CPM3700 Acid Gas Removal Plants

3700 Acid Gas Removal Plants

Author: B. (Barbara) Cooke

AbstractThree types of amines are commonly used in acid gas removal plants: monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA). Hot potassium carbonate systems (Benfield and Catacarb) are primarily used for CO2 removal. This section covers corrosion problems found in CO2 and H2S removal plants using these processes.

Contents Page

3710 Introduction 3700-3

3720 Process Description: Amine Treating Plants 3700-3

3730 Corrosion in Amine Treating Plants 3700-6

3731 General or Preferential Corrosion

3732 Stress Corrosion Cracking: Carbon Steel

3733 Stress Corrosion Cracking: Stainless Steels

3734 Influence of Design and Operating Variables

3740 Corrosion Control in Amine Treating Plants 3700-19

3741 Use of Alloy Equipment

3742 Corrosion Inhibitors

3743 Corrosion Monitoring

3750 Process Description—Hot Potassium Carbonate Plants 3700-24

3760 Corrosion in Hot Potassium Carbonate Plants 3700-26

3761 General or Preferential Corrosion


3763 Stress Corrosion Cracking: Stainless Steels

3764 Influence of Design, Operating Variables

3770 Corrosion Control in Hot Carbonate Treating Plants 3700-29

Chevron Corporation 3700-1 August 1999

3700 Acid Gas Removal Plants Corrosion Prevention and Metallurgy Manual

3771 Use of Alloys

3772 Use of Corrosion Inhibitors

3773 Corrosion Monitoring

3780 References 3700-30

August 1999 3700-2 Chevron Corporation

Corrosion Prevention and Metallurgy Manual 3700 Acid Gas Removal Plants

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3710 IntroductionAcid gas removal plants remove carbon dioxide (CO2) or hydrogen sulfide (H2S) from gas and liquid streams. CO2 removal plants are important parts of hydrogen manufacturing plants and ammonia plants. H2S removal plants process sour gas streams from a variety of sources, including producing locations, crude units, cata-lytic reformers or hydrotreaters, fluid catalytic crackers, and hydrocrackers.

Three types of amines are commonly used in acid gas removal plants. MEA (mono-ethanol amine) and DEA (diethanol amine) have been used for many years for both CO2 and H2S removal, while MDEA (methyl diethanol amine) is a relative newcomer. Also, DIPA (di-isopropanol amine) is used in SCOT tailgas plants at Port Arthur and Philadelphia. DIPA plants will not be discussed in detail here, although corrosion problems are similar to those in acid gas removal plants.

For several years, hot potassium carbonate systems (Benfield and Catacarb) have been used, primarily for CO2 removal. This section reviews these processes and the variables in design and operation that affect corrosion.

Amine and potassium carbonate plants use chemical solvent processes that depend on reversible chemical reactions. Other processes use solvents that depend on phys-ical absorption in solution of acid gases. Examples include Shell’s Sulfinol Process (Sulfolane, or tetrahydrothiophene dioxide) and Fluor’s Solvent (propylene carbonate) and Purisol (NMP or N-methyl-2-pyrrolidone). We use Flour Solvent and Purisol in hydrogen plants at El Segundo and Pascagoula, but have no plants using Sulfinol. Neither process will be discussed in this chapter.

All acid gas removal processes share corrosion problems and problem areas:

• Corrosion caused by extreme turbulence in which the acid gas flashes (as pressure letdown valves and downstream piping, and the regenerator feedtray/distributor)

• Corrosion in regenerator overhead system caused by the presence of wet acid gas without the alkaline solvent (includes the regenerator shell above feed tray)

• Corrosion in the hot, lean system (reboiler, hot piping, bottom of regeneratoThe mechanism(s) is not clearly understood but is related to temperature.

These problems will be discussed in more detail later in the section, along withcorrosion problems specific to certain processes.

3720 Process Description: Amine Treating PlantsA flow diagram of a typical amine treating unit is shown in Figure 3700-1. In thisprocess, acidic gases such as hydrogen sulfide or carbon dioxide react with ceamines to form compounds that are stable at lower temperatures but may be bdown by heating. In the case of hydrogen sulfide and DEA, the reaction may bewritten as follows:



Fig. 3700-1 Materials for Amine Gas Treating Plants



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2R2NH + H2S ↔ R2NH2SH2NR2(Eq. 3700-1)

DEA and MEA are the amines most often used. Their advantages include high reac-tivity and lower solvent cost; their disadvantages are their inability to cope with COS, CS2, mercaptans, and oxygen-bearing gases, and higher utility costs than the MDEA and hot potassium carbonate processes. MEA is the most common process in CO2 removal plants, DEA in H2S removal plants.

MDEA has been tried recently with mixed results: it performs well in H2S or H2S/CO2 plants, but in CO2-only plants, corrosion control must be carefully considered.

MDEA and proprietary MDEA blends offer two advantages:

• Selectivity. They absorb H2S and reject most CO2. This produces richer feed tothe sulfur plant. The selectivity of the MDEA can be tailored to a specific process by blending.

• Lower cost to regenerate. The lower heat of reaction with H2S and CO2 and the ability to operate at 50% MDEA concentration greatly reduces the heat regenerate MDEA. This results in steam savings in the regenerator.

In an amine treating plant, the sour gas is contacted at high pressures with cooamine, which absorbs H2S and/or CO2. The purified process gas passes overheadfrom the top of the absorber column, while the rich amine solution containing thH2S and CO2 is removed from the bottom, preheated by a heat exchanger and sto the regenerator or stripper column. At the elevated temperatures and reducepressures of the regenerator, the acid gases are liberated from the amine and eas the overhead product. The “lean amine” (more or less free of acid gas compnents) is withdrawn from the bottom of the column, cooled, and returned to the absorber column to repeat the cycle. CO2 wastes are sold or vented to atmosphereH2S wastes are incinerated or further processed to recover elemental sulfur.

Absorber columns characteristically operate at temperatures from ambient to a150°F and pressures from 100 psi to several thousand psi. Regenerator bottomtemperatures typically fall between 240°F and 280°F and pressures normally afew psi at most.

Most amine treating plants have a filter system that removes scale, solids, hydrbons, and other impurities to minimize erosion and localized corrosion from scadeposits. The filter system includes both mechanical filtration and in some plancarbon absorbers. MEA plants also have a reclaimer, but boiling points of otheramines are too high for reclamation to be practical. The MEA reclaimer receiveslipstream from the regenerator and boils off amine, which is returned to the reerator. Reclaimer bottoms concentrate degradation products, which are periodidiscarded.



3730 Corrosion in Amine Treating Plants

3731 General or Preferential CorrosionThe amine treating process has been in use for many years and the inherent corro-sion problems are well documented in both published and Company literature. Despite available knowledge on the subject, corrosion problems are common. Older plants that have operated trouble-free for a number of years can suddenly become troublesome following minor operating changes such as introduction of new feeds (hydrocrackers) or increases in feed rates (loading).

The type and severity of corrosion and the methods of mitigation depend on several variables. The most important are: the gas being treated, choice of amine (MEA, DEA, MDEA) as an absorption solution or solvent, operating temperatures, solvent concentration, acid gas loading, purity or cleanliness of the solvent, feed rates as percent of design, flow velocities, inhibitors used, and equipment design and metallurgy.

In general, aqueous amine solutions, being alkaline, are noncorrosive to carbon steel when not highly loaded with H2S or CO2. For this reason, most equipment in these plants is carbon steel and suffers little or no attack. Absorber columns and cold piping are seldom subject to corrosion and are almost always constructed of carbon steel with a nominal corrosion allowance.

Amine solutions tend to liberate acid gases when heated, creating corrosive condi-tions. Control of hot amine corrosion requires limiting the regeneration tempera-tures, the solution concentration, and the level of impurities in the amine solution by measures such as reclaiming or filtering. Proper selection of materials is also important.

Figure 3700-1 shows potentially corrosive areas of an amine plant. A portion of amine plants that characteristically shows serious corrosion is the hot regenerator bottoms system. Attack may occur in the reboiler, reboiler return line, lower portion of the column, hot amine piping, and rich/lean amine exchangers. Corrosion is often not uniform, occurring either as pitting or highly localized attack in turbulent areas. Figures 3700-2 and 3700-3 show examples of corrosion related to turbulence and velocity in amine piping.

