A Selexol Retrofit for Energy Savings
Physical solvents are now replacing chemical solvents for carbon dioxide separation in anhydrous ammonia manufacturing plants to reduce the thermal energy requirement for ammonia synthesis.
Carl G. Swanson, Jr., Consultant, Omaha, NE 68132 Frank C. Burkhard, Boonton, NJ 07005
Prior to 1950, the usual commercial method for the removal of carbon dioxide in gaseous mixtures containing the same was by absorptoion of the carbon dioxide
in water. Because of the relatively low absorption coefficient of water for C02 at room temperatures, research was conducted, beginning in the nineteen forties, for a solvent haying a higher absorption coefficient. The amines, called chemical solvents because of their bonding with carbon dioxide, -were
developed and marketed during this period, followed by potassium carbonate solutions.
Allied Chemical and Dye Corporation, now the Allied Corporation, began a
research project in 1949 in search of a physical solvent, one whose absorption of C0
2was not a chemical absorption but rather analogous to the C0
2in a water absorption system. Out of this
undertaking came an organic solvent, the dimethyl ether of polyethylene glycol
(Dmpeg), later to be known as Selexol solvent.
The solvent is a transparent, nearly odorless mixture of related compounds with a molecular weight of 280 and having thé«foilowing properties.
Freeze Point °C (°F) -22 to -29 (-8 to -20)
Flash Point °C (°F) 151 (304)
Properties @ 250°C (77°F):
Vapor Pressure, Pa (mmHg) 0.093 (0.0007) Specific Heat, J/kg°K (btu/lb. °F)
2052 (0.49)
Density, kg/m
3(Ib./gal.) 1027 (3.57) Viscosity, c
p5.9
Thermal Conductivity, W/m°K (3tu/fthr°F) 0.17 (0.10)
Selective Removal of CO? and Sulfur Compounds
While actual solubility data is proprietary relative solubilities can be examined.
Relative to Methane, the solubilities of various gases are depicted as follows:
Component
H
2Least Soluble N
2.CO CH
4C0
2COS NH
3H
2S CH
3SH S0
2H
2Most Soluble
R = K'CHa
K' Component 0.20
0.30 0.43 1.
15.2 35.
73.
134.
340.
1400.
11000.
'i/here K' = y_ =
mol comp in gas phase/mol gas
mol co<np in llq. phase/ (mol comp in liq. phase + mol Selexol)
Readily apparent is not only the solubility differential between CÛ2 and \\%
and N£, but also the differential between CH4, CÓ2 and the Sulfurous Gases. The former differential enables the separation of CÛ2 from synthesis gas; the latter differential facilitates the separation of CÛ2 and r^S from Methane as well as the capability of selective absorption of H2S from CÛ2« This last property provides a very neat application in the sweetening of natural gas by allowing separate removal of first H2$, then CÛ2.
The use of the solvent for the removal of acid gases from a gaseous mixture is called the Selexol Process. In March of 1982, Norton Company acquired from Allied all rights to the Solvent and the Process.
Current Applications of the Process
Early applications of this property of selectivity in absorption of CÛ2 and ^S were in the gas fields of Texas. The Valero Transmission Company began at their 3rey Ranch Plant in 1969 to use the process for bulk CÛ2 removal of natural gas, Figure 1.
CÛ2 was reduced from 43% to less than 3.5%, while H2S was removed from 18 ppm to less than 4 ppm. Shortly thereafter the Northern Natural Gas Company at their Oates Plant began sweetening natural gas by reducing the CÛ2 from 18% to less than 2.5%, while
reducing l^S from 100 ppm to less than 4 ppm, Figure 2. (All percentages and ppm in this paper, relating to gases, are on a volume basis.)
From 1969 on, the process has been used world wide to reduce the CÖ2 concentrations
from as high as 65% in wellhead gas to as low as 50 ppm in synthesis gas and to reduce the HgS from ranges in excess of 9% to less than 1 ppm.
Beginning in 1976, the process found application in the purification of synthetic natural gas where in addition to CÛ2 and H2S, carbonyl sulfide (COS) must also be dealt with. The process is now employed or installations are pending in coal
gasification and liquefaction, enhanced oil
recovery and landfill operations as well as offshore platform recovery of natural gas.
