CORROSION IN ALKANOLAMINE PLANTS: CAUSES AND MINIMIZATION

P.C. Rooney and M.S. DuPart The Dow Chemical Company GAS/SPEC Technology Group

Building B- 1605 Freeport, TX 77541

ABSTRACT

Corrosion in alkanolamine plants can be caused by a number of factors. Guidelines are given to maintain solvent cleanliness, acid gas loadings, solvent velocity and metallurgy required to minimize the effects of corrosion. Also, sources and ways to minimize the corrosive effects of CO, heat stable amine salts (HSAS), oxygen and ammonia are presented.

Keywords: alkanolamine, corrosion, gas treating

BACKGROUND

There have been several books written that provide an excellent resource on the broad topic of gas treating.~4 Each give the reader extensive data covering everything from the design of a plant to the analytical methods required to analyze plant operating solutions. The topic of corrosion in alkanolamine plants learned over the past 45+ years is included in each of the above books. For example, Kohl and Neilsen devote more than hal fofa chapter to amine plant corrosion (reference I, pp188-224). The Gas Conditioning Fact Book devotes about one-third of a chapter to corrosion in amine systems (reference 2, pp 148-174). Reports reviewing the general topic of corrosion in alkanolamine plants dating back to the late 1950's have also been published (for example, see references 5-12). Many more papers have been published on more specific topics of the causes of corrosion in alkanolamine plants (i.e. effect of heat stable salts, acid gas loadings, amine degradation).

Clearly, the topic of corrosion plays an important role in the design and successful operation of a commercial gas plant. With this in mind, this paper is presented as a practical guide to identifying causes of corrosion and ways to minimize corrosion in alkanolamine plants.

Copyright 2000 by NACE International.Requests for permission to publish this manuscript in any form, in part or in whole must be in wdting to NACE International, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in U.S.A.

DISCUSSION

Amine Concentration and Loadings

Table 1 gives guidelines for amine concentration and acid gas loadings that are commonly accepted in the industry to minimize carbon steel corrosion] 3 In mixed CO2/H2S acid gas service where the ratio of H2S to CO 2 is above about 1/19, the total acid gas loadings are somewhat higher due to the formation of a protective iron sulfide (FeS) film formed via the reaction of H2S with the iron in carbon steel. ~4 It is further pointed out by Nielsen et alJ that the acid gas should contain at least 5 vol.% H2S and that the H2S partial pressure should be greater than 5.1 kPa (0.74 psia) before the higher acid gas loading guidelines should be used. Although diglycolamine is listed at 70wt.% maximum, more recent reports suggest that diglycolamine gets much more corrosive with CO2 when the amine concentration exceeds about 50wt.%. ~5

Plant Temperature Guidelines

According to DuPart et al., 7 the maximum bottoms absorber temperature is 180F (82C) and the maximum stripper bottoms temperature should be less than 255F (124C). Chakma and Meisen Z6 recommend a slightly lower reboiler temperature (248F, 120C) based upon their work with MDEA degradation. To minimize thermal degradation of the amine, the reboiler heat source should not exceed 300F (149C). 5'7

Plant Metallurgy

Carbon steel, 304 SS, 304 L SS, 316 SS and 316 L SS are all recommended for general use . 7 Avoid copper, brass or other copper bearing alloys due to known amine / copper complexation ~7 which may result in accelerated corrosion. Martensitic 410 SS is not recommended for amine service. DuPart showed one example of severe pitting towards 410 SS in a plant solution using 15wt.% DEA. 7 Work performed in this lab using liquid and vapor coupons with MDEA Blend A [loaded to only 0.010wt.% CO2 and heated to 260F (126.7C) for28 days in an autoclave] showed very little corrosion protection of the 410 S S compared to carbon steel whereas the 304L and 316L SS showed excellent resistance to corrosion (see Table 2).

Carbon steel is generally acceptable when used for the absorber, lean/rich exchanger, lean amine cooler tubes ad shell, carbon bed, reflux drum and stripper shell. In addition, carbon steel is often used for the reboiler tube sheet and side stream channels, the reflux condenser tubes and shell, the pump casing and lean amine piping. The austenitic stainless steels (304 SS, 304 L SS, 316 SS and 316 L SS) are often used for the absorber, carbon bed and stripper internals, the tubes of the lean/rich exchanger and reboiler, the impellers of the pump, and the rich amine piping. In amine units used in refineries for H2S removal 304L or 316L is required in the stripper overhead due to corrosion caused from ammonium bisulfideJ s

When joining dissimilar metals together such as carbon steel to stainless steel it is very important to prevent galvanic corrosion sites. For example, attaching SS trays with carbon steel bolts results in the carbon steel bolts becoming anodic compared to the cathodic SS trays. Threaded connections are not

recommended since severe erosion corrosion of the threads results due to the turbulence caused by the threaded area.

Maximum solution velocities of 3 ft/sec. (0.91m/sec.) have been recommended by DuPart (reference 7 and references cited therein) for carbon steel, although others recommend as high a 6ft./see. (1.83m/see.) as being acceptable for carbon steel. Stainless steel is required above these levels.

