6 Mon Feb 9 - Comparing Calculated to Measured Values
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School
Texas A&M University *
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Course
416
Subject
Mechanical Engineering
Date
Nov 24, 2024
Type
Pages
26
Uploaded by SargentTeamDugong21
Petroleum Engineering 416
Comparing Calculated to Measured Values
Texas A&M University
1
In Our Work, We Calculate Things…
•
And it is often necessary to compare our calculations to actual or measured values
–
Calibrate the method we are using so that we can make additional calculations when we don’t have actual data to compare
–
Comparing calculated values to measured values gives us (an our managers and peers) confident that we can make calculations reasonably accurately for those times when we don’t have measured values to comapre
2
In Our Work, We Calculate Things…
•
A good example of this, and one that is used often, is decline curve analysis
–
In decline curve analysis, actual data (
production history
) is curve-
fit (
history matched
) with an equation (usually Arps hyperbolic decline curve equation)
–
By matching the historical data, the parameters for the decline curve equation: qi, dni, and b are established
–
Then, using the equation with the proper inputs that match the historical data, we can make a reasonable forecast into the future
–
You see, our forecast is only as good as we can demonstrate that it is a take-off from historical production
3
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Example: Compare Calculated to Actuals
Filled circles for Actual
Solid line for Calculated
Open circles for Actual
Solid line for Calculated
Curve-Fit of Historical Production Data to Decline Curve Equation
100
1,000
10,000
0
5
10
15
20
25
30
35
40
45
50
Time, days
Gas Rate, Mcf/day
Actual
Match
Forecast
Match Parameters
qi = 4,576 Mcf/day
b = 2.61
dni = 11,570.8%
100
1,000
10,000
0
10
20
30
40
50
60
70
80
90
100
110
Time, days
Gas Volumes, Mcf/day
Actual
Match
Match Parameters
qi = 7,568 Mcf/day
b = 2.65
dni = 2,382.8%
Forecast does not have to be dashed; could also be a solid line
The point is, when comparing actual to calculated values, generally (but not always)
, actual data are symbols and calculated data are solid lines
4
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
8/19/08
6:00 PM
8/20/08
12:00 AM
8/20/08
6:00 AM
8/20/08
12:00 PM
8/20/08
6:00 PM
8/21/08
12:00 AM
8/21/08
6:00 AM
8/21/08
12:00 PM
8/21/08
6:00 PM
8/22/08
12:00 AM
8/22/08
6:00 AM
8/22/08
12:00 PM
8/22/08
6:00 PM
Pressure, psi
Measured Tubing Pressure
Calculated BHP from Tubing Pressure
Example Comparing Measured Data to Calculated Values
Comparison of Measured BHP data to
Calculated BHP’s
Solid symbol for Actual or Measured and a solid line for Calculated
5
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
8/19/08
6:00 PM
8/20/08
12:00 AM
8/20/08
6:00 AM
8/20/08
12:00 PM
8/20/08
6:00 PM
8/21/08
12:00 AM
8/21/08
6:00 AM
8/21/08
12:00 PM
8/21/08
6:00 PM
8/22/08
12:00 AM
8/22/08
6:00 AM
8/22/08
12:00 PM
8/22/08
6:00 PM
Pressure, psi
Measured Tubing Pressure
Calculated BHP from Tubing Pressure
Example Comparing Measured Data to Calculated Values
Comparison of Measured BHP data to
Calculated BHP’s
Same as previous example, but used the “smoothed-line” option for the calculated values. Generally, I don’t like using the smoothed-line option.
6
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Comparison of Measured BHP data to Calculated BHP’s
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
8/19/08 6:00
PM
8/20/08
12:00 AM
8/20/08 6:00
AM
8/20/08
12:00 PM
8/20/08 6:00
PM
8/21/08
12:00 AM
8/21/08 6:00
AM
8/21/08
12:00 PM
8/21/08 6:00
PM
8/22/08
12:00 AM
8/22/08 6:00
AM
8/22/08
12:00 PM
8/22/08 6:00
PM
Pressure, psi
Measured Tubing Pressure
Calculated BHP from Tubing Pressure
Example Comparing Measured Data to Calculated Values
Just another way of comparing Calculated to Actuals
In this example, I prefer a line over symbols for the calculated values.
