8 gas dehydration
Post on 28-Apr-2015
Embed Size (px)
CATR HP E 8 Gas DehydrationGas dehydration is the process of removing water vapor from a gas stream to lower the temperature at which water will condense from the stream. This temperature is called the "dew point" of the gas. Most gas sales contracts specify a maximum value for the amount of water vapor allowable in the gas. Typical values are 7 lb/MMscf in the Southern U.S., 4 lb/MMscf in the Northern U.S. and 2 to 4 lb/MMscf in Canada. These values correspond to dew points of approximately 32F for 7 Ib/ MMscf, 200F for 4 Ib MMscf, and 0 0 F for 2 lb/MMscf in a 1,000 psi gas line. Dehydration to dew points below the temperature to which the gas will be subjected will prevent hydrate formation and corrosion from condensed water. The latter consideration is especially important in gas streams containing CO2 or H2S where the acid gas components will form an acid with the condensed water. The capacity of a gas stream for holding water vapor is reduced as the stream is compressed or cooled. Thus, water can be removed from the gas stream by compressing or cooling the stream. However, the gas stream is still saturated with water so that further reduction in temperature or increase in pressure can result in water condensation. This chapter discusses the design of liquid glycol and solid bed dehydration systems that are the most common methods of dehydration used
*Reviewed for the 1999 edition by Lindsey S. Stinson of Paragon Engineering Services, Inc.
for natural gas. In producing operations gas is most often dehydrated by contact with triethylene glycol. Solid bed adsorption units are used where very low dew points are required, such as on the inlet stream to a cryogenic gas plant where water contents of less than 0.05 lb/MMscf may be necessary. WATER CONTENT DETERMINATION The first step in evaluating and/or designing a gas dehydration system is to determine the water content of the gas. The water content of a gas is dependent upon gas composition, temperature, and pressure. For sweet natural gases containing over 70% methane and small amounts of "heavy ends," the McKetta-Wehe pressure-temperature correlation, as shown in Figure 8-1, may be used. As an example, assume it is desired to determine the water content for a natural gas with a molecular weight of 26 that is in equilibrium with a 3% brine at a pressure of 3,000 psia and a temperature of 1500F. From Figure 8-1 at a temperature of 1500F and pressure of 3,000 psia there is 104 Ib of water per MMscf of wet gas. The correction for salinity is 0.93 and for molecular weight is 0.98. Therefore, the total water content is 104 x 0.93 x 0.98 = 94.8 lb/MMscf. A correction for acid gas should be made when the gas stream contains more than 5% CO 2 and/or H 2 S. Figures 8-2 and 8-3 may be used to determine the water content of a gas containing less than 40% total concentration of acid gas. As an example, assume the example gas from the previous paragraph contains 15% H2S. The water content of the hydrocarbon gas is 94.8 lb/MMscf. From Figure 8-3, the water content of H2S is 400 lb/MMscf. The effective water content of the stream is equal to (0.85)(94.8) + (0.15)(400) or 141 lb/MMscf. GLYCOL DEHYDRATION By far the most common process for dehydrating natural gas is to contact the gas with a hygroscopic liquid such as one of the glycols. This is an absorption process, where the water vapor in the gas stream becomes dissolved in a relatively pure glycol liquid solvent stream. Glycol dehydration is relatively inexpensive, as the water can be easily "boiled" out of the glycol by the addition of heat. This step is called "regeneration" or "reconcentration" and enables the glycol to be recovered for reuse in absorbing additional water with minimal loss of glycol.
Water Content of Hydrocarbon Gas
C ret n f r Gs Gat o c o a rv o i i y CG
Gs Gat a rv i y Meur Wgt oca eh l l i C ret n f r S l iy o c o at o i i n jaieM UJOJd O22H _ s auug Luoj-j O H T t l S d in Bn , % oa o s r e i l i HYDRATE FORMATION LINE Warning: D s e lines are ah d meta-stable equilibrium. Actual equilibrium is lower water content. Angle is a. function of composition. Position of this line is a function of g s a composition* W t r c ne t of natural g s s with a o t ns e ae c re t n for salinity and r l tv d n iy or co s i eai e e s . t At r MK t and Wh, Hdoab n fe c ea ee y r c r o Poes g A g s 1958 r c sn , u ut i . Tmea r. F e prt e u Figure 8-1. McKetta-Wehe pressure-temperature correlation. (From Gas Suppliers Association, Engineering Data Book, 10th Edition.) Processors Lb water/million cu ft of wet gas at 6OT and 14 7 psia
Effective water content, tb/MMscf ( 14.7 psia and 600P
Pressure, psia Figure 8-2. Effective water content of CO2. (From Gas Processors Suppliers Association, Engineering Data Book, 10th Edition.) Process Description
Most glycol dehydration processes are continuous. That is, gas and glycol flow continuously through a vessel (the "contactor" or "absorber") where they come in contact and the glycol absorbs the water. The glycol flows from the contactor to a "reboiler" (sometimes called "reconcentrator" or "regenerator") where the water is removed or "stripped" from the glycol and is then pumped back to the contactor to complete the cycle. Figure 8-4 shows a typical trayed contactor in which the gas and liquid are in counter-current flow. The wet gas enters the bottom of the contactor and contacts the "richest" glycol (glycol containing water in solution)
Effective water content, Ib/MMscf (a 14.7 psia and 600F
Pressure, psia Figure 8-3. Effective water content of H2S. (From Gas Processors Suppliers Association, Engineering Data Book, 10th Edition.)
