86 Design of GAS-HANDLING Systems and Facilities [text continued from page 83) Generally, the following design criteria should be provided to the man- ufacturers or vendors for sizing an exhaust heat recovery unit. 1. Total heat duty required to heat the fluid 2. Properties of the fluid to be heated 3. The outlet temperature of the heated fluid 4. Operational relationships between heat sources and users (e.g., which users continue to operate when sources shut down?) 5. Exhaust gas flow rates at anticipated ambient and at various loads from maximum to minimum 6. Exhaust gas temperature at anticipated ambient and at various loads 7. Maximum exhaust back pressure 8. Ambient temperature range The design of heaters and waste heat recovery units is beyond the scope of this book. Sizing and design are best left to manufacturers, However, the concepts discussed in this chapter and in Chapter 2 can be used to verify the manufacturer's proposals. HEAT EXCHANGER EXAMPLE PROBLEM Design a seawater cooler to cool the total stream from the example field in its later stages of life from a flowing temperature of 175°F to a temperature of 100°F to allow further treating. Given: Inlet 100 MMscfd at 0.67 SG (from Table 2-10) 6,000 bopd at 0.77 SG 15 bbl water/MMscf T, = 175°F P, = 1,000 psig Water vapor in gas = 60 Ib/MMscf (See Chapter 4.) Outlet T 2 =100°F P2 = 990 psig Water vapor in gas = 28 Ib/MMscf (See Chapter 4.) Seawater T 3 = 75°F Limit temperature rise to 10°F Use 1-in. OD 10 BWG Tubes on iM-in. Pitch Heat Exchangers 87 PlpJMejQi 1. Calculate water flow rate in outlet and water vapor condensed. 2. Calculate heat duty. 3. Determine seawater circulation rate. 4. Pick a type of exchanger and number of tubes required. Solution: 1. Calculate free water and water vapor flow rates. Water flow rate in inlet: Free water = (100 MMscfd)(15 bbl/MMscfd) = 1,500 bwpd Water flow rate in outlet: Free water = 1,500 bwpd Water vapor condensed: Water flow rate in outlet: 2. Calculate heat duty a. Gas duty T, = 635°R T 2 = 560°R T av =597.5°R P c = 680 psia (Table 2-10) P R = P/P C =1.47 T r = 375°R (Table 2-10) T R = T av /T c = 1.59 q g = 41.7(AT)C g Q g C g = 2.64 [29 x S x C -f AC p j C - 0.528 Btu/lb°F (Figure 2-14) b. Condensate duty c. Free water duty d. Water latent heat duty e. Total heat duty 3. Water circulation rate Limit AT for water to 10°F to limit scale. 4. Heat exchanger type and number of tubes Choose TEMA R because of large size. Select type AFL because of low temperature change and LMTD correction factor. Heat Exchangers 89 The water is corrosive and may deposit solids. Therefore, flow water through tubes and make the tubes 70/30 Cu/Ni. Flow the gas through the shell. Calculate LMTD: Correction factor (Figure 3-10): Calculate number of tubes: 90 Design of GAS-HANDLING Systems and Facilities From Table 3-4 for 1-in. OD, IM-in, square pitch, fixed tube sheet, four passes, shell ID = 29 in. Use 39-in. ID x 20 ft Lg w/682 1-in. OD, 10 BWG tubes VA-'m., square pitch with four tube passes: Check the water velocity in tubes. From Volume 1: u There are four passes. Thus, 682/4 tubes are used in each pass, Comments About Example Once a specific heat exchanger is chosen, the flow per tube is known, so it is possible to use the correlations of Chapter 2 to calculate a more precise overall heat transfer coefficient (U). An example of calculation of U is given in Chapter 5. Note that more than 30% of the heat duty was required to cool the water and condensate. If the liquids had first been separated, a smaller exchanger and lower seawater flow rate could have been used. In most gas facilities, where cooling is required, the cooler is placed downstream of the first sep- arator for this reason. Often an aerial cooler is used for this service. Heat Exchangers 91 In this example we selected a final outlet temperature of 100°F. This would be sufficiently low if the gas were only going to be compressed and dehydrated. For our case, we must also treat the gas for H 2 S and CO 2 removal (Chapter 7). If we chose an amine unit, which we will in all like- lihood, the heat of the reaction could heat the gas more than 10° to 20°F, making the next step, glycol dehydration, difficult (Chapter 8). In such a case, it may be better to cool the gas initially to a lower temperature so that it is still below 110°F at the glycol dehydrator. Often this is not pos- sible, since cooling water is not available and ambient air conditions are in the 95 °F to 100°F range. If this is so, it may be necessary to use an aerial cooler to cool the gas before treating, and another one to cool it before dehydration. CHAPTER 4 Hydrates * Resembling dirty ice, hydrates consist of a water lattice in which light hydrocarbon molecules are embedded. They are a loosely-linked crys- talline chemical compound of hydrocarbon and water called cathrates, a term denoting compounds that may exist in stable form but do not result from true chemical combination of all the molecules involved. Hydrates normally form when a gas stream is cooled below its hydrate formation temperature. At high pressure these solids may form at temperatures well above 32°F. Hydrate formation is almost always undesirable because the crystals may cause plugging of flow lines, chokes, valves, and instrumen- tation; reduce line capacities; or cause physical damage. This is especially true in chokes and control valves where there are large pressure drops and small orifices. The pressure drops cause the temperature to decrease, and the small orifices are susceptible to plugging if hydrates form. Hydrate formation leading to flow restrictions is referred to as "freezing." The two major conditions that promote hydrate formation are (1) the gas being at the appropriate temperature and pressure, and (2) the gas being at or below its water dew point with "free water" present. For any particular composition of gas at a given pressure there is a temperature below which hydrates will form and above which hydrates will not form. As the pressure increases, the hydrate formation temperature also increases. If there is no *Reviewed for the 1999 edition by Dennis A. Crupper of Paragon Engineering Services, Inc. 92 Hydrates 93 free water, that is, liquid water, hydrates cannot form. Secondary condi- tions such as high gas velocities, agitation of any type, and the formation of a nucleation site may also help form hydrates. These secondary condi- tions are almost always present in the process piping stream. Methods of preventing hydrate formation include adding heat to assure that the temperature is always above the hydrate formation temperature, lowering the hydrate formation temperature with chemical inhibition, or dehydrating the gas so that water vapor will not condense into free water. It is also feasible to design the process so that if hydrates form they can be melted before they plug equipment. Before choosing a method of hydrate prevention or dehydration, the operating system should be optimized so as to minimize the necessary treating. Some general factors to consider include the following: (1) reduce pressure drops by minimizing line lengths and restrictions, (2) take required pressure drops at the warmest conditions possible, and (3) check the economics of insulating pipe in cold areas. This chapter discusses the procedures used to calculate the temperature at which hydrates will form for a given pressure (or the pressure at which hydrates will form for a given temperature), the amount of dehydration required to assure that water vapor does not condense from a natural gas stream, and the amount of chemical inhibitor that must be added to lower the hydrate formation temperature. It also discusses the temperature drop that occurs as gas is expanded across a choke. This latter calculation is vital to the calculation of whether hydrates will form in a given stream. The next chapter discusses the use of LTX units to melt the hydrates as they form, and the use of indirect fired heaters to keep the gas temperature above the hydrate formation temperature. Chapter 8 describes processes and equipment to dehydrate the gas and keep free water from forming. DETERMINATION OF HYDRATE FORMATION TEMPERATURE OR PRESSURE Knowledge of the temperature and pressure of a gas stream at the well- head is important for determining whether hydrate formation can be expected when the gas is expanded into the flow lines. The temperature at the wellhead can change as the reservoir conditions or production rate changes over the producing life of the well. Thus, wells that initially flowed at conditions at which hydrate formation in downstream equipment was not expected may eventually require hydrate prevention, or vice versa. 94 Design of GAS-HANDLING Systems and Facilities If the composition of the stream is known, the hydrate temperature can be predicted using vapor-solid (hydrate) equilibrium constants. The basic equation for this prediction is: where Y n = mol fraction of hydrocarbon component n in gas on a water-free basis K n = vapor-solid equilibrium constant for hydrocarbon component n The vapor-solid equilibrium constant is determined experimentally and is defined as the ratio of the mol fraction of the hydrocarbon component in gas on a water-free basis to the mol fraction of the hydrocarbon com- ponent in the solid on a water-free basis. That is: where x n = mol fraction of hydrocarbon component in the solid on a water-free basis Graphs giving the vapor-solid equilibrium constants at various temper- atures and pressures are given in Figures 4-1 through 4-4. For nitrogen and components heavier than butane, the equilibrium constant is taken as infinity. The steps for determining the hydrate temperature at a given system pressure are as follows: 1. Assume a hydrate formation temperature. 2. Determine K n for each component. y 3. Calculate -~ for each component. K n y n 4. Sum the values of ——. K n 5. Repeat steps 1-4 for additional assumed temperatures until the sum- y mation of — — is equal to 1.0 K n Hydrates 95 Figure 4-1. Vapor-solid equilibrium constant for (a) methane, (b) ethane, and n- butane. (From Gas Processors Suppliers Association, Engineering Data Book.} [...]... Y/K =1. 0at74 0 ]F yn/i . linearly, y n , Mole Fraction in Gas 0. 014 4 0.0403 0.000 019 0. 855 5 0. 057 4 0. 017 9 0.00 41 0.00 41 0.0063 1. 0000 Y /K= 1. 0at74 0 ] At 70 Kn Infinity Infinity 0.3 0. 95 0.72 0. 25 0 . 15 0.72 Infinity F °F y n /i< n 0.00 0.00 0.00 0.90 0.08 0.07 0.03 0.00 0.00 J.08 At . glycol MW 32.04 46,07 60 .10 62.07 76 .10 10 6 .10 K 2,3 35 2,3 35 2,3 35 2,200 3 ,59 0 4,370 where AT = depression of hydrate formation temperature, °F MW = molecular weight of inhibitor (Table 4- 2) K = constant. (Courtesy of Smith Industries, Inc .) 10 0 Design of GAS-HANDLINCr Systems and facilities by Figure 4-6. The graph shows the water content in pounds of water per MMscf of saturated