GPSA ENGINEERING DATABOOK ERRATA(2004 SI Edition)

GPSA ENGINEERING DATABOOK ERRATA (2004 SI Edition) PAGE DESCRIPTION 3-1 Figure 3-1, Change units for LTB 4-18 Figure 4-24, Missing text 4-22 Figure 4-32, Change 0.082 to 0.82 5-18 Equation 5-27, Corrected 6-23 Figure 6-26, Missing text 7-1 Figure 7-1, Change figure reference 7-4 Figure 7-5, Correct equation 7-14 Figure 7-21, Correct figure title 12-1 Figure 12-1, Change figure reference for k 12-12 Figure 12-13, Replaced 12-13 Figure 12-14, Replaced 12-16 Figure 12-17, Missing text 13-8 Figure 13-10, Missing text 13-15 Example 13-3, Change figure reference 18-16 Figure 18-14, Missing text 19-2 Figure 19-1, Missing text 20-21 Example 20-10, Change 1.68 to 16.8 21-7 Figure 21-5, Correct viscosity for MDEA 21-26 Desorex text, Correct units 23-26 Change CO2 in text 23-36 Example 23-11, Change text 24-40 Figure 24-37, Missing text 25-10 Methane-Ethane Binary, Change x-axis scale SECTION 3 Measurement The information presented in this section provides sufficient information for determining flow quantities with a reasonable degree of accuracy, but not necessarily to the accuracy desired for custody transfer. Agreement of acceptable accuracy for cus- tody transfer should be between the parties involved, and sup- plemental information and procedures may be required, such as the API Manual of Petroleum Measurement Standards or corresponding ISO standards. C = Pitot tube flow coefficient C` = the product of multiplying all orifice correction factors CNT = volume indicated by the number of pulses or counts Cpl = liquid pressure correction factor. Correction for the change in volume resulting from application of pressure. Proportional to the liquid compressi- bility factor, which depends upon both relative density and temperature. Cps = correction factor for effect of pressure on steel. See API Manual of Petroleum Measurement Standards, Chapter 12, Section 2 Cg = gravity correction factor for orifice well tester to change from a gas relative density of 0.6 Ctl = liquid temperature correction factor. Proportional to the thermal coefficient which varies with den- sity and temperature Cts = correction factor for effect of temperature on steel Cu = velocity of sound in the gas non-flowing condition. d = orifice diameter, mm D = internal pipe diameter of orifice meter run or prover section, mm DL = Minimum downstream meter tube length, mm Dp = the difference between the flowing pressure and the equilibrium vapor pressure of the liquid. Du = diameter of the meter bore. R = flowing fluid density, kg/m3 e = orifice edge thickness, mm E = orifice plate thickness, mm Em = modulus of elasticity for steel [(206.8)(10 6)] kPa F = liquid compressibility factor Fa = orifice thermal expansion factor. Corrects for the metallic expansion or contraction of the orifice plate. Generally ignored between –20°C and 50°C Fg = relative density factor applied to change from a relative density of 1.0 (air) to the relative density of the flowing gas Fgt = gravity-temperature factor for liquids Fc = orifice calculation factor Fn = numeric conversion factor Fna = units conversion factor for pitot tubes Fpb = pressure base factor applied to change the base pressure from 101.55 kPa (abs) Fpm = pressure factor applied to meter volumes to cor- rect to standard pressure. See API Manual of Petroleum Measurement Standards, Chapter 12, Section 2 Fpv = supercompressibility factor required to correct for deviation from the ideal gas laws = @@@@” 1�Z Fs = steam factor Fsl = orifice slope factor Ftb = temperature base factor. To change the tempera- ture base from 15°C to another desired base Ftf = flowing temperature factor to change from the assumed flowing temperature of 15°C to the ac- tual flowing temperature Ftm = temperature correction factor applied to displace- ment meter volumes to correct to standard tem- perature. See API Manual of Petroleum Measurement Standards, Chapter 12, Section 2 G,G1 = specific gravity at 15°C Gf = specific gravity at flowing temperature H = pressure, mm of mercury hm = differential pressure measured across the orifice plate in mm of mercury at 15°C hw = differential pressure measured across the orifice plate in mm of water at 15°C @@@@@” hwPf = pressure extension. The square root of the differen- tial pressure times the square root of the abso- lute static pressure k = ratio of the specific heat at constant pressure to the specific heat at constant volume K = a numerical constant. Pulses generated per unit volume through a turbine, positive displacement, coriolis or ultrasonic meter Key = Fn (Fc + Fsl) = orifice factor L = distance between upstream and downstream transducer. LTB = Length of tube bundle, in flow conditioner, mm (See Fig. 3-3) MF = meter factor, a number obtained by dividing the actual volume of liquid passed through the meter during proving by the volume registered by the meter P = pressure, kPa (abs) FIG. 3-1 Nomenclature 3-1 Fig. 4-23 gives relative controller gain, integral time, and derivative time for the various control mode combinations for quarter-decay response as related to ultimate controller gain setting, Ku, and ultimate period Pu. Gain settings are also shown in units of proportional band, PB. Fig. 4-24 shows some typical settings for various types of process controllers. Example 4-2 — An example using the Ziegler-Nichols method is given below: For a certain temperature control system, the ultimate sen- sitivity Ku was found to be 1.5 kPa per °C, and the ultimate period Pu was found to be two minutes. A three mode PID con- troller is required. Using Fig. 4-24: Proportional gain Kp: Kp = 0.6 Ku = 0.6 (1.5 kPa/°C) = 0.9 kPa/°C Integral time constant Ti: Ti = Pu/2, Ti = 2/2 = 1.0 minute Derivative time constant Td: Td = Pu/8, Td = 2/8 = 0.25 minutes Control Mode Considerations The process control engineer has the responsibility for matching the many and variable characteristics of the process to be controlled with the most effective control hardware avail- able.6 Fig. 4-25 provides guidelines for choosing the mode of control for various types of applications based upon the proc- ess reaction rate and size and speed of load changes. Special considerations should be made in applying a “split- range” controller. A common example is a column temperature controller on a cryogenic demethanizer. In this system the first half (0-50%) of the controller output actuates the “free” heat ex- change with the incoming feed, and the second half (50-100%) of the controller output actuates the supplemental heat from the hot oil system. Adaptive gain control may be required since the heat- ing value of the hot oil is much greater than that of the gas used in the heat exchange. EMBEDDED ADVANCED CONTROL Embedded advanced control will usually give an improved plant performance over that achievable with traditional tech- niques. By introducing Embedded Advanced Control, a high level of reliability and security is provided to maximize control system uptime. Since embedded advanced control tools have direct access to controller I/O, they may access process meas- urements and actuators with no communication jitter or delay. This allows use of these tools on the fastest processes. CONTROL VALVES Selecting the proper control valve for each application in- volves many factors. The valve body design, actuator style, and plug characteristic are critical items for selection.Proper valve sizing is necessary for accurate, efficient, economical process control. In areas where personnel will be affected, noise pre- diction and control becomes a significant factor. Engineering application guidelines, nomographs, and equa- tions presented in the following pages may be used to deter- mine the correct control valve configuration, size and flow characteristics, and to predict noise levels for most applica- tions. The material presented here may also be used to evalu- ate the