mini frac & after closure analysis · pdf filefracture gradient was determined to be 1.009...

15
Definitive Optimization AER/OGC Requirements Oil/Gas Optimization - Technical Services 300, 840-6 TH Ave SW, Calgary, Alberta T2P 3E5 Tel: 1 (855) 933-3678 Fax: 1 (403) 794-0055 Website: www.defopt.com MINI FRAC & AFTER CLOSURE ANALYSIS REPORT Company Ltd. 100/00-00-000-00W0/0 (Surface 00-00) Name Field Name Formation February 6 18, 2013 DISTRIBUTION: Client Name/Company Ltd. DEFINITIVE PROJECT COORDINATOR: PREPARED BY: Definitive Optimization DATE: March 7, 2013

Upload: doantu

Post on 08-Mar-2018

217 views

Category:

Documents


0 download

TRANSCRIPT

Page 1: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Definitive Optimization

AER/OGC Requirements – Oil/Gas Optimization - Technical Services 300, 840-6TH Ave SW, Calgary, Alberta T2P 3E5 Tel: 1 (855) 933-3678 Fax: 1 (403) 794-0055 Website: www.defopt.com

MINI FRAC & AFTER CLOSURE

ANALYSIS REPORT

Company Ltd.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field – Name Formation

February 6 – 18, 2013

DISTRIBUTION: Client Name/Company Ltd.

DEFINITIVE PROJECT COORDINATOR:

PREPARED BY: Definitive Optimization

DATE: March 7, 2013

Page 2: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Definitive Optimization

AER/OGC Requirements – Oil/Gas Optimization - Technical Services 300, 840-6TH Ave SW, Calgary, Alberta T2P 3E5 Tel: 1 (855) 933-3678 Fax: 1 (403) 794-0055 Website: www.defopt.com

SUMMARY OF RESULTS (MINI-FRAC)

1. Fracture closure time (tc) was determined to be 4853.92 min.

2. Fracture closure pressure (Pc) was determined to be 9033 psia at the toe sleeve (Ddatum = 11344.0 ftKB-TVD), 4140 psia at surface.

3. The instantaneous shut-in pressure was determined to be 11444 psia at Ddatum, 6518 psia at

surface, and therefore, the net fracture pressure was calculated to be 2411 psi. Closure time was initially difficult to assess, however, was further confirmed utilizing other available techniques.

4. Fracture gradient was determined to be 1.009 psi/ft.

5. Based on the G-function time (Gc) of 106.5, the fluid efficiency for the water injection was

determined to be 98.2%.

SUMMARY OF RESULTS (AFTER-CLOSURE)

6. The derivative plot used for after closure flow regime identification indicates a transition into a late-time trend of approximate -1/2 slope signifying linear flow. The presence of pseudo-radial flow was not observed.

7. Although pseudo-radial flow was not observed, a late-time extrapolation was conducted on the

radial plot to obtain a maximum permeability and pressure estimate. In addition, a late-time extrapolation was also conducted on the linear plot to obtain a minimum pressure estimate. Estimates from the straight-line analyses were used as starting parameters for simulation. The analysis was conducted using a fracture model. Since pseudo-radial flow was not observed, confidence in the results is low. However, the estimated reservoir pressure from simulation is within the pressure range obtained.

8. The initial reservoir pressure of 8698 psia at Ddatum was obtained from simulation.

9. The flow capacity (kh)o was also obtained from simulation and was determined to be 0.111 md-ft. The effective permeability to oil (ko) was therefore estimated to be 0.0074 md, based on a net pay of 15.0 feet.

www.wtaservices.com (P09284)

Page 3: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Definitive Optimization

AER/OGC Requirements – Oil/Gas Optimization - Technical Services 300, 840-6TH Ave SW, Calgary, Alberta T2P 3E5 Tel: 1 (855) 933-3678 Fax: 1 (403) 794-0055 Website: www.defopt.com