Filtration

Carbon filtration of the lean amine has proven to be very beneficial in reducing particles that promote erosion corrosion and abrasion of passive films as well as effectively removing hydrocarbons and amine degradation products. Bituminous carbon was found to be very effective at removing amine degradation products, although the capacity was low.~9 A 5-10% slip stream of lean amine through the carbon bed is common. Because of carbon's low capacity, it should be replaced every 6 months or sooner, depending on the service. A convenient way to determine if the carbon needs replacement is to compare the amine color or Fe levels both before and after the carbon bed. Active carbon should show better color and lower color after the carbon bed than before. New charges of carbon should be thoroughly backwashed with water prior to remove dissolved oxygen in the pores of the carbon as well as to prevent carbon fines from entering the plant.

Mechanical filtration should be used to remove all particles greater then 5 microns. In COs-only service, it is most common to have the filters installed upstream and downstream of the carbon bed. In mixed acid gas service, a full rich stream filter is also recommended to remove FeS that may precipitate. Paper and sock-type filters should be used with caution since these may collapse and recontaminate the amine solution.

Role of Oxygen in Amine Degradation

Oxygen has been found to degrade MEA, DEA and MDEA as far back as 1950. 50 In 1956, it was shown that MEA degraded with oxygen to form formic acid, ammonia, amides and "polymers". 2r In 1962, MEA and oxygen was found to form glycine, glycolic acid and oxalic acid. 22 A 1992 study showed that MDEA, DEA and MEA formed formic acid, oxalic acid and acetic acid. 23 More recently, a Dow study 24 showed that DEA, MDEA, diglycolamine and MEA formed various levels of formates, glycolates and oxalalates when air was bubbled through amine solutions containing with and without COs at 180F (82.2C). In the case of MDEA, oxygen was found to also form 1600ppm DEA in only 28 days] 4 DIPA was found to form formate, acetates glycolates and propionates 25 as well as propionates and monoisopropanolamine (MIPA) 26 when exposed to oxygen. As will be discussed later, these amine heat stable salts (i.e. formates, acetates, glycolates and propionates) are known to increase solution corrosivity and plant operating costs.

For plants using MDEA to slip CO2 in mixed acid gas service, increased DEA concentrations caused by oxygen may reduce the ability of the MDEA to slip CO2. Increased CO2 removal as a result of the DEA may reduce the amount of gas that can be effectively treated because of plant design limits (i.e. rich amine loading and pump circulation rates). The amount of DEA that noticeably affects COs slip in MDEA is often in the range of 5000ppm DEA and higher. With this small an amount of DEA, vacuum

reclamation may not be possible without significant MDEA losses. The result is that the plant must accept lower treated gas rates or purchase a new charge of MDEA.

Oxygen in the feed gas has also been linked to the formation of bicine. 27 Severe corrosion was noted for bicine in laboratory autoclave studies. It has also been implicated as being responsible for severe corrosion in the reboiler of a Dow coal gasification plant using MDEA. 28

0 II

(HOCH2CH2)zNCH2COH

Bicine

As is discussed by McKnight, 29 reducing or eliminating oxygen contamination in gas streams is a very time consuming and labor-intensive process. Dedicated oxygen analyzers at the plant and the field boosters can help locate where oxygen leaks occur. Possible sources of air entry include well-head equipment (valves and fittings), metering equipment (tubing, temperature taps and valves), unscrupulous producers who want to increase sales volume of marginal wells, pipelines (either by corrosion or puncture) and unplugged, abandoned wells. Air entering via the amine storage tank, surge tank or vapor recovery unit (VRU) is also possible, especially if there is an insufficient nitrogen or inert gas pad.

Oxygen scavengers (i.e. sulfites, hydroxylamines, hydrazine) are well known to reduce oxygen to part per billion (ppb) levels in boiler feed water, 3 and they may be useful in reducing oxygen solubility and heat stable salt build up. This is especially true as a short-term fix for low levels of oxygen contamination until the source of oxygen can be located.

Role of Carbon Monoxide (CO) in Amine Degradation

Carbon monoxide is a problem in HYCO (hydrogen / carbon monoxide) and coke oven gas plants, and to a lesser degree in partial oxidation (POX) and FCC overhead gas plants using alkanolamines to remove CO2 and/or H2S. CO has been shown to react with caustic or the tertiary amines MDEA or diethylethanolamine (DEEA) to form formate salts. 3~ Dow work has shown that MEA and DEA formed formate salts and formamides when reacted with CO (see below). 27 Tertiary amines like MDEA or DEEA do not form formamides since there is no available N-H for the CO to insert into. More recently, DIPA was reported to give about five times more formate than DEA when each were reacted with CO. 25

There is no evidence to date that indicates whether these formamides are corrosive. However, especially in HYCO and coke oven plants where formate levels often exceed 20,000ppm formate salts, there have been serious corrosion problems especially in the stripper and stripper overheads where formic acid levels may be especially high. When especially formate is seen as the predominant heat stable salt, CO and/or cyanides (see next section) should be suspected as being the source of the problem. As will be discussed later, formates are known to increase solution corrosivity and plant operating costs.