performance of valves installed in existing plants. The equations given in this section are used to calculate the flow coefficient (Cv or Cg) required for a valve to pass the re- FIG. 4-22 Typical Responses Obtained When Determining Ultimate Gain and Ultimate Period Mode Kp or PB(%) Ti Td (P) 0.5 Ku 2(PBu) max. zero (PI) 0.45 Ku 2.2(PBu) Pu/1.2 zero (PD) 0.6 Ku 1.65(PBu) max. Pu/8.0 (PID) 0.6 Ku 1.65(PBu) Pu/2.0 Pu/8.0 FIG. 4-23 Ziegler-Nichols Settings for 1/4 Decay Response1 4-18 Process Gain PB(%) Integral Derivative Ti (sec) min/repeat Td (sec) Flow 0.6-0.8 167-125 3.0-1.8 0.05-0.03 0.0 Pressure 5.0 20.0 120-60 2.0-1.0 0.0 T Level emp. 1.0-2.0 0.8-1.2 100-50 125-83 120-30 600-300 2.0-0.5 10.0-5.0 6.0-12 0.6-1.2 FIG. 4-24 Typical Controller Settings with the listed Cv should then be used in the chosen siz- ing equation to calculate a revised, required Cv. This it- eration process continues until the calculated Cv and equals the manufactuer’s listed Cv. 4. For a new valve selection a valve size is typically chosen such that the maximum, calculated Cv is close to 75% to 85% of valve travel.This allows for process variability while maintaining flow capability. The minimum, calculated Cv should typically occur at or about 10% of valve travel. 5. Fp is the Piping Geometry Factor. It corrects the sizing equations for the effects of fittings such as reducers and expanders that are attached to the valve body ends. Fp values can be determined via test or calculated per the ANSI/ISA S75.01 standard. If the valve has no such fit- tings attached, e.g., the nominal value size and nominal pipe size are the same, then Fp = 1.0. Refer to the full standard for the Fp calculations in cases where fittings do exist. Other valve configurations, such as ball and butterfly valves, can be sized in a similar manner using the unique Xc and Cv values derived by the manufacturers. Valve Style Body Size, mm Flow Characteristic raeniLegatnecrePlauqE Globe Cv Xc FL Cv Xc FL 25 8 0.74 0.88 17 0.61 0.84 38 17 0.69 0.84 30 0.70 0.82 50 25 0.70 0.85 62 0.68 0.77 63 49 0.66 0.84 84 0.71 0.81 75 66 0.66 0.82 118 0.70 0.82 100 125 0.67 0.82 181 0.74 0.82 150 239 0.74 0.85 367 0.78 0.84 200 268 0.60 0.85 526 0.74 0.87 Ball 25 16 0.53 0.86 – – – 50 59 0.53 0.81 – – – 75 120 0.50 0.80 – – – 100 195 0.52 0.80 – – – 150 340 0.52 0.80 – – – 200 518 0.54 0.82 – – – 250 1000 0.47 0.80 – – – 300 1530 0.49 0.78 – – – Butterfly 50 60 0.37 0.69 – – – 75 111 0.40 0.69 – – – 100 238 0.40 0.69 – – – 150 635 0.40 0.69 – – – 200 1020 0.40 0.69 – – – 250 1430 0.40 0.69 – – – 300 2220 0.40 0.69 – – – 350 2840 0.40 0.69 – – – 400 3870 0.40 0.69 – – – *At approximately 70% of valve travel. Maximum valve capacity may be estimated using the values given in this figure in conjunction with Fig. 4-29. For a more detailed analysis of capacity capabilities of a given valve at other percentages of travel, consult the valve manufacturer’s data. FIG. 4-32 Typical Cv, Xc� and FL Values for Valves* 4-22 Spherical Radiation Intensity Formula: I � �Wf �NHV �E 14.4 P �R2 Eq 5-20 This equation has been found to be accurate for distances as close to the flame as one flame length. Equation 5-20 is valid so long as the proper value of fraction of heat radiated, E, is inserted. Classically, E has been consid- ered a fuel property alone. Brzustowski et al.10 experimentally observed a dependence of E on jet exit velocity. Other authors have presented models that consider the carbon particle con- centration in the flame. The fraction of heat radiated is a func- tion of many variables including gas composition, tip diameter, flare burner design, flowrate and velocity, flame temperature, air-fuel mixing, and steam or air injection; therefore a flare supplier should be consulted to determine the specific values for a given application. A list of vendor recommended fraction of heat radiated values for the most frequently flared gases is shown in Fig. 5.20. To calculate the