Although CO2 removal plants often use a corrosion inhibitor, carbonic acid corro-sion can occur in the overhead system, particularly in the overhead condenser, if the inhibitor and the alkaline amine are not carried overhead. Carbonic acid corrosion takes the form of localized erosion-corrosion. Generally, the remedy for the condenser tube corrosion is upgrading to T-304 stainless steel. If air coolers are used, inlet and outlet headers should also be stainless steel. Carbonic acid corrosion also attacks metal in turbulent sections of piping and the liquid impingement areas of the reflux drum.

Regenerator overhead corrosion is also a problem in H2S removal plants, which typically do not use inhibitors. Overhead corrosion has increased with increasing use of high nitrogen crudes. Cracking or hydrotreating high nitrogen stocks



produces cyanide and ammonia, which go overhead in the regenerator, get picked up in the condensing water, and reflux back to the regenerator. Because the ammonia and cyanides cannot easily escape from the system, they build up to very high concentrations. As a result, the regenerator overhead can contain high levels of ammonium bisulfide (NH4HS) and, often, excess ammonia.

Alkaline sour water corrosion is a problem in plant processing hydrocracker, coker, or FCC gases. In these plants, experience indicates that stainless steels (Types 304 and 316) corrode at about the same rate as carbon steel. Corrosion control measures include use of ammonium polysulfide to convert cyanides to harmless thiocyanates, reflux bleed streams to minimize buildup of NH4HS in reflux loops, velocity limits (20 fps) in steel piping, and titanium grade 2 condenser tubes. For more informa-tion, refer to Sections 3200, 3300, and 3800 of the Corrosion Prevention and Metal-lurgy Manual, Volume 2.

Fig. 3700-2 Example 1—Corrosion Related to Turbulence and Velocity in Amine Piping



The reflux bleed stream (see Figure 3600-1) allows removal of NH3 and control of ammonium bisulfide that would otherwise concentrate in the overhead system. Ideally, NH4HS should be limited to a maximum of 2% to 3%. This is often not possible, but reducing NH4HS to even 5% to 10% is desirable. The reflux bleed piping also allows purging of any hydrocarbon trapped in the overhead system.

MDEA Plant CorrosionBecause MDEA can be used at higher concentrations than DEA or MEA, many plants have converted to MDEA to increase efficiency. Chevron uses MDEA at St. Helen’s NH3 Plant, Salt Lake’s H2S plant, some H2S/CO2 plants at Port Arthur, and several natural gas plants. All plants have operated within the limits of 50% (max.) solution concentration and loadings of 0.45 moles acid gas/mole amine. Suppliers of MDEA, including Dow and Union Carbide, claim that it is noncorrosive up to 50% solution concentration.

Fig. 3700-3 Example 2—Corrosion Related to Turbulence and Velocity in Amine Piping



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Company experience and industry surveys indicate that corrosion control is depen-dent on the acid gas on solution cleanliness [1-3]. In H2S plants, MDEA corrosion is typically low because the H2S forms a protective sulfide scale on the metal surfaces. However, some CO2 plants, including St. Helen’s NH3 plant, Mobil’s Torrance H2 plant, and an Agrico NH3 plant, have had severe MDEA corrosion. Plants with MDEA should not use inhibitors intended for MEA because they tend to increase corrosion.

MDEA is degraded more easily than other amines, and we believe that most corro-sion can be avoided by keeping the MDEA free of degradation products. Since MDEA cannot be reclaimed, this is best done by avoiding oxygen entry and using carbon absorbers along with mechanical filters to remove impurities. The mechan-ical filters remove solid contaminants, while the carbon absorbers remove hydrocar-bons, which cause foaming.

The carbon absorbers should be changed regularly. Most users rely on Fe measure-ments to determine when the filters need replacing. Although there is no fixed Fe concentration to use, Fe typically drops substantially when new filters are installed, then rises and levels off at a plateau before eventually rising again. Filters should be changed before this final rise. With proper filtration, MDEA corrosion is typically no worse than inhibited MEA and is usually not as severe.


Amine Stress Corrosion CrackingAmine solutions can cause corrosion cracking of nonstress-relieved carbon steel. In general, MEA can crack steel under milder conditions (e.g. lower temperatures) than DEA or MDEA. The industry has reported cases of MEA cracking down to ambient temperatures and DEA cracking down to 140°F [4-6]. DEA and MDEAbehave similarly in terms of stress corrosion cracking.

In 1991, amine stress corrosion cracks were found in 150°F lean DEA piping inEl Segundo VGO hydrotreater. Tests showed that the piping had not been stresrelieved or the stress-relief had been inadequate. Although the line temperature150°F when the piping leaked, temperatures had run as high as 190°F during it17 years of operation [7].

Carbon steel in amine service is most likely to crack in areas of the plant operaat the highest temperature levels. Stress corrosion can occur both rapidly and esively at regenerator bottoms temperatures (240–280°F), but becomes less seras the temperature is decreased.

Water-washing prior to shutdown steam-out is essential to prevent stress corrocracking of nonstress-relieved equipment, which operates at low temperatures during service. A water-wash with distilled water or steam condensate will remoresidual amines, which can crack nonstress-relieved equipment when heated dsteam-out. Residual amines present during steam-outs cracked a nonstress-reMEA absorber column in a Chevron refinery in 1974.



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The most reliable way to avoid stress corrosion cracking is to stress-relieve welds in amine service. See Figure 3700-4 for a summary of the current stress-relief guide-lines. Currently we recommend stress relief of all pressure vessels in MEA service, regardless of operating temperature. Piping in MEA service should be stress-relieved if it operates above 100°F. Even intermittent service lines, like Regenepumpout line to amine storage tank, should be considered.

Stress relief guidelines for DEA and MDEA plants can be slightly less restrictivethan those for MEA. Again, all pressure vessels should be stress-relieved regarof operating temperature. On piping, butt welds (normally 2 inches and larger) should be stress-relieved if operating above 100°F. Socket and seal welds (nor1½ inches and smaller) do not require stress relief.

Figure 3700-5 gives inspection guidelines for existing plants where original strerelief was not as extensive. From a technical viewpoint, the Company does notconsider it necessary to inspect DEA and MDEA vessels operating below 150°unless more than 50 ppm H2S are present. In that case, refer to inspection guide-lines for wet H2S cracking. If equipment was ever in MEA service, it should be inspected once as an MEA vessel (regardless of its present service), and subsquently according to guidelines for its present service.

When repairing stress-relieved equipment in hot amine service, it is necessary stress-relieve repair welds to avoid cracking. A small weld on the outside of a column or vessel can result in stress corrosion cracking on the inner surface. Calso may start from such apparently unimportant items as an arc strike on a vewall, or fillet welded support shoes on the outside of hot piping. Vessels should stress-relieved by ASME Code approved practices (e.g., a full circumferential bof heat, not localized on one side only).

Fig. 3700-4 Stress Relief Guidelines for Newly Constructed Amine Plants

Stress Relieve?

MEA DEA and MDEA

Absorber yes yes

Regenerator yes yes

Pressure Vessels in Main Circulating Loop(1) yes yes

Butt Welded Piping Above 100°F yes yes

Socket and Seal Welds Above 100°F yes no

Storage TanksShellHeating Coils

noyes

noyes

Notes: 1. External welds often create through-wall stresses sufficient to cause ID SCC. Hence, any external weld should be treated as an internal one.

2. Operators of existing plants can consult with CRTC Materials and Equipment Engineering to formulate long-term plans on how to bring their plants up to these new standards.

(1) This includes any absorber overhead K.O. drum



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For general guidelines on equipment inspection and repair, refer to API Recom-mended Practice 945, “Avoiding Environmental Cracking in Amine Units.” This publication also gives a general overview of amine and wet H2S cracking in amine plants.

Wet H2S Cracking and BlisteringThe term wet H2S cracking refers to hydrogen induced cracking, stress oriented hydrogen induced cracking, sulfide stress cracking, and hydrogen blistering. Althese cracking mechanisms can be active where carbon steel is exposed to H2S and liquid water. A minimum H2S level to 50 ppm is used for inspection purposes, busome cracks have been found in vessels with less than 50 ppm H2S in water. For more details and clarification, see Section 450 and Figure 400-39 of the Corrosion Prevention and Metallurgy Manual, Volume 1.