CH3N[CH2CH2OH]2

(MDEA)

CO MDEAH + HCOO"

(Formate salt)

H2NCH2CH2OH

(MEA)

CO

O H \

N-C-H

HOCH2CH2//

(HF)

+ HCOO" (Formate salt)

O HOCH2CH 2

co \ II HN[CH2CH2OH] 2 .~ N-C-H + HCOO-

HOCH2 CH- j2 (Formate salt (DEn)

(BHEF)

Causes and Minimization of Cyanide (HCN)

There are many papers that discuss HCN corrosivity in amine plants) ~ HCN enters an amine unit via cracking of naturally occurring nitrogen compounds found in most coals and crude. FCC, HYCO and coke oven gas plants are most often affected by HCN. Delayed coking and visbreaking also results in some cyanide formation. Dow experience is that HCN attacks especially stainless steel and that about one-third of the HCN entering the amine unit is hydrolyzed to formate salts, which accelerates corrosion even further. One recent report 33 describes hydrogen blistering and/or cracking in the FCCU, corrosion in the amine regenerator, high amine make-up rates, amine foaming, and hydrogen corrosion in the sour water stripper. Tell-tale blue staining due to Fe (CN)6 was also noted at several locations.

Corrosion inhibitors (i.e. film-formers and oxygen scavengers) are generally not successful in controlling corrosion due to HCN. Installation of a water wash before the absorber, while effective for the removal of acetic acid and formic acid, appears to be ineffective in eliminating HCN from entering the amine unit) Caustic treating of the alkanolamine does not appear to be effective in neutralizing the HCN. Apparently, the higher pH of the caustic treated amine results in more hydrolysis of the HCN to formate in the absorber. Polysulfide (either ammonium polysulfide or ammonium polysulfide) injection into a wash water system installed before the absorber and polysulfide injection into the reflux water appears to be successful in reducing corrosion due to HCN. TM A recent paper describes a refinery that was unable to control HCN efficiently with ammonium polysulfide, but did switch to a commercial

HCN scavenger that completely removed HCN and signs of hydrogen blistering from the regenerator overhead. 35

Causes and Minimization of Thiocyanate (SCN)

The are two principle ways that thiocyanates can get into an amine system: a) as an inlet component of FCC gas streams and 2) reaction of elemental sulfur (formed from the reaction of H2S and oxygen) with HCN). Urban 3a estimates that about one-half of the cyanide in their FCCU reacted to form thiocyanates. Thiocyanates can be reduced by minimizing the presence of oxygen and also by purging the stripper reflux water. There does not appear to be any literature indicating that SCN is corrosive in amine systems. In fact, there are several sources suggesting that various metal thiocyanates are corrosion inhibitors. 36

Causes and Minimization of Sulfate, Sulfite and Thiosulfate

Sulfates and sulfites can be introduced in the amine unit via make-up water. Oxygen in the feed gas can also react with HzS to form elemental sulfur (S), sulfites (SO3), thiosulfates ($203-) and sulfates (SOn) along with dithionites ($204) and polythionates (S,O6).

In a tail gas unit, when SO2 breakthrough occurs, thiosulfate is predominantly formed. It is not uncommon to have upwards of 20-30,000ppm of thiosulfate formed from a single SO 2 breakthrough. When this occurs, enough of the amine may be neutralized so that H2S treat cannot be maintained. Purging reflux water can help remove the thiosulfates from the system, but with major SO2 breakthroughs the solvent must be reclaimed or disposed of in order to meet required H2S specifications. Another potential problem with SO2 breakthrough is that it has also been implicated in bicine formation (see Role of Oxygen in Amine Degradation for discussion on bicine corrosivity). Monitoring the TGU quench water pH for signs of SO 2 breakthrough can help identify quickly when an SO2 breakthrough has occurred.

As will be discussed later, sulfates and sulfite have been shown to increase solution corrosivity and plant operating costs. The key to minimizing sulfates and sulfltes is to minimize the presence of oxygen by blanketing the amine storage tank and amine sump with inert gas. Checking the make-up water for potential sulfur species is also important.

Causes and Minimization of Ammonia (NH~)

Ammonia can be generated in an amine system by thermal degradation of the amine, oxidative degradation of the amine, as a by-product of the reaction of HCN and water (resulting in the formation of carboxylic acids and NH3). Ammonia can also be present in significant amounts in FCC units, delayed coker and visbreaking gas streams.

Ammonia is completely soluble in amine solutions and is regenerated completely in the stripper. The ammoniacal condensate absorbs CO2 to form ammonium carbamate or bicarbonate, thereby plugging the condensor. 39 In a refinery unit, the ammoniacal condensate absorbs H2S to make ammonium bisulfide, making the condensate corrosive. One cure is to purge the reflux water of the ammonia to prevent plugging and build-up of corrosice compounds. The use of a titanium condensor has also been

suggested to minimize corrosion due to ammonia and it's reaction with H2S and/or C02, 37 but this type of metallurgy is not commonly used in this service today.