Indeed, three plants are now in operation where decomposition gases from garbage
landfills are being sweetened by the process and injected directly into metropolitan utility gas mains. These applications are in addition to the use of the solvent for CÛ2 Removal in ammonia plants, both new and old.
The Process for New Ammonia Plants
The application of the process for C02 removal in an ammonia plant differs from its application in the natural gas industry in two (2) ways. First, the reformed and converted natural gas does not contain sulfur compounds in need of removal; and, second, the degree of purity of the product gas is such in terms of CÛ2 content that the solvent returning to the CO? absorber must be leaner than in natural gas applications, where often solvent regeneration is
accomplished solely by flashing from absorber pressures. Consequently, in
addition to flashing, gas stripping must be employed. This operation will enable the absorber to deliver product gas in terms of CÛ2 to as low as 500 ppm or lower if
desired.
The Sheritt Gordon Mines plant in Alberta, Canada, built by Kellogg and
started up this spring, operates with absorber pressure of 3.21 MPa (465 psia),
reduces the CÛ2 from 18% to less than 1000 ppm, and delivers CÛ2 to Urea at a 70%
recovery rate and with a purity in excess of 98%. It should be noted, however, that with a change in design, CÛ2 recovery rates in the range of 90%, or even as high as 95%, can be achieved.
The C-I-L Plant in Ontario, Canada, (ICI Process/Uhde engineering), slated for startup in 1985, will operate with an absorber pressure of 3..08 M Pa (447 psia) and also deliver product gas of quality similar to Sherritt Gordon. The UCAM Plant in Amsterdam, another Kellogg installation, will do the same.
These so called new, low energy ammonia
plants are purported to produce ammonia with
energies in the range of 29 MM J/kg (25 MM
Btu/ST) of NH3 or lower. Indeed, it is a
fact that these ammonia plants will employ
many energy saving measures of which the
Selexol process is only one, but certainly
an important one.
Revlw of Installed Retrofits
In recent years, the fertilizer market conditions in the U.S. have been such that buildng a new ammonia plant hasn't been particular auspicious. However, due to the exponentially escalating price of energy, much thought has been given to retrofitting existing ammonia plants to improve their efficiency. Indeed, some thought has been given to replacing an existing plant with a new one having improved efficiency.
Increasing capital cost must be balanced carefully against improved efficiency, and high reliability must always be of prime concern. However, with ever increasing energy costs, special attention must be paid to integrating the energy balance of the ammonia plant with that of other facilities at the site. Ammonia plant design has
always been energy directed, with some going so far as to consider an ammonia plant as primarily a power generation plant, which produces ammonia as a by-product.
The oldest Selexol process for CÛ2 removal in an ammonia plant was installed as a quasi-retrofit at the Allied Chemical plant in Omaha, Nebraska, Figure 3. Here the process removes the bulk of the CÛ2 from the reformed and converted gases (97%), with final clean up accomplished with a mini-MEA System. Installed in 1965, this plant has operated for nearly 18 years with no corrosion, no foaming, and no solvent
degradation. Per unit of gas processed, the system reduced the energy for CÛ2 removal by 90% of that formerly required with an MEA System, Table 1. This installation together with others completed in a $12 million
Energy Conservation Project
permitted the shutdown of one auxiliary boiler and materially reduced the steam production from the other. The steam saved was routed to other areas in the plant. It
is the new use of released thermal energy that makes what is a very standardized process for CÛ2 removal into a unique and singular project for each individual plant looking at retrofitting. The fact that this is low level thermal energy makes
retrofitting an existing ammonia plant a difficult assignment.
The ASED plant in Willebroek, Belgium, was retrofitted with this process in a partial oxidation plant which formerly used a pressured water wash for CÛ2 removal. The plant takes syngas from heavy oil PUX
containing 33% CÛ2 and 200 ppm H£S and
delivers gas with less than 1% CÛ2 and less than 4 ppm H2S. Product gas with CÛ2
concentrations of less than 50 ppm have been observed at reduced rate. This plant is a showcase for solvent consumption with usage below the usual range of 0.1 pound per ST NH3 produced.