RESULTS

Injection Pressure at Ddatum, Pinj (psia) ..................................................................... 12990 Instantaneous Shut In Pressure at Surface, ISIP (psia) .......................................... 6518

Instantaneous Shut In Pressure at Ddatum, ISIP (psia).............................................. 11444

Fracture Closure Pressure at Surface, Pc (psia)...................................................... 4140

Fracture Closure Pressure at Ddatum, Pc (psia) ......................................................... 9033

Net Fracture Pressure at Ddatum, ∆pnet (psi)............................................................... 2411

Fracture Closure Time, tc (min) ................................................................................ 4853.9

G-Function Time, Gc ................................................................................................ 106.5 Fracture Gradient, (psi/ft) ......................................................................................... 1.009 Fluid Efficiency, (%) ................................................................................................. 98.2

Estimated Initial Reservoir Pressure at Ddatum, PRi (psia) ......................................... 8698 Total Fluid-Loss/Leakoff Coefficient, C (ft/min

1/2) ...................................................

T Reservoir Fluid-Loss/Leakoff Coefficient, C (ft/min

1/2)............................................

R

Flow Capacity, (kh)o (md.ft)......................................................................................

2.22e-4 1.69e-4 0.1110

Permeability to Oil, ko (md)....................................................................................... 0.0074

Fracture Half-Length, Xf (ft) ...................................................................................... 80.0

Choked Fracture Skin, sc ......................................................................................... 0.0

Skin equivalent to Xf, sxf ........................................................................................... -4.9 Apparent Skin, s’ ..................................................................................................... -4.9

Atmospheric Pressure: 13.489 psi

RESERVOIR PARAMETERS

Net Pay, h (ft) ........................................................................................................... 15.0

Effective Horizontal Well Length, Le (ft) ................................................................... 9453.0

Porosity, φt (%) ........................................................................................................ 6.0

Gas Saturation, Sg (%) ............................................................................................. 0.0

Oil Saturation, So (%) ............................................................................................... 74.0

Water Saturation, Sw (%) ......................................................................................... 26.0

Temperature, TR (°F)................................................................................................ 270.0

Source : Company Energy Inc.

GAS PROPERTIES Gas Relative Density, G (air = 1) ............................................................................. N/A Gas Composition, N2 (%) ......................................................................................... N/A Gas Composition, CO2 (%) ...................................................................................... N/A Gas Composition, H2S (%)....................................................................................... N/A Pseudo Critical Pressure, Pc (psi) ............................................................................ N/A

Pseudo Critical Temperature, Tc (K) ........................................................................ N/A

Source : N/A

OIL PROPERTIES Oil API, (

oAPI)........................................................................................................... 43.0

Oil Density, (lb/ft3) .................................................................................................... 50.62

Source : Company Energy Inc.

www.wtaservices.com (P09284)

Page 4: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Definitive Optimization

AER/OGC Requirements – Oil/Gas Optimization - Technical Services 300, 840-6TH Ave SW, Calgary, Alberta T2P 3E5 Tel: 1 (855) 933-3678 Fax: 1 (403) 794-0055 Website: www.defopt.com

WATER PROPERTIES (Treating Fluid)

Water Specific Gravity.............................................................................................. 1.000 Fluid Composition .................................................................................................... Fresh Water Surface Fluid Temperature (°F) ............................................................................... N/A

Source : Company Energy Inc.

INJECTION

Final Injection/Pump Rate (bbl/min) ......................................................................... 6.07 Final Injection/Pump Rate (bbl/d)............................................................................. 8737.74 Water Injection Volume (bbl).................................................................................... 167.0* Pump Time (min)...................................................................................................... 27.52

Source : Company Energy Inc., * Includes 42 bbl, 9.9 ppg brine, ** Final pump time 24.4 min.