intensity of radiation at different locations, it is necessary to determine the length of the flame and its angle in relation to the stack (see Fig. 5-21). A convenient ex- pression to estimate length of flame, Lf, is shown below, based on information from equipment suppliers. Lf � �0.12 �d ”@@@$Pw1400 Eq 5-21 or from API 521 Lf � 2.14 � Qr u 10 6 0.474 Eq 5-22 For conventional (open pipe) flares, an estimate of total flare pressure drop is 1.5 velocity heads based on nominal flare tip diameter. The pressure drop equivalent to 1 velocity head is given by: $Pw � �0.102 R V2 2 � R V2 19.62 Eq 5-23 $Pw is the pressure drop at the tip in mm of water. After de- termining tip diameter, d, using Eq 5-23, and the maximum required relieving capacity, flame length for conditions other than maximum flow can be calculated using Eq 5-21 and Eq 5-22. Common practice is to use tip velocities of up to Mach 0.5 for short term emergency flows and Mach 0.2 for maximum continuous flowing. d � � @@@@@@@@@” 3.23 u 10 5 u WP2 u M u ¤¥¦ Z u Tk u MW³´µ 0.5 u1000 Eq 5-24 Sonic velocity of a gas is given by: a � ”@@@@k RoMW T Eq 5-25 The center of the flame is assumed to be located at a distance equal to 1/3 the length of the flame from the tip. The angle of the flame results from the vectorial addition of the velocity of the wind and the gas exit velocity. Q � tan 1 ¤ ¥ ¦ Vw Vex ³ ´ µ Eq 5-26 Vex � 168”@@$PW1400 Eq 5-27 Note: API gives a greater lean angle The coordinates of the flame center with respect to the tip are: Xc � �Lf � 3 �sin Q Eq 5-28 Yc � �Lf �3 �cos Q Eq 5-29 The distance from any point on the ground level to the center of the flame is: R � @@@@@@@@@@@@@@@” �X Xc 2 � �Hs � Yc 2 Eq 5-30 Q Lf yC XC d HS + YC R X - XC X HS WIND Courtesy American Petroleum Institute FIG. 5-21 Dimensional References for Sizing a Flare Stack Carbon Monoxide 0.075 Hydrogen 0.075 Hydrogen Sulfide 0.070 Ammonia 0.070 Methane 0.10 Propane 0.11 Butane 0.12 Ethylene 0.12 Propylene 0.13 The maximum value of E for any gas is 0.13. FIG. 5-20 Fraction of Heat Radiated Values for Flared Gases 5-18 6-23 Diam. of Sphere Depth of Liquid, meters meters 0.5 1 2 4 6 8 10 12 14 16 18 20 25 30 35 40 45 50 0.5 0.065 – 1 0.262 0.524 – 2 0.654 2.094 4.189 – 4 1.440 5.236 16.755 33.510 – 6 2.225 8.378 29.322 83.776 113.097 – 8 3.011 11.519 41.888 134.041 226.194 268.082 – 10 3.796 14.661 54.454 184.307 339.292 469.144 523.598 – 12 4.581 17.802 67.021 234.572 452.389 670.206 837.757 904.778 – 14 5.367 20.944 79.587 284.837 565.486 871.268 1 151.916 1 357.167 1 436.754 – 16 6.152 24.086 92.153 335.103 678.583 1 072.329 1 466.075 1 809.556 2 052.505 2 144.66 – 18 6.938 27.227 104.720 385.368 791.681 1 273.391 1 780.234 2 261.945 2 668.257 2 948.91 3 053.63 – 20 7.723 30.369 117.286 435.634 904.778 1 474.453 2 094.393 2 714.334 3 284.009 3 753.15 4 071.50 4 188.79 – 25 9.687 38.223 148.702 561.297 1 187.521 1 977.107 2 879.791 3 845.306 4 823.388 5 763.77 6 616.19 7 330.38 8 181.22 – 30 11.650 46.077 180.118 686.961 1 470.264 2 479.762 3 665.188 4 976.279 6 362.767 7 774.39 9 160.88 10 471.97 13 089.96 14 137.16 – 35 13.614 53.931 211.534 812.625 1 753.007 2 982.416 4 450.586 6 107.251 7 902.146 9 785.01 11 705.56 13 613.56 17 988.69 21 205.73 22 449.28 – 40 15.577 61.785 242.950 938.288 2 035.750 3 485.071 5 235.983 7 238.223 9 441.525 11 795.62 14 250.25 16 755.15 22 907.43 28 274.31 32 070.40 33 510.29 – 45 17.541 69.639 274.366 1 063.952 2 318.493 3 987.725 6 021.381 8 369.196 10 980.904 13 806.24 16 794.94 19 896.74 27 816.16 35 342.89 41 691.52 46 076.65 47 712.90 – 50 19.504 77.493 305.781 1 189.615 2 601.237 4 490.379 6 806.778 9 500.168 12 520.283 15 816.86 19 339.63 23 038.33 32 724.90 42 411.47 51 312.64 58 643.01 63 617.20 65 449.79 FIG. 6-26 Partial Volumes of Spheres — Cubic Meters Tank Width, m Tank Length, m 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 0.5 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 1.0 