7
2-3/8” tubing
ID = 1.995”
Perfs:
7,189 – 7,197
5-1/2” Casing
ID = 4.892”
Set at 7,305 ft
EOT at
7,193 ft
Flow Type (1=annulus, 0 = tubing)
0
gas gravity
0.7
Tubing ID, inches
Flow Length, feet
True Vertical Depth, feet
Tubing OD, inches
Casing ID, inches
CO2
0
H2S
0
Flowing Surface Temperature, °F
70
Reservoir Temperature, °F
175
Gas Rate, Mcf/day
Shut In Tubing Pressure, psi
Water Rate, bbls/day
Calculated WGR, bbl/MMcf
0
Example 1:
Calculate BHP at mid-perfs from Surface Pressure
•
Perforated, flow tested for 2 days, then shut in
•
After 30 days, the field reported the shut in tubing pressure is 4,600 psi
•
Estimate reservoir pressure
What are the Inputs for our jBHPRESS
Function? 8
Example 1: Calculate BHP
Reservoir Pressure Gradient = Reservoir Pressure/Reservoir Depth (TVD)
Flow Type (1=annulus, 0 = tubing)
0
gas gravity
0.7
Tubing ID, inches
1.995
Flow Length, feet
7,193
True Vertical Depth, feet
7,193
Tubing OD, inches
2.375
Casing ID, inches
4.892
CO2
0
H2S
0
Gas Rate, Mcf/day
0
Shut In Tubing Pressure, psi
4,600
Water Rate, bbls/day
0
Flowing Surface Temperature, °F
70
Reservoir Temperature, °F
175
Calculated WGR, bbl/MMcf
0
Calculated BHP at 7,193 feet, psi
5,445
Reservoir Pressure Gradient, psi/ft
0.76
How accurate is our calculated number? Do we feel confident in this number?
Please NOTE:
Gas Rate is 0
WGR is 0
9
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Example 1: Calculate BHP from Surface Pressure
•
We should ask to get a measured SIBHP, explaining that –
This is a critical piece of information for booking reserves and making production forecasts
–
We are going to drill many wells in this area and you want to calibrate your calculation methods for future wells so that you don’t have to measure BHP every time
10
Gauge Depth
feet
Gauge Pressure
psi
Gradient
psi/ft
0
4,600
1,000
4,720
0.120
2,000
4,836
0.116
3,000
4,952
0.116
4,000
5,066
0.114
5,000
5,188
0.122
6,000
5,307
0.119
6,500
5,368
0.122
7,000
5,430
0.124
7,100
5,441
0.110
7,150
5,449
0.160
7,175
5,451
0.080
7,193
5,453
0.111
Given Data
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
4,400
4,600
4,800
5,000
5,200
5,400
5,600
Pressure, psi
Depth, feet
Typical Measured Static BHP Data from the Field
Gradient in psi/ft = Specific Gravity * 0.433 psi/ft
API
131.5
141.5
Gravity
Specific °
+
=
Gradient
=
7175
7193
5451
5453
−
−
= 0.111 psi/ft
We are looking for
(1) a fluid level
(2) the deepest pressure measured
-
This looks like a pretty dry gas gradient (~0.1 psi/ft) all the
way from surface to 7,193 feet (i.e., no fluid level)
-
Fresh water gradient is 0.433 psi/ft
-
Salt water gradient is ~0.465 psi/ft
-
Condensate (60° API) is ~0.32 psi/ft
11
My Solution to Example 1
Is this a normally pressured reservoir?
So, our calculation is pretty good in this case. Dry gas; it ought to be.
