Current Practices in Oil and Gas Stimulation · Current Techniques Used for Stimulation Oil and Gas...

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


Confidential



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



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



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



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



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



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



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



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



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



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



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



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



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 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



Re (ft) 100.000

Rw (ft) 0.350


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



Re (ft) 100.000

Rw (ft) 0.350


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

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Current Practices in Oil and Gas Stimulation · Current Techniques Used for Stimulation Oil and Gas...

Documents