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 1.5 1.50 3.00 4.50 6.00 7.50 9.00 10.50 12.00 2.0 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00 2.5 2.50 5.00 7.50 10.00 12.50 15.00 17.50 20.00 3.0 3.00 6.00 9.00 12.00 15.00 18.00 21.00 24.00 3.5 3.50 7.00 10.50 14.00 17.50 21.00 24.50 28.00 4.0 4.00 8.00 12.00 16.00 20.00 24.00 28.00 32.00 4.5 4.50 9.00 13.50 18.00 22.50 27.00 31.50 36.00 5.0 5.00 10.00 15.00 20.00 25.00 30.00 35.00 40.00 5.5 5.50 11.00 16.50 22.00 27.50 33.00 38.50 44.00 6.0 6.00 12.00 18.00 24.00 30.00 36.00 42.00 48.00 6.5 6.50 13.00 19.50 26.00 32.50 39.00 45.50 52.00 7.0 7.00 14.00 21.00 28.00 35.00 42.00 49.00 56.00 7.5 7.50 15.00 22.50 30.00 37.50 45.00 52.50 60.00 8.0 8.00 16.00 24.00 32.00 40.00 48.00 56.00 64.00 8.5 8.50 17.00 25.50 34.00 42.50 51.00 59.50 68.00 9.0 9.00 18.00 27.00 36.00 45.00 54.00 63.00 72.00 9.5 9.50 19.00 28.50 38.00 47.50 57.00 66.50 76.00 10.0 10.00 20.00 30.00 40.00 50.00 60.00 70.00 80.00 10.5 10.50 21.00 31.50 42.00 52.50 63.00 73.50 84.00 11.0 11.00 22.00 33.00 44.00 55.00 66.00 77.00 88.00 11.5 11.50 23.00 34.50 46.00 57.50 69.00 80.50 92.00 12.0 12.00 24.00 36.00 48.00 60.00 72.00 84.00 96.00 1 cu meter = 264.172 U.S. gal. = 219.9692 Imperial gallons = 6.2898 bbls (42 U.S. gals) FIG. 6-27 Approximate Contents (Cubic Meters) of Rectangular Tanks Per Meter of Liquid* SECTION 7 Separation Equipment PRINCIPLES OF SEPARATION Three principles used to achieve physical separation of gas and liquids or solids are momentum, gravity settling, and coa- lescing. Any separator may employ one or more of these prin- ciples, but the fluid phases must be "immiscible" and have dif- ferent densities for separation to occur. A = area, m2 Ap = particle or droplet cross sectional area, m 2 C = empirical constant for separator sizing, m/h C* = empirical constant for liquid-liquid separators, (m3 u mPa u s)/(m2 u day) C` = drag coefficient of particle, dimensionless (Fig. 7-3) Di = separator inlet nozzle diameter, mm Dp = droplet diameter, m Dv = inside diameter of vessel, mm Gm = maximum allowable gas mass-velocity necessary for particles of size Dp to drop or settle out of gas, kg/(h u m2) g = acceleration due to gravity, 9.81 m/s2 Hl = width of liquid interface area, m J = gas momentum, kg/(m u s2) K = empirical constant for separator sizing, m/s KCR = proportionality constant from Fig. 7-5 for use in Eq 7-5, dimensionless L = seam to seam length of vessel, mm Ll = length of liquid interface, mm M = mass flow, kg/s Mp = mass of droplet or particle, kg MW = molecular mass, kg/(kg mole) P = system pressure, kPa(abs) Q = estimated gas flow capacity, (Sm3/day)/m2 of filter area QA = actual gas flow rate, m 3/s R = gas constant, 8.31 [kPa(abs) u m3]/[K u kg mole] Re = Reynolds number, dimensionless Shl = relative density of heavy liquid, water = 1.0 Sll = relative density of light liquid, water = 1.0 T = system temperature, K t = retention time, minutes U = volume of settling section, m3 Vt = critical or terminal gas velocity necessary for particles of size Dp to drop or settle out of gas, m/s W = total liquid flow rate, m3/day Wcl = flow rate of light condensate liquid, m 3/day Z = compressibility factor, dimensionless Greek: Rg = gas phase density, kg/m3 Rl � liquid phase density, droplet or particle, kg/m3 M = viscosity of continuous phase, mPa u s Filter Separators: A filter separator usually has two com- partments. The first compartment contains filter-coalescing elements. As the gas flows through the elements, the liquid particles coalesce into larger droplets and when the drop- lets reach sufficient size, the gas flow causes them to flow out of the filter elements into the center core. The particles are then carried into the second compartment of the vessel (containing a vane-type or knitted wire mesh mist extrac- tor) where the larger droplets are removed. A lower barrel or boot may be used for surge or storage of the removed liquid. Flash Tank: A vessel used to separat