Sulfide stress cracking (SSC) can occur in carbon steel columns, vessels, heatexchanger shells, and piping. In 1990, Carter Creek's DEA regenerator had sulcracking in the bottom head and lower shell, following improper application of aoxidizing corrosion inhibitor. A catastrophic failure in 1984 of a Union Oil amineabsorber from stress oriented hydrogen induced cracking was initiated by SSC

Fig. 3700-5 Amine Plant Inspection Guidelines(1)

MEA DEA, MDEA

1. Nonstress-relieved Vessels (2)

Inspection MethodFrequency

T less than 150°F

T greater than 150°F

WFMT (3)

1 every other scheduled shutdown

1 every scheduledshutdown

WFMT

(note (4))

1 every other scheduled shutdown

2. Stress-relieved Regenerators


WFMT(note (5))

WFMT(note 5)

3. Nonstress-relieved piping (6)


T Between 100°F & 150°FT Greater Than 150°F

UT (7)

50%/5 years

UT

(note (8))50%/5 years

(1) Some vessels otherwise exempt from the requirements for amine stress corrosion cracking inspection may require special inspection for wet H2S cracking.

(2) Any evidence of or history of hydrogen blistering in a vessel necessitates inspecting all welds internally, using wet fluorescent magnetic particle testing (WFMT).

(3) WFMT = wet fluorescent magnetic particle testing(4) From a technical viewpoint, the CRTC Materials and Equipment Unit does not consider it necessary to inspect DEA and MDEA vessels

operating at less than 150°F, unless more than 50 ppm H2S are present. In that case, refer to inspection guidelines for wet H2S cracking.(5) If not done previously, schedule a one-time internal inspection of the bottom third of the regenerator column. Any future inspections will

be determined by your findings.(6) Piping 1-1/2 inch and smaller need not be inspected.(7) UT = shear wave ultrasonic testing(8) Inspection necessary unless stress corrosion has occurred elsewhere in the plant below 150°F.



hard welds. A maximum hardness of 200 BHN for carbon steel welds is necessary to avoid SSC. For more information on sulfide cracking, see Section 452 of the Corrosion Prevention and Metallurgy Manual, Volume 1.

Hydrogen blisters can form in several areas of H2S removal plants. Most blisters develop in the regenerator overhead system. Cyanides in the overhead system promote blistering by destroying the protective iron sulfide film on the steel surfaces. Blistering has also been detected in both the upper and lower sections of ammonia scrubbers, which are used in amine plants in newer units. In very highly loaded MEA plants (0.4 moles acid gas/mole amine), hydrogen blisters can form in the bottom of the absorbers. In these plants, steel blistered in the absence of cyanide and ammonia.

To control cyanides, ammonium polysulfide is sometimes injected into the over-head system of the cracking unit (i.e. FCC or hydrocracker) upstream of the amine plant. Most amine plants do not use ammonium polysulfide injection, except as a temporary measure. Typically, a plant would consider using polysulfide if corrosion rates were high and a spot FeCl test detected cyanides. (For details on the FeCl test procedure, consult CRTC Materials and Equipment Engineering). The FeCl test is a qualitative test for cyanides. The most reliable quantitative test for cyanides is ion chromatography.

We generally recommend a nominal polysulfide injection rate of five to ten times the stoichiometric amount needed to react with cyanides in the process. Polysulfide rates can be optimized by monitoring hydrogen activity using hydrogen probes.

If polysulfide is injected into the regenerator overhead system, use ammonium polysulfide, rather than sodium polysulfide. Either form of polysulfide will be refluxed back to the regenerator column and mixed into the circulating amine solu-tion. However, while ammonium polysulfide decomposes in the column, in the case of sodium polysulfide, the sodium ion stays in the amine and builds up to undesir-able high levels. Another advantage of ammonium polysulfides is its faster reac-tivity with cyanides.

3733 Stress Corrosion Cracking: Stainless SteelsStainless steels are susceptible to two types of stress corrosion cracking in acid gas removal plants: chloride cracking and polythionic cracking. Both mechanisms will crack only austenitic stainless steels (e.g. Type 300 series).

Chloride CrackingStainless steel tubes have suffered chloride stress corrosion cracking in amine plant regenerator reboilers, rich-lean heat exchangers, and MEA relcaimers. Chlorides can be introduced with produced water or with the caustic, carbonate, or make-up water added to the system.

Because most commercial grades of both sodium hydroxide and sodium carbonate contain a significant percentage of sodium chloride, only low-chloride- containing chemicals should be used in plants with stainless steel equipment. Other chloride



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sources are feed contamination and the water source used for makeup amine solutions.

Only low-chloride steam condensate should be used for makeup. Acceptable levels of chloride in amine plants with stainless steel reboilers are not definitely known, but indications are that levels in the amine solution should not exceed 500 ppm chloride. This chloride concentration can cause chloride SCC of stainless steel tubes if U-tube bundles have not been stress-relieved or straight sections fully annealed or properly stress-relieved after straightening.

Polythionic CrackingStainless steels have failed in hydrogen sulfide removal plants through stress corro-sion cracking by polythionic acids. (See Section 3400 and Section 400 of the Corro-sion Prevention and Metallurgy Manual, Volume 1, for discussions of polythionic cracking.)

Polythionic cracking is caused by acidic constituents formed from oxidation of iron sulfide corrosion products. Polythionic acid stress corrosion occurs only in stainless steel grades that are susceptible to sensitization and therefore subject to intergran-ular corrosion.

Formation of polythionic acids can occur in amine treating plants only during shut-downs, when the equipment might be allowed to stand in contact with moisture and oxygen. Iron sulfide scale is first formed from corrosion of carbon steel equipment and later deposited in the stainless steel piping. During a shutdown, the scale appar-ently oxidizes enough to form the acidic environment that promotes cracking.

Intergranular stress corrosion cracking of sensitized stainless steel has also occurred in CO2 removal plants. For this reason, we recommend the following practices for both H2S and CO2 removal plants. Do not use regular grades of stainless steel such as Type 304 where welding is required or for U-tubes that require stress relief. Use only low carbon or stabilized grades (Types 304L, 316L, 321, or 347) in these appli-cations. Review stress relief procedures to assure that they do not sensitize equip-ment. Use electric resistance stress relief methods for exchanger u-tubes. Soda ash wash stainless steel equipment that is sensitized.

3734 Influence of Design and Operating VariablesDesign and operating variables have a great influence on corrosion in acid gas removal plants. Changes in operating variables to increase plant throughput tend to increase corrosion. Considerable information is available, especially for MEA/CO2 plants, on the effect of design and operating variables on corrosion [8–12]. Thissection summarizes the influence of a number of these variables. Most of the pples discussed refer to corrosion of carbon steel in systems using MEA; DEA aMDEA systems have similar tendencies.

Most company amine plants use alloys in critical equipment such as regeneratobottoms and reboilers. However, if conditions are severe enough these alloys calso corrode; therefore, attention to design and operating details is necessary tminimize corrosion, downtime, and maintenance expenses.



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Primary Operating Variables:The primary variables are:

• Temperature• Solution Strength• Acid Gas Loading

Temperature. Corrosion is a strong function of temperature with increasing temature increasing corrosion. The highest temperature and, therefore, worst corrois usually found in the regenerator bottoms system.

The high alkalinity of the amine minimizes corrosion until temperatures in excesabout 250°F are reached. Above 250°F, carbon steel corrosion is significant anspecial alloys and/or inhibitors are required. This corrosion is probably related timpurities and degradation products in the amine, such as heat stable salt and acid compounds.

In MEA reclaimers, tube metal temperatures above 300°F–325°F will result in amine degradation and corrosion even in stainless steel. Operating and designconditions must therefore avoid creating hot tube metal surfaces. For more infotion on reclaimer operating conditions, consult a member of the CRTC Light Hycarbon Processing Team.