A third retrofit is the TVA coal gasification plant at Muscle Shoals,
Alabama, Figure 4. This plant gasifies coal in a Texaco gasifier to provide feedstock for an existing ammonia plant normally operated with reformed natural gas. The coal-derived syngas is cooled, cleaned and shifted. Most of the COS present is
catalytically hydrolyzed ahead of the Ob Removal unit. Feed gas is scrubbed first in the lower section of the absorption column with a semilean solvent (obtained by
miltiple flashing) and then scrubbed in the upper column with a fully lean solvent
(obtained after nitrogen stripping).
Product syngas with less than 1 ppm H 2 S + COS passes through a ZnO guard unit and then enters the original natural gas reforming plant where further purification is achieved using the existing low temperature shift, CÛ2 removal and methanator units. Recovered CÛ2 passes through an auxiliary H£S
conversion plant and is then sent to the urea plant.
The third example becomes increasingly important with the consideration of
petroleum coke and other solid hydrocarbons as a feedstock for an ammonia plant, since the removal of CÛ2 and Sulfurous Gases will require a process with selectivity.
Examination of Proposed Retrofits
Of prime interest in considering the replacement of a chemical solvent process in the COg removal step with a physicaT"solvent process is the overall plant energy balance.
The steam released with this replacement must be used efficiently somewhere else.
Some plants run high steam to carbon ratios solely to obtain a sufficient supply of steam from waste heat boilers to operate the CÛ2 reboilers. In these instances,
installation of a physical solvent will not
only permit the reduction of the steam to
carbon ratio but also the fuel required to
raise this portion of the steam to primary
reformer temperatures. Steam to carbon
ratios in the range of 3:1 can often be
achieved.
Retrofits for conventional ammonia plants have been studied in depth by many, both here and abroad. Among these are PONA Engineers, an engineering services arm of the Norton Company. Retrofit studies by PONA indicate that capital costs for a Retrofit will range from 3 million dollars to 9 million dollars for a 1000 ST ammonia plant, depending on the degree of CÛ2 removal desired by the Selexol portion of the CÛ2 removal process, with payouts from 1.5 to 3 years based on $5 gas, Table 2.
Generally speaking, the capital requiranent is less for bulk CÓ2 removal as compared to total CÖ2 removal, but the energy savings are not as great. As previously stated, each is a unique study requiring a thorough knowledge of the energy balance throughout the complex. Further, as with any retrofit, rather than fitting the equipment to the process, as with a new plant, the process must be fitted to as much of the equipment
as is possible. Other requirements for consideration are: (1) degree of CÜ2 recovery, (2) quality of the C02, and (3) CÛ2 content of producu gas.
A typical Selexol C02 Removal System for a new low energy grass roots Ammonia Plant requires the following equipment:
C02 Absorber Flash Vessels Stripper
Refrigeration Unit
Sidestream Water Removal System
Main Solvent Pump w/hydraulic turbine Recycle Compressor
Stripper Blower
Feed/Product Gas F.xchanger
Most of these operating units will be needed in any ammonia plant Retrofit.
An examination of several Case Studies will bear this out:
Case I: In retrofitting a carbonate solution system to provide for total CÛ2 Removal, generally the existing absorber and stripper towers are adequate once internals are replaced with high efficiency packing.
Since the solvent rate is usually the same as carbonate solution, existing pumps can be utilized. However, refrigeration chiller, flash vessels, recycle compressor and stripper blower are usually required.
Case II: When an existing plant is operating with an ami ne system and total C02
Removal by the Selexol process is desired, it may be necessary to add a second absorber in parallel so that the increased liquid to gas (L/G) ratio would reduce the CÛ2 leakage to 1000 ppm or below. The existing
regenerator may require a swedged unit mounted on top for final clean up. This
leaves the flash vessels, refrigeration unit and motive equipment to be acquired.
Case III: As in Case II, if a lower CÛ2 leakage is desired, it nay be necessary to install a new second absorber operating
in series upstream of the existing absorber.
Again, the flash tanks, refrigeration system, pump and blower must be acquired.
Case IV: In many instances it is desirable to employ the Process for bulk removal of C02» using a mini-MEA unit for final C'U2 removal down to one desired liniit.
In this instance final regeneration of the solvent by stripping most likely will not be required and the additional new equipment will then be an absorber, flash vessels,
chiller and pumps. This scheme has the added advantage of requiring a minimum of downtime for tia-in, since the additional equipment can be erected beforehand. The existing CÛ2 Removal System will then become the polishing unit.