DOWNHOLE CONFIGURATION Well Type ................................................................................................................. Horizontal Oil Well License ............................................................................................................. 0000000 KB, (ft) ...................................................................................................................... 00.0 GL, (ft) ...................................................................................................................... 00.0 KB - GL, (ft) .............................................................................................................. 0.0

Frac String Depth, (ftKB-MD) ................................................................................... 00000.00 Frac String Depth, (ftKB-TVD) ................................................................................. 00000.00 Frac String O.D., (in) ................................................................................................ 0.00 Frac String Density, (lb/ft) ........................................................................................ 0.00 Intermediate Casing Depth, (ftKB-MD) .................................................................... 00000.00 Intermediate Casing Depth, (ftKB-TVD)................................................................... 00000.00 Casing O.D. (in) ....................................................................................................... 0.00 Casing Density, (lb/ft)............................................................................................... 0.00 Production Casing/Liner, (ftKB-MD)......................................................................... 00000.00 Production Casing/Liner, (ftKB-TVD) ....................................................................... 00000.00 Casing/Liner O.D. (in) .............................................................................................. 0.00 Casing/Liner Density, (lb/ft)...................................................................................... 0.00 PBTD, (ftKB-MD)...................................................................................................... 00000.00 PBTD, (ftKB-TVD) .................................................................................................... 00000.00 Packer Depth, (ftKB-MD) ......................................................................................... 00000.00 Packer Depth, (ftKB-TVD)........................................................................................ 00000.00 Stage Top, (ftKB-MD)............................................................................................... 00000.00 Stage Top, (ftKB-TVD) ............................................................................................. 00000.00 Stage Bottom, (ftKB-MD) ......................................................................................... 00000.00 Stage Bottom, (ftKB-TVD)........................................................................................ 00000.00

Ddatum, (ftKB-MD) ...................................................................................................... 00000.00

Ddatum, (ftKB-TVD)..................................................................................................... 00000.00

Source : Company Energy Inc.

www.wtaservices.com (P09284)

Page 5: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

Time (h)

WellTest32TM

Ver 7.5.2.211

14000

13000

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

February 6 – 18, 2013 DFIT

End Injection

Well Shut In For Falloff

Date 2013/02/06 13:19:23

t 2.90 h

t 0.41 h

pdata 12990.0 psi(a)

qw -8737.74 bbl/d

Total Test

Measured pressures were converted from surface to 11344.0 ftKB-TVD (Ddatum).

0

-1000

12000

11000

10000

ISIP (surface) 6518.3 psi(a)

ISIP (D) 11443.9 psi(a)

Ddatum 11344.000 ft

Frac grad 1.009 psi/ft

ISIP

t 2.91 h

t 0.00 h

pdata 11443.9 psi(a)

End of Test

Date 2013/02/18 08:01:03

t 285.60 h

t 282.69 h

pdata 8864.8 psi(a)

-2000

-3000

-4000

9000

Analysis 1

-5000

8000 -6000

7000 -7000

6000 -8000

5000

pdata

qwater

-9000

0 25 50 75 100 125 150 175 200 225 250 275 300

Liq

uid

Ra

te (b

bl/d

) P

ressu

re (

psi(

a))

Page 6: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

Time (h)

WellTest32TM

Ver 7.5.2.211

-

14000

100/00-00-000-00W0/0 (Surfac 00-00)

Name Field / Name Formation

February 6 – 18, 2013 DFIT

Total Test (Magnified) 0

Measured pressures were converted from surface to 11344.0 ftKB-TVD (Ddatum). End Injection

Well Shut In For Falloff

13000

12000

End Injection

End Injection

Date 2013/02/06 11:39:33

Date 2013/02/06 13:19:23

t 2.90 h

t 0.41 h

pdata 12990.0 psi(a)

qw -8737.74 bbl/d

ISIP (surface) 6518.3 psi(a)

ISIP (D) 11443.9 psi(a)

