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

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1972

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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

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Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Coil Proppant Concentration (lb/gal)

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4/20054:00 14:20 14:40 15:00 15:20 15:40

23/04/200516:00

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Coil Tubing Pressure (psi) Treating Tubing Pressure (psi)Slurry Rate (bpm) Cummins Rate (bpm)Proppant Conc (lb/gal)

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CircGel

CirculateCutting Sand

CirculateGel

CircAcid

Circ FR Water

PumpGel down Annulus

Monitor Pressure Decline Pad 100 Mesh Pad 0.5ppg

1.0ppg

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6.0ppg Flush

23/04/200512:00 12:20 12:40 13:00 13:20 13:40

23/04/214:0

Time

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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

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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

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Rate HistoryBHP HistoryMatched BHPAverage Pressure

Volumetric OGIP = 5.41 BCF

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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

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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

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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

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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