Casé V: Some plants may be retrofitted by simply repacking both the regenerator and stripper, replacing trays with packing, installing a flash system incljding a vacuum flash to maximize CÛ2 production.
Case VI: In many instances, efforts toward energy conservation may be
facilitated by installing feed/product heat exchangers on the absorber and on the regenerator. The former cools the feed gas with product gas; the latter exchanges heat between the stripping air and stripper exit gases as well as the CÛ2 product.
This last Case is only the beginning in the utilization of thermal energy available
in the Retrofit plant or released by the Retrofit in other areas of gas reforming.
Most, if not all this thermal energy is low level heat in the shifted process gas that formerly supplied the carbonate or ami ne reboilars. This portion of the feasibility study is unique for each and every
fertilizer complex. Depending on the needs of each plant, the released energy can be made available for low pressure steam
generation, boiler feed water preheat,
generation of electricity, absorption refrigeration, etc.
As mentioned earlier, in some plants, the steam/carbon ratio in the primary
reformer can be reduced since process gas heat for reboilers is no longer required.
The important thing to remember is that use of this thermal energy must be found in order to justify a retrofit.
In Conclusion
The same external variables influencing the decision to build a new ammonia plant
also influence the decision whether or not to retrofit. The downturn in the economy has been felt in the manufacture of
agricultural chemicals in the same way as it has been felt in industry in general.
Indeed, some marginal operators are not sure there is any money to be made at all in the short term, or even in the long term. The effect of gas deregulation, predicted by so many in as many di i ."°rent ways, remains uncertain. The Payment In Kind Plan (so called PIK Plan) most assuredly will have a marked effect on the farm economy. Whether forty percent of the land idle this year in Nebraska, thirty-five percent idle in Iowa, and similar statistics in other states will result in a healthier farm economy in future years remains to be seen.
All of the above together with the government's indecision as to how to handle the problem of low-priced import ammonia minimizes the options or alternatives for the ammonie producer:
î PRODUCT
WATER
MATERIAL BAIAHCE (VOI.%) Feed Product C02 43 3.5 CH4 57 96.5
Figure 1. Grey Ranch plant of Lo Vaca Gathering Co.
1. Operations can discontinue, an action already taken by some plant operators. Such shutdowns may be only temporary, or they may be permanent.
I. Fertilizer manufacturers can either process their ammonia needs
overseas with their own new facilities or they can integrate imported ammonia with their own state-side operations.
3. Producers can erect their own new low energy facilities in the United States or they can retrofit their present facility with energy conserving devices.
One thing is clear, and that is the untenability of the Status Quo. Existing non low energy ammonia plants will be able to survive in either the long term or the short term only by modernizing with energy conservation measures.
BURKHARD, F.C. SWANSON, C.G.
MATBBAL BALANCE (Vol. %)
Feed CH, 32.0 CO, 18.0
Product 97.5
2.5 (128ppm) (4PJKII)
Figure 2. Removal of CO
2and H
2S.
PRODUCT
FEED
Fted Product ToüreaPUnl CO, 17 05 9U M, 61 71 - K.+CO 22 26.5 03
VENT
Figure 3. Purification of synthesis gas.
Table 1. Energy requirements.
HOHOETHftiroLftHItC
REGENERATOR REBOILERS DEHYDRATION UNIT
ELECTRICITY ABSORBER REGENERATOR
ROTAT1N6 EflUIPHEHT CÛ2 COMPRESSOR REFRIGERATION
COMPRESSORS
BTU/1000 SCF 6A5 jgffiS BTU/1000 SCF GAS 12.950 1.600
1,110
280 10 2.080 180
180
UIÉ-
11
78 18
18
13,230 1,610 1,150
155
PRODUCT (V
ry
CO CH«
n.« astu œ.62
53^0 7S.5S 0.07 Q.09 0.44 O.Q - 7.9}
2.94 4.U 0.03 0.02 ai4 0.20 0.01 0.01
Table 2. Cost of a Selexol retrofit.
AMMONIA PRODUCTION (in lent/day)
Lm* than 1000
« « «•••>« •!•
Mar* than 1000
BULK C02 REMOVAL
From 1.5-
Fron» 2.9-
TOTAL C02 REMOVAL
From 3.0-
From 9.0-
