6 Mon Feb 9 - Comparing Calculated to Measured Values

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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 26
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