Ddatum 11344.000 ft

Frac grad 1.009 psi/ft

ISIP

t 2.91 h

t 0.00 h

-1000

2000

11000

10000

Date 2013/02/06 10:36:03

t 0.18 h

t 0.03 h

pdata 9972.7 psi(a)

qw -8737.74 bbl/d

t 1.24 h

t 0.02 h

pdata 10047.1 psi(a)

qw -8737.74 bbl/d

pdata 11443.9 psi(a)

Analysis 1

-3000

-4000

9000 -5000

8000

7000

6000

Date 2013/02/06 10:34:03

t 0.15 h

t 0.00 h

pdata 6740.9 psi(a)

qw -8737.74 bbl/d

End of Falloff

Began Injection

Date 2013/02/06 11:38:29

t 1.22 h

t 1.04 h

pdata 8632.9 psi(a)

qw 0.00 bbl/d

Began Final Injection

Date 2013/02/06 12:54:57

t 2.50 h

t 1.26 h

pdata 8717.8 psi(a)

qw 0.00 bbl/d

-6000

-7000

-8000

5000

pdata

qwater

-9000

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50

Liq

uid

Ra

te (b

bl/d

) Pre

ssu

re (

psi(

a))

Page 7: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

WellTest32TM

Ver 7.5.2.211

450

February 6 – 18, 2013 DFIT G-Function 13000

22000

400

350

300

250

Pump Time 24.4 min

ISIP (surface) 6518.3 psi(a)

ISIP (D) 11443.9 psi(a)

Ddatum 11344.000 ft

Frac grad 1.009 psi/ft

Fracture Closure

Date 2013/02/09 22:10:37

Gc 106.498

tc 4851.23 min

tc 4853.92 min

pc (surface) 4139.7 psi(a)

pc 9033.1 psi(a)

98.16 %

pnet 2410.7 psi

Analysis 1

12500

12000

11500

11000

20000

18000

16000

14000

12000

200

10500 10000

150

Semilog Derivative

pdata

First Derivative

10000

8000

6000

100 9500

4000

50 9000

2000

0 8500 0

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210

G-function time

Firs

t De

riva

tive d

p/d

G (p

si(a

))

p (p

si(a

))

Se

mil

og

Deri

vati

ve

G

dp

/dG

(

psi(

a))

Page 8: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

WellTest32TM

Ver 7.5.2.211

700

February 6 – 18, 2013 DFIT MiniFrac Sqrt(t) 15000

14000

600

14000

12000

500

Pump Time 24.4 min

ISIP (surface) 6518.3 psi(a)

ISIP (D) 11443.9 psi(a)

Ddatum 11344.000 ft

Frac grad 1.009 psi/ft

13000

10000

400

Fracture Closure

Date 2013/02/09 22:10:37

tc 4851.23 min

tc 4853.92 min

pc (surface) 4139.7 psi(a)

pc 9033.1 psi(a)

pnet 2410.7 psi

Semilog Derivative

pdata

First Derivative

12000

8000

300 11000 6000

200

10000

4000

Analysis 1

100 9000 2000

0 8000 0

0 2 4 6 8 9 11 13 15 17

t1/2 (h)

Firs

t De

riva

tive d

p/d

(t 1

/2) (ps

i(a)/h

r1

/2)

p (p

si(a

))

Se

mil

og

Deri

vati

ve

(

t1/2

) d

p/d

(t1

/2)

(p

si(

a))

Page 9: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

WellTest32TM

Ver 7.5.2.211

105

6

4

3

2

104

6

4

3

2

February 6 – 18, 2013 DFIT Derivative

pdata

Derivativedata

PPDdata

106

4

2

105

4

2

104

4

2

103

103

6

4

3

2

User Defined

Slope 0.500

Slope -1/2

4

2

102

4

2

102

6

4

3

2

Fracture Closure

Date 2013/02/09 22:10:37

101

4

2

1.0

4

2

101

10-3

2 3 4 5 6 7

10-2

2 3 4 5 6 7

10-1

2 3 4 5 6 7

1.0

t (h)

2 3 4 5 6 7

101

2 3 4 5 6 7

102

2 3 4 5 6 7 10-1

103

Firs

t De

riva

tive d

p/d

(t) (p

si/h

r) p

, S

em

ilo

g D

eri

vati

ve

(

t)d

p/d

(t)

(

psi(

a))

Page 10: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

WellTest32TM

Ver 7.5.2.211

9200

February 6 – 18, 2013 DFIT Minifrac Radial (Nolte)

9150

9100

9050

9000

8950

8900

8850

Pseudo-radial flow was not observed.