Causes and Minimization of Chlorides

Chlorides enter the alkanolamine system mostly from chloride-containing make-up water, although chlorides may also enter with the incoming natural gas as entrained salt water. Chloride may also enter coal gasification units since the coal often contains chlorides. In the high temperature areas of the combustion process, the chlorides are converted to HCI, which then enters the alkanolamine with the incoming gas.

It is well documented in the literature that the chloride ion is responsible for pitting, crevice corrosion and stress corrosion cracking of stainless steels while carbon steels are notoriously susceptible to general corrosion by chlorides. 38 Chloride-induced stress corrosion cracking, pitting (carbon steel less so than stainless steel pitting) and crevice corrosion are the recognized effects of chlorides in alkanolamine solutions. 5'7"s However, there are a number of general operating experiences in amine plants with chloride levels as high as 10,000ppm that have not resulted in confirmed corrosion. This may be due to the fact that these levels were experienced as sodium chloride rather than HCI reacting with the amine to form the amine chloride. As will be seen later, Dow has performed several laboratory experiments showing that chlorides can also give high general corrosion to carbon steel.

The best ways to prevent chlorides from entering the amine unit include adequate inlet separation, high quality make-up water and desalting of crude.

Guidelines for Make-Up Water

High quality make-up water helps reduce the amount of contaminants that enter the amine operating solution. Dow's guidelines are the following:

Total Hardness (Ca & Mg)

Chlorides

Sodium

Potassium

Iron

5 0 ppmw max

2 ppmw max

3 ppmw max

3 ppmw max

10 ppmw max

Heat Stable Amine Salt (HSAS) Guidelines

It is generally agreed upon that the presence of HSAS increases the corrosivity of alkanolamine plant operating solutions. 39 These HSAS are called heat stable since the reaction of the acid with amine is not reversible under normal regenerator conditions. For example, a 30wt.% MDEA solution containing 5wt.% HSAS as the formate salt only dissociates 3ppmw formic acid in the regenerator at 121 C.4' The result is that the presence of HSAS also decreases the acid gas carrying capacity of the amine solution, increases the viscosity and increases the operating costs of running the amine unit.

Dow has done extensive laboratory work on amine solutions and actual plant solutions with heat stable salts and their effect on corrosion to try and determine guidelines on the amount of HSAS allowable in a plant solution before operators need to increase their awareness to possible corrosion problems. 27"39 As is seen in Figure 1, most HSAS show a similar increase in carbon steel weight loss corrosion as the pH of the solution is decreased due to the addition of the acid. Bicine and oxalic acid showed much enhanced corrosivity to carbon steel due to their ability to complex with the Fe. From these studied, the following guidelines were given based upon 10mpy (25.4um/yr) or less carbon steel coupon corrosivity:

250ppm oxalate and bicine (very corrosive species) 500ppm C1, sulfate, formate, sulfite, glycolate, malonate 1000ppm acetate or succinate 10,000ppm SCN, thiosulfate, NH 3

In addition, the guideline for the total amount of HSAS salts was given as 0.5wt.%.

Caustic Neutralization of HSAS

Most authors in the literature believe that caustic neutralized HSAS are less corrosive than the corresponding HSAS (see Reference 42 and references cited therein). Dow's work with carbon steel weight loss coupons using caustic neutralized amine solutions and caustic neutralized refinery plant solutions also shows the benefits of caustic neutralization. 2v'39 Dow's experience with many customer plants is that caustic neutralization is often beneficial if done properly. The only exception appears to be in plants having HCN and NH3 does it appear that caustic neutralization is not beneficial [see Causes and Minimization of Cyanide (HCN) section]. There is a recent paper showing that a complex refinery has used a combination of corrosion inhibitor and caustic neutralization for over 4 years without cleaning or reclamation even though the amine contained very high levels of acid contaminants (including NH 3 and HCN). 35 The key to the successful use of caustic neutralization is that it always be carried out in a careful and controlled manner. Dow recommends never neutralizing more than 80wt.% of the HSAS. The rate of caustic addition should be continuous and slow (0.1% of circulation rate). Finally, a maximum of about 10% of the total amine concentration can be neutralized before viscosity problems and solids problems appear.

It is noted that not all agree with the benefits of caustic neutralization. Cummings and/or Keller 43 have written a series of papers showing that caustic neutralization can increase corrosivity of amine solutions containing H2S. In all their papers, linear polarization resistance (LPR) was used to measure corrosion rates. As is pointed out by Asperger et al., 44 LPR is not an effective method for use in systems using H2S because it is required that the system come to a steady state before meaningful corrosion rates can be interpreted by the LPR. With HzS present, the system never really comes into steady state due to the complex chemical reactions occurring in the solution and on the electrodes of the LPR.