Gauge Depth
feet
Gauge Pressure
psi
0
4,600
Flow Type (1=annulus, 0 = tubing)
0
1,000
4,720
gas gravity
0.7
2,000
4,836
Tubing ID, inches
1.995
3,000
4,952
Flow Length, feet
7,193
4,000
5,066
True Vertical Depth, feet
7,193
5,000
5,188
Tubing OD, inches
2.375
6,000
5,307
Casing ID, inches
4.892
6,500
5,368
CO2
0
7,000
5,430
H2S
0
7,100
5,441
Gas Rate, Mcf/day
0
7,150
5,449
Shut In Tubing Pressure, psi
4,600
7,175
5,451
Water Rate, bbls/day
0
7,193
5,453
Flowing Surface Temperature, °F
70
Reservoir Temperature, °F
175
Calculated WGR, bbl/MMcf
0
Calculated BHP at 7,193 feet, psi
5,445
Measured BHP at 7,193 feet, psi
5,453
Difference Calculated to Measured
-0.15%
Reservoir Pressure Gradient using Measured BHP, psi/ft
0.76
Given Data
%
15
.
0
100
5435
5453
-
5445
100
x Value
Accepted
Value
Accepted
Value
Calculated
Error Percent =
=
−
=
x
Percent Error
12
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2-3/8” tubing
ID = 1.995”
Perfs:
7,189 – 7,197
5-1/2” Casing
ID = 4.892”
Set at 7,305 ft
EOT at
5,816 ft
Flow Type (1=annulus, 0 = tubing)
0
gas gravity
0.7
Tubing ID, inches
Flow Length, feet
True Vertical Depth, feet
Tubing OD, inches
Casing ID, inches
CO2
0
H2S
0
Flowing Surface Temperature, °F
70
Reservoir Temperature, °F
175
Gas Rate, Mcf/day
Shut In Tubing Pressure, psi
Water Rate, bbls/day
Calculated WGR, bbl/MMcf
0
Example 2:
Calculate BHP at mid-perfs from Surface Pressure
•
Perforated, flow tested for 2 days, then shut in
•
After 30 days, the field reported the shut in tubing pressure is 3,612 psi
•
Estimate reservoir pressure
13
Example 2: Calculated BHP
How accurate is our calculated number? Do we feel confident in this number?
So, again, we ask for a measurement`
Flow Type (1=annulus, 0 = tubing)
0
gas gravity
0.7
Tubing ID, inches
1.995
Flow Length, feet
5,816
True Vertical Depth, feet
7,193
Tubing OD, inches
2.375
Casing ID, inches
4.892
CO2
0
H2S
0
Gas Rate, Mcf/day
0
Shut In Tubing Pressure, psi
3,612
Water Rate, bbls/day
0
Flowing Surface Temperature, °F
70
Reservoir Temperature, °F
175
Calculated WGR, bbl/MMcf
0
Calculated BHP at 7,193 feet, psi
4,354
Reservoir Pressure Gradient, psi/ft
0.61
14
Gauge Depth
feet
Gauge Pressure
psi
Gradient
psi/ft
0
3,612
1,000
3,715
0.103
2,000
3,816
0.101
3,000
3,917
0.101
4,000
4,017
0.100
5,000
4,214
0.197
5,250
4,327
0.452
5,500
4,443
0.464
5,750
4,559
0.464
5,816
4,589
0.455
Given Data
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
3,000
3,200
3,400
3,600
3,800
4,000
4,200
4,400
4,600
4,800
Pressure, psi
Depth, feet
Typical Measured Static BHP Data from the Field
Sometimes, operators do not like to lower tools outside the tubing unnecessarily. All we did was ask for a BHP measurement and we assumed they would measure pressure at Mid-Perfs. Next time, I’ll remember to have that discussion with operations.
Gradient
=
5750
5816
4559
4589
−
−
= 0.455 psi/ft
We are looking for
(1) a fluid level
(2) the deepest pressure measured
(they only measured to 5,816 ft)
-
There is a fluid level, we can see it on the chart and we can see it by calculating pressure gradient between measurements
-
Where is the fluid level?