Permeability is maximum estimate.

8800

Analysis 1

kh 0.1862 md.ft

h 15.000 ft

k 0.0124 md

p* 8771.5 psi(a)

8750 Upper range estimate of reservoir pressure

8700

1.50

pdata

1.40

1.30

1.20

1.10

1.00

0.90

0.80

FR1

0.70

0.60

0.50

0.40

0.30

0.20

0.10

0.0

p

(p

si(

a))

Page 11: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc.

100/00-00-000-00W0/0 (Surface 00-00)

Name Field / Name Formation

WellTest32TM

Ver 7.5.2.211

9200

February 6 – 18, 2013 DFIT Minifrac Linear (Nolte)

9100

9000

Analysis 1

pc 9033.1 psi(a)

CR 1.69e-04 ft/min1/2

CT 2.22e-04 ft/min1/2

p* 8671.0 psi(a)

8900

Lower range estimate of reservoir pressure

8800

8700

8600

1.00

pdata

0.90

0.80

0.70

0.60

0.50

FL2

0.40

0.30

0.20

0.10

0.0

p

(p

si(

a))

Page 12: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

WellTest32

TM Ver 7.5.2.211

C:\Users\Jean\Documents\Well Test Analysis\PetraCat Energy Services\13-0002 Lawlar 41-15SH\XTO Energy-Lawlar 41-15SH-DFIT (201 3-02-18).fkt 07-Mar-13

0

WellTest32TM

Ver 7.5.2.211

C:\Users\Jean\Documents\Well Test Analysis\PetraCat Energy Services\13-0002 Lawlar 41-15SH\XTO Energy-Lawlar 41-15SH-DFIT (2013-02-18).fkt 07-Mar-13

3-02-18).fkt 07-Mar-13

WellTest32TM

Ver 7.5.2.211

C:\Users\Jean\Documents\Well Test Analysis\PetraCat Energy Services\13-0002 Lawlar 41-15SH\XTO Energy-Lawlar 41-15SH-DFIT (201

Erro

r (%)

Imp

uls

e D

eri

vati

ve

(

t)2

dp

/d(

t)

14000

13000

12000

11000

10000

9000

8000

7000

pdata

pmodel

Ext. pmodel

Early Time

15000

14000

13000

12000

11000

10000

9000

8000

7000

pdata

pmodel

Late Time

6000

5000

6000 Ext. p

5000

model

0 25 50 75 100 125 150 175 200 225 250 275 30

t (h)

4000 3500 3000 2500 2000

1 / t (h-1)

1500 1000 500 0

Simulation attempts were conducted with a primary focus on the late-time

and early-time data to obtain estimates of pressure and permeability.

14000

13000

12000

11000

10000

History

4 pi (syn) 8698.0 psi(a)

pwo (syn) 12800.0 psi(a) 3

2

1

0

105

104

103

102

Derivativedata

Derivativemodel

PPDdata

PPDmodel

Derivative

106

105

104

103

9000 -1 101 102

8000 -2 1.0 101

7000 kh 0.1110 md.ft s' -4.885 -3

6000

h 15.000 ft

k 0.0074 md

sXf -4.893

Xf 80.000 ft

pdata

pmodel -4

10-1 1.0

sc 0.000 % Error 10-2 10-1

5000 -5

0 24 48 73 97 121 145 169 193 217 242 266 290

Time (h)

