:00 14:20 14:40 15:00 15:20 15:40
23/04/200516:00
Time
0
5
10
15
20
25
30B
0
1
2
3
4
5
6
7
8
9
10C
Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Proppant Conc (lb/gal)
A AB BC
CircGel
CirculateCutting Sand
CirculateGel
CircAcid
Circ FR Water
PumpGel down Annulus
Monitor Pressure Decline Pad 100 Mesh Pad 0.5ppg
1.0ppg
2.0ppg
3.0ppg
4.0ppg
5.0ppg
6.0ppg Flush
23/04/200512:00 12:20 12:40 13:00 13:20 13:40
23/04/214:0
Time
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000A
Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Coil Proppant Concentration (lb/gal)
A AB BC
4/20054:00 14:20 14:40 15:00 15:20 15:40
23/04/200516:00
Time
0
5
10
15
20
25
30B
0
1
2
3
4
5
6
7
8
9
10C
Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Proppant Conc (lb/gal)
A AB BC
CircGel
CirculateCutting Sand
CirculateGel
CircAcid
Circ FR Water
PumpGel down Annulus
Monitor Pressure Decline Pad 100 Mesh Pad 0.5ppg
1.0ppg
2.0ppg
3.0ppg
4.0ppg
5.0ppg
6.0ppg FlushCirc
GelCirculate
Cutting SandCirculate
GelCircA
cidCirc FR Water
PumpGel down Annulus
Monitor Pressure Decline Pad 100 Mesh Pad 0.5ppg
1.0ppg
2.0ppg
3.0ppg
4.0ppg
5.0ppg
6.0ppg Flush
•Have Perform Minifrac on All Treatments
•Use 15% HCL as Breakdown Fluid
•Pump Cutting Sand into Formation During Minifrac
•Coil Pressure Acts as “Dead String” During Treatment
BHA
•Total BHA about 6 feet in Length
•Ball Sub Forces Coil Rate Through Jets Although Allows Reverse Circulation
Well 3 – Case History
•3 Zones Targeted For Pin-point Stimulation
•One Zone To Be Added Post Frac Due To High Kh
•Top Zone Showed 0.5 Ft Of Conventional Pay From Logs (Typically Not A Target)
•Reservoir Pressure From Wireline Formation Tester 3600-3800 Psi With Mobility's Of 0.5 – 1.5 Md/Cp
•AFE Rate Expectation Of 1.7 MMscf/Day
32 Klbs 34%
41 Klbs 45%
47 Klbs 21%
7.3 mmscfd
GR
GAPI0 200
GDF1F
GAPI0 150
CAL
IN5 15
9200
9250
9300
9350
9400
DE
PT
HF
EE
T
PHIE
%30 0
HPV
V/V0.3 0VSH_1
V/V0 1
PHIE_1V/V1 0
COAL_10 1
TQUF1_1DEGF245 255
SUF1F_1RPS-10 110
xx
Post-PLT Perforations
Added 1 mmscfd
Interesting to note that frac did not grow into this
sand
Proppant Flow %
Well 3 - PLT
Well 3 – Production Match
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
0 50 100 150 200 250Time (Days)
Rat
e (M
SC
F/da
y)
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
Pre
ssur
e (p
sia)
Rate HistoryBHP HistoryMatched BHPAverage Pressure
Volumetric OGIP = 5.41 BCF
0.001
0.01
0.1
1
10
100
1000
0.000001 0.00001 0.0001 0.001 0.01 0.1 1 10 100
Single Phase Production Simulator
•Well online at 6.7 MMscf/day
•Xf = 140 ft (Uniform Flux)
•Kh = 32 md.ft
• K = 0.4 md
•Area = 120 acres
Well 7 – Case History
•4 Zones Targeted For Pin-point Stimulation + Bottom Zone Conventionally Perforated And Fracture Stimulated
•AFE Rate Of 2.2 MMscf/Day
•Six Other Wells In The Field Fracture Stimulated Between 1997 And 2003
Proppant Flow %
56 Klbs 63%
46 Klbs 12%
124 Klbs 16 %
Well 7 - PLT•Well Flowed 4 MMscf/Day
During Flowing Passes
• First Zone Fracture Treatment Pumped Through Conventional Perforations -> Flow From Single Set Of Perforations
•Two Sets Of Holes Open During Top Stage -> Flow Only From Upper Holes
•No Benefit From Post-frac Perforations
GRGAPI0 200
GDF1FGAPI0 150
CALIN6 16
PE
RF
S
8700
8750
8800
8850
8900
8950
9000
9050
9100
9150
9200
9250
9300
9350
9400
9450
9500
9550
9600
9650
9700
9750
9800
9850
9900
9950
10000
10050
DE
PT
HF
EE
T
VOL_WATER_3%30 0
VOL_GAS_3%30 0
PHIE_2%30 0
VSH_2V/V0 1
PHIE_2V/V1 0
COAL_30 1
AUF1_1DEGF270 320
SUF3F_1RPS-20 40
46 Klbs 3%
54 Klbs 6%
Well 7 – Production Match Single Phase Production Simulator
•Well online at 6.0 MMscf/day
•Xf = 50 ft (Finite Conductivity)
•Kfwf= 730 md.ft
• Kh = 15.5 md.ft
• K = 0.07 md
•Area = 200 acres
Volumetric OGIP = 26.56 BCF
0.001
0.01
0.1
1
10
100
1000
0.000001 0.00001 0.0001 0.001 0.01 0.1 1 10 100
0
2000
4000
6000
8000
10000
12000
14000
0 10 20 30 40 50 60 70 80 90 100Time (Days)
Rat
e (M
SC
F/da
y)
0
500
1000
1500
2000
2500
3000
3500
4000
4500
5000
Pre
ssur
e (p
sia)
Actual Rates vs AFE Expectations
Pinpoint Results Against Expectations
-100%-75%
-50%-25%
0%25%
50%75%
100%
Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7 Well 8
Well
Act
ual v
s Ex
pect
ed Q
i (%
Summary•Have Performed 55 Treatments in 13 wells. Have aborted 6
treatments due to low leakoff or no breakdown.
•Of 12 Wells with Production Data -- 10 Have Exceeded Expectations with Avg. of 30% Increase In Initial Rate
•Data Strongly Suggests That Treating Multiple Perforated Intervals In One Treatment Is Poor Practice
•No Benefit From Post-frac Perforating Fractured Intervals
•Very Limited Benefit From Post-frac Perforating Non-Fractured Intervals -> Consistent With Low Permeability Formations
•Plan to Perform an Additional 5-10 Pin-Point Treatments During remainder of 2005 and ~15 Treatments during 2006
1st Pin-Point Treatment Outside of North America - July 21, 2004