Somewhere between 4,000 feet and 5,000 feet
15
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Gauge Depth
feet
Gauge Pressure
psi
Gradient
psi/ft
0
3,612
1,000
3,715
0.103
2,000
3,816
0.101
3,000
3,917
0.101
4,000
4,017
0.100
5,000
4,214
0.197
5,250
4,327
0.452
5,500
4,443
0.464
5,750
4,559
0.464
5,816
4,589
0.455
Given Data
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
3,000
3,200
3,400
3,600
3,800
4,000
4,200
4,400
4,600
4,800
Pressure, psi
Depth, feet
Typical Measured Static BHP Data from the Field
We are looking for
(1) a fluid level
(2) the deepest pressure measured
(they only measured to 5,816 ft)
-
There is a fluid level, we can see it on the chart and we can see it by calculating pressure gradient between measurements
-
Where is the fluid level?
Somewhere between 4,000 feet and 5,000 feet (say ~4,800 feet)
So, the BHP we calculated previously is wrong because we assumed a dry gas gradient from the surface to mid-perfs at 7,193 feet
16
My Solution to Example 2
For this calculation, we do not need to use our BHP function
Measured Pressure at 5,816 feet, psi
4,589
Distance from Measured Pressure to Mid-Perfs, feet
1,377 (7,193 - 5,816)
Fluid Gradent Below Measured Pressure, psi/ft
0.455
Incremental pressure below Measure Pressure, psi
626
Estimated BHP at mid-perfs (7,193 ft), psi
5,215 (4,589 + 626)
Reservoir Pressure Gradient, psi/ft
0.72
= 5,215 psi / 7,193 feet = 0.72 psi/ft
If there is an unknown fluid level in the wellbore, then it is difficult to calculate BHP accurately
17
8-5/8” casing at
1,800 feet
Landed Hz @
6,645 feet MD
6,340 feet TVD
TD @ 11,645 feet MD
6,340 feet TVD
90° inclination
336° azimuth
2-3/8” tubing
ID = 1.995”
5-1/2” Casing
ID = 4.892”
Set at 11,645 ft
EOT at
6,645 ft
Example 3:
Calculate BHP During Test
•
Horizontal Well Frac’d in 8 stages, plug and perf style
•
After plugs drilled out, tubing was run (no packer)
•
Well is flowing up tubing
•
Calculate BHP during the test from both the tubing and casing pressure
This is the information that is collected while testing.
date/time
Surface Temp
°F
Gas Rate Mcf/day
Water Rate
bbls/day
Tubing Pressure psi
Casing Pressure psi
8/10/2014 20:00
8/10/2014 21:00
8/10/2014 22:00
8/10/2014 23:00
8/11/2014 0:00
8/11/2014 1:00
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8-5/8” casing at
1,800 feet
Landed Hz @
6,645 feet MD
6,340 feet TVD
TD @ 11,645 feet MD
6,340 feet TVD
90° inclination
336° azimuth
2-3/8” tubing
ID = 1.995”
5-1/2” Casing
ID = 4.892”
Set at 11,645 ft
EOT at
6,645 ft
Example 3:
Calculate BHP During Test
•
Horizontal Well Frac’d in 8 stages, plug and perf style
•
After plugs drilled out, tubing was run (no packer)
•
Well is flowing up tubing
•
Calculate BHP during the test from both the tubing and casing pressure
This is the information that is collected while testing.
date/time
Surface Temp
°F
Gas Rate Mcf/day
Water Rate
bbls/day
Tubing Pressure psi
Casing Pressure psi
8/10/2014 20:00
8/10/2014 21:00
8/10/2014 22:00
8/10/2014 23:00
8/11/2014 0:00
8/11/2014 1:00
Is it clear what the significance is,
whether there is a packer in the hole or not?
BHP from Tubing
BHP from Casing
Flow Type (1=annulus, 0 = tubing)
gas gravity
0.7
0.7
BHT
177
177
Tubing ID, inches
Flow Length, feet
True Vertical Depth, feet
Tubing OD, inches
Casing ID, inches
CO2, %
0
0
H2S, %
0
0
Surface Temperature, °F
Gas Rate, Mcf/day
WGR, bbl/MMcf
8-5/8” casing at
1,800 feet
Landed Hz @
6,645 feet MD
6,340 feet TVD
TD @ 11,645 feet MD
6,340 feet TVD
90° inclination
336° azimuth
2-3/8” tubing
ID = 1.995”
5-1/2” Casing
ID = 4.892”
Set at 11,645 ft
EOT at
6,645 ft
Example 3:
Calculate BHP During Test
•
Horizontal Well Frac’d in 8 stages, plug and perf style
•
After plugs drilled out, tubing was run (no packer)
•
Well is flowing up tubing
•
Calculate BHP during the test from both the tubing and casing pressure
What are the Inputs for our jBHPRESS
Function? This is the information that is collected while testing.
date/time
Surface Temp
°F
Gas Rate Mcf/day
Water Rate
bbls/day
Tubing Pressure psi
Casing Pressure psi
8/10/2014 20:00
8/10/2014 21:00
8/10/2014 22:00
8/10/2014 23:00
8/11/2014 0:00
8/11/2014 1:00
date/time
days
Surface Temp
°F
Gas Rate Mcf/day
Water Rate
bbls/day
WGR bbls/
MMcf
Tubing Pressure psi
Casing Pressure psi
BHP from Tubing
psi
BHP from Casing
psi
8/10/2014 20:00
0.0000
102
2,243
655
292
1,210
1,590
2,007
1,881
8/10/2014 21:00
0.0417
104
2,809
614
219
1,283
1,659
2,061
1,963
8/10/2014 22:00
0.0833
106
3,296
587
178
1,266
1,729
2,040
2,045
8/10/2014 23:00
0.1250
108
3,764
752
200
1,194
1,782
2,089
2,108
8/11/2014 0:00
0.1667
108
4,094
832
203
1,196
1,869
2,164
2,212
8/11/2014 1:00
0.2083
106
4,164
637
153
1,184
1,734
2,049
2,051
8/11/2014 2:00
0.2500
106
4,221
444
105
1,154
1,705
1,912
2,017
8/11/2014 3:00
0.2917
106
4,221
377
89
1,150
1,681
1,867
1,988
8/11/2014 4:00
0.3333
108
4,206
518
123
1,050
1,675
1,854
1,980
8/11/2014 5:00
0.3750
108
4,100
356
87
1,049
1,671
1,743
1,975
8/11/2014 6:00
0.4167
108
4,004
438
109
1,051
1,648
1,784
1,947
8/11/2014 7:00
0.4583
109
3,861
693
179
1,049
1,632
1,917
1,927
8/11/2014 8:00
0.5000
108
3,829
349
91
935
1,612
1,599
1,904
8/11/2014 9:00
0.5417
111
3,676
699
190
962
1,599
1,816
1,887
8/11/2014 10:00
0.5833
115
3,602
735
204
935
1,594
1,803
1,879
8/11/2014 11:00
0.6250
115
3,646
335
92
909
1,578
1,544
1,860
8/11/2014 12:00
0.6667
117
3,610
341
94
880
1,570
1,517
1,849
8/11/2014 13:00
0.7083
117
3,739
655
175
888
1,561
1,730
1,838
8/11/2014 14:00
0.7500
117
3,700
717
194
872
1,556
1,746
1,832
•
This is an example of the kind of data that is being recorded during the flowback after the fracs (cleanup after fracs)
–
Grey cells are input (measured) and white cells numbers that I calculated
•
This is typical flowback data in that it is collected every hour or so
•
Where is the Tubing and Casing Pressures measured?
•
Where is the BHP being calculated? (what depth?)
21
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0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
4,500
4,750
0
1
2
3
4
5
6
7
8
Gas Rate, Mcf/day Pressure, psi WGR, bbl/MMcf
Time, days
Gas Rate
WGR
Tubing Pressure
Casing Pressure
Calc BHP from Tubing
Calc BHP from Casing
•
The solid orange and green lines are the calculated BHP’s from surface Tubing and Casing pressures. They are not going to be an exact overlay, but they should be close.
22
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•
If I’m not happy with how close the BHP calculated fromm Tubing Pressure is to that calculated from Casing Pressure, then I can make some adjustments to “calibrate” the calculations.
