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