Solution Strength. Another factor affecting corrosion is amine solution strength,which is the sum of the free amine concentration and the amine tied up as heatstable salts. Industry guidelines and company experience indicate that the uppelimit for MEA solution strength is about 20 weight percent MEA in aqueous solution. Above this level serious corrosion is often encountered because high conctrations require increased regeneration temperatures, which tend to degrade thamine. The upper limits for DEA concentrations are somewhat higher at 25 to 30 weight percent. MDEA can be used up to 50 weight percent.

Acid Gas Loading. Another important solution variable is acid gas loading, expressed as moles of acid gas per mole amine. Acid gas loading is related to gas feed rate and solution circulation rates that are built into a plant design. Sizplant too small or operating a plant above design limits can lead to serious corrsion. For MEA plants, acid gas (i.e. H2S or CO2) loadings above 0.40 moles acid gas per mole MEA cause significant corrosion of carbon steel equipment. The limits for H2S/DEA plants are somewhat higher, at about 0.4 to 0.6 moles H2S per mole DEA.

These limits are largely dictated by equilibrium considerations (in the H2S/DEA reaction 0.5 moles H2S per mole DEA is ideal), but ultimately are set by corrosionconsiderations. If more H2S or CO2 is dissolved into solution than can react with thamines, then very corrosive amine compounds form. Even at low loadings, corrsion is a function of the amount of CO2 or H2S dissolved. Figure 3700-6 shows theeffects of CO2 gas loading and temperature on corrosion in an MEA system.

Figure 3700-7 gives optimum and maximum recommended acid gas loadings aMEA concentrations. New inhibitors may allow operation at higher loadings andsolution concentrations than indicated.



Fig. 3700-6 Effect of Acid Gas Loading and Temperature on Corrosion. These data were developed in a pilot plant and are only shown here to illustrate general trends. The actual corrosion rates may be different for a commercial plant.

Fig. 3700-7 Optimum and Maximum Acid Gas Loadings and MEA Concentrations



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Control of amine solution strengths and acid gas loadings are of prime importance. Performing routine analyses is good operating practice. If plants have to be oper-ated in excess of design capacity, it is better to operate with slightly higher solution strengths and moderate loadings, rather than with normal solution strength and high loadings.

Summary—Primary Variables. The three primary variables of temperature, solu-tion concentration, and acid gas loading are not independent. If any two are held constant, corrosion will tend to increase as the third variable increases. The critical value of the third variable will depend on the magnitude of the other two.

Secondary Operating VariablesThe secondary variables are:

• Solution cleanliness• Velocity/turbulence

Solution Cleanliness. Contamination or degradation of amine solutions can leadserious corrosion and foaming [13]. Operating and corrosion problems usually bwhen the circulating solution gets dirty. For long, trouble-free solution life, it is necessary to recognize these problems and to know how to prevent them. Connants can be degradation products, heat-stable salts, oxygen, dissolved hydrocbons, liquid hydrocarbons, and solids.

Degradation of amines can occur by several mechanisms. Amines oxidize readthe presence of oxygen and form corrosive organic acids. To prevent oxidation,amine storage and surge vessels should be gas blanketed to keep air out of thesystem. Air leakage into a hot system (pump suctions) causes serious problemOrganic oxygen scavengers can be injected to reduce corrosion rates, but theirmust be carefully controlled to avoid accumulation in reboilers and heat exchan

Organic acids (such as hydrocyanic, formic, acetic, and oxalic) sometimes formduring the amine plant process or as a result of oxygen contamination can causserious heat stable salt problems. Heat stable salts are products of reactions bethese organic acids and the basic amines. For example, HCN will react with H2S to form thiocyanic acid (HSCN). In turn, the thiocyanic acid will react with an aminto form heat stable salt amine thiocyanate. The salt is “heat stable” because theamine cannot be regenerated by adding heat.

Control of heat stable salts is important because an amine solution becomes mcorrosive as the level of heat stable salts in the solution increases. At high leveheat stable salts, overstripping of the amine will further increase corrosion rates[14]. We believe this occurs because the lean amine does not have enough sulestablish and maintain a protective iron sulfide film on carbon steel surfaces. UCarbide recommends limiting heat stable salts to less than 10% of the total minconcentration (e.g. 2.5 wt.% for a 25 wt.% amine solution). Industry experienceindicates that corrosion is low if a plant limits heat stable salts in the solution to2.5–3.0 wt.%.



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Solution degradation can also occur from excessive temperatures or localized over-heating. Hot spots in reboilers can decompose the amine to form corrosive compounds. Gas contaminants like COS or CS2 can also cause degradation of MEA solutions. These compounds should be removed from gas streams in MEA/CO2 plants (DEA and MDEA are less affected), and regenerator bottoms temperatures should be kept as low as possible (but above the amine boiling point).

Dissolved or entrained liquid hydrocarbon contamination can lead to fouling, over-heating, increased corrosion problems, and foaming. Sludge and suspended solids are also troublesome. The principal solid impurity is iron sulfide, but magnesium, calcium, silicate, and other inorganic compounds have been detected. Calcium and magnesium salts generally result from using raw water as makeup instead of steam condensate.

Solids in amine solutions contribute to erosion-corrosion, foaming and fouling. The finely divided iron sulfide may be a corrosion product from the acid gas removal plant or may enter the absorber with the feed gas stream. As these particles grow and settle out, they form a black, sticky, and abrasive mass which can cause erosion-corrosion in turbulent flow areas. This sludge also deposits in low-flow areas, exchanger surfaces, and trays, and can cause severe foaming problems. Under sludge deposits pitting and preferential attack are common problems.

Solution cleanliness is controlled in DEA and MDEA by filtration and in MEA by filtration plus reclamation. Good filter systems include mechanical filters, which remove sludge and solid impurities from the amine solution. Mechanical filters should receive continuous 100% flow of the solution. The recommended filter size is 5–10 microns, and the recommended solids content in the amine solution is 100 ppm. Differential pressure indicators are used to determine when filters areplugged. For high filtration loads, consider using automatic backwash filters or 3M bag filters.

Because DEA and MDEA cannot be reclaimed, carbon absorption is used to redissolved organic impurities that cause foaming. Carbon absorbers are essenticontrol conversion in MDEA plants, since MDEA degrades easily. They are alsodesirable in DEA systems, but are not as critical. As a bare minimum, at least 1of the solution should pass through the carbon while small plants may filter 100Plants should increase the percentage of flow through the carbon filters as mucpossible. A sock filter is typically placed downstream of the carbon absorbers totrap carbon fines.

In MEA plants, reclaimers are important in reducing corrosion, foaming, and fouling. Reclaiming restores the amine usefulness by removing high-boiling andnonvolatile impurities such as heat-stable salts, suspended solids, and iron profrom the plant solution. It is the most economical and popular method of mini-mizing contamination of plant MEA solutions. Reclaiming consists of a semiconuous batch distillation of a 1% to 3% slipstream of the circulating hot, lean MEAsolution. The length of a reclaimer cycle depends on the degree of contaminatiwith short cycles required for badly fouled solutions. Problems in Company planare sometimes attributable to running a reclaimer too long before dumping. Usu



and a-ove

ine h has ill e

la .

ign is in sed.

red cel-of

reclaimers are used when degradation levels of the amine solution are over 1%, or about 10% of the solvent concentration.

Soda ash or caustic soda is added in stoichiometric amounts to the reclaimer to free the combined MEA and neutralize the heat-stable salts and volatile acids. A low-chloride soda ash, such as natural soda ash, or a rayon or mercury cell grade of caustic soda should be used to prevent chloride stress corrosion cracking of stain-less steel equipment, especially reclaimer tubes (see Section 3733). Some Company reclaimers have been operated in the past without soda ash or caustic additions. This practice is not recommended, since solution degradation is enhanced and the amine tied up with heat-stable salts is not reclaimed.

Both Port Arthur and Pascagoula have used caustic injection as a low cost method of controlling heat stable salts and corrosion problems. Port Arthur has injected caustic at several DEA plants including the 841 and 842 Amine Plants and the 1241 FCC Unit. Caustic has also been added in MDEA plants (e.g. #243 and #244 H2S Plants, SCOT Tail Gas Units #1 and #2). In 1992, Pascagoula injected caustic into lean DEA at the 94 Plant after erosion-corrosion occurred in regenerator reboilers above 3.5 wt.% heat stable salts. Caustic was injected following a study by a DEA Task Force [15]. The corrosion rates decreased after adding caustic.

Caustic breaks up heat stable by dissociating the organic acid from the amine and forming sodium salts. Union Carbide believes that sodium salts are less corrosive than heat stable salts; however, this is not accepted industry-wide [16]. Another potential risk of caustic injection is precipitation of sodium salts in equipment oper-ating at relatively low temperatures (<120°F). Pascagoula experienced plugginghigh pressure differentials in several absorber columns operating at low tempertures. The plugged columns were taken out of service and water-washed to remthe sodium salts. Dow and Texaco have reported that caustic can also increasefoaming.

Consult with the CRTC treating expert in the General Processing Unit to determthe correct procedure for caustic injection. Use the rayon grade of caustic, whica low chloride level. The range of caustic concentration and the injection rate wvary depending on plant conditions, such as the type and concentration of aminsalt. The caustic should be injected as slowly as possible to reduce the risk of precipitation and plugging. Even at the recommended injection rates, Pascagoureported plugging in several absorbers operating at low temperatures (<120°F)

Velocity/Turbulence. High flow velocities or turbulence can cause localized erosion-corrosion in amine acid gas removal plants. For this reason, piping deslimited to a maximum of 6 fps fluid flow for carbon steel. At points of turbulencehot solution piping, long radius bends (if possible) or stainless steel should be uSpecial care is needed at points of solution entry into vessels, reboilers, and exchangers. Adequate inlet baffles in exchangers are necessary.

Lean amine pumps and rich amine pressure letdown valves often suffer severeerosion-corrosion. Stainless steel, often hardfaced with Stellite, is usually requito solve these problems. Pump cavitation is a common problem that leads to acerated corrosion. Calculation of NPSH requirements should allow for the effect



dissolved gases, which is often overlooked. Installing the lean amine pump after the rich/lean exchanger often solves this cavitation problem.

Longer equipment life can be obtained by selecting the proper point to reduce the pressure of the amine solution. Desorption of acid gases and dissolved hydrocar-bons usually occurs when the pressure of the rich solution is significantly lowered, and causes excessive corrosion of the control valves and adjacent downstream piping. The absorber or flashdrum pressure should be maintained through heat exchangers to minimize flashing of acid gases. Control valves and downstream piping on the rich solution stream leaving the absorber can be subject to corrosion if there is a high pressure drop across them. The valves and piping downstream of the control valves should be stainless steel in all plants. To minimize the length of stain-less piping, the control valves should be located close to the flash drum and to the regenerator. See Figure 3700-1.

3740 Corrosion Control in Amine Treating Plants

3741 Use of Alloy EquipmentExcept as discussed below, equipment in amine plants is normally carbon steel. Refer to Figure 3700-1.

Rich/Lean ExchangerThe hot lean amine side of this exchanger is generally Type 304L stainless steel, although some gas plants can use carbon steel successfully. The cold rich side is carbon steel. 70-30 Cu-Ni has been used in H2S-free MEA/CO2 plants where carbon steel was not adequate. 70-30 Cu-Ni should not be used if oxidative inhibi-tors (e.g. amine guard) are employed, since they cause pitting. 304L should be used in these cases.

Absorber Bottom Control Valve and Pressure Letdown Valve to RegeneratorThese valves can be subject to acidic erosion-corrosion and so are stellite-hardfaced Type 304.

Rich Amine Piping from Absorber Bottom Control Valve to Accumulator and From Pressure Letdown Valve to RegeneratorThis piping is also Type 304L to avoid acidic erosion-corrosion.

RegeneratorThe regenerator is clad with Type 304L in two areas:

• Above the feed tray where acidic corrosion is possible• Below the bottom tray where hot amine corrosion can occur



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Regenerator Overhead Acid Gas CoolerThe tubes in this exchanger are usually Type 304L. If this is an air-cooled exchanger, 304L is used for the inlet and outlet headers. In H2S removal plants where cyanide- and ammonia-induced corrosion are possible, titanium tubes have been used.

Overhead Reflux Return PipingThis piping is T304L to avoid acidic corrosion.

Hot Lean PipingThe following hot lean piping is T304L to avoid hot amine corrosion:

• From regenerator to rich/lean exchanger• To reclaimer and return (MEA only)• To reboiler and return

Reclaimer (MEA only)The tubes in the reclaimer are T304L to avoid hot amine corrosion.

ReboilerReboiler tube corrosion can be one of the most serious operating problems enctered in acid gas removal plants, and solutions sometimes involve several variaStress-relieved stainless steel tubes (Types 304L, 321) are usually used in ComH2S and CO2 removal plants. Monel is often used in MEA/CO2 plants when there are no sulfur compounds present. Tube corrosion in both stainless steel and Mcan occur under certain circumstances in all types of plants. Problems are usuaattributable to high localized temperatures and to inadequate stripping in the reerator. This allows acid gas to be stripped in the reboiler.

Corrosion can occur under baffles when high pressure steam (150 psi or greatehot synthesis gas is used for a heating medium. Poor shellside flow in tube supbaffle crevices creates high tube temperature zones and corrosion of stainless In MEA/CO2 plants, Monel has proven to be somewhat superior to stainless steresisting this form of high temperature corrosion. However, in plants with H2S, Monel cannot be used. It is also unsuitable if oxidative inhibitors (e.g., amine guare being used, because these cause pitting of Monel.

Titanium shows promise in severe services where Monel and stainless steel hahad poor corrosion resistance and short service lives (less than 5 years). Compexperience with titanium reboilers is limited to two in H2S plants at El Segundo, in service since October 1973 and October 1975. In these plants, austenitic stainlsteel suffered intergranular corrosion/cracking and hot spot underbaffle corrosioTitanium reboiler tubes are susceptible to hydriding, which makes the tubes bribut does not affect their corrosion resistance. Hydrided tubes require careful handling during shutdowns.

Although often uneconomical in new plants (where stainless steel can be used)design alternative to expensive tube materials is to lower the steam pressure in



ater tubes ide

to ing g and The . The al-

tube

ob-

d al

al some

to avoid high skin temperatures and high heat flux rates. Low pressure steam at 50 psi is usually recommended, with inlet temperatures monitored to avoid super-heat. Desuperheating is done using condensate injection or inlet restricting orifices to throttle steam flows. However, when condensate partially floods the reboiler tubes, the heat load concentrates in the top section of the bundle, which can cause tube failure.

Mechanical design is an important factor in reboiler corrosion. Regardless of mate-rial, the following design considerations should be observed.

The length of U-tubes should be limited to prevent condensate “logging” and whammer. Water hammer can produce severe tube vibration and grooving of theat support baffles. Reboilers should be designed with a liberal amount of shellsvapor disengaging space between tubes, and sufficient surface to produce a “simmering” action rather than violent boiling.

In existing units where vapor binding is a problem, some tubes can be removedform an X or V in the center of the bundle as a path of low resistance for escapvapors. A widely spaced square-pitch tube pattern is preferred for easy cleaninreduction of the high velocity scrubbing action associated with two-phase flow. tube bundle should be elevated about 6 inches from the shell bottom, on a slidebundle should always be kept covered with 6 to 8 inches of liquid to prevent locized drying and overheating, and thus corrosion.

The amine solution should enter the reboiler at several locations to improve thenatural circulation of liquid in the reboiler shell. Several vapor exit locations willreduce the stagnant pockets of acid gases in the reboiler.

An analysis of solution entering and leaving the reboiler will determine the effi-ciency of the stripping operation. A high acid gas loading in the reboiler causescorrosion.

New plant designs should consider all of these factors and would benefit from athorough analysis of problems in existing plants. If design or operating changescannot be made readily, then poor bundle life may be inevitable.

Lean Amine PumpThis pump is usually Type 304, but can be carbon steel if potential cavitation prlems are avoided. See Section 3734 on velocity and turbulence effects.

Other General Guidelines for Alloy EquipmentThe choice of alloys in acid gas removal plants depends on several variables, including the nature of the acid gas (H2S or CO2), process used (MEA, DEA, MDEA), inhibitors used (Dow, Amine guard, etc.), turbulence or flow velocity, antemperature or nature of corrosion (hot regenerator or cool overhead). Additiongeneral guidelines on use of alloys follow.

Stainless Steels. Austenitic stainless steels (Type 304 or 304L) are used for criticequipment in all plants, in both hot areas and overhead condensers. However,



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corro- aks

rs, rial uples

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one sea

H2S/DEA plants do experience serious cyanide-induced corrosion, and here tita-nium condenser tubes are used.

Type 410 stainless steel (11-13 Cr) often gives poor performance in amine plants; therefore, Type 304 is used for trays and valve trim when alloy is required.

Stellite hard-facing over Type 304 performs well in pressure letdown valves where high turbulence causes erosion-corrosion.

To avoid sensitization, only extra-low carbon or stabilized grades of stainless steel should be used where welding or stress relief is required.

Monel and 70-30 Cu-Ni. Copper and nickel-based alloys (Monel and 70-30 Cu-Ni) are not suitable in the high temperature areas of H2S removal plants. Brass alloys are not suitable in any of these plants because of the high alkalinity of the solutions.

Some inhibitors (i.e., Union Carbide amine guard) can cause pitting of Monel in CO2/MEA systems, so should not be used in plants with Monel reboilers.

Monel has good high temperature resistance to corrosion in sulfur-free MEA/CO2 systems and will outperform stainless steel in reboilers when tube metal tempera-tures exceed 300°F.

70-30 Cu-Ni can be used in sulfur-free MEA/CO2 plants for rich/lean exchangers olean MEA coolers when carbon steel is not adequate.

Titanium. Titanium grade 2 tubes (20 ga.) have performed well in H2S/DEA regen-erator overhead condensers where cyanide corrosion limited the life of austenitstainless steels. Titanium grade 2 tubes are currently used in DEA regenerator head condensors at Richmond and El Segundo. Previous titanium bundles in thcondensors hydrided and were replaced after 12–19 years.

Titanium tubes have also performed well (since 1973–75) in MEA and DEA/H2S reboilers at El Segundo, where austenitic stainless steel suffered intergranular sion/cracking and hot spot underbaffle corrosion. A 1990 hydrotest detected noleaks in the DEA reboiler; however, at least 7% of the bundle had been pluggedpreviously. Handling may account for some of this damage, since most of the lewere in the outer 2–3 rows of the bundle.

When titanium is chosen for regenerator overhead condensors or amine reboilewe recommend grade 2 (commercially pure titanium) tubes with the same matefor the carcass and grade 2 or grade 12 for the tubesheet. Avoiding galvanic coreduces the risk of titanium hydriding.

Water-Cooled Exchangers. For water-cooled exchangers, a compromise is frequently necessary between stock-side and water-side corrosion resistance. FCO2/MEA plants, this poses no problem, since 70-30 Cu-Ni tubes are resistant virtually all types of cooling water as well as to the process fluids. For H2S plants, the problem is more complicated, especially if sea water or poor quality coolingwater rules out carbon steel.

Stainless steel will pit or crack in brackish cooling water or sea water, but has dwell in lean amine coolers using fresh cooling water. Monel is not adequate for



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water cooling, and 70–30 bimetallic tubes have had limited success. Titanium hbeen used successfully by others in lean amine coolers and has excellent resisto sea water. Thin gauge tubes (20 ga) are often cost-competitive with 16 ga 70-30 Cu-Ni.

3742 Corrosion InhibitorsFor many years, H2S removal plants have been inhibited with organic, water-solufilming amines (e.g. Kontol K-12 and Betz WS-58). Filming amines prevent sluddeposits, but their success as inhibitors has been mixed. Betz WS-58 is currenused at the Carter Creek Gas Plant. Over the past 10 years, the plant has had eight years of experience with this inhibitor. To date, hydrogen blistering has nooccurred while injecting WS-58 and coupon corrosion rates have generally beenthan 10 mpy. However, at times, coupons in the rich stream through the rich/leaexchangers have corroded at rates as high as 26 mpy.

In recent years, DEA plants at Port Arthur and Richmond have had some succewith oxygen scavengers/metal passivators, such as Nalco 5173, which promotestable sulfide films. Port Arthur's 841 and 842 amine plants, along with the AVU144 amine plant (now out of service), have successfully used Nalco 5173 to scenge oxygen, which degraded the amine. A Richmond DEA plant has used 517since 1990 to solve an iron sulfide fouling problem. Although pump problems prevented continuous 5173 injection, the inhibitor appeared to stabilize the formtion of heat stable salts when it was injected consistently over a six month perio

Adding the correct dosage continuously into a circulating solvent or overhead system is critical to a passivating inhibitor's success. If the chemical is underfedinhibitor can accelerate corrosion. Underfeeding Nalco 5173 contributed to sulfcracking and corrosion problems at the Carter Creek Gas Plant. After injecting for about a year, severe sulfide cracking had occurred in the bottom of the DEAregenerator. Additionally, severe pitting was found in the hottest rich amine exchanger, and steel coupons in a rich amine line had hydrogen blistered.

For over 30 years, CO2 removal plants (usually MEA) have employed oxidative inhibitors, such as Union Carbide's Amine Guard. These inhibitors contain meta(e.g. vanadium, arsenic, antimony), which promote stable oxide films on carbonstainless steel. If H2S is present, oxidative inhibitors are not effective because theformation of a sulfide film will compete with oxide formation. Oxidative inhibitorstend to increase corrosion of Monel and 70-30 Cu-Ni.

The use of oxidative inhibitors is declining due to restrictions on their disposal. alternative to inhibited MEA is MDEA, which can be used at higher concentratioand does not require inhibition. Oxidative inhibitors should not be used in MDEplants because they will increase corrosion.

3743 Corrosion MonitoringAn inhibitor program will not be successful unless corrosion rates in the systemcontinuously monitored. Both retractable corrosion coupons and corrosometer



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i-y tlet t-

the

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tas-

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probes are used for this purpose. Field experience indicates that in some cases retractable coupons give more reliable data under both turbulent and laminar flow conditions. Corrosometers offer the advantage of continuous data collection, without the need for removing and replacing coupons.

The location of probes or coupons should be chosen with care, particularly if corro-sion in the plant is highly localized. New plants should have probe connections consisting of 1½" full port gate valves installed in critical locations, such as reboioutlet vapor lines and the rich amine piping between the rich/lean exchanger anregenerator.

Probes may not be satisfactory if corrosion occurs by pitting or if the fluid velocties and turbulence at the test are sufficient to cause the probe element to fail bfatigue. If the best test location is a highly turbulent area such as the reboiler ouline, better results will be obtained with retractable corrosion specimens. Retracable specimens are described in Section 500 of the Corrosion Prevention and Metallurgy Manual.

Coupons normally are removed every 2–4 weeks for evaluation. Coupon data should be supplemented with inspection data to confirm the results. Monitoringsolution's Fe content in CO2 plants, or the filter change frequency in H2S plants, can also provide valuable information on relative corrosion rates.

3750 Process Description—Hot Potassium Carbonate PlantsHot potassium carbonate processes are similar to amine processes, except that they employ an aqueous solution of K2CO3, and the absorber operates at a higher temperature, between 230°F and 240°F. The process cannot be used on gas scontaining only H2S, so applications are limited to CO2 removal plants. The most popular carbonate processes are those that contain an activator (promoter) andinhibitor such as:

• Benfield. DEA Activator and Vanadium Inhibitor• Catacarb. Alkanolamine and Borate Activators, Vanadium Inhibitor

The process chemistry is similar in both of these patented processes. All hot posium carbonate solutions absorb CO2 according to the following reaction:

high pressure

CO2 + H2O + K2CO3 ↔ 2KHCO3(Eq. 3700-2)

The flow diagram for a hot carbonate plant, shown in Figure 3700-8, looks verysimilar to an amine plant, except rich/lean exchangers are not necessary. Absooperate hot to avoid precipitation of the bicarbonate (KHCO3) salt. Lines carrying rich solution are steam traced to maintain temperatures in streams back to the regenerator.



olu-hibit sed

ssful ng a

The Benfield process (Union Carbide) requires payment of a process royalty. Chevron formerly operated a Benfield plant at SACROC. The process may be used for removal of CO2, H2S, and COS from sour gases at absorber pressures of 150 psi or greater. It is claimed that the Benfield process provides low utilities costs, high CO2 removal, low corrosion, and low plant investment.

A properly designed and operated plant can be relatively corrosion-free, but strict adherence to process details, solution chemistries, etc., is important because poorly inhibited CO2-rich hot potassium carbonate is very corrosive to carbon steel.

A Benfield plant uses a 25–30 weight percent K2CO3 solution with 3 weight percent DEA as an activator to improve its performance. Vanadium compounds in the stion, such as vanadium pentoxide and potassium meta vanadate, are used to incorrosion. Inhibitor concentrations are usually about 0.5 weight percent, expresas KVO3.

Prepassivation of clean equipment prior to startup is an important part of succeBenfield plant operation. This is called vanadation and is performed by circulati

Fig. 3700-8 Typical Flow Diagram—Hot Carbonate Plant



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. To such

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hot solution of potassium carbonate with about 0.8% of potassium meta vanadate for 2 to 5 days prior to startup. The minimum time period for vanadation is 48 hours. Temperatures are kept just below boiling (240°F) by heat in the reboiThis pretreatment coats all equipment with a protective oxide layer (Fe3O4) that prevents corrosion during operation if temperature, velocities, inhibitor concenttions, and valence states are maintained within design limits. It is not necessaryrevanadate after a shutdown unless repairs have been made or new steel has installed. Corrosion problems can occur in areas of high turbulence, but are ususolved by use of 18-8 stainless steel (Type 304L).

The Catacarb process (Eickmeyer and Associates) also requires payment of a process royalty and is very similar to the Benfield process. Chevron has a Cataunit at El Segundo (H2 Plant No. 3). The main difference between the Catacarb aBenfield processes is that the Catacarb process uses an undisclosed activator continuous air blowing to maintain the inhibitor in the proper valence state.

As at Benfield plants, vanadium is used in the Catacarb process as an inhibitorbe effective, it should be maintained in the +5 valence state. Reducing agents, as H2S, can reduce its valence to +4 (vanadium tetroxide, V2O4) or even +3 (vanadium trioxide, V2O3). In these reduced states, vanadium is much less effecas an inhibitor. The Catacarb process, therefore, uses injection air to keep the vdium well oxidized (in the +5 valence state) so that it remains effective.

Benfield solutions, evidently because of problems with the DEA activator, do nouse air injection. The vanadium valence state is maintained by use of a chemicoxidizing agent.

System chemistries are similar for both processes, and prepassivation or vanadprocedures are important for both.

3760 Corrosion in Hot Potassium Carbonate Plants

3761 General or Preferential CorrosionFigure 3700-8 shows the potential corrosive areas in a hot potassium carbonatsystem. In general, lean carbonate solutions, being alkaline, are not corrosive tcarbon steel and so carbon steel is used for most equipment in these plants. However, hot carbonate solutions with CO2 are corrosive to carbon steel, which explains why the proprietary processes all provide inhibitors. A properly designand inhibited system should be noncorrosive to carbon steel. However, stainlessteel is still required for reboiler tubes and other critical equipment where turbulence exists, such as pressure letdown valves and piping into the regenerator.

Corrosion inhibition in the Benfield and Catacarb processes depends on an adhhigh integrity iron oxide layer protecting the carbon steel. The purpose of the vadium inhibitor is to make the liquid sufficiently oxidizing so that the correct film (Fe3O4) is formed. Anything that reduces V+5 to V+4 lessens the solution's ability topassivate steel. For example, bicarbonate and Fe+2 are harmful. Bicarbonate is not present on initial passivation, but forms after contact with CO2. Solution containing



orth

ning ys be

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extra-avoid

bicarbonate can maintain the oxide film, but probably is not oxidizing enough to reform the film in damaged areas. Once the passive layer is lost it is difficult to restore. This is especially true in high velocity and turbulent areas.

Any time a repair is made to equipment in a carbonate plant, the steel must be repas-sivated, regardless of the size of the equipment or its location in the plant. We have seen severe corrosion in cases where repassivation is not done. At Pascagoula, corrosion which started at a condensate leak into the absorber eventually became severe enough to require replacement of large plate sections. Once corrosion starts, it can be nearly impossible to stop, short of upgrading to Type 304L steel.

The integrity of the protective oxide layer is also endangered by the presence of H2S. A small amount of H2S is tolerable, but above a few hundred ppm H2S, the V+5 inhibitor is reduced to V+4 and is ineffective. There is competition between formation of an oxide scale and formation of a sulfide scale. Neither is stable and severe corrosion can occur. This, along with mechanical damage of the scale, was the reason for corrosion on the order of 4000 mpy at SACROC in 1986.

Above several thousand ppm H2S, a sulfide scale is stable and the vanadium inhib-itor is not needed. However, the H2S level above which corrosion is acceptable is not well defined. If H2S levels are expected to be between a few hundred and a few thousand ppm, an amine process should be used rather than a carbonate one.

Regenerator overhead systems can corrode because the nonvolatile inhibitor does not protect the overhead. Acidic corrosion can occur in overhead condensers and turbulent flow areas as a very localized attack in the form of carbonic acid erosion-corrosion. A solution has been to use stainless steel (Type 304) condenser tubes. If air coolers are used, both tubes and inlet and outlet headers should be stainless steel because serious corrosion has occurred in carbon steel headers.

3762 Stress Corrosion Cracking: Carbon SteelCarbonate solutions have caused stress corrosion cracking of carbon steel when the electrochemical potential of the steel in contact with the solution has been within a well-defined range [17–18]. For example, the regenerator reboiler shell at the NSnyder gas plant (SACROC) cracked about two-thirds of the way through at a nonstress-relieved circumferential weld. Also, SCC has occurred behind strip lipanels in an absorber tower [19]. For this reason, major equipment should alwastress-relieved in these plants.

3763 Stress Corrosion Cracking: Stainless SteelsAs in amine treating plants, austenitic stainless steel reboilers in hot potassiumcarbonate plants can be subject to chloride SCC. See Section 3733 for a discuof this cracking and potential chloride sources. Again, chlorides should be limitea maximum of 500 ppm.

Intergranular corrosion is also possible in hot potassium carbonate plants, and low carbon grades of welded or stress-relieved stainless steels are required to sensitization. See Section 3733.



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or n ut.

s o eld e

s. n of n

-d

3764 Influence of Design, Operating VariablesCorrosion in hot potassium carbonate plants is influenced by process design and operating variables. The effects of many of these variables are similar in carbonate plants and amine plants. Alloys used in critical equipment such as regenerator bottoms and reboilers can corrode if care is not used in defining these variables.

Primary VariablesTemperature. As in amine plants, the worst corrosion is found where temperatures are highest: regenerator reboilers. The vanadium inhibitor helps protect these areas, but alloy equipment is still necessary.

Solution Strength. Since hot potassium carbonate processes are licensed, solution strengths outside of the recommended range, 25–30%, are not common. Abovcorrosion is not necessarily worse, but the solution will crystallize in service andcause erosion problems and instrument plugging.

Acid Gas Loading: Recommended maximum acid gas loadings for carbonate plants are set by the Licensor in terms of maximum conversion of carbonate tobicarbonate in the solution.

Secondary VariablesThe secondary variables are:

• Solution cleanliness• Velocity/turbulence

Solution Cleanliness. Contamination of carbonate solutions can lead to serious corrosion. See Section 3734 for a discussion of problems caused by dissolved entrained hydrocarbon sludge and suspended solids. As at amine plants, carbofiltration is a key to solution cleanliness, preventing foaming. It may also reducecorrosion because the Fe content of the solution will drop with carbon changeo

Velocity/Turbulence. Hot potassium carbonate solution is more corrosive in areaof increased velocity and turbulence; therefore, carbon steel velocity is limited t6 fps here. Also, Union Carbide has recommended the following limits for Benfiplants: 2, 6.5, and 12 fps for 2, 10, and 26-inch pipe, respectively. Union Carbidlimits vapor phase velocities to 70 fps.

See Section 3734 for information regarding pumps and pressure letdown valveThe same problems are possible in carbonate plants. Since a substantial portiothe CO2 flashes when the pressure is reduced (about 1/3), the mechanical desigof the rich solution inlet to the regenerator is extremely important to prevent failures from excess vibration. Vibration can also break the protective oxide film anresult in catastrophic corrosion.



.

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3770 Corrosion Control in Hot Carbonate Treating Plants

3771 Use of AlloysHot potassium carbonate plants (Benfield and Catacarb) are essentially noncorro-sive to carbon steel when properly inhibited, but extremely corrosive when not. In general, the Company refers to the Licensor for materials recommendations. The following is a list of equipment that usually requires material other than carbon steel.

• Absorber. Below the first tray, T304L cladding is used.

• Absorber bottom control valve and pressure letdown valve to regenerator. These valves are stellite-hard faced T304 to avoid acidic erosion-corrosion

• Piping from absorber bottom control valve to accumulator and from pres-sure letdown valve to regenerator. This piping is also T304L to avoid acidic erosion-corrosion.

• Regenerator. The top of the regenerator above the feed tray is T304L clad.

• Regenerator overhead acid gas cooler. T304L tubes are used in this exchanger. If this is an air cooler, inlet and outlet headers should also be T

• Reboiler. The reboiler tubes are usually T304L. See also the discussion oneffects of reboiler design on corrosion in Section 3741.

• Lean carbonate pump. This pump is usually T304, but carbon steel can be used if potential corrosion problems are avoided. See Section 3734 on veloand turbulence effects.

Other General GuidelinesSome other general guidelines on use of alloy equipment in carbonate plants afollows:

• To avoid sensitization, only extra-low carbon or stabilized grades of stainlesteel should be used where welding or stress relief is required.

• Brass alloys are not suitable in these plants, because of the high alkalinity osolutions.

• For water-cooled exchangers, compromise is frequently necessary to obtaibest combination of stock-side and water-side corrosion resistance. When cooling water is used, stainless steel tubes are suitable. If seawater or pooquality cooling water is used, 70-30 Cu-Ni tubes are an option as long as H2S is not present. If there is H2S, titanium tubes can be used.

3772 Use of Corrosion InhibitorsCorrosion inhibitors play a very important part in both the Benfield and Catacarprocesses; poor inhibition can cause serious operating problems and unschedu



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o-

rge

shutdowns. An important operating procedure in these plants is prepassivation, or vanadation, of clean metal surfaces by circulating a hot carbonate solution containing 0.8 weight percent of vanadium throughout the plant equipment for several days.

This pretreatment lays down protective vanadate-iron oxide films which are then maintained by properly inhibited (0.5 weight percent vanadium) carbonate solu-tions. Thereafter, the vanadium compounds, to be effective, should be maintained in a fully oxidized +5 valence state. If reduced to V+4 by sulfur contamination, the vanadium compounds are less effective as inhibitors and corrosion may result. This reduction can sometimes be detected as a color change from brown or yellow to green.

Since corrosion protection in carbonate systems depends on a protective film, accel-erated attack can occur at localized breaks in the film. Rapid corrosion can occur where metal surfaces rub together or in areas of high turbulence.

3773 Corrosion MonitoringSee Section 3743. Close monitoring of the iron content of carbonate solutions is the principal method of monitoring corrosion in carbonate plants. Iron contents in excess of 100 ppm are cause for concern.

3780 References1. Ploetz, J. P. “MDEA Plant Corrosion Coupon Rack,”11-15-88, File

75.16.86.01.

2. Potter, G. L. “Survey of Corrosion Experience in MDEA-Based Amine Systems,” November 30, 1990, File 75.16.31.01.

3. Piehl, R. L. “Richmond MDEA Conversion,” 9-28-87, File 75.16.31.1; “MDEA Survey,” 10-19-88 memo to File 75.16.31.1., “MDEA Conversion,” 4-28-89, File 75.16.31.02.

4. Richert, J. P., A. J. Bagdasarian, and C. A. Shargay. “Stress Corrosion Craof Carbon Steel in Amine Systems,” presented at Corrosion '87, 3-9 to 2-13San Francisco, paper #187.

5. Richert, J. P., A. J. Bagdasarian, and C. A. Shargay. “Extent of Stress Corrsion Cracking in Amine Plants Revealed by Survey,” Oil and Gas Journal, June 5, 1989, p. 45.

6. Bagdasarian, A.J., C. A. Shargay, and J. W. Coombs, “Stress Corrosion Cracking of Carbon Steel in DEA and `ADIP' Solutions,” Materials Perfor-mance, May 1991, pp. 63–67.

7. Klehn, R. “Amine Stress Corrosion Cracking of El Segundo P-1600 DischaLean Piping,” February 26, 1992, File 75.16.86.



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8. Ferrell, D. E. “Cracked H2S Absorber, C-4001, H2S Plant, Irving Refinery,” Materials Laboratory Report, File No. P-460.14, February 20, 1975.

9. Ballard, D. “How to Operate an Amine Plant,” Hydrocarbon Processing, April 1966.

10. Butwell, K. F. “How to Maintain Effective MEA Solutions,” Hydrocarbon Processing, April 1968.

11. Dingman, J. C., D. L. Allen, and T. F. Moore. “Minimize Corrosion in MEA Units,” Hydrocarbon Processing, September 1966.

12. Williams, E., and H. P. Leckie. “Corrosion and Its Prevention in an MEA GaTreating Plant,” Materials Protection, July 1968.

13. Pegors, S. R. “5 H2S Foaming Report,” Richmond Refinery Memorandum, June 7, 1989.

14. Wagner, E. J. “Pascagoula 1992 Amine Plant High Corrosion Rates,” El Segundo Refinery Memorandum, September 2, 1993.

15. Longworth, A. L. “DEA Task Force Recommendation Report,” Pascagoula Refinery Report, August 5, 1992.

16. Keller, A. E., R. M. Kammiller, F. C. Veatch, A. L. Cummings, J. C. Thompseand S. M. Mecum, “Heat Stable Salt Removal from Amines by the HSSX Process Using Ion Exchange,” pp. 4–5. Presented at the Laurence Reid GaConditioning Conference," March 2, 1992.

17. Atkins, K. T. G. “Corrosion in CO2 Removal Plant Towers,” Ammonia Plant Safety, a CEP Technical Manual published by AIChE, Volume 16, 1974.

18. Schutt, H. U. “Intergranular Wet Hydrogen Sulfide Cracking,” Paper #454. Presented at NACE Corrosion 92 Conference.

19. Kolff, S. W., Technical Department KEMIRA B.V. “Corrosion of a CO2 Absorber Tower,” Plant/Operation Progress, Vol. 5, No. 2 (April 1986), pp. 65–72. Presented at AIChE 1985 Summer National Meeting, Aug. 25-21985, File 75.16.31.2 (literature).

Suggested ReadingBienstock, D., and J. H. Field. “Corrosion Inhibitors for Hot-Carbonate SystemsCorrosion, December 1961.

Conners, J. S., and A. J. Miller. “Operating Problems Related to Gas Treating,”Oil and Gas Journal, February 2, 1950.

Dingman, J. C. “Effect of MEA Variables on Corrosion,” Chemical Engr. Prog., Safety in Air and Ammonia Plants, Volume 9, 1967.

Goar, B. C. “Today's Gas Treating Processes,” No. 1 and 2, Oil and Gas Journal, July 12, 1971 and July 19, 1971.



Hafsten, R. J. “Literature Survey—Corrosion in Amine Gas Strippers,” API Subcommittee on Corrosion, May 2, 1957.

Hawkes, E. N., and B. F. Mago. “Stop MEA CO2 Unit Corrosion,” Hydrocarbon Processing, August 1971.

Hitchcock, E. A. “Modern CO2 Removal,” AMPO 74, ICI Operating Symposium, 1974.

Mottley, J. R., and D. R. Fincher. “Inhibition of MEA Solutions,” Materials Protection, Vol. 2, No. 8, 26-30, 1963.

Nathan, C. C. “Corrosion Inhibitors,” NACE Publication, 1973.

Nelson, W. L. “Questions on Technology,” Oil and Gas Journal, June 20, 1966.

Strelzoff, S. “Choosing the Optimum CO2 Removal System,” Chemical Engi-neering, September 15, 1975.

Sudbury, J. D., O. L. Riggs, and J. F. Leterle. “LAB Inhibitor Stops DEA Corrosion,” Petroleum Refiner, May 1958.


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CPM3700 Acid Gas Removal Plants

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