•
Everything in the chart below is identical to the previous chart except I changed the Tubing ID from 1.995” to 1.900” which only affected the BHP’s Calculated from the Tubing Pressure
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
4,500
4,750
0
1
2
3
4
5
6
7
8
Gas Rate, Mcf/day Pressure, psi WGR, bbl/MMcf
Time, days
Gas Rate
WGR
Tubing Pressure
Casing Pressure
Calc BHP from Tubing
Calc BHP from Casing
23
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•
Take a look at when the well was shut in (~6.3 hours). Notice that the surface Casing and Tubing Pressure read about the same values? Therefore, the calculated BHP’s will also be about the same. What does this mean?
•
What are flow rate and WGR do we use to calc BHP from Casing Pressure?
•
When the well is shut in, the flow rate up the tubing is also 0 (no friction) and WGR = 0 (same values we use to calc BHP from Casing Pressure – so, when the tubing and casing pressures read the same, it doesn’t necessarily mean there is not fluid level, but it means that if there is a fluid level, it is the same in the annulus and tubing
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
4,500
4,750
4
4.5
5
5.5
6
6.5
7
Gas Rate, Mcf/day Pressure, psi WGR, bbl/MMcf
Time, days
Gas Rate
WGR
Tubing Pressure
Casing Pressure
Calc BHP from Tubing
Calc BHP from Casing
24
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•
Look at the shut in time period at 5.3 hours. Why doesn’t the tubing and casing pressures read the same?
•
The only conclusion is that the fluid level in the annulus and casing are not the same
•
In the way we calculate BHP, we assume there is not a static fluid level, so when the well is shut in, we are assuming a “dry” gas gradient in the tubing or annulus
•
Notice that the BHP calculated from the Tubing is lower than that from the Casing. This is an indication that there is a fluid level in the Tubing that is not in the annulus that we are not taking into account in our calculations
•
It doesn’t conclusively mean there is not fluid in the annulus, but that whatever fluid level there is, it’s higher in the tubing than the annulus
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2,250
2,500
2,750
3,000
3,250
3,500
3,750
4,000
4,250
4,500
4,750
4
4.5
5
5.5
6
6.5
7
Gas Rate, Mcf/day Pressure, psi WGR, bbl/MMcf
Time, days
Gas Rate
WGR
Tubing Pressure
Casing Pressure
Calc BHP from Tubing
Calc BHP from Casing
25
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date/time
days
Surface Temp
°F
Gas Rate Mcf/day
Water Rate
bbls/day
WGR bbls/
MMcf
Tubing Pressure psi
Casing Pressure psi
BHP from Tubing
psi
BHP from Casing
psi
8/17/2014 0:00
6.1667
106
2,566
590
230
853
1,414
1,537
1,667
8/17/2014 1:00
6.2083
108
2,661
702
264
839
1,411
1,597
1,662
8/17/2014 2:00
6.2500
100
1,980
453
229
1,280
1,447
1,964
1,709
8/17/2014 3:00
6.2917
70
0
0
0
1,514
1,506
1,807
1,797
8/17/2014 4:00
6.3333
70
0
0
0
1,545
1,541
1,844
1,840
8/17/2014 5:00
6.3750
70
0
0
0
1,568
1,564
1,872
1,868
8/17/2014 6:00
6.4167
70
0
0
0
1,591
1,582
1,901
1,890
8/17/2014 7:00
6.4583
70
0
0
0
1,601
1,604
1,913
1,916
8/17/2014 8:00
6.5000
70
0
0
0
1,609
1,615
1,923
1,930
8/17/2014 9:00
6.5417
72
939
771
821
846
1,612
1,877
1,925
8/17/2014 10:00
6.5833
93
3,245
841
259
882
1,549
1,772
1,836
8/17/2014 11:00
6.6250
104
4,250
898
211
927
1,509
1,961
1,782
8/17/2014 12:00
6.6667
104
3,727
571
153
857
1,481
1,648
1,748
Here’s what the numbers look like during the second shut in period
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