There is one paper by Litschewski 55 that does present information from coupons and plant inspections that indicated caustic addition to their MDEA has the potential to initiate crevice corrosion in stainless steel. Coupon corrosion rates historically were less than 12mpy (305um/yr) with formate concentrations

up to about 8000ppm. After caustic addition, corrosion rates increased to 44.4mpy (1128um/yr) while formate concentration increased to 11,900ppm. The author suggests that formate level and/or Na concentration was the cause of the increased corrosion. The paper does not give an inlet gas composition, but it is likely that the formate concentration increased due to HCN and/or CO in the inlet gas, both of which would increase formate levels due to the high pH of the amine solution after caustic treating. Again, systems having HCN and/or CO should probably not consider caustic as a way to control corrosion in their plant.

The Role Of Amine / CO 2 Degradation Products on Corrosion

The reaction of alkanolamines (especially MEA, DEA, DIPA and diglycolamine) with CO2 to form diamines, oxazolidinones, substituted piperazines, and polyamines is well known (for example, see references 1,2,3, 15, 23, 25, 26, 37, 46 and references cited therein). MDEA also degrades in the presence of COz, but to a far lesser extent than other alkanolamines. 47

Reports on the role of corrosion and amine / CO 2 degradation compounds is very scarce. The most often cited source that amine degradation products are non-corrosive is by Blanc, Grail and Demarais. 48 In this study, they found that there was little difference in C 1018 carbon steel coupon corrosivity between 30% DEA or DEA + hydroxyethylpiperazine when heated to 80C with an HzS partial pressure of 20 bars. However, Chakma and Meisen have shown by LPR that a solution of DEA, HEOD, BHEP and THEED has a corrosivity of 0.4mm/yr (16. l mpy) compared to DEA having 6.1 times lower corrosivity under the same conditions. Coupon weight loss tests at 100C using saturated COz solutions at room temperature and atmospheric pressure did confirm BHEP's non-corrosiveness, but did find that HEOD was much more corrosive to the carbon steel.

The reports of above are somewhat contradictory. In addition, both studies were performed under conditions that are far different than most plant applications. As Dow reported last year on a large number of plants using DEA and/or MDEA plants over many years, 50 the total amount of degradation due to CO 2 is often much less than 2wt.%. The vast majority of these plants operate very well and do not show the amount of degradation or corrosivity that lab degradation studies using amines + CO2 show.

How To Monitor Plant Solution Corrosivity

There are many ways to monitor the solution corrosivity in a plant. Although it is easy to monitor Fe concentration over time and correlate high Fe with increased corrosion, we have found that Fe levels do not provide a reliable way to indicate active corrosion. 5~ The fact that the active corrosion products (i.e. FeS, FeCO3 and iron hydroxides) are often insoluble and precipitate in various places in the plant is only one example of why low Fe in solution can be misleading. While changes in Fe, Cr and Ni can not be ignored, monitoring of the plant using coupons or probes is essential. Trends of linear polarization resistance (LPR) and electrical resistance (ER) probes can give useful (qualitative) day to day corrosivity information if used properly. However, coupons measured every 14-30 days often gives the best measure of actual corrosion based upon plant inspections. 45'52

Amine Reclamation

Anion exchange is an excellent way to reduce high heat stable salts in alkanolamine solutions to extremely low levels. Of course, if high amounts of Na or K are in the solution (due to NaOH or KOH neutralization), then a cation exchange resin may also have to be used to fully clean the alkanolamine solution. While ion exchange has typically been performed by outside vendors, there is a report of Crown Central Petroleum having success with it's own on-site purchased amine purification system. 53 Solution reclaiming by distillation (or vacuum distillation) will also remove heat stable salts to very low levels. In order to recover valuable amine, as well as prevent distillation of some acids into the distilled amine, caustic neutralization is often performed. Reclaiming by distillation can also remove other contaminates (e.g. ethylene glycol, triethylene glycol and hydrocarbons) to very low levels that anion exchange will not remove. The choice as to which reclaiming method to use for your plant will depend on the amount and type of heat stable salt that needs to be removed as well as whether other contaminants that are also needing to be removed. In either case, it is very important that chelating anions such as bicine and oxalate are removed as much as possible (

8. M.S. DuPart, T. R. Bacon and D. J. Edwards, "Understanding Corrosion in Alkanolamine Gas Treating Plants, Part 2", Hydrocarbon Processing, June: 1993.

. N. N. Bich, F. Vacha and R. Schubert, "Corosion in MDEA Sour Gas Treating Plants: Correlation Between Laboraory Testing and Field Experience, CORROSION/96, NACE: Houston, TX, Paper No. 392.

10. H. L. Craig, Jr. and B. D. McLaughlin, "Corrosive Amine Characterization", CORROSION/96, NACE: Houston, TX, Paper No. 394.

11. J. S. Connors, "Designing Amine Treaters to Minimize Corrosion", Proceedings of The Laurance Reid Gas Conditioning Conference, March 6-7, 1957, pp. 119-136.

