Example 19- 7 — Oil absorption is to be used to recover 75 percent of the propane from 100 moles of the rich gas stream shown below. The absorber is to have six theoretical plates. What oil circulation rate is to be used if the average temperature and pressure of the absorber are 104°F and 1,000 psig? The entering lean oil is assumed to be completely stripped or denuded of rich gas components. What will be the composition of the residue gas leaving the absorber? Solution Steps
Since higher oil rates require more energy for heating, cooling, and pumping, the optimum design is usually one that uses the minimum possible oil rate with a reasonable size absorber. The lowest molecular weight lean oil should be used. This will be fixed by oil vapor pressure and absorber operating temperature. Most problems in absorber operation center around oil quality and rates. Proper stripping of the oil is necessary to minimize lean oil losses to the gas and to maximize absorption capacity.
Using the equilibrium ratio charts (Section 25), obtain the K-value for each component at 104 °F and 1,000 psig. From Fig. 19-51 at Ea = 0.75, A = 0.80
In a calculation sense, a stripper is simply an upside-down absorber. For hand calculations, a stripping factor is defined as
Using Eq 19-29: Lo = (0.8) (0.37) (100) = 29.6 moles/hr (based on 100 moles of gas) Using Eq 19-28, the oil rate calculated and the component K-values determine the absorption factor "A" for the remaining components. For example, for methane:
Using the absorption-factor values read values of E a for each component (Fig. (Fig. 19-51). 19-51). Solve Eq. 19-30 for each component to determine the moles of components in the residue gas, Y 1. For example, for methane: Y n + 1 − Y o
=
90.6 − Y 1 = 0.091 90.6 − 0
Y 1 = 82.36 Note: For this example, Y o = 0 since entering lean oil is assumed completely stripped of rich gas components. This assumption will not be true for all cases. Calculate the moles of each component in the rich oil. For example, for methane: l =
Comp
Y n + 1 − Y 1 + Y o = 90.6 − 82.36 + 0 = 8.24 Mol %
K
A
Ea
Y 1
l
3.25
0.091
0.091
82.36
8.24
C1
90.6
C2
4.3
0.9
0.329
0.329
2.89
1.41
C3
3.2
0.37
0.80
0.75
0.80
2.40
iC4
0.5
0.21
1.41
0.96
0.02
0.48
nC4
1.0
0.17
1.74
0.985
0.015
0.985
C6
0.4
0.035
8.46
1.0
0.0
0.40
86.085
13.915
Total
100.0
ST =
KV L
then: X m + 1 − X 1 X m + 1 − Y o
Eq 19-31
=
+1 Sm − ST T +1 Sm −1 T
= Es
Eq 19-32
Fig. 19-51 can be used to perform stripper calculations in a similar manner to absorber calculations.
29.6 A = = 0.091 3.25 (100)
Y n + 1 − Y 2
STRIPPER CALCULATIONS
The use of an average absorption factor, as defined in Eq 19-28, ignores the change in gas volume from inlet to outlet. Also, the assumptions of average temperature and K-values can cause significant errors in the preceding calculation method. Fig. 19-51 can also be used to determine the trays required for a given lean oil r ate or to calculate recoveries with a given oil rate and tray count. Fig. 19-51 shows that oil rate declines with increasing number of trays and that beyond about eight theoretical trays little increase in efficiency is achieved.
SOUR WATER STRIPPERS Sour water is a term used for water containing dissolved hydrogen sulfide. Facilities Facilities for processing sour gas may have several sources of sour water. water. These include water from inlet separators, water from compressor discharge scrubbers, quench water from certain Claus unit tail-gas cleanup processes, and water from the regeneration of solid bed product treaters or dehydrators. In some plants it is possible to dispose of this water by using it for makeup to the gas treating solution. However, most sour gas plants have an excess of water and the hydrogen sulfide must be removed to a level of 1 to 2 ppmw before disposing of the water. Sour water strippers are used for this purpose. Sour water strippers commonly have 10 to 15 trays or 20 to 30 feet of packing. The feed enters at the top and heat is supplied either by a reboiler or by steam injection directly below the bottom tray tray.. Typical operating conditions are: Pressure, psig Feed Temperature, °F Bottom Temperature, °F Reboil Heat, Btu/gal. Residual H2S, ppmw
10 200 240 1000 0.5
-
15 230 250 2000 2.0
Overhead vapors from sour water strippers contain hydrogen sulfide, steam, trace amounts of hydrocarbons and, in some plants, carbon dioxide. These vapors are usually sent to the regenerator (still) condenser in plants using aqueous treating solutions. Alternatively Alternatively, the vapors may be sent directly to the sulfur recovery unit, or incinerated if emission standards are not exceeded. Foaming occurs in sour water strippers and the tower diameter should be based on operation at 50 to 70 percent of the flooding loads for a non-foaming system. 25 The required number of theoretical trays and stripping vapor quantity can be calculated as shown in the following example. However, the results of such calculations must be used only as a guide to the relative effects of changing vapor rates
FIG. 19-51 Absorption and Stripping Factor Correlation
and trays. This is because tray efficiencies or packing HETPs are not known accurately and the effec ts of other components in the sour water change the apparent solubility of hydrogen sulfide. Ammonia, which is common in refinery sour waters, can increase the hydrogen sulfide solubility by a factor of 10 or more. A more detailed design procedure is then required for refining sour water strippers than that given in the following example.26
Example 19-8 — Sour water containing 2500 ppmw of hydrogen sulfide is to be stripped to 1.5 ppmw. Enough indirect reboiler heat is provided to allow 0.75 pounds of steam to leave the top tray for each gallon of feed. The feed r ate is 10 gpm and the tower top is to operate at 21.0 psia. Determine the number of theoretical trays required. Set desired overall material balance:
m
Es
1
0.98891
2
0.99988
3
0.99999
Two theoretical trays would be required for the stated conditions. Since tray efficiencies or packing HETPs are not predictable, 10 actual trays or 20 feet of packing would be used. The relative effect of various operating pressures and reboiler heat rates can be estimated by the above method.