10-4 2 3 5 10-3 2 3 5 10-2 2 3 5 10-1 2 3 5 1.0 2 3 5 101 2 3 5 102 2 3 5 103

t (h)

WellTest32TM

Ver 7.5.2.211

p (P

PD

) (ps

i/hr) P

ressu

re (

psi(

a))

p

(p

si(

a))

(psi

hr)

p

(p

si(

a))

Page 13: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc. Start Test Date: 2012/12/13

Well Name Name Formation:

Gauge 1 Time

Ga

ug

e 1

Ca

sin

g T

em

pe

ratu

re , °F

Final Test Date: 2013/02/18

12000

Surface Pressure and Temperature Plot

400

8000

t = 1319.5067 p = 5168.99 2013/02/06 11:39:33 End Injection

t = 1321.1706 p = 8073.66 2013/02/06 13:19:23 End of Injection Well Shut In For Falloff

300

t = 1318.4483 p = 5095.56 2013/02/06 10:36:03 End Injection

Pressure

t = 1603.8650 p = 3973.59 2013/02/18 08:01:03

4000 200

t = 1320.7633 p = 3828.67 2013/02/06 12:54:57 End of Falloff Began Final Injection

t = 1318.4147 p = 1787.40

0 2013/02/06 10:34:02 Began Injection

t = 1319.4889 p = 3744.91 2013/02/06 11:38:29

End of Falloff Began Injection

t = 1604.2400 p = 25.63 2013/02/18 08:23:33

100

Temperature

-4000

0

0:00 12:00 0:00 12:00 0:00 12:00 0:00 12:00 0:00 12:00 0:00 2013/2/4 2/5 2/7 2/8 2/10 2/11 2/13 2/14 2/16 2/17 2/19

Gauge 1

Casin

g P

ressure

, p

si(a)

Page 14: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Energy Inc. Start Test Date: 2012/12/13

Well Name Name Formation:

Gauge 1 Time

Final Test Date: 2013/02/18 Surface Pressure Plot (Magnified) 9000

t = 1321.1706 p = 8073.66 2013/02/06 13:19:23 End of Injection Well Shut In For Falloff

6000

t = 1318.4483 p = 5095.56 2013/02/06 10:36:03 End Injection

t = 1319.5067 p = 5168.99 2013/02/06 11:39:33 End Injection

3000

t = 1319.4889 p = 3744.91 2013/02/06 11:38:29

End of Falloff Began Injection

t = 1320.7633 p = 3828.67 2013/02/06 12:54:57 End of Falloff Began Final Injection

t = 1318.4147 p = 1787.40 2013/02/06 10:34:02 Began Injection

0

10:00 2013/2/6

10:30 11:00 11:30 12:00 12:30 13:00 13:30 14:00

Gauge 1

Casin

g P

ressure

, p

si(a)

Page 15: MINI FRAC & AFTER CLOSURE ANALYSIS · PDF fileFracture gradient was determined to be 1.009 psi/ft. 5. Based on the G-function time (Gc ... -5000 8000 -6000 7000 -7000 6000 -8000 water

Company Ltd. Well Name

100/00-00-000-00W0/0 (Surface 00-00)

Name Field – Name Formation February 6 – 18, 2013

* TERMS: The interpretations and conclusions presented in this report are the opinions

based on information from geological, engineering and other available data. This report

embodies the author’s best, sound engineering practices and efforts and the results are not and

should not be guaranteed. The author does not guarantee the accuracy of geological, engineering

and other available data and interpretation provided for use in this analysis. The author does not

accept any responsibility and shall not be liable in negligence or otherwise, for any loss or

damage resulting from the possession or use of the report in terms of correctness or otherwise.

The use and application of this report in whole or part is exclusively at the user’s own risk. The

release of liability shall also be binding upon the client’s permitted assigns, administrators, heirs,

executors and successors. The author’s liability to the client shall not exceed the amount of fees

it received for performing the services under this agreement under no circumstances.

www.wtaservices.com (P09284)