12. J. S. Connors, "Aqueous-Amine Acid-Removal Process Needn't be Corrosive", Oil & Gas J., 1958, 56 (March 3), 100.

13. For example, see: Gas Processors Suppliers Association Engineering Data Book, Eleventh Edition, FPS Version, Volume II, Chapter 21, 1998.

14. "Avoiding Environmental Cracking in Amine Units" American Petroleum Institute (API) Recommeded Practice 945, 1 st Edition, August, 1990.

15. a) M. Nakayanagi, "Corrosion and Formation of Complexes of Carbon Steel and Stainless Steel in CO2-Loaded Aqueous Diglycolamine Solution", J. Japan Petroleum Institute, 1998, 41 (2), 107. b) Y. Tomoe, M. Shimizu and H. Kaneta, "Active Dissolution and Natural Passivation of Carbon Steel in Carbon Dioxide-Loaded Alkanolamine Solutions", CORROSION/96, NACE: Houston, TX, Paper No. 395.

16. A. Chakma and A. Meisen, "MDEA Degradation With CO2", 35 th Canadian Chemical Engineering Conference, October 6-9, Calgary: 1985.

17. R. M. Smith and A. E. Martel, "Critical Stability Constants", Volume 2: Amines, Plenum Press: NY, 1975.

18. R. A.White, "Materials Selection for Petroleum Refineries and Gathering Facilities", NACE: Houston, TX, 1988, pp9-98.

19. A. Chakma and A. Meisen, "Activated Carbon Adsorption of Diethanolamine, Methyl Diethanolamine and Their Degradation Products", Carbon, 1989, 27(4), p.573.

20. R. C. Kindrick, K. Atwood and M. R. Arnold, "The Relative Resistance to Oxidation of Commercially available Amines", Girdler Corp. Report No. T2.15-1-30 to the U.S. Navy, 1950.

21. B. G. Hofmeyer, H. G. Scholten and W. G. Lloyd, "Contamination and Corrosion in Monoethanolamine Gas Treating Solutions", Presented at The National Meeting of The American Chemical Society, Dallas: TX, April 8-13, 1956.

22. M. A. Scheiman, "A Review of Monoethanolamine Chemistry", U.S. Naval Research laboratory Report No. 5746 (1962).

23. C. Blanc, M. Grall and G. Demarais, "The Part Played by Degradation Products in the Corrosion of Gas Sweetening Plants Using DEA and MDEA", Proceedings of The 32 "d Annual Gas Conditioning Conference: Norman, OK, 1982.

24. a) P. C. Rooney, M. S. DuPart, T. R Bacon, "The Role of Oxygen in the Degradation of MEA, DGA, DEA and MDEA", Proceedings of The 48 'h Annual Laurance Reid Gas Conditioning Conference, March 1-4, 1998, pp.335-347, b) P. C. Rooney, M. S. DuPart, T. R Bacon, "Oxygen's Role in Alkanolamine Degradation", Hydrocarbon Processing Int. Ed., 1998, 77(7), p.109.

25. P. F. A. van Grinsven, G. J. v. Heeringen, E. C. Heyman and M. L. Dillon, "DIPA as the Preferred Solvent for Amine Treatment in Refinery Applications", Proceedings of The 49 th Annual Laurance Reid Gas Conditioning Conference, Feb, 21-24, 1999, pp.230-247.

26. J. E. Critchfield and J. L. Jenkins, "Evidence of MDEA Degradation in Tail gas Treating Plants", Petroleum Technology Quarterly, 1999 (Spring), pp87-95.

27. P. C. Rooney, M. S. DuPart, T. R Bacon, "Effect of Heat Stable Salts on Solution Corrosivity of MDEA-Based Alkanolamine Plants", Proceedings of The 47 th Annual Laurance Reid Gas Conditioning Conference, March 2-5, 1997, pp. 12-30.

28. J. G. Green, "Identification of a Corrosive Agent in an Industrial Process: Mass Spectrometry as a part of a Multi-Technique Problem Solving Effort", Presentation at the 39 th ASM Conference on mass Spectrometry and Allied Topics, May, 1991.

29. McKnight, J. E. "Air Exclusion Key to Gathering-System Upkeep", Oil and Gas J., 1988, Feb.8, 41.

30. Reardon, P. A.; Kelly, J. A. "New Oxygen Scavengers and Their Chemistry Under Hydrothermal Conditions", CORROSION/96, NACE: Houston, TX, Paper No. 175, 1986.

31. C. J Kim, A. M. Palmer and G. E. Milliam, "Absorption of Carbon Monoxide into Aqueous Solutions of K2CO3, Methyldiethanolamine and Diethylethanolamine", Ind. Eng. Chem. Res. 1988, 27, 324.