FIG. 19-52 Henry s Constants for H2S in Water ’
Feed = 10 gpm (8.33 lb/gal) (60 min/hr) = 5000 lb/hr Overhead steam = 10 (60) 0.75 = 450 lb/hr Feed lb/hr 12.50 4987.50 5000.00
H2S Water
Bottoms lb/hr 0.007 4537.500 4537.507
Overhead lb/hr 12.493 450.000 462.493
Required fraction of H2S to be stripped: 12.493/12.50 = 0.99944 Estimate top temperature: Fraction water vapor in overhead 450/462.493 = 0.973 Partial pressure water in overhead 0.973 (21) = 20.4 psia Temperature (from steam table, Fig. 24-37) at 20.4 psia = 229°F Estimate the K-value for H 2S at top conditions: K = Henry’s Constant/Total pressure Henry’s Constant for H2S at 229°F = 2.05 (104) psia (Fig. 19-52) K = 2.05 (104)/21.0 = 976.2
Temp, °F
H (H2S), psia
100
1.10 (10 )
200
1.82 (10 )
300
2.6 (104)
4 4
REFERENCES 1. Chien, H. H. Y., "A Rigorous Method for Calculating Minimum Reflux Rates in Distillation", AIChE Jour. 24, July, 1978. 2. Chien, H. H. Y., "A Rigorous Calculation Method for the Minimum Stages in Multicomponent Distillation", Chem. Eng. Sci. 28, 1967-74, 1973. 3. Fenske, M. R., "Fractionation of Straight-Run Pennsylvania Gasoline", Ind. Eng. Chem. 24, 482-5, 1932. 4. Winn, F. W., "New Relative Volatility Method for Distillation Calculations", Pet. Refiner. 37(5), 216-218, 1958. 5. Underwood, A. J. V., "Fractional Distillation of Multicomponent Mixtures", Chem. Eng. Prog. 44, 603-14, 1948. 6. Erbar, J. H., and Maddox, R. N., "Latest Score: Reflux vs. Trays", Petr. Refiner 40(5), 183-188, 1961. 7. Fair, J. R., and Bolles, W. L., "Modern Design of Distillation Columns", Chem. Engr. 75(9), 156-178, April 22, 1968. 8. Katz, D. L., et al., "Handbook of Natural Gas Engineering", McGraw-Hill, 1959.
V = mols vapor leaving top tray
9. Koch Engineering Co., "Flexitray Design Manual", 1982.
12.493 450 + = 25.37 34 18
10. Glitsch, Inc., "Ballast Tray Design Manual", Third Edition.
=
L = mols liquid to top tray 12.5 4987.5 = + = 277.5 34 18 Use Eq 19-31 to calculate fraction H2S stripped: ST =
(976) (25.37)
277.5 m + 1)
Es =
S(T
m + 1)
S(T
= 89.2
− ST −1
Assume various values for "m" and calculate "Es": Results are:
11. Nutter Engineering, "Float Valve Design Manual", Aug., 1981. 12. AIChE, "Bubble-Tray Design Manual", New York, 1958. 13. Smith, B. D., "Design of Equilibrium Stage Processes", McGrawHill, 1963. 14. Vital, T. J., et al., "Estimating Separation Efficiency", Hyd. Proc. 63, 147-153 Nov., 1984. 15. O’Connell, H. E., "Plate Efficiency of Fractionating Columns and Absorbers", Trans. AIChE 42, 741-755, 1946. 16. Eckert, J. S., "Selecting the Proper Distillation Column Packing", Chem. Eng. Prog. 66(3), 39, 1970. 17. Vital, T. J., et al., "Estimating Separation Efficiency", Hyd. Proc. 63, 75-78 Dec., 1984. 18. Eckert, J. S., "Tower Packings . . . Comparative Performance", Chem. Eng. Prog. 59(5), 76-82, 1963.