just before the glycol leaves the column. The gas encounters leaner and leaner glycol (that is, glycol containing less and less water in solution), as it rises through the contactor. At each successive tray the leaner glycol is able to absorb additional amounts of water vapor from the gas. The counter-current flow in the contactor makes it possible for the gas to transfer a significant amount of water to the glycol and still approach equilibrium with the leanest glycol concentration. The contactor works in the same manner as a condensate stabilizer tower described in Chapter 6. As the glycol falls from tray to tray it becomes richer and richer in water. As the gas rises it becomes leaner and leaner in water vapor. Glycol contactors will typically have between 6 and 12 trays, depending upon the water dew point required. To obtain a 7 lb/MMscf specification, 6 to 8 trays are common.
D GS OT R A U Y M ETATR S XC IT R O BBL FAT Y 1 fUBOCP A # T PE 8R Y. ) GPLFO)N M C (L O DW OE TY. O 8 C R Y
GN L LC YO I
TBSET UEHE TB GS ND TB) UE (A ISE UE I GELCL HA A/ HNE ET S YOR G X AG C LLCL ,EN A GO Y TSSLS O E GT A A ME E SD KR BBL CP UB A E (Y . O 10 BBL T P F 2 UB E CP P TA) A E RY S R
W G E A T FOBEE RM NS SR BLT CU I R GTO VLE Y CLCL LVL ORL EE NO A V GCL LO Y C GIHL tRC LO Y TO OE RBLR EI
Figure 8-4. Typical glycol contactor in which gas and liquid are in counter-current flow.
As with a condensate stabilizer, glycol contactors may have bubble cap trays as shown in Figure 8-4, or they may have valve trays, perforated trays, regular packing or structured packing. Contactors that are 12% in. and less in diameter usually use regular packing, while larger contactors usually use bubble cap trays to provide adequate contact at gas flow rates much lower than design. Structured packing is becoming more common for very large contactors. It is possible to inject glycol in a gas line and have it absorb the water vapor in co-current flow. Such a process is not as efficient as countercurrent flow, since the best that can occur is that the gas reaches near equilibrium with the rich glycol as opposed to reaching near equilibrium with
the lean glycol as occurs in counter-current flow. Partial co-current flow can be used to reduce the height of the glycol contactor by eliminating the need for some of the bottom trays. The glycol will absorb heavy hydrocarbon liquids present in the gas stream. Thus, before the gas enters the contactor it should pass through a separate inlet gas scrubber to remove liquid and solid impurities that may carry over from upstream vessels or condense in lines leading from the vessels. The inlet scrubber should be located as close as possible to the contactor. On larger streams filter separators (Volume 1, Chapter 4) are used as inlet scrubbers to further reduce glycol contamination and thus increase the life of the glycol charge. Due to their cost, filter separators are not normally used on streams less than approximately 50 MMscfd. Often on these smaller units a section in the bottom of the contactor is used as a vertical inlet scrubber as shown in Figure 8-5. Dry gas from the top of the gas/glycol contactor flows through an external gas/glycol heat exchanger. This cools the incoming dry glycol to increase its absorption capacity and decrease its tendency to flash in the contactor and be lost to the dry gas. In some systems, the gas passes over a glycol cooling coil inside the contactor instead of the external gas/glycol heat exchanger. The glycol reconcentration system is shown in Figure 8-6. The rich or "wet" glycol from the base of the contactor passes through a reflux condensor to the glycol/glycol preheater where the rich glycol is heated by the hot lean glycol to approximately 1700F to 2000F. After heating, the glycol flows to a low pressure separator operating at 35 to 50 psig, where the entrained gas and any liquid hydrocarbons present are removed. The glycol/condensate separator is a standard three-phase vessel designed for at least 15-30 minutes retention time and may be either horizontal or vertical. It is important to heat the glycol before flowing to this vessel to reduce its viscosity an