32. a) A. Jayaraman "Corrosion and its control in petroleum refineries - a review" Corrosion Prevention and Control, 1995, 42(6), pp123-131, b) R.D. Kane and M.S. Cayard "Improve Corrosion Control in Refining Processes", 1995 (November), pp.125-142, c) R.W. Bucklin and J.D. Mackey "Sulfur, Pollution and Corrosion Management in a Modem Refinery", 1983 AICHE Summer National Meeting, Denver, CO, Paper No. 66e. d) E.F. Ehmke "Polysulfide Stops Polysulfide FCCU

Corrosion", Hydrocarbon Processing, 1981 (July), pp. 149-155. e) E.F. Ehmke "Use Ammonium Polysulfide to Stop Corrosion and Hydrogen Blistering", NACE CORROSION/81, April 6-10, 1981, Toronto, Paper No. 59. f) B.W. Neumaier and C.M. Schillmoller "Deterrence of Hydrogen Blistering at a Fluid Catalytic Cracking Unit", proceedings of The API Division of Refining, 1955, 35(3), pp.92-109.

33. D. Urban, "Control Cyanides at Source", Hydrocarbon Processing, 1998, 77 (7), 85.

34. A. Jayaraman and R. C. Saxena, "Corrosion and it's Control in Petroleum Refineries- A Review", Corrosion Prevention & Control, 1995, 42 (6), 123.

35. E. W. van Hoom, "Improve Amine Operation in Corrosion Service. Experience at a Complex Refinery", Proceedings of The Gas Processors Association European Chapter Meeting, London, Feb. 18, 1998.

36. For example, see: a) E. W. Hanson, "Corrosion Inhibitors for Aqueous Brines", U.S. Patent No. 4,980,074 assigned to The Dow Chemical Company, 1990. b) M. S. DuPart, B. D. Oakes and D. C. Cringle, "Method and Composition for Reducing Corrosion in the Removal of Acidic gases From Gaseous Mixtures", ", U.S. Patent No. 4,446,119 assigned to The Dow Chemical Company, 1984.

37. J. G. McCullouh and R. B. Nielsen, "Contamination and Purification of Alkaline Gas Treating Solutions", CORROSION/96, NACE: Houston, TX, Paper No. 396.

38. M. G. Fontana and N. D. Greene in Corrosion Engineering, 2 'a edition, McGraw Hill, 1978.

39. Roundtable discussion during 45 th Annual Laurance Reid Gas Conditioning Conference, March 3-6, 1996, Norman, Oklahoma.

40. a) Rooney, P. C.; Dupart, M. S.; Bacon, T. R., "Effect of Heat Stable Salts on MDEA Solution Corrosivity" Hydrocarbon Process., Int. Ed. (1997), 76(4), 65-68,p 71. b) Rooney, P. C.; Dupart, M. S.; Bacon, T. R.; Willbanks, K. D., "Effect of Chlorides on Solution Corrosivity of Methyldiethanolamine (MDEA) Solutions" CORROSION/97, NACE: Houston, TX, Paper No. 345. c) Rooney, P. C.; Dupart, M. S.; Bacon, T. R., "Effect of Heat Stable Salts on Solution Corrosivity ofMDEA-Based Alkanolamine Plants. Part III" Proc. Laurance Reid Gas Cond. Conf. (1997) pp12- 30. d) Rooney, P. C.; Dupart, M. S.; Bacon, T. R., "Effect of Heat Stable Salts on Solution Corrosivity of MDEA-Based Alkanolamine Plants. Part II, Proc. Laurance Reid Gas Cond. Conf. (1996) pp154-167, e) Rooney, P. C.; Bacon, T. R.; DuPart, M. S. "Effect of Heat Stable Salts on MDEA Solution Corrosivity" Hydrocarbon Process., Int. Ed. (1996), 75(3), pp95-103.

41. H. J. Liu, J. W. Dean and S. F. Bosen, "Neutralization Technology to Reduce Corrosion From Heat Stable Amine Salts", CORROSION/95, NACE: Houston, TX, Paper No. 572.

42. L. E. Haaka, S. F. Bosen and H. J. Liu, "The Role of Anion Contaminants on Corrosion in Refinery Amine Units", AICHE Spring National Meeting, Houston TX, 1995, Paper No. 55d.

43. a) A.L. Cummings, F.C. Veatch and A.E. Keller "Corrosion and Corrosion Control Methods in Amine Systems Containing Hydrogen Sulfide", Materials Performance, 1998 (January), pp42-48, b) A.L. Cummings, F.C. Veatch and A.E. Keller "Corrosion and Corrosion Control Methods in Amine Systems Containing H2S" CORROSION/97, NACE: Houston, TX, Paper No. 341. c) S.M. Mecum, F. C. Veatch and A. L. Cummings, "Why Caustic Addition is bad for Amine Systems", Hydrocarbon Processing, 1997, 76 (10), 115. d) A. E. Keller and S. M. Mecum, "Heat-Stable salt Removal From Amines by the HSSX Process Using Ion Exchange", Proc. Laurance Reid Gas Cond. Conf., March 2-4, 1992, pp61-92.

44. M. J. Litschewski, "More Experiences With Corrosion and Fouling in a Refinery Amine System", CORROSION/96, NACE: Houston, TX, Paper No. 391.

45. R. G. Asperger, H. J. Liu and J. W. Dean, "Accurate, Reproducible Measurement of Reduced Corrosion in Gas Treating Amine Systems After Application of Judicious Neutralization Techniques", AICHE Spring National Meeting, Houston TX, 1995, Paper No. 55e.

46. C. J. Kim, "Degradation of Alkanolamines in Gas Treating Solutions: Kinetics of Di-2- propanolamine Degradation in Aqueous Solutions Containing Carbon Dioxide", Ind. Eng. Chem. Res., 1988, 27, 1.

47. For example, see: a) O. F. Dawodu and A. Meisen, "Degradation of Alkanolamine Blends by Carbon Dioxide", Canadian J. Chem. Eng., 1996, 74, 960. b) A. Chakma and A. Meisen, "MDEA Degradation with CO2", Proceedings of the 35 th Canadian Chemical Engineering Conference, October 6-9, 1985. c) A. Chakma and A. Meisen, "Identification of Methyldiethanolamine Degradation Products by Gas Chromatography and Gas Chromatography-Mass Spectrometry", J. Chromatography, 1988, 45 7, 287.

48. C. Blanc, M. Grail and G. Demarais, "The Part Played by Degradation products in the Corrosion of Gas Sweetening Plants Using DEA and MDEA", Proc. Laurance Reid Gas Cond. Conf. (1982) ppC1-C26.

49. A. Chakma and A. Meisen, "Corrosivity of iethanolamine solutions and Their Degradation Products", Ind. Eng. Chem. Res., 1986, 25, 627.

50. M. S. DuPart, P. C. Rooney and T. R. Bacon, "Comaprison of Laboratory and Operating Plant Data on MDEA / DEA Blends", Proc. Laurance Reid Gas Cond. Conf., Feb. 21-24,1999, pp141-155.

51. P. C. Rooney and M. S. DuPart, "Why Metals Solubility May Not Be a Good Indicator of Corrosion in Alkanolamine Systems", CORROSION/99, NACE: Houston, TX, Paper No. 263.

52. For example, see: a) R. D. Kane and M. S. Cayard, Chem. Eng. Progress, 1998, 94(10), p.49. b) R. G. Asperger; J. R. Davidson; C. W. Martin and R. L. Pearce, Proceedings of The Laurance Reid Gas Conditioning Conference, March 8-10, 1976, pp.Bl-19, c) J. C. Dingman; D. L. Allen and T. F. Moore, "Minimizing Corrosion in MEA Systems", Proceedings of The Laurance Reid Gas Conditioning Conference, April 5-6, 1966, pp.D 1-10.

53. "Pasadena Refinery Has Initial Success With and On-Site Amine-Purification System", Oil & Gas J., 1999, March 8 issue, p80.

Table 1. Recommended Amine Concentration and Acid Gas Loadings

Amine Max. Max. Lean CO 2 M/M Max. Rich CO 2 M/M Wt.%

Monoethanolamine 20 0.15 (CO2-only) 0.35 (CO2-only) (MEA) 0.16 (mixed CO2/H2S ) 0.45 (mixed COJH2S) Inhibited MEA 30 Diethanolamine (DEA) 30 0.07 (CO2-only) 0.40 (CO2-only)

0.08 (mixed CO2/H2S ) 0.70 (mixed COJHzS) Diisopropanolamine 40 0.005 (CO2-only) 0.45 (CO2-only) (DIPA) 0.01 (mixed CO2/H2S ) 0.55 (mixedCOJH2S) Diglycolamine 50-70 0.10 0.40 Methyldiethanolamine 50 0.005 (CO2-only) 0.45 (CO2-only) (MDEA) 0.01 (mixed COJH2S ) 0.55 (mixed COJH2S ) MDEA specialty blends 50 0.015 (CO2-only) 0.45 (CO2-only)

0.23 (mixed COJH2S ) 0.55 (mixed COJH2S)

Table 2. Weight Loss Coupon Results for MDEA Blend A Heated to 260F for 28 Days.

Corrosion Rate mpy (um/yr.) Liquid Coupons

C 1010 carbon steel 174.5 (4432) a 304L SS 0.3 (7.62) 316L SS 1.2 (30.48) 410 SS 79.0 (2007)

Vapor Space Coupons CIOIO carbon steel 22.0 (559) ~ 304L SS 0.3 (7.62) 316L SS 0.7 (17.8) 410 SS 8.9 (226)

a) Severe pitting noted.

Figure l. Plot of Carbon Steel Weigh Loss Corrosivity vs. pH for MDEA Solutions Containing Various Amounts of HSAS.

5000 J ' Acetic acid

"~ 4000 %NN " Oxalic acid L Formic acid 3000 ~ ~ Oxalic acid 2000 [Bicine ~ ~ ' . Sulfuric acid

t, 2 ., Malonic acid 1000 Succinic acid

o 0 ~- -~- --~ - ~ , Glycolic acid 9.5 10 10.5 11 t l .5 HCI

pH Bicine

numbr: 00494banr: