A Study of Corrosion in Hydroprocess Reactor EffluentAir Cooler Systems
API PUBLICATION 932-ASEPTEMBER 2002
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A Study of Corrosion inHydroprocess Reactor Effluent Air Cooler Systems
Downstream Segment
API PUBLICATION 932-ASEPTEMBER 2002
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CONTENTS
Page
1 INTRODUCTION. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
2 PREAMBLE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
3 1975 NACE SURVEY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
4 1996 UOP SURVEY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
5 1998 API SURVEY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75.1 Preliminary Survey—Broad Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75.2 Interview Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105.3 Reactor Effluent Air Coolers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125.4 REAC Inlet and Outlet Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135.5 Water Wash Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 225.6 Water Sources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235.7 Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 235.8 Corrosion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 255.9 Alloy Substitution to Prevent Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 255.10 Inhibition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
6 DISCUSSION AND ANALYSIS OF SURVEY RESPONSES . . . . . . . . . . . . . . . . . 276.1 General Equipment Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276.2 Nitrogen Content of the Feed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276.3 Salt Deposition and Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286.4 Management of Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286.5 Factors Influencing Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 286.6 Corrosion Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296.7 Water Washing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 296.8 Corrosion Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 306.9 Flow Effects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
7 CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
8 FUTURE RESEARCH . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
APPENDIX A PLOTS OF CORROSION SEVERITY VERSUS VARIOUS PARAMETERS FROM THE UOP SURVEY DATA FOR ALL COOLER TUBES (REFERENCE 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
APPENDIX B PLOTS OF CORROSION SEVERITY VERSUS VARIOUS PARAMETERS FROM THE UOP SURVEY DATA FORREAC PIPING (REFERENCE 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
APPENDIX C QUESTIONNAIRE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
Figures1 Effect of
K
p
on REAC Tube Corrosion (from Ref. 7) . . . . . . . . . . . . . . . . . . . . . . . 42 Effect of NH
4
HS Concentration in the Downstream Separator on REACTube Corrosion (from Ref. 7) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
3 Effect of Velocity on REAC Tube Corrosion (from Ref. 7) . . . . . . . . . . . . . . . . . . . 6
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Page
4 Preliminary Survey of Subcommittee Participants for Levels of Experience . . . . . 8A-1 Corrosion of Air Cooler Tubes—The Combined Effect of Calculated
Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s) on Corrosion Severity. . . . . . . . . . . . . 34
A-2 Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separatorand Calculated Maximum Tube Velocity (ft/s) on Corrosion Severityfor Balanced and Unbalanced Headers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
A-3 Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Tube Velocity (ft/s) on Corrosion Severity for Balanced Header Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
A-4 Corrosion of Air Cooler Tubes—The Combined Effect of CalculatedAmmonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s) on Corrosion Severity for Balanced Inlet and Unbalanced Outlet Header Systems . . . . . . . . . . . . . . . . . . . . 35
A-5 Corrosion of Air Cooler Tubes—The Combined Effect of CalculatedAmmonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Tube Velocity (ft/s) on Corrosion Severity for Unbalanced Header Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
B-1 Corrosion of REAC Outlet Header—The Combined Effect of CalculatedAmmonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Outlet Header Velocity (ft/s)on Corrosion Severity . . . . . . 38
B-2 Corrosion of REAC Outlet Header or Piping—The Combined Effect ofCalculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Velocity (ft/s) in the Outlet Headeror Piping on Corrosion Severity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
B-3 Corrosion of REAC Outlet Piping—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Outlet Piping Velocity (ft/s) on Corrosion Severity . . . . . . 39
B-4 Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Outlet Header Velocity (ft/s) on Corrosion Severityfor Balanced and Unbalanced Header Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . 39
B-5 Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s) on Corrosion Severityfor Balanced Header Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
B-6 Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator andCalculated Maximum Outlet Header Velocity (ft/s) on Corrosion Severity for Balanced Inlet and Unbalanced Outlet Header Systems . . . . . . . . . . . . . . . . . 40
B-7 Corrosion of REAC Outlet Header—The Combined Effect of CalculatedAmmonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s) on Corrosion Severity for Unbalanced Header Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Tables 1 Summary of REAC Environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32 Preliminary Survey Results. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93 Summary of Preliminary Survey Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104 Preliminary Survey Results (Showing Only Units Selected for Site Visits) . . . . . 11
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5 Summary of Preliminary Survey Results (Showing Only Units Selected for Site Visits) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
6 Compilation of Information from Plant Interviews . . . . . . . . . . . . . . . . . . . . . . . . 147 Compilation of Information from Plant Interviews—Air Cooler Tubes . . . . . . . . 178 Air Cooler Tube Experience from Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189 Compilation of Information from Plant Interviews—Piping Information. . . . . . . 1910 Piping Experience from Survey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2011 Wash Water Details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2112 Inspection Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2413 Corrosion Experience . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
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1
A Study of Corrosion in Hydroprocess Reactor Effluent Air Cooler Systems
This study was sponsored by the American PetroleumInstitute (API), Committee on Refinery Equipment, Subcom-mittee on Corrosion and Materials Research. The purpose ofthe study was to provide technical background, based onindustry experience and consensus practice, for controllingcorrosion in hydroprocess reactor effluent systems. The find-ings reported herein will be used as an interim resource by theindustry and as a basis for a future API recommended prac-tice document.
1 Introduction
The treatment of crude distillation products with hydrogento produce higher yields of gasoline and jet fuel became amajor part of refinery technology with the introduction ofhydrocracking in the 1950s. Later, other hydrofining pro-cesses for removal of impurities from products were intro-duced. These technologies all had similar corrosionexperiences that eventually were identified as being associ-ated with the presence of hydrogen sulfide (H
2
S) and ammo-nia (NH
3
), and their reaction product ammonium bisulfide(NH
4
HS), in the reactor effluents. Minor contaminants suchas chlorides and oxygen were also believed to have an influ-ence on corrosion. But in general, corrosion was associatedwith salt deposition, concentrated solutions of ammoniumbisulfide and the flow velocity.
In 1976, R. L. Piehl (Standard Oil of California) conducteda survey for the National Association of Corrosion Engineers(NACE) on corrosion in Reactor Effluent Air Cooler (REAC)systems. Industry-wide experience was gathered and ana-lyzed to establish guidelines to minimize REAC corrosion. In1996, Unocal/UOP conducted an extensive survey of theirlicensees world wide. Their conclusions confirmed the valid-ity of the original parametric guidelines and contributed to theimportance of certain design features in avoiding corrosionproblems. Since the earlier survey, failures have continued tooccur and while it is believed that most have resulted fromoperation outside of the guidelines, there has been no system-atic study of the experience or open documentation of indi-vidual events.
2 Preamble
Information for this report has been gathered from open lit-erature, private company reports and interviews with represen-tatives of major refining companies. The terminology used byeach of these sources to describe some of the corrosion eventshas varied slightly and may have introduced some doublemeanings. Every effort has been made in this document tomaintain consistency and avoid confusion. Specifically, wehave tried to differentiate between “localized corrosion” as acategory of corrosion phenomena (e.g., pitting, crevice corro-
sion or stress corrosion cracking) and corrosion that has beenconfined to a small area of the corroding surface at a specificlocation in the process equipment. For the most part, localizedcorrosion will refer to the latter, i.e., corrosion occurring on asmall area, or at a specific location in the process. Where aspecific type of corrosion has occurred the proper description,for example, pitting, or stress corrosion cracking, will be used.
Throughout the report, reference is made to the effects ofvelocity on corrosion. It is commonly acknowledged thatvelocity induces accelerated attack by a mechanism involvingthe erosive effect of the high velocity liquid. The many con-tributors have frequently referred to this phenomenon as ero-sion. The consensus however appears to be that themechanism is one of accelerated corrosion. This should moreproperly be categorized as erosion-corrosion. Thus, unlessotherwise stated, the use of the term erosion-corrosion ismeant to describe the severe corrosion experienced by highvelocity fluid flow.
3 1975 NACE Survey
Prior to this survey, R. L. Piehl had presented the results ofstudies conducted by his company at an API Division ofRefining meeting in Philadelphia, May 15 – 17, 1968
1
. Thesestudies provided the earliest insights into the corrosion prob-lems associated with this new technology and attempted toidentify critical parameters contributing to the corrosion ofcarbon steel equipment.
Among the important conclusions reached at that time wasthe recognition that sulfide corrosion in an alkaline environ-ment was the primary cause of corrosion. The quantities andrelative ratios of ammonia and hydrogen sulfide were per-ceived as important and the possible influence of minor con-taminants such as chlorides and oxygen were acknowledged.The study concluded that the dominant mode of attack waserosion-corrosion of air cooler tube ends and some flowvelocity limitations were suggested to avoid the problem.
It was subsequently recognized that the subject was muchmore complex than originally thought and that other equip-ment, especially piping, was also affected. To broaden the database and capture as much experience as possible, NACE GroupCommittee T-8 (Refining Industry Corrosion) set up TaskGroup T-8-1 to conduct a survey of the T-8 membership on thesubject of corrosion of hydroprocess effluent air coolers
2
.Information was gathered on forty-two plants from fifteenrefining companies, mostly in the United States. In general, theresults were supportive of the original definition of the prob-
1
R. L. Piehl, “How to Cope with Corrosion in Hydrocracker EffluentCoolers,”
Oil & Gas Journal
, July 8, 1968.
2
R. L. Piehl, “Survey of Corrosion in Hydrocracker Effluent AirCoolers,”
Materials Performance
, January 1976.
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2 API P
UBLICATION
932-A
lem, but tended to underscore the complexity of the problemrather than provide clearer guidance. The ability of bothammonium chloride and ammonium bisulfide to condense assolids from the vapor phase and thereby cause blockage of theflow path was the motivation to introduce a water wash to solu-bilize the deposited material. Unfortunately, the resulting aque-ous solutions are extremely corrosive unless substantiallydiluted, and are in fact the cause of the corrosion problems inthese systems.
The survey gathered data on the chemical composition ofthe effluent stream including contaminants, and attempted todefine the corrosivity of the aqueous phase by factoring in theamount of water added to the system and its velocity. Theconcentration of bisulfide solution was measured in mostcases at the downstream water separator and this value wasused as a measure of the aggressiveness of the processstream. It was observed that at a concentration of 2% bisul-fide or below corrosion was mild but at 3% – 4% or more,significant corrosion began to occur.
The results helped to support a previously suggested rela-tionship between the bisulfide concentration and velocity,wherein the bisulfide level was represented by the product ofmole% NH
3
×
mole% H
2
S, designated as the
K
p
(Piehl) fac-tor. It was proposed that for
K
p
values of 0.1 – 0.5, velocitiesin the range 15 ft/s – 20 ft/s would be appropriate but for
K
p
values above 0.5 there was no suitable velocity. The higherthe
K
p
value the tighter the tolerance on velocity. It was alsofound that velocities of 10 ft/s – 12 ft/s could result in stag-nant deposits underneath which severe corrosion could occur,hence a lower limit of 10 ft/s was suggested, with an upperlimit of 20 ft/s and an optimum of 15 ft/s.
A major conclusion drawn from this survey was that aircooler corrosion is a complex phenomenon having numerousinterdependent variables. This reduces the prospects of suc-cessfully eliminating corrosion by control of one or even sev-eral of the variables.
4 1996 UOP Survey
In the 20 years following the NACE survey the problemswith corrosion continued, giving rise to a number of publica-tions discussing various aspects of the phenomenon
3
,
4
. Aircooler tubes continued to be the principal focus of the discus-sions although piping problems were also recognized. Labo-ratory studies of corrosion were unable to clarify the use ofparametric variables in controlling corrosion
5,6
. Thus, in1996, Unocal/UOP initiated a survey of its licensees to
expand the experience data base and possibly identify anynew factors in the corrosion of REACs and related piping.
The survey consisted of a comprehensive 10-page ques-tionnaire covering a variety of process and mechanical designinformation and corrosion experience. Topics included gen-eral operating conditions such as process mode, feedstocks,gas flow rates, contaminants (H
2
S, NH
3
, Cl, CN), water washdetails, and flow velocities. Air cooler and piping design andlayout, materials and corrosion experience were also covered.
Forty-six responses were received from operators of five dif-ferent types of hydroprocess unit. The information in theresponses was compiled into tabulated formats and analysesmade of the effects of certain variables on the corrosion experi-enced. Not all the respondents were able to provide values foreach of the key parameters requested so that UOP had to pro-vide estimated values by calculation from key operating datasuch as feed quality, charge rates, reactor efficiencies, flowrates, temperatures, pressures, and tube and piping flow areas.Note that these calculations, in particular velocities, were notbased on rigorous process simulation but rather on factoredestimates based on representative models for each unit configu-ration. To ensure consistency, UOP calculated values for
K
p
,NH
4
HS concentration and velocities for all of the units.
The results were presented in Paper 490 at Corrosion 97
7
.The diversity in the responses is illustrated in Table 1, whichsummarizes the range of values received for the key vari-ables; however, it cannot be construed that such a range ofvalues in the key parameters will necessarily result in widepattern of corrosion behaviors because of the interdepen-dency of corrosion on several parameters at the same time.Only if all the parameters are at one end of the range or theother can extreme behavior be anticipated. In addressing cor-rosion of carbon steel air cooler tubes, the effect of
K
p
factoron the severity of corrosion was evaluated by plotting
K
p
fac-tor versus level of corrosion experienced. The level of corro-sion was associated with tube life and the following rankingsused.
3
A. M. Alvarez and C. A. Robertson, “Materials and Design Consid-erations in High Pressure HDS Effluent Coolers,”
MaterialsProtection and Performance
, May 1973.
4
E. F. Ehmke, “Corrosion Correlations with Ammonia and Hydro-gen Sulfide in Air Coolers,”
Materials Performance,
July 1975.
5
D. G. Damin and J. D. McCoy, “Prevention of Corrosion inHydrodesulfurizer Air Coolers,”
Materials Performance
, December1978.
6
C. Scherrer, M. Durrieu and G. Jarno, “Distillate and Resid Hydro-processing: Coping with Corrosion with High Concentrations ofAmmonium Bisulfide in the Process Water,”
Materials Performance
,November 1980.
7
A. Singh, C. Harvey and R. L. Piehl, “Corrosion of Reactor Efflu-ent Air Coolers” Paper 490, Corrosion 97.
Severe (S) Tube life of 5 years or lessModerate (M) Tube life of 6 – 10 yearsLow (L) Tube life greater than
10 years with reported corrosion occurring
None (N) No corrosion reported
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
3
A plot of the data is shown in Figure 1. The four horizontalbands represent the four levels of corrosion but it can be seenthat there is considerable overlap in the range of
K
p
factors ateach level. The best conclusion that can be drawn is that thereis a trend showing that the severity of corrosion increaseswith increase of
K
p
, confirming Piehl’s observation. Theimprecise nature of the correlation however does not permit auseful guideline to be developed. Similar plots were devel-oped for corrosion severity versus:
1. Downstream separator bisulfide concentration (seeFigure 2),2. Maximum air cooler tube velocity (see Figure 3).
Note: Where values were not reported by the plants, values calculatedby UOP were used. These calculated values are valid only for bal-anced systems with assumed uniform flow distribution. They may beinaccurate where less than full condensation has occurred. As pre-sented, the data were so scattered that no correlation or inferencecould be drawn. It was evident that occurrences of corrosion do notcorrelate well with individual parameters partly because of the inac-curacies just discussed and in addition, because of the interdepen-dency of some of the parameters. By simultaneously plotting thelevel of corrosion against both bisulfide concentration and velocity,only a very slight improvement was obtained (see Appendix A, Fig-ure A-1). However, when the influence of piping symmetry on thedistribution of flow through the air coolers was introduced as a fourthparameter, more striking relationships were apparent (see AppendixA, Figures A-2 through A-5).
The air cooler piping system consists of a single inletpipe connected to a branched manifold system called theinlet header, which distributes the flow equally to each cellof the air cooler. The outlet flow from each cell is gatheredby a similar manifold arrangement called the outlet header,which reduces to a single outlet pipe leading to the separa-tor. With the piping headers (inlet and outlet) hydraulicallybalanced (see Figure A-3), no corrosion or low corrosionof the air cooler tubes is apparent. Several moderate corro-
sion points appeared, but two of these were associatedwith very high bisulfide concentrations. Similarly, wherethe inlet piping header is balanced, corrosion tends to below (see Figure A-4). On the other hand, when both head-ers were unbalanced (see Figure A-5), corrosion of thetubes was predominantly severe or moderate. It is clearthat uneven distribution of flow through the air cooler cre-ates conditions of either low or high velocities where cor-rosion can occur. Unfortunately, in most cases reported,neither the bisulfide concentration nor the magnitude ofthe velocity at the location where corrosion occurs isknown, so that a more refined correlation is not possible.The data were screened to exclude air coolers with returnbend tubes and those with ferrules. All of the plots areincluded in Appendix A (see Figures A-1 to A-5).
The above analytical approach was also applied to theassociated REAC piping. Piping failures have been the causeof some of the most serious incidents in these units. Discus-sions of experiences with REAC piping corrosion can befound in the NACE T-8 committee minutes and have beendocumented by Piehl
8
as well as the UOP study. Appendix B (see Figures B-1 to B-7) are data plots for out-
let headers and piping corresponding to the air cooler tubeseries. Two sets of data have been used, one for the maximumvelocity in the air cooler outlet header and the other for maxi-mum velocity in the piping from the header system to the sep-arator, if greater. Since the piping has a greater thickness thanair cooler tubing, the classification of corrosion severity hasbeen changed. Severe corrosion is considered as less than 10years life, moderate corrosion between 10 and 20 years andlow corrosion as measurable but with a greater than 20 yearpredicted life.
The conclusions are similar to those for the air coolersshowing an unclear relationship when just two or threeparameters are plotted and an improvement when the fourthparameter is added. Figure B-1 shows the combined effect ofbisulfide concentration and header velocity on corrosion. Theexceptions to good performance generally lie in the regime ofhigh bisulfide and high velocity. There are however severalsevere corrosion data points that fall below 4% bisulfide andless than 20 ft/s velocity, a regime that is normally regardedas acceptable. If the maximum piping velocity is included inthe data (see Figure B-2), severe corrosion shifts to the rightindicating that corrosion is associated with higher velocities.The correlation is stronger when only the maximum outletpiping velocity is plotted (see Figure B-3), and severe corro-sion is shown only when velocities are greater than 25 ft/s.
Figure B-4 includes the effect of the header configurationand indicates that serious corrosion has been experienced onlywhen the system is unbalanced whereas with balanced headersexperience has been favorable even at surprisingly high veloc-
Table 1—Summary of REAC Environments
Minimum Value
Median Value
Maximum Value
K
p
0.00 0.17 8.1
Wash water rate, vol-% feed
0.5 5.2 15.7
Foul water NH
4
HS content, wt-%
a
0.6 4.8 17.2
REAC tube velocity, ft/s
3.0 ~ 13.0 39.0
REAC outlet piping velocity, ft/s
4.3 15.1 44.9
Note:
a
Interpreted to mean NH
4
HS content of sour water in downstreamseparator.
8
R. L. Piehl, “Survey of Corrosion in Hydrocracker Effluent AirCoolers,”
Materials Performance
, January 1976.
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4 API P
UBLICATION
932-A
Fig
ure
1—E
ffect
of K
p on
RE
AC
Tub
e C
orro
sion
(fr
om R
ef. 7
)
0.00
10.
010.
11
10
Kp,
mol
-% H
2S ×
mol
-% N
H3
Corrosion severity
NLMS
Not
e:F
= Fe
rrul
es u
sed
at tu
be e
nds
FF
F
FF
S =
Tub
e lif
e ≤
5 ye
ars
M =
Tub
e lif
e 6
– 10
yea
rsL
= Tu
be li
fe >
10
year
sN
= N
o co
rros
ion
F
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
5
Fig
ure
2—E
ffect
of N
H4H
S C
once
ntra
tion
in th
e D
owns
trea
m S
epar
ator
on
RE
AC
Tub
e C
orro
sion
(fr
om R
ef. 7
)
04
812
16
Am
mon
ium
bis
ulfid
e co
ncen
trat
ion,
wt-
%
Corrosion severity NLMS
Not
e:F
= F
erru
les
used
at t
ube
ends
F
F
FF
F
S =
Tub
e lif
e ≤
5 ye
ars
M =
Tub
e lif
e 6
– 10
yea
rsL
= T
ube
life
> 1
0 ye
ars
N =
No
corr
osio
n
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6 API P
UBLICATION
932-A
Fig
ure
3—E
ffect
of V
eloc
ity o
n R
EA
C T
ube
Cor
rosi
on (
from
Ref
. 7)
0
3
6
9
12
Nom
inal
pea
k tu
be v
eloc
ity, m
/sec
Corrosion severity NLMS
FF
FF
FF
Not
e:F
= F
erru
les
used
at t
ube
ends
S =
Tub
e lif
e ≤
5 ye
ars
M =
Tub
e lif
e 6
– 10
yea
rsL
= T
ube
life
> 1
0 ye
ars
N =
No
corr
osio
n
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
7
ities and bisulfide concentrations. The data in Figure B-4 isclarified by showing the effect of each configuration sepa-rately as in Figures B-5, B-6, and B-7. Unfortunately, theseobservations do not provide any precise guidance as to corro-sion behavior with velocity but on the other hand are not inconflict with the suggested ranges proposed by Piehl. A seri-ous shortcoming is the lack of predictability of erosion-corro-sion in terms of both the velocity conditions that initiate it andthe locations where it might occur.
The UOP survey also reported on the performance of vari-ous alloys for REAC tubes and piping, corrosion of othercomponents and in addition discussed air cooler tube fouling.The report concluded with a list of design and operating rec-ommendations which support the 1975 NACE study but didnot add any further enlightenment or provide new guidelinesfor dealing with the problem.
5 1998 API Survey
The present study was initiated in 1997 and consisted oftwo parts:
1. A preliminary survey to obtain a broad overview of theproblem within the task group members’ experience. 2. An interview process of selected companies in whichdetails of their corrosion experiences were explored.
5.1 PRELIMINARY SURVEY—BROAD OVERVIEW
A brief questionnaire was sent to all task group membersinviting them to provide general information about two unitswithin their company’s operations where the corrosion expe-rience in one unit was significantly different from the other.Any unit that had experienced a catastrophic event such as anexplosion or fire was to be included. Where possible the sec-ond unit would be one that had a predictable and essentiallytrouble free corrosion record.
The preliminary questionnaire is shown in Figure 4. Thesurvey was divided into three major categories.
1.
Level of distress.
This was intended to give a measureof the severity of the corrosion problems experienced foreach unit and to identify units with poor experience fromthose with good experience.2.
Economic levels.
Another measure of the seriousnessof the corrosion problem is the frequency with whichequipment replacements have to be made or if a large cap-ital investment in alloy replacements is believed to benecessary. This category provided some insight into thoseaspects.3.
Corrosion control.
The level of effort needed to keepcorrosion under control is an indication of the seriousnessof the problem to the owner. Included in this categorywere some corrosion control measures and the quality ofinspection.
Unfortunately, in attempting to keep the survey brief toelicit maximum and timely response, some line items con-
tained more than one subject. This ambiguity has been takeninto account in drawing conclusions from the responses anddoes not appear to be a major deterrent to the usefulness ofthe results.
Table 2 is a complete compilation of the responsesreceived. The categories discussed above are listed at the leftside of the table. Each column represents an individual unitidentified by a code letter which has been used consistentlythrough the remainder of this report. The type of unit is iden-tified by a code letter as follows:
HCU
hydrocracking
HTU
hydrotreating—this includes hydrodesulfuriza-tion and hydrodenitrification units.
Table 3 summarizes the data from the responses and thefollowing conclusions have been drawn.
a. Out of 24 units included in the survey:• Five units reported fires and explosions.• Four units reported unscheduled outages.• Ten units reported experiencing corrosion but manage it
by regular replacement of carbon steel or have substi-tuted alloy for carbon steel.
• Five units reported no significant corrosion.b. A total of 12 units have substituted alloy for carbon steel.c. Ten units use alloy extensively.d. Two units report low corrosion rates but have experienced
fires. This indicates localized corrosion resulting in a seri-ous leak.
e. Only two units report using inhibition. One of these had anunscheduled outage.
f. Fifteen plants use regular inspection, that is, inspectionsconducted at planned intervals, usually at unitturnarounds.
g. Eleven plants use extensive inspection. The thickness mea-suring locations have been increased or 100% UTinspection is used to detect localized corrosion.
h. Seventeen plants use special frequent inspection. Thisincludes on-line UT and radiography.
There is no distinction of behavior by type of unit. Bothhydrocrackers and hydrotreaters have had comparable corro-sion experiences. The experience is clearly diverse although itis apparent that those units that have suffered a catastrophicevent have upgraded to alloy even when corrosion is gener-ally mild, whereas some units have never had a problem andcarbon steel has been quite satisfactory for all equipmentitems. Inhibition is not a widely used method of corrosioncontrol but those who use it clearly perceive an economicadvantage in doing so. It is evident that many reactor effluentsystems are subjected to more rigorous inspection than otherrefinery units as indicated by the number of units receivingfrequent or special inspections. The latter include techniquesthat are detailed and time consuming but are more thoroughthan alternative methods.
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8 API P
UBLICATION
932-A
Figure 4—Preliminary Survey of Subcommittee Participants for Levels of Experience
Levels of distress
a) No corrosion or corrosion requiring replacement of equipment on a scheduled basis.
b) Corrosion requiring replacement of equipment on an unscheduled basis.
c) Corrosion causing an outage (unscheduled and sudden).
d) Corrosion causing a fire, explosion, and property damage.
Economic levels
a) Replacement of carbon steel items i) exchanger bundles, ii) piping, iii) weld repair.
b) Frequent extensive in-kind replacement of carbon steel items.
c) Replacement of carbon steel with alloy.
d) Replacement of alloy with alloy.
e) Prolonged outage for replacement.
f) Unit reconstruction.
Corrosion Monitoring Control (Mark as many as are applicable.)
a) Mild corrosion monitored by regular maintenance.
b) Extensive use of alloy in critical locations.
c) Successful use of inhibition.
d) Extensive inspection—all equipment frequently.
e) Special inspection techniques/frequent inspection. (Define frequent as less than 1 year interval.)
f) Use of chemical analysis indicators—e.g., Kp factors, NH 4 HS concentration.
g) Wash water quality.
h) Wash water quantity.
Comments (Please add additional pages as needed.)
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
9
Tabl
e2—
Pre
limin
ary
Sur
vey
Res
ults
AB
CD
EF
GW
HJ
KL
MN
YO
RU
DD
PQ
ST
XH
CU
HT
UH
CU
HT
UH
TU
HC
UH
CU
HT
UH
CU
HC
UH
CU
HT
UH
CU
HT
UH
CU
HT
UH
TU
HT
U
Lev
el o
f D
istr
ess
a
) N
o c
orr
osi
on
XX
XX
X X
Xb
) S
che
du
led
re
pla
cem
en
tX
XX
XX
XX
XX
XX
c)
Un
sch
ed
ule
d o
uta
ge
XX
XX
d)
Exp
losi
on
, fir
eX
XX
XX
Eco
no
mic
Lev
els
e)
Re
pla
cem
en
t ca
rbo
n s
tee
lX
XX
XX
XX
XX
XX
XX
XX
Xf)
F
req
ue
nt,
ext
en
sive
CS
re
pla
cem
en
tX
Xg
) A
lloy
for
CS
XX
XX
XX
XX
XX
XX
h)
Allo
y re
pla
cem
en
tX
XX
i)
Pro
long
ed o
utag
eX
XX
j)
Un
it re
con
stru
ctio
nX
Co
rro
sio
n C
on
tro
lk)
M
ild c
orr
osi
on
, re
gu
lar
insp
ect
ion
XX
XX
XX
XX
XX
XX
XX
Xl)
E
xte
nsi
ve u
se o
f a
lloy
XX
XX
XX
XX
XX
m
) In
hib
itio
nX
Xn
) E
xte
nsi
ve,
fre
qu
en
t in
spe
ctio
nX
XX
XX
XX
XX
XX
o)
Sp
eci
al,
fre
qu
en
t in
spe
ctio
nX
XX
XX
XX
XX
XX
XX
XX
XX
p)
Ch
em
ica
l a
na
lyse
s: K
p f
act
ors
XX
XX
XX
XX
XX
XX
XX
XX
XX
X
q)
Wa
sh w
ate
rÑq
ua
lity
XX
XX
XX
XX
XX
XX
XX
XX
XX
XX
XX
X
r)
W
ash
wa
terÑ
qu
an
tity
XX
XX
XX
XX
XX
XX
XX
XX
XX
XX
XX
X
C
om
me
nts
:A
: C
.S.
pip
eÑ
> 8
25
; 4
44
exc
ha
ng
er
tub
es;
> 0
.5 m
m/y
r; v
elo
city
= 6
m/s
; b
isu
lfid
e =
4 w
t%
B:
Re
pla
cem
en
t o
f ca
rbo
n s
tee
l in
exc
ha
ng
ers
; (s
ee
co
lum
n E
ab
ove
)C
: F
ou
r la
rge
le
aks
; th
ree
fir
es,
all
rela
ted
to
bis
ulfi
de
/Cl
corr
osi
on
H:
Wa
shÑ
8 k
g/h
r a
t 1
9.2
mb
sdM
: W
ash
Ñ6
.8 k
g/h
r a
t 1
4.0
mb
sd
O:
Cl
corr
osi
on
at
wa
ter
inje
ctio
n p
oin
tR
: C
l, F
co
rro
sio
n a
t w
ate
r in
ject
ion
po
int
X:
No
sig
nifi
can
t re
pla
cem
en
t o
f ca
rbo
n s
tee
l ite
ms
for
ma
ny
yea
rs (
see
co
lum
n E
ab
ove
)
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10 API P
UBLICATION
932-A
The results of this brief survey clearly invite a moredetailed investigation into the differences between those unitsthat have experienced no significant corrosion and those thathave had explosions or fires. It is also evident that some oper-ators are required to spend more time and money in maintain-ing their units than others. Previous attempts to address theseissues by studying the underlying factors known to affect cor-rosion behavior have failed to produce a clear picture of thedifferences. This is believed to be due to the complexity offactors and the lack of precise control of those factorsthroughout the system.
The next step in this present survey was designed, there-fore, to take a different approach to test the above premise. Itwas decided that instead of gathering broad, detailed informa-tion on each of the units selected for study, the informationsought would be relevant to a specific corrosion experienceonly. In this way, it was hoped to separate local aberrationsfrom general unit performance and possibly improve theparametric relationships between causes and effects.
To accomplish this, a selection was made of a number ofoperating companies that met the following criteria.
1. They operate units with experience at both ends of thespectrum.2. They were known to have reliable engineeringresource.
The number of locations visited was influenced by budge-try considerations.
To test the validity of the selection of companies for inter-view, their responses to the preliminary survey were sepa-
rated from Table 2 and are presented in Table 4. A summaryof the information is given in Table 5. Comparing Tables 3and 5 it can be seen that the percentage of units falling intoeach category is approximately the same in both cases indi-cating that the selected units are representative of the totalpopulation.
5.2 INTERVIEW PROCESS
Following review of the responses, a number of companieswere selected and arrangements made to interview key per-sonnel with respect to reactor effluent system corrosion.These interview arrangements were made through the taskgroup members but a request was made to have presentappropriate staff engineers with an intimate knowledge ofcorrosion, process and inspection aspects involved in each ofthe units selected for study. All of the participants were veryco-operative, but it was evident in some companies that staffreductions and re-assignments had an effect on the time avail-able for such studies. Few engineers remain that have a life-time of experience with these units.
Prior to the visits, a detailed questionnaire (shown inAppenedix C) was sent to the interviewees to provide a basisfor the discussions and indicate the quality of informationbeing sought. The UOP survey demanded a substantialamount of detailed information, which was needed to com-pute values for the process parameters of interest. The presentsurvey was designed to avoid imposing an unnecessary bur-den on the respondents in requesting extraneous process datathat would not have a foreseeable use. However, a certain
Table 3—Summary of Preliminary Survey Results
a) No corrosion 5b) Scheduled replacement 10c) Unscheduled outage 4d) Explosion, fire 5
e) Replacement carbon steel 1 2 8 5f) Frequent, extensive CS replacement 0 2 0 0g) Alloy for CS 5 1 5 1h) Alloy replacement 1 0 2 0i) Prolonged outage 3 0 0 0j) Unit reconstruction 1 0 0 0
k) Mild corrosion, regular inspection 1 4 6 4l) Extensive use of alloy 5 1 3 1
m) Inhibition 0 1 0 1n) Extensive, frequent inspection 4 2 3 2o) Special, frequent inspection 4 2 8 3p) Chemical analyses: Kp factors 5 2 9 3q) Wash waterÑquality 4 4 10 5r) Wash waterÑquantity 4 4 10 5
SUBTOTALS
Economic Levels
Level of Distress
Corrosion Control
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
11
Tabl
e4—
Pre
limin
ary
Sur
vey
Res
ults
(S
how
ing
Onl
y U
nits
Sel
ecte
d fo
r S
ite V
isits
)
BC
EW
IY
OR
UQ
XS
UB
TO
TA
LS
HC
UH
TU
HT
UH
CU
HC
UH
CU
HT
UH
CU
HT
UH
CU
HT
U
Lev
el o
f D
istr
ess
a)
No
co
rro
sio
nX
X X
2
b)
Sch
ed
ule
d r
ep
lace
me
nt
XX
XX
X6
c)
Un
sch
ed
ule
d o
uta
ge
X
d)
Exp
losi
on
, fir
eX
XX
3
Eco
no
mic
Lev
els
e)
Re
pla
cem
en
t ca
rbo
n s
tee
lX
XX
XX
XX
14
2
f)
Fre
qu
en
t, e
xte
nsi
ve C
S r
ep
lace
me
nt
XX
02
0
g)
Allo
y fo
r C
SX
XX
XX
XX
33
1
h)
Allo
y re
pla
cem
en
tX
X1
10
i)
Pro
long
ed o
utag
eX
X2
00
j)
Un
it re
con
stru
ctio
nX
10
0
Co
rro
sio
n C
on
tro
l
k)
Mild
co
rro
sio
n,
reg
ula
r in
spe
ctio
nX
XX
XX
XX
14
2
l)
Ext
en
sive
use
of
allo
y X
XX
XX
31
1
m)
Inh
ibiti
on
XX
01
1
n)
Ext
en
sive
, fr
eq
ue
nt
insp
ect
ion
XX
XX
21
1
o)
Sp
eci
al,
fre
qu
en
t in
spe
ctio
nX
XX
XX
XX
X3
41
p)
Ch
em
ica
l a
na
lyse
s: K
p f
act
ors
XX
XX
XX
XX
XX
X3
62
q)
Was
h w
ater
Ñqu
ality
XX
XX
XX
XX
XX
X3
62
r)
Wa
sh w
ate
rÑq
ua
ntit
yX
XX
XX
XX
XX
XX
36
2
K p V
alu
es0
.12
0.0
30
.33
0.4
50
.23
0.3
40
.3 Ð
0.4
50.
4 Ð
10
.04
0.0
5
Co
mm
ents
:
X:
No
sig
nifi
can
t re
pla
cem
en
t o
f ca
rbo
n s
tee
l ite
ms
for
ma
ny
yea
rs (
see
co
lum
n E
ab
ove
)
B:
Re
pla
cem
en
t o
f ca
rbo
n s
tee
l in
exc
ha
ng
ers
(se
e c
olu
mn
E a
bo
ve)
C:
Fo
ur
lar g
e l
ea
ks;
thre
e f
ire
s, a
ll re
late
d t
o b
isu
lfid
e/C
l co
rro
sio
n
O:
Cl
corr
osio
n at
wat
er i
njec
tion
poin
t
R:
Cl,
F c
orr
osi
on
at
wa
ter
inje
ctio
n p
oin
t
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12 API P
UBLICATION
932-A
amount of detail to evaluate each experience was requested. Itwas decided that the data collected would be specific to eachcorrosion incident discussed. In this way, the parametersaffecting each incidence of corrosion would be available, butthe laborious task of gathering all the process, operating andmaintenance records could be eliminated. This made theinformation base more manageable. The questionnaire cov-ered all of the subjects pertinent to corrosion in REAC sys-tems and served as an agenda for the discussions.
The contents of each interview were recorded as hand-writ-ten notes backed up by copies of relevant data sheets, flowdiagrams and reports. Each significant corrosion experiencewas discussed in chronological order until the entire historyof the unit was completed. The results of these discussionswere compiled into a spreadsheet presented in Table 6.
5.3 REACTOR EFFLUENT AIR COOLERS
All of the data relevant to the reactor effluent air coolershave been sorted from Table 6 and is presented separately inTable 7. The table identifies the plant and type of unit and givesa brief description of the corrosion problem, including theapparent cause. Where additional background information orobservations are available, they have been added as comments.Numerical data has been compiled separately in Table 8.
There has been a wide variety of experience with air cool-ers in terms of useful life. Tube failures have occurred in aslittle as a few months in the worst case (Plant C), but inanother unit (Plant U), carbon steel tubes have lasted 25 years
with no failures. In the first case, corrosion was due to deposi-tion of ammonium salts in the air cooler tubes with probablyjust enough water present to create an aggressive concen-trated salt solution. Subsequent efforts to solve the problemby substituting chrome steels and later stainless steels wereunsuccessful until Alloy 800 was installed some 14 yearslater. The maximum tube velocities in this air cooler werehigh with respect to Piehl’s guidelines and the ammoniumbisulfide concentration in the downstream separator was 13%suggesting that this too might have been a contributing factor.In the second case, the operating conditions are very mild.There has never been any plugging or corrosion because theair cooler operates at an outlet temperature above the salt con-densation point (150°F). It is interesting that this unit also hasunbalanced outlet piping, which apparently is not a factorbecause the deposition of salts does not come into play.
One of the earliest problems with carbon steel air coolertubes was severe localized corrosion of the tube ends (PlantsW, EE, and Y). This was caused by high velocity and turbu-lence at the entrance to the tube and in some cases at the out-let end of the tube. This type of attack is thought by many tobe an example of erosion-corrosion. The problem has beensolved by the use of alloy ferrules with carbon steel tubes.Both stainless steel and Alloy 800 ferrules are used. Whereferrules are used, they must be designed with a tapered end sothat there is no abrupt transition from the ferrule to the tubecausing downstream eddies. Loose fitting ferrules can admitcorrosive solutions to the annulus with the tube wall and ini-
Table 5—Summary of Preliminary Survey Results (Showing Only Units Selected for Site Visits)
Level of Distressa) No corrosion 2b) Scheduled replacement 6
c) Unscheduled outaged) Explosion, fire 3
Economic Levelse) Replacement carbon steel 1 4 2f) Frequent, extensive CS replacement 0 2 0g) Alloy for CS 3 3 1h) Alloy replacement 1 1 0i) Prolonged outage 2 0 0j) Unit reconstruction 1 0 0
Corrosion Controlk) Mild corrosion, regular inspection 1 4 2l) Extensive use of alloy 3 1 1
m) Inhibition 0 1 1n) Extensive, frequent inspection 2 1 1o) Special, frequent inspection 3 4 1p) Chemical analyses: Kp factors 3 6 2q) Wash waterÑquality 3 6 2r) Wash waterÑquantity 3 6 2
SUBTOTALS
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
13
tiate crevice corrosion (Plant W). Alloy 800 tubes have notbeen reported to have tube end corrosion problems.
The results of discussions with respondents indicated thatvelocity must be controlled to avoid corrosion problems.Although the data in Table 8 is incomplete, it can be seen thatserious corrosion is associated with either high bisulfide con-centrations or high velocity, or both (Plants C, W, AA, andEE). Conditions of high bulk fluid velocity also lead to turbu-lence and localized corrosion or erosion-corrosion. The datain Table 8 is not in conflict with 20 ft/s as a reasonable upperlimit on tube velocity when associated with 4% bisulfide.Plant Y appears to be in conflict with this conclusion, how-ever the lower velocities could have resulted in underdepositcorrosion from salt build-up when the bisulfide concentrationwas 7% – 8%. The data for Plant O in Table 8 indicates thathigher velocities can be tolerated if the bisulfide concentra-tions are low.
One of the factors emphasized by this review is the criticalrole of wash water. Plants that experienced severe corrosionearly in their history have attributed the problem to lack ofwash water (Plants B, R, and Y) and have often been able tocorrect the problem by increasing the water rate. There is awide variation from process to process in the amount ofinjected water that vaporizes when introduced to the processstream. None of the respondents reported more than 75%vaporization, indicating a minimum of 25% of the injectedwater remains as liquid after introduction. When a singleinjection point is used, the aqueous phase has to distributeitself through the inlet piping header system and the air coolertube bundles in proportion to the effluent flows in that equip-ment. To eliminate the influence of an unbalanced pipingheader system, some operators use multiple injection points(see Table 11). These are usually located on the air coolerinlet nozzle close to the tube bundle inlet. The purpose is toensure that each bundle receives the same amount of washwater. However, individual monitoring of each injection lineis required, and frequent manual adjustment of the flow con-trol valves is often needed. The small diameter water linesand injectors are also prone to plugging depending on thequality of water used. Wash water preferences will be dis-cussed below when that specific topic is addressed.
Where corrosion has been serious and persistent, unit oper-ators have sometimes invested in Alloy 800 or Alloy 825 as apermanent solution. Alloy 800 has been used for at least 17years with no major failures (Plant B); however, pitting corro-sion has been reported (Plants Q and E) so that the long-termreliability has been put in question. One of these casesreported a chloride content of 50 ppm in the separator water.The level at which chlorides are significant with respect topitting of Alloy 800 has not been established although labora-tory tests
9
identify 100 ppm as harmful. One operator alsoreceived laminated Alloy 800 tubes that were not discovereduntil they had been in service some time.
5.4 REAC INLET AND OUTLET PIPING
All comments relating to inlet and outlet piping associatedwith the REACs have been sorted from the general commentsin Table 6 and presented as a separate compilation in Table 9.The numerical data have been reformatted and are presentedin Table 10.
The piping system discussed in this section covers the pip-ing from the water injection point, the inlet headers to the aircooled exchangers, and the outlet headers and piping to theseparator drums.
Out of the 12 units included in the detailed survey, one halfexperienced piping corrosion problems. Of the better per-forming group two were inhibited, two use alloy and two didnot experience any significant corrosion. Corrosion has beenexperienced on both the inlet and outlet sides of the REACs.The corrosion has often been localized at tees, elbows or asgrooving of straight run pipe. Depending on upstream factors,such as type of catalyst and feedstock quality, condensed saltscan be ammonium fluoride, chloride or bisulfide, or combina-tions of the three. Some operators employ fluoride catalystactivators giving rise to residual fluorides in the system (PlantR). The deposition temperature for the chloride salt is higherthan the fluoride salt deposition temperature which in turn ishigher than the bisulfide condensation temperature. Appar-ently, the aggressiveness of the salts is in the same order.Severe corrosion by deposition of ammonium chloride is themost prevalent type of attack.
5.4.1 Inlet Piping
Corrosion of the inlet piping was reported for two areas,immediately around the water injection point and in the head-ers before the REACs. Around the injection point, direct waterimpingement has been a problem. When excessive vaporiza-tion occurs, the amount of liquid water remaining could be toolow and this results in concentrated aqueous salt corrosion.Salt deposits in the feed/effluent exchangers upstream of thewater injection point have resulted in severe corrosion whenwater has come in contact with the deposits, from eithersplashing or saturation above the dew point. One solution hasbeen to use an alloy lining in the immediate area. One operatorhas used Alloy 625 successfully for this purpose. Localizedcorrosion can also occur as a concentrated aqueous phaseresulting from insufficient wash water flows through the pip-ing system. At elbows where surface velocities can increasedue to turbulence, the attack may be particularly severe. Bothstraight-pipe corrosion and erosion-corrosion of elbows havebeen reported by respondents. Again, the solution has been touse alloy for protection. In one case, Plant Q, installing Alloy
9
C. Scherrer, M. Durrieu and G. Jarno, “Distillate and Resid Hydro-processing: Coping with Corrosion with High Concentrations ofAmmonium Bisulfide in the Process Water,”
Materials Performance
,November 1980.
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14 API P
UBLICATION
932-A
Tabl
e6—
Com
pila
tion
of In
form
atio
n fr
om P
lant
Inte
rvie
ws
Pla
nt
Un
itL
oca
tio
n o
f C
orr
osi
on
Typ
e o
f C
orr
osi
on
Cau
sati
ve F
acto
rsC
om
men
ts
BH
CU
Air
co
ole
r tu
be
sB
isu
lfid
e c
orr
osi
on
La
ck o
f w
ash
wa
ter.
Inst
alle
d 1
97
1;
faile
d i
n 6
ye
ars
(fir
e);
re
pla
ced
with
Allo
y 8
00
.
A/C
ou
tlet
pip
ing
Gro
ovi
ng
an
d c
ha
nn
elin
g2
5 f
t/s
att
ack
in
tu
rbu
len
t a
rea
do
wn
stre
am
of
elb
ow
. N
ow
co
rro
din
g a
t 5
0 m
py.
S
usp
ect
oxy
ge
n a
nd
ch
lori
de
s. N
o
corr
osi
on
wh
en
oxy
ge
n a
nd
ch
lori
de
s u
nd
er
con
tro
l.
Ori
gina
l 18"
rep
lace
d w
ith 2
2" in
199
4.
Tri
m c
oo
ler
U-b
en
d c
orr
osi
on
Lo
we
r ve
loci
ty a
nd
low
er
tem
pe
ratu
re t
ha
n A
/C.
Lo
we
r ra
te o
f co
rro
sio
n.
Re
pla
ced
ca
rbo
n s
tee
l w
ith A
lloy
80
0 i
n 1
98
1 (
10
ye
ars
).
Eff
lue
nt/
fra
ctio
na
tor
fee
d e
xch
an
ge
rT
ub
e t
hin
nin
g (
24
ye
ars
);
bis
ulfi
de
co
rro
sio
nS
usp
ect
oxy
ge
n (
50
pp
b)
invo
lve
d;
inle
t p
ipin
g
@
29
ft/
sÑst
ill i
n s
erv
ice
.F
aile
d i
n 1
99
5 a
fte
r 2
4 y
ea
rs a
t <
5 m
py.
QH
CU
A/C
in
let
pip
ing
(c.
s.)
Bis
ulfi
de
co
rro
sio
nH
igh
ve
loci
tyÑ
43
ft/
s: l
ow
wa
ter
inje
ctio
n.
No
n-s
ymm
etr
ica
l p
ipin
g l
ayo
ut;
14
" p
ipe
. In
sta
lled
Allo
y 8
00
el
bow
s in
inle
t un
til p
ipe
repl
aced
with
825
. B
oth
inle
t an
d ou
tlet
pipi
ng n
ow 8
25.
A/C
ou
tlet
pip
ing
(c.
s.)
Bis
ulfi
de
co
rro
sio
nH
igh
ve
loci
tyÑ
34
ft/
s: l
ow
wa
ter
inje
ctio
n.
A/C
tu
be
s (c
.s.)
Tu
be
th
inn
ing
Ñb
isu
lfid
e
corr
osi
on
Allo
y 8
00
re
pla
cem
en
t; h
ave
fo
un
d p
ittin
g.
Als
o
exp
eri
en
ced
le
aks
fro
m e
xte
rna
l co
rro
sio
n.
Th
irty
-six
tu
be
le
aks
fro
m 1
96
7 Ð
19
83
. In
sta
lled
fe
rru
les
in
19
83
. A
fte
r 1
mo
nth
, o
ne
tu
be
le
ak.
R
etu
be
d w
ith A
lloy
80
0
tub
es
in 1
98
4 Ð
19
85
.
Fra
ctio
na
tor
fee
d/e
fflu
en
t ex
chan
ger
Tu
be
co
rro
sio
nB
isu
lfid
e c
orr
osi
on
fro
m w
ate
r in
fra
ctio
na
tor
fee
d;
retu
be
d
in 1
981
with
Allo
y 80
0.S
tart
up
19
67
with
ca
rbo
n s
tee
l tu
be
s. E
igh
ty-s
ix U
-be
nd
tu
be
s p
lug
ge
d b
y 1
97
6 l
ea
k. L
ea
k in
19
78
ca
use
d o
uta
ge
. R
etu
be
d
with
ca
rbo
n s
tee
l in
19
81
. R
etu
be
d w
ith A
lloy
80
0 in
19
83
.
Tri
m c
oo
ler
Bis
ulfi
de
co
rro
sio
n;
als
o
wa
ter
sid
e a
tta
ckS
usp
ect
oxy
ge
n i
nvo
lve
d.
Film
ing
am
ine
ad
de
d i
n 1
99
4.
Wa
ter
sid
e c
orr
osi
on
by
MIC
; p
oo
r ch
lori
na
tion
;
10
mp
y Ð
15
mp
y o
n c
ha
nn
els
. R
etu
be
d i
n 1
98
3 w
ith c
arb
on
ste
el.
CH
TUA
/C t
ub
es
(c.s
.)B
isu
lfid
e c
orr
osi
on
13
% b
isu
lfid
e;
25
ft/
s.F
ailu
re 7
7 d
ays
(1
96
7).
Tri
ed
12
Cr,
17
Cr,
an
d
18
-8
up
gra
de
s. A
lloy
80
0 i
nst
alle
d i
n 1
98
1.
17
% m
ax
(13
%
ave
rag
e)
am
mo
niu
m b
isu
lfid
e;
25
ft/
s.
A/C
o
utle
t p
ipin
gB
isu
lfid
e c
orr
osi
on
Sw
irlin
g g
roo
ved
pa
tte
rn.
Up
gra
de
d t
o A
lloy
80
0.
No
w 8
25
be
cau
se o
f P
TA
.
Co
mp
ress
or
suct
ion
lin
eB
isu
lfid
e c
orr
osi
on
10
% Ð
15
% b
isu
lfid
e.
Ra
tes
of
10
0 m
py
Ð 5
00
mp
y in
tu
rbu
len
t flo
w b
eh
ind
we
ld p
rotr
usi
on
. H
igh
NH
3 i
n g
as
phas
e re
duce
d by
low
erin
g w
ash
wat
er t
empe
ratu
re.
Pro
ble
m c
au
sed
by
hig
h a
mm
on
ia i
n v
ap
or
cau
sin
g b
isu
lfid
e
salt
de
po
sit.
P
inh
ole
ju
st b
eh
ind
we
ld j
ett
ed
on
to o
pe
rato
r re
sulti
ng
in
sh
ut
do
wn
. N
ea
r m
iss.
Co
rro
sio
n i
n c
olu
mn
to
lera
ble
at
10
% b
ut
no
t 1
5%
bis
ulfi
de
.
Hyd
rog
en
re
cycl
e
dead
leg
Am
mo
niu
m c
hlo
rid
e
corr
osi
on
De
ad
le
g a
llow
ed
co
nd
en
sate
to
fo
rm.
Ga
s o
il H
T h
ydro
ge
n.
12
Cr
de
ad
le
g 6
" p
ipe
la
rge
en
ou
gh
to
a
llow
cir
cula
tion
an
d s
alt
acc
um
ula
tion
.
OH
TUS
ep
ara
tor
liqu
id/r
ea
cto
r e
fflu
en
tA
mm
on
ium
ch
lori
de
co
rro
sio
nN
ot
en
ou
gh
in
term
itte
nt
wa
sh w
ate
r. W
ett
ed
bu
t n
on
-flo
win
g d
ep
osi
ts.
Op
era
tion
al
de
fect
. S
olid
de
po
sits
pu
she
d d
ow
nst
rea
m i
nto
e
xch
an
ge
r.
30
0 m
py
Ð 4
00
mp
y.
No
w 6
25
ove
rla
id.
A/C
tu
be
sN
o c
orr
osi
on
No
co
rro
sio
n b
eca
use
of
3-p
ha
se f
low
.N
o s
olid
s d
ep
osi
ts;
1%
bis
ulfi
de
in
se
pa
rato
r; 2
6 f
t/s.
RH
CU
A/C
tu
be
sA
mm
on
ium
flu
ori
de
/ch
lori
de
co
rro
sio
nU
nd
erd
ep
osi
t co
rro
sio
n.
Ina
de
qu
ate
wa
sh w
ate
r (d
istr
ibu
tion
).F
luo
rid
es
fro
m h
ydro
cra
ckin
g c
ata
lyst
. N
ee
ds
re-f
luo
rin
atio
n.
U
pg
rad
ed
to
typ
e 4
10
sta
inle
ss s
tee
l (1
98
4).
D
esi
gn
ed
fo
r a
nn
ula
r flo
w.
We
irs
in i
nle
t h
ea
de
r.
Co
rro
sio
n i
n t
ub
es
< 1
m
py
sin
ce 1
98
4.
Wa
ter
inje
ctio
n p
oin
tC
orr
osi
on
-ero
sio
n
ad
jace
nt
to i
nle
tIn
suff
icie
nt
wa
sh w
ate
r. 1
in
. m
eta
l lo
ss i
n 1
0 y
ea
rs.
Se
vere
att
ack
(6
5 m
py)
. R
ed
esi
gn
ed
with
sp
ray
no
zzle
an
d
we
ld o
verl
aid
with
In
con
el
62
5.
Inst
alle
d s
tatic
mix
er.
A/C
in
let
pip
ing
A
mm
on
ium
flu
ori
de
co
rro
sio
n4
00
mils
in
20
ye
ars
. N
H4F
or
NH
4Cl
; to
o h
ot
for
bis
ulfi
de
.R
ep
lace
d i
n 1
97
8.
La
ste
d t
o 1
99
7.
Copyright American Petroleum Institute Reproduced by IHS under license with API
Document provided by IHS Licensee=Bureau Veritas/5959906001, 11/02/200419:37:55 MST Questions or comments about this message: please call the DocumentPolicy Group at 303-397-2295.
--`,``,,```,`,``,```,,,,```,`-`-`,,`,,`,`,,`---
A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
15
Tabl
e6—
Com
pila
tion
of In
form
atio
n fr
om P
lant
Inte
rvie
ws
(Con
tinue
d)
Pla
nt
Un
itL
oca
tio
n o
f C
orr
osi
on
Typ
e o
f C
orr
osi
on
Cau
sati
ve F
acto
rsC
om
men
ts
WH
CU
A/C
inl
et p
ipin
gT
hinn
ing
at e
xcha
nger
in
let.
Ba
lan
ced
pip
ing
Hig
h n
itro
ge
n f
ee
d;
Kp
> 0
.45
; 8
% b
isu
lfid
e.
Aft
er
first
exp
eri
en
ce w
ith c
arb
on
ste
el,
use
d 1
2 C
r.
Inte
rmitt
en
t w
ash
to
pre
ven
t sa
lt fo
ulin
g.
Use
in
hib
itor.
A/C
tu
be
sR
ecu
rrin
g p
rob
lem
s w
ith
carb
on
ste
el
tub
es;
b
isu
lfid
e c
orr
osi
on
8%
bis
ulfi
de
; <
20
ft/
s ve
loci
ty i
n t
ub
es;
ca
rbo
n s
tee
l tu
be
s.19
68 Ð
198
0 un
sche
dule
d re
plac
emen
t; a
fter
198
0 w
ent
to
5-y
ea
r sc
he
du
le.
Fo
ur
lea
ks s
ince
. F
ou
r ye
ars
min
imu
m,
ave
rag
e >
5 y
ea
rs.
Ero
sio
n a
t o
utle
t o
f la
st p
ass
. U
se t
ype
3
04
fe
rru
lesÑ
pitt
ed
in
an
nu
lus
du
e t
o c
hlo
rid
es.
A/C
ou
tlet
he
ad
er
Bis
ulfi
de
co
rro
sio
nR
eq
uir
ed
re
pla
cem
en
t o
f h
ea
de
rs.
Un
ba
lan
ced
pip
ing
.W
ash
wa
ter
ad
just
ed
acc
ord
ing
to
bis
ulfi
de
co
nte
nt,
nitr
og
en
co
nte
nt,
an
d f
ee
d r
ate
. 7
5%
no
n-v
ap
ori
zin
g.
A/C
ou
tlet
pip
ing
No
se
rio
us
corr
osi
on
Ñn
o
rep
lace
me
nt
So
me
Ls
ove
rla
id w
ith 3
09
/18
-8.
In
dic
ate
s e
rosi
on
-co
rro
sio
n a
t >
20
ft/
s.S
tric
t co
ntr
ol
of
bis
ulfi
de
in
acc
um
ula
tor
(8%
).
W(2
)H
CU
A/C
ou
tlet
pip
ing
Se
vere
bis
ulfi
de
e
rosi
on
Ñfir
eIn
cre
ase
d v
elo
city
be
cau
se o
f 1
0%
in
cre
ase
in
liq
uid
fe
ed
.U
nsy
mm
etr
ica
l p
ipin
g w
ith i
mp
ing
em
en
t d
ue
to
sh
arp
tu
rns.
V
elo
city
ch
an
ge
fro
m 2
0 f
t/s
Ð 2
7 f
t/s.
XH
TUA
ll ca
rbo
n s
tee
l e
qu
ipm
en
tN
o s
eri
ou
s co
rro
sio
n
pro
ble
ms
Kp =
0.0
5; 2
% Ð
3%
bis
ulfid
e; 1
5 ft
/s t
ube
velo
city
.B
alan
ced
pipi
ng;
annu
lar
flow
; st
ripp
ed s
our
wat
er w
ash,
60%
va
pori
zed;
low
chl
orid
es.
EE
HC
UA
/C t
ub
es
Bis
ulfi
de
co
rro
sio
nT
ub
e t
hin
nin
g.
Fe
rru
les
inst
alle
d o
n i
nle
t o
f ro
w 2
.
Thi
nnin
g of
inl
ets
to 3
rd a
nd 4
th r
ows.
N
ever
had
tub
e p
lug
gin
g.
Ca
rbo
n s
tee
l tu
be
s, A
lloy
80
0 f
err
ule
s.
Ori
gin
al
top
ro
w t
ype
3
04
sta
inle
ss s
tee
lÑch
an
ge
d t
o A
lloy
80
0.
Tu
be
life
ha
s va
rie
d f
rom
5 Ð
16
ye
ars
. A
ll tu
be
s ch
an
ge
d t
o A
lloy
80
0 i
n
19
97
. Kp =
0.1
2 Ð
0.2
; b
isu
lfid
e =
4%
at
sep
ara
tor.
A/C
pip
ing
No
sig
nifi
can
t co
rro
sio
nL
ow
bis
ulfi
de
; V
elo
citie
s ~
30
ft/
s.
IH
CU
All
carb
on
ste
el
eq
uip
me
nt
No
se
rio
us
corr
osi
on
p
rob
lem
sU
nb
ala
nce
d p
ipin
g;
bis
ulfi
de
~ 4
%.
Ve
loci
ties
no
t p
rovi
de
d.
Kp =
0.2
3.
YH
CU
A/C
tu
be
sB
isu
lfid
e c
orr
osi
on
Kps
incr
ea
sed
fro
m 0
.09
to
0.3
2 o
ver
time
. V
elo
citie
s in
1
0 f
t/s
Ð 1
5 f
t/s
ran
ge
. 4
% b
isu
lfid
e.
Ca
rbo
n s
tee
lÑin
itia
l p
rob
lem
s tu
be
en
d c
orr
osi
on
. P
erf
ora
tion
ca
me
la
ter.
R
etu
be
d w
ith c
arb
on
ste
el
ap
pro
xim
ate
ly e
very
5
yea
rs.
Pla
n t
o u
pg
rad
e t
o A
lloy
82
5 o
n n
ext
re
tub
e.
Fo
rme
rly
sing
le w
ash
wat
er p
oint
Ñno
w m
ultip
le.
Poo
r w
ater
dis
trib
utio
n.
A/C
pip
ing
B
isu
lfid
e c
orr
osi
on
in
let
he
ad
ers
Ve
loci
ties
in i
nle
t h
ea
de
r sy
ste
m o
f 1
7 f
t/s
Ð 2
7 f
t/s.
Un
ba
lan
ced
in
let
an
d o
utle
t p
ipin
g.
> 2
0 m
py.
P
oss
ible
ch
lori
de p
robl
em d
ue t
o in
adeq
uate
wat
er in
inle
t.
Pip
ing
upgr
aded
to
Allo
y 82
5 on
sm
all
size
s.
Allo
y 62
5 ov
erla
y on
la
rge
ca
rbo
n s
tee
l p
ipin
g.
Pos
sibl
e ch
lori
de p
robl
em d
ue t
o in
adeq
uate
wat
er.
HP
Se
pa
rato
rB
isu
lfid
e c
orr
osi
on
-e
rosi
on
Imp
ing
em
en
t a
tta
ck.
Sta
inle
ss s
tee
l im
pin
ge
me
nt
pla
te o
f a
de
qu
ate
siz
e.
ZH
TUA
/C t
ub
es
Bis
ulfi
de
co
rro
sio
nÑ
thin
nin
g
lead
ing
to f
ire
Typ
e 4
10
sta
inle
ss s
tee
l tu
be
s. F
ailu
re a
fte
r 7
ye
ars
.
2
0 m
py
Ð 2
5 m
py.
B
ott
om
tu
be
gro
ovi
ng
. B
isu
lfid
es
conc
entr
ated
to
19%
in
oute
r ce
lls.
Poo
r w
ater
d
istr
ibu
tion
.
No
n-s
ymm
etr
ica
l p
ipin
g a
nd
sin
gle
po
int
wa
ter
inje
ctio
n.
T
ubes
upg
rade
d to
Allo
y 82
5.
Thr
ough
put
incr
ease
d be
fore
fa
ilure
.
A/C
pip
ing
No
co
rro
sio
nA
lloy
82
5.
He
ad
er
bo
xes
an
d o
utle
t p
ipin
g v
eri
fied
82
5.
No
ve
loci
ties
ava
ilab
le.
AA
HTU
A/C
ou
tlet
pip
ing
Co
rro
sio
n-e
rosi
on
of
carb
on
ste
el
pip
ing
Bis
ulfi
de
co
rro
sio
n.
Re
pla
ced
elb
ow
s w
ith A
lloy
80
0.
Ve
loci
ties
18
ft/
s Ð
32
ft/
s.
With
in 2
yea
rs u
pgra
ded
all
pipe
to
Allo
y 80
0.
Cha
nged
to
Allo
y 8
25
be
cau
se o
f p
oly
thio
nic
aci
d c
rack
ing
Ñin
sta
llatio
n
err
or.
B
ala
nce
d i
nle
t a
nd
ou
tlet.
1
4%
Ð 1
5%
bis
ulfi
de
.
A/C
tu
be
sN
o c
orr
osi
on
Allo
y 8
00
tu
be
s a
nd
Allo
y 8
00
bo
xes.
Ori
gin
al
tu
be
s A
lloy
80
0.
Ve
loci
ties
18
ft/
s Ð
20
ft/
s.
Eff
lue
nt/
fra
ctio
na
tor
feed
exc
hang
erA
mm
on
ium
ch
lori
de
d
ep
osi
tion
Co
rro
sio
n u
pst
rea
m o
f w
ate
r in
ject
ion
. A
dd
ed
in
term
itte
nt
inje
ctio
n p
oin
ts.
Me
tallu
rgy
up
gra
de
d f
rom
17
Cr
to 2
205
dupl
ex S
S.
Copyright American Petroleum Institute Reproduced by IHS under license with API
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16 API P
UBLICATION
932-A
Tabl
e6—
Com
pila
tion
of In
form
atio
n fr
om P
lant
Inte
rvie
ws
(Con
tinue
d)
Pla
nt
Un
itL
oca
tio
n o
f C
orr
osi
on
Typ
e o
f C
orr
osi
on
Cau
sati
ve F
acto
rsC
om
men
ts
HP
LT s
epar
ator
wat
er
ou
tlet
pip
eB
isu
lfid
e c
orr
osi
on
Le
vel
con
tro
l p
rob
lem
. S
tra
tifie
d f
low
with
co
nce
ntr
ate
d
bis
ufid
e a
t st
ee
l su
rfa
ce 8
% Ð
28
% b
isu
lfid
e i
n a
qu
eo
us
ph
ase
, n
orm
ally
15
% Ð
16
%.
Sw
irl p
atte
rn o
f at
tack
ter
min
ated
at
wel
d pr
otru
sion
whi
ch
act
ed
as
a f
low
str
aig
hte
ne
r. L
oca
l a
tta
ck i
mm
ed
iate
ly a
fte
r w
eld.
CS
rep
lace
d w
ith A
lloy
800.
HP
LT
se
pa
rato
r o
utle
t p
ipe
Ñh
ydro
carb
on
Bis
ulfi
de
co
rro
sio
n d
ue
to
w
ater
ent
rain
men
t W
ate
r ca
rryo
ver
fro
m h
igh
le
vel
in s
ep
ara
tor.
Ext
rem
e
corr
osi
on
up
to
1-i
n.
loss
in
on
e w
ee
k.S
eve
re c
orr
osi
on
of
we
ldo
let.
De
tect
ed
by
rad
iog
rap
hy
be
fore
fa
ilure
occ
urr
ed
. N
ea
r m
iss.
LP
LT
se
pa
rato
r o
ff
ga
s p
ipin
gIm
pin
ge
me
nt
att
ack
S
ulfu
r d
ep
osi
t b
uild
up
ca
use
d r
est
rict
ed
flo
w a
nd
ero
sio
n-
corr
osi
on
. R
eq
uir
es
liqu
id c
arr
yove
r.P
rob
ab
ly e
rosi
on
-co
rro
sio
n f
rom
dro
ple
t im
pin
ge
me
nt.
By-
pa
ss d
ea
d l
eg
sB
isu
lfid
e c
orr
osi
on
(Se
e P
lan
t C
fo
r sa
me
pro
ble
m.)
C
orr
osi
ve d
ep
osi
ts
form
ed
by
circ
ula
tion
in
op
en
de
ad
le
g.
Lo
caliz
ed
att
ack
ove
r 1
ft2
are
a.
Eq
uip
me
nt
do
wn
stre
am
of
sep
ara
tors
Pro
ble
ms
cau
sed
by
bis
ulfi
de
s a
nd
cya
nid
es
Occ
urs
w
he
re s
alt
con
cen
tra
tion
ta
kes
pla
ce.
S
trip
pe
r o
verh
ea
d r
ece
ive
r va
po
r lin
e h
ad
to
be
re
pla
ced
at
6
mo
nth
in
terv
als
.
BB
HC
UF
ee
d/e
fflu
en
t ex
chan
ger
Ch
lori
de
pitt
ing
of
tub
es
on
fe
ed
sid
eT
ype
32
1 s
tain
less
ste
el
tub
es
pitt
ed
du
e t
o C
l in
fe
ed
.
Fa
il e
very
2 y
ea
rs.
Up
gra
de
d t
o 2
54
SM
O.
No
de
salte
r.
Eff
lue
nt
pip
ing
u
pst
rea
m A
/CU
nd
er
de
po
sit
att
ack
Am
mo
niu
m c
hlo
rid
e.
Co
rro
sio
n a
rou
nd
wa
ter
inje
ctio
n p
oin
t a
nd
do
wn
stre
am
pip
ing
.
A/C
tu
be
sC
arb
on
ste
el
tub
es
Hig
h v
elo
citie
s u
p t
o 6
0 f
t/s
in i
nle
ts.
Ve
loci
ties
red
uce
d
to 1
5 f
t/s
Ð 1
7 f
t/s.
Un
ba
lan
ced
pip
ing
.9
% b
isu
lfid
e m
ax.
; 3
.5%
Ð 4
% a
vg.
Ch
an
ge
d f
rom
4-p
ass
to
2-p
ass
to
re
du
ce v
elo
citie
sÑso
lve
d p
rob
lem
. W
ate
r a
ccu
mu
latio
n i
n l
ow
er
pre
ssu
re d
rop
tu
be
ba
nks
ca
use
d
seal
ing
and
incr
ease
d flo
w in
ope
n ba
nks.
CC
HC
UE
fflu
en
t p
ipin
g f
rom
e
xch
an
ge
rs t
o
sep
ara
tor
Bis
ulfi
de
co
rro
sio
n6
% Ð
6.8
% b
isu
lfid
e.
Ve
loci
ties
up
to
32
ft/
s.E
xtra
he
avy
CS
re
pla
ced
eve
ry 8
ye
ars
. U
pg
rad
ed
to
Allo
y 8
25
be
cau
se o
f in
cre
asi
ng
N i
n f
ee
d.
1st
sta
ge
eff
lue
nt
trim
co
ole
rB
isu
lfid
e c
orr
osi
on
~ 6
.5%
bis
ulfi
de
.U
-tu
be
exc
ha
ng
er.
Up
gra
de
d f
rom
CS
to
mo
ne
l a
fte
r 2
ye
ars
.
1st
sta
ge
eff
lue
nt/
fee
d
exch
ange
rB
isu
lfid
e c
orr
osi
on
~ 6
.5%
b
isu
lfid
e V
elo
city
38
ft/
s Ð
40
ft/
s.O
rig
ina
l C
S >
10
ye
ars
life
. U
pg
rad
ed
to
3R
E6
0 d
up
lex
allo
y.
2n
d s
tag
e e
fflu
en
t fe
ed
exc
ha
ng
er
Bis
ulfi
de
co
rosi
on
Ch
an
ge
d t
ub
es
fro
m 1
7 C
r to
3R
E6
0 a
fte
r 1
5 y
ea
rs.
EH
TU A
/C t
ub
es
Allo
y 8
00
Ñfo
un
d p
ittin
g
aft
er
7 y
ea
rsO
rig
ina
l 8
00
tu
be
s a
nd
he
ad
er
bo
xes.
Fo
un
d p
ittin
g a
nd
d
ela
min
atio
ns.
U
pg
rad
ed
to
Allo
y 8
25
. S
usp
ect
ch
lori
de
s ca
use
d p
ittin
g.
Tu
be
ve
loci
ties
12
ft/
s Ð
17
ft/
s.
A/C
pip
ing
Co
rro
sio
n-e
rosi
on
of
outle
t el
bow
res
ultin
g in
fir
e
Ca
rbo
n s
tee
l p
ipin
g.
In
let
pip
ing
ba
lan
ced
; o
utle
t p
ipin
g
un
ba
lan
ced
. B
isu
lfid
e <
8%
.
Ve
loci
ties
9 f
t/s
Ð 2
6 f
t/s.
Un
it m
od
ifie
d t
o i
ncl
ud
e H
PH
T s
ep
ara
tor
for
pro
cess
re
aso
ns.
F
ailu
re o
ccu
rre
d a
fte
r 9
mo
nth
s.
Fa
ilure
occ
urr
ed
in
ou
tlet
elb
ow
aft
er
inst
alla
tion
of
HP
HT
se
pa
rato
r.
Re
du
ced
wa
ter
wa
sh,
incr
ea
sed
bis
ulfi
de
, a
nd
un
ba
lan
ced
fa
n o
pe
ratio
n.
In
cre
ase
d H
2.
Eff
lue
nt/
fee
d
exch
ange
rN
o c
orr
osi
on
Op
era
tes
at
40
0+
with
no
sa
lt d
ep
osi
ts.
No
wa
ter
wa
sh o
n th
is i
tem
.P
lan
to
in
cre
ase
op
era
tion
to
50
0 d
eg
ree
s.
Co
nce
rn w
ith
na
ph
the
nic
aci
ds.
E
fflu
en
t h
as
5 p
pm
Ð 1
0 p
pm
ch
lori
de
s.
UH
TUA
/C t
ub
es
No
co
rro
sio
nH
2S
in
exc
ess
of
am
mo
nia
. 6
% b
isu
lfid
e.
V
elo
city
10
ft/
s.N
o p
lug
gin
g.
Dis
con
tinu
ed
up
stre
am
wa
ter
wa
sh.
Am
mo
nia
lo
w;
tem
pe
ratu
res
hig
h.
Sin
gle
po
int
wa
ter
inje
ctio
nÑ
tota
lly
vap
ori
zed
. C
arb
on
ste
el
tub
es.
5
Cr
cha
nn
els
. F
ou
r b
ays
to
tw
o a
fte
r a
dd
itio
n o
f H
PH
T s
ep
ara
tor
du
e t
o r
ed
uce
d
thro
ug
hp
ut.
A/C
pip
ing
No
co
rro
sio
nC
urr
en
tly c
arb
on
ste
elÑ
up
gra
din
g t
o A
lloy
82
5.
U
nb
ala
nce
d o
utle
t p
ipin
g.
RE
AC
in
let
velo
city
21
ft/
s.P
lan
nin
g a
dd
itio
n o
f H
PH
T s
ep
ara
tor.
K p
= 0
.8.
Allo
y 8
25
p
ipin
g f
rom
in
ject
ion
po
int
to s
ep
ara
tor.
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
17
Tabl
e7—
Com
pila
tion
of In
form
atio
n fr
om P
lant
Inte
rvie
ws—
Air
Coo
ler T
ubes
Pla
nt
Un
itL
oca
tio
n o
f C
orr
osi
on
Typ
e o
f C
orr
osi
on
Cau
sati
ve F
acto
rsC
om
men
ts
BH
CU
Air
co
ole
r tu
be
sB
isu
lfid
e c
orr
osi
on
La
ck o
f w
ash
wa
ter.
Inst
alle
d 1
97
1;
faile
d i
n 6
ye
ars
(fir
e);
re
pla
ced
with
Allo
y 8
00
.
QH
CU
A/C
tu
be
s (c
.s.)
Tub
e th
inn
ing
Ñb
isu
lfid
e
corr
osi
on
Allo
y 8
00
re
pla
cem
en
t; h
ave
fo
un
d p
ittin
g.
A
lso
expe
rien
ced
leak
s fr
om e
xter
nal
corr
osi
on
.
36
tu
be
le
aks
fro
m 1
96
7 Ð
19
83
. In
sta
lled
fe
rru
les
in 1
98
3.
Aft
er
1
mo
nth
, 1
tu
be
le
ak.
R
etu
be
d w
ith A
lloy
80
0 t
ub
es
in 1
98
4 Ð
19
85
.
CH
TUA
/C t
ub
es
(c.s
.)B
isu
lfid
e c
orr
osi
on
13
% b
isu
lfid
e;
25
ft/
s.F
ailu
re 7
7 d
ays
(1
96
7).
Tri
ed
12
Cr,
17
Cr,
an
d 1
8-8
up
gra
de
s. A
lloy
80
0 i
nst
alle
d i
n 1
98
1.
17
% m
ax
(13
% a
vera
ge
) a
mm
on
ium
bis
ulfi
de
; 2
5 f
t/s.
OH
TUA
/C t
ub
es
No
co
rro
sio
nN
o c
orr
osi
on
be
cau
se o
f 3
-ph
ase
flo
w.
No
so
lids
de
po
sits
; 1
% b
isu
lfid
e i
n s
ep
ara
tor;
26
ft/
s.
RH
CU
A/C
tu
be
sA
mm
on
ium
flu
ori
de
/ch
lori
de
co
rro
sio
n
F c
on
de
nsa
tion
te
mp
era
ture
> c
hlo
rid
es.
Flu
ori
de
s fr
om
hyd
rocr
ack
ing
ca
taly
st.
Ne
ed
s re
-flu
ori
na
tion
.
Up
gra
de
d t
o t
ype
41
0 s
tain
less
ste
el
(19
84
).
De
sig
ne
d f
or
an
nu
lar
flow
. W
eir
s in
in
let
he
ad
er.
C
orr
osi
on
in
tu
be
s <
1 m
py
sin
ce 1
98
4.
WH
CU
A/C
tu
be
sR
ecu
rrin
g p
rob
lem
s w
ith c
arbo
n st
eel
tub
es;
bis
ulfi
de
co
rro
sio
n
8%
bis
ulfi
de
; <
20
ft/
s ve
loci
ty i
n t
ub
es;
ca
rbo
n s
tee
l tu
be
s.1
96
8 Ð
19
80
un
sch
ed
ule
d r
ep
lace
me
nt;
aft
er
19
80
we
nt
to 5
ye
ar
sch
ed
ule
. F
ou
r le
aks
sin
ce.
Fo
ur
yea
rs m
inim
um
, a
vera
ge
> 5
ye
ars
. E
rosi
on
-co
rro
sio
n a
t o
utle
t o
f la
st p
ass
. U
se t
ype
30
4 f
err
ule
sÑp
itte
d
in a
nn
ulu
s d
ue
to
ch
lori
de
s.
XH
TUA
ll ca
rbo
n s
tee
l e
qu
ipm
en
tN
o s
eri
ou
s co
rro
sio
n
pro
ble
ms
Kp =
0.0
5;
2%
Ð 3
% b
isu
lfid
e;
15
ft/
s tu
be
ve
loci
ty.
Bal
ance
d pi
ping
; an
nula
r flo
w;
stri
pped
sou
r w
ater
was
h, 6
0%
vapo
rize
d; lo
w c
hlor
ides
.
EE
HC
UA
/C t
ub
es
Bis
ulfi
de
co
rro
sio
nT
ub
e t
hin
nin
g.
Fe
rru
les
inst
alle
d o
n i
nle
t o
f ro
w 2
. T
hinn
ing
of in
lets
to
3rd
and
4th
row
s.
Ne
ver
ha
d t
ub
e p
lug
gin
g.
Ca
rbo
n s
tee
l tu
be
s, A
lloy
80
0 f
err
ule
s.
Ori
gin
al
top
ro
w t
ype
30
4
sta
inle
ss s
tee
lÑch
an
ge
d t
o A
lloy
80
0.
Tu
be
life
ha
s va
rie
d f
rom
5 Ð
16 y
ears
. A
ll tu
bes
chan
ged
to A
lloy
800
in 1
997.
Kp =
0.1
2 Ð
0.2
; b
isu
lfid
e =
4%
at
sep
ara
tor.
IH
CU
All
carb
on
ste
el
eq
uip
me
nt
No
se
rio
us
corr
osi
on
p
rob
lem
sU
nb
ala
nce
d p
ipin
g;
bis
ulfi
de
~ 4
%.
Ve
loci
ties
no
t p
rovi
de
d.
Kp
= 0
.23.
YH
CU
A/C
tu
be
sB
isu
lfid
e c
orr
osi
on
Kps
incr
ea
sed
fro
m 0
.09
to
0.3
2 o
ver
time
. V
elo
citie
s in
10
ft/
s Ð
15
ft/
s ra
ng
e.
7
% Ð
8%
bis
ulfi
de
.
Ca
rbo
n s
tee
lÑin
itia
l p
rob
lem
s tu
be
en
d c
orr
osi
on
. P
erf
ora
tion
ca
me
la
ter.
R
etu
be
d w
ith c
arb
on
ste
el
ap
pro
xim
ate
ly e
very
5 y
ea
rs.
Pla
n
to u
pgra
de t
o A
lloy
825
on n
ext
retu
be.
For
mer
ly s
ingl
e w
ash
wat
er
poin
tÑno
w m
ultip
le.
Poo
r w
ater
dis
trib
utio
n.
ZH
TUA
/C t
ub
es
Bis
ulfi
de
co
rro
sio
nÑ
thin
nin
g
lea
din
g t
o f
ire
Typ
e 4
10
sta
inle
ss s
tee
l tu
be
s. F
ailu
re a
fte
r 7
ye
ars
. 2
0 m
py
Ð 2
5 m
py.
B
ott
om
tu
be
g
roo
vin
g.
Bis
ulfi
de
s co
nce
ntr
ate
d t
o 1
9%
in
o
ute
r ce
lls.
Po
or
wa
ter
dis
trib
utio
n.
No
n-s
ymm
etr
ica
l p
ipin
g a
nd
sin
gle
po
int
wa
ter
inje
ctio
n.
Tu
be
s u
pg
rad
ed
to
Allo
y 8
25
. T
hro
ug
hp
ut
incr
ea
sed
be
fore
fa
ilure
.
AA
HTU
A/C
tu
be
sN
o c
orr
osi
on
Allo
y 8
00
tu
be
s a
nd
Allo
y 8
00
bo
xes.
Ori
gin
al
tu
be
s A
lloy
80
0.
Ve
loci
ties
18
ft/
s Ð
20
ft/
s.
BB
HC
UA
/C t
ub
es
Ca
rbo
n s
tee
l tu
be
sH
igh
ve
loci
ties
up
to
60
ft/
s in
in
lets
.
Ve
loci
ties
red
uce
d t
o 1
5 f
t/s
Ð 1
7 f
t/s.
U
nb
ala
nce
d p
ipin
g.
9%
bis
ulfi
de
ma
x.;
3.5
% Ð
4%
avg
. C
ha
ng
ed
fro
m
4-p
ass
to
2-p
ass
to
re
du
ce v
elo
citie
sÑso
lve
d p
rob
lem
. W
ate
r a
ccu
mu
latio
n i
n l
ow
er
pres
sure
dro
p tu
be b
anks
cau
sed
seal
ing
and
incr
ease
d flo
w i
n op
en
ba
nks
.
EH
TU A
/C t
ub
es
Allo
y 8
00
Ñfo
un
d
pitt
ing
aft
er
7 y
ea
rsO
rigi
nal
800
tube
s an
d he
ader
box
es.
Fou
nd
pitt
ing
an
d d
ela
min
atio
ns.
U
pg
rad
ed
to
Allo
y 8
25
. S
usp
ect
ch
lori
de
s ca
use
d p
ittin
g.
T
ub
e v
elo
citie
s 1
2 f
t/s
Ð 1
7 f
t/s.
UH
TUA
/C t
ub
es
No
co
rro
sio
nH
2S
in
exc
ess
of
am
mo
nia
. 6
% b
isu
lfid
e.
V
elo
city
10
ft/
s.N
o pl
uggi
ng.
Dis
cont
inue
d up
stre
am w
ater
was
h.
Am
mon
ia l
ow;
tem
pe
ratu
res
hig
h.
Sin
gle
po
int
wa
ter
inje
ctio
nÑ
tota
lly v
ap
ori
zed
.
Ca
rbo
n s
tee
l tu
be
s.
5 C
r ch
an
ne
ls.
Fo
ur
ba
ys t
o t
wo
aft
er
ad
diti
on
o
f H
TH
P s
ep
ara
tor
du
e t
o r
ed
uce
d t
hro
ug
hp
ut.
Copyright American Petroleum Institute Reproduced by IHS under license with API
Document provided by IHS Licensee=Bureau Veritas/5959906001, 11/02/200419:37:55 MST Questions or comments about this message: please call the DocumentPolicy Group at 303-397-2295.
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18 API P
UBLICATION
932-A
Tabl
e8—
Air
Coo
ler T
ube
Exp
erie
nce
from
Sur
vey
Pla
nt
Un
itO
rig
ina
l M
ate
ria
lC
orr
osi
on
rat
e (l
ife
)
Ma
teri
al
Up
gra
de
(lif
e to
dat
e)E
rosi
on
-C
orr
osi
on
Sa
lt
dep
osi
tT
hin
nin
gO
ther
Cau
se o
f C
orr
osi
on
HS
co
nce
ntr
atio
n
(%)
Ve
loc
ity
(ft
/s)
K pB
HC
UC
S
18
mp
y
(6 y
ea
rs)
Allo
y 80
0
(1
7 y
ea
rs)
XX
Insu
ffic
ient
was
h w
ater
5% Ð
22
%
(ca
lcu
late
d)
17 Ð
19
0.2
QH
CU
CS
Allo
y 8
00
(1
4
yea
rsÑ
pitt
ing
)X
Bis
ulfi
de
co
rro
sio
n19
0.0
14
Ð 0
.04
0
CH
TUC
S5
00
mp
y
(77
da
ys)
Va
rio
us
to
Allo
y 82
5a
(9 y
ea
rs)
XH
igh
bis
ulfi
de
s; h
igh
ve
loci
ty1
3 a
vera
ge
;
1
7 m
ax.
250
.2 Ð
0.5
OH
TUC
SN
on
eN
oLo
w b
isul
fide
1%26
0.2
2
RH
CU
CS
200
mpy
(6 m
on
ths)
12
Crb
XX
Flu
ori
de
s/ch
lori
de
sÑh
igh
d
ep
osi
tion
te
mp
era
ture
.
Insu
ffic
ient
was
h w
ater
WH
CU
CS
Use
30
4 S
S
ferr
ule
sc
XH
igh
exi
t ve
loci
ty8%
Cu
rre
ntly
< 2
0>
0.4
5
XH
TUC
SS
ince
19
72
No
ne
No
Fa
vora
ble
op
era
ting
p
ara
me
ters
2% Ð
3%
150
.05
EE
HC
UC
S w
/ 80
0 fe
rru
les;
3
04
to
p
row
20
mp
yA
lloy
800
(new
)X
No
XH
igh
velo
city
and
low
w
ater
was
h4%
30
in
; 2
0 o
ut
0.1
2 Ð
0.2
IH
CU
CS
N
on
e4%
0.2
3
YH
CU
CS
25
mp
y (e
st.)
CS
, A
lloy
82
5
next
upg
rade
X?
Pitt
ing
Low
wat
er r
ate;
poo
r d
istr
ibu
tion
7% Ð
8%
(r
ed
uce
d t
o 4
%)
11 Ð
15
in;
8
Ð 1
1 o
ut
0.3
4
ZH
TU1
7 C
r2
0 m
py
Ð 2
5 m
py
Allo
y 8
25
No
XH
igh
bis
ulfi
de
Up
to
19
% i
n
lo
w fl
ow c
ells
AA
HTU
Allo
y 8
00
13
ye
ars
No
co
rro
sio
n1
2 Ð
15
%1
8 Ð
20
BB
HC
UC
SN
on
eX
Hig
h t
ub
e e
nd
ve
loci
ties
caus
ed b
y un
even
flo
w3
.5%
Ð 4
%
avg
.; 9
% m
ax.
60
ft/
s
re
du
ced
to
1
5 f
t/s
Ð 1
7 f
t/s
EH
TUA
lloy
80
0A
lloy
82
5P
ittin
gd
Su
spe
ct c
hlo
rid
es
< 8
%12
Ð 1
76
.1
UH
TU C
SN
on
eN
oLo
w N
H3
3.9
ave
rag
e;
6.0
%10
~0
.8
No
tes:
d M
an
ufa
ctu
rin
g d
efe
cts.
Typ
e o
f C
orr
osi
on
a C
arb
on
ste
el
faile
d i
n 7
7 d
ays
.b R
ep
lace
d f
ailu
re w
ith C
S.
Ch
an
ge
d t
o 1
2C
r fo
r p
roce
ss r
ea
son
s.
c C
hlo
rid
e c
orr
osi
on
be
hin
d t
he
ou
tlet
ferr
ule
.
Copyright American Petroleum Institute Reproduced by IHS under license with API
Document provided by IHS Licensee=Bureau Veritas/5959906001, 11/02/200419:37:55 MST Questions or comments about this message: please call the DocumentPolicy Group at 303-397-2295.
--`,``,,```,`,``,```,,,,```,`-`-`,,`,,`,`,,`---
A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
19
Table 9—Compilation of Information from Plant Interviews—Piping Information
Plant Unit Location of Corrosion Type of Corrosion Causative Factors Comments
B HCU A/C outlet piping Grooving and channeling.
25 ft/s attack in turbulent area downstream of elbow. Now corroding at 50 mpy. Suspect oxygen and chlorides. No corrosion when oxygen and chlorides under control.
Original 18" replaced with 22" in 1994.
Q HCU A/C inlet piping (c.s.) Bisulfide corrosion. High velocityÑ43 ft/s: low water injection. Non-symmetrical piping layout; 14" pipe. Installed Alloy 800 elbows in inlet until pipe replaced with 825. Both inlet and outlet piping now 825.
A/C outlet piping (c.s.) Bisulfide corrosion. High velocityÑ34 ft/s: low water injection.
C HTU A/C outlet piping Bisulfide corrosion. Sequential addition of Alloy 600 to downstream piping. Failure occurred downstream of last upgrade in remaining carbon steel section.
Occurred in 1982. No info on parameters.
R HCU A/C piping NH4F corrosion. 100 mpy.
1 mil in 10 years. Ammonium fluoride. Replaced in 1978 and again in 1996.
W HCU A/C inlet piping Thinning at exchanger inlet. Balanced piping.
High nitrogen feed; Kp > 0.45; 8% bisulfide.
After first experience with carbon steel used 12 Cr. Intermittent wash to prevent salt fouling. Use inhibitor.
A/C outlet piping No serious corrosionÑno replacement.
Some ells overlaid with 309 / 18-8. Indicates erosion-corrosion at > 20 ft/s.
Strict control of bisulfide in accumulator (8%).
W(2) HCU A/C outlet piping Severe erosion-corrosionÑfire.
Increased velocity because of 10% increase in liquid feed.
Unsymmetrical piping with impingement due to sharp turns. Velocity change from 20 ft/s Ð 27 ft/s.
X HTU All carbon steel equipment
No serious corrosion problems.
Kp = 0.05; 2% Ð 3% bisulfide; 15 ft/s tube velocity.
Balanced piping; annular flow; stripped sour water wash, 60% vaporized; low chlorides.
EE HCU A/C piping No significant corrosion.
Low bisulfide; Velocities ~ 30 ft/s.
I HCU All carbon steel equipment
No serious corrosion problems.
Unbalanced piping; bisulfide ~ 4%. Velocities not provided. Kp = 0.23.
Y HCU A/C piping Bisulfide corrosion inlet headers.
Velocities in inlet header system of 17ft/s Ð 27 ft/s.
Unbalanced inlet and outlet piping. > 20 mpy. Possible chloride problem due to inadequate water in inlet. Piping upgraded to Alloy 825 on small sizes. Alloy 625 overlay on large carbon steel piping.
Z HTU A/C piping No corrosion. Alloy 825. Header boxes and outlet piping verified 825. No velocities available.
AA HTU A/C outlet piping Erosion-corrosion of carbon steel piping.
Bisulfide corrosion. Replaced elbows with Alloy 800. Velocities 18 ft/s Ð 32 ft/s. Within 2 years upgraded all pipe to Alloy 800. Changed to Alloy 825 because of polythionic acid crackingÑ installation error. Balanced inlet and outlet. 14% Ð 15% bisulfide.
HPLT separator outlet pipe
Bisulfide corrosion. Carbon steel pipe replaced with Alloy 800. 12% Ð 15% bisulfide in aqueous phase.
HPLT separator outlet pipeÑ hydrocarbon
Bisulfide corrosion due to water entrainment; near miss.
LPLT separator off gas piping
Impingement attack downstream of sulfur deposits.
Deposit buildup restricted flow and caused erosion-corrosion. Requires water carryover.
BB HCU Effluent piping upstream A/C
Under deposit attack.
Ammonium chloride. Corrosion around water injection point and downstream piping.
CC HCU Effluent piping from exchangers to separator
Bisulfide corrosion. 6% Ð 6.8 % bisulfide. Velocities up to 32 ft/s.
Extra heavy CS replaced every 8 years. Upgraded to Alloy 825 because of increasing N 2 in feed.
E HTU A/C piping Erosion-corrosion of outlet elbow resulting in fire.
Carbon steel piping. Inlet piping balanced; outlet piping unbalanced. Bisulfide < 8%. Velocities 9 ft/s Ð 26 ft/s.
Unit modified to include HTHP separator for process reasons. Failure occurred after 9 months. Failure occurred in outlet elbow after installation of HTHP separator. Reduced water wash, increased bisulfide, and unbalanced fan operation. Increased H2 .
U HTU A/C piping No corrosion. Currently carbon steelÑupgrading to Alloy 825. Unbalanced outlet piping. REAC inlet velocity 21 ft/s.
Planning addition of HPHT separator. Kp = 0.8. Alloy 825 piping from injection point to separator.
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20 API P
UBLICATION
932-A
Tabl
e10
—P
ipin
g E
xper
ienc
e fr
om S
urve
y
Pla
nt
Un
itIn
letÑ
(I)
Ou
tlet
Ñ(O
)O
rig
inal
M
ate
ria
lC
orr
osi
on
Rat
e (l
ife
)
Mat
eria
l U
pg
rad
e
(lif
e to
dat
e)B
alan
ced
Un
bal
ance
dS
ing
leM
ult
iple
Wat
er w
ash
rat
e (g
pm
)
HS
co
nce
ntr
atio
n
(%)
Vel
oci
ty
(ft/
s)
KpB
HC
UO
CS
50
mp
ya
groo
ving
none
XX
120
n.a
.25
0.1
2
QH
CU
IC
S;
adde
d 80
0 el
bow
sIn
hibi
ted
Allo
y 82
5X
low
43
OC
SIn
hibi
ted
Allo
y 82
5X
340
.04
CH
TUO
CS
; A
lloy
600
liner
No
corr
osio
nA
lloy
825
XN
one
(ori
gina
lly
12
gpm
)7%
Ð 1
0%
RH
CU
I C
S6
5 m
py
NH
4F
co
rro
sio
nW
eld
over
lay
Allo
y 62
5 ar
ound
inj
ectio
n p
oin
t
X15
6 gp
m4%
n.a
.
WH
CU
IC
ST
hinn
ingb
Line
d w
ith 3
21
SS
X
XA
djus
ted
12 g
pm Ð
32
gpm
8%<
20
> 0
.45
OC
ST
hinn
ingb
Wel
d ov
erla
y 30
9/18
-8
elbo
ws
X8%
< 2
0c
> 0
.45
W2
HC
UO
CS
Imp
ing
em
en
t co
rro
sio
nD
uple
x 22
05X
n.a
27
IH
CU
I &
OC
SN
o se
riou
s co
rro
sio
nN
on
eX
X60
gpm
4%0
.23
ZH
CU
I &
OA
lloy
825
No
ne
XX
n.a
n.a
n.a
AA
HTU
OC
SE
rosi
on-
corr
osio
n of
pi
ping
Allo
y 80
0 to
82
5 la
ter
due
to
PT
A c
rack
ing
XX
n.a
.14
% Ð
15%
18 Ð
34
EH
TUO
CS
Ero
sion
-co
rros
ion
of
elbo
ws
(fire
)
Allo
y 82
5X
170
gpm
(ta
rget
)6%
Ð 7
%9
Ð 26
n.a
.
UH
TUI
CS
No
corr
osio
nN
one
XX
16 g
pm4.
6% a
vera
ge21
0.4
Ð 1
OX
IH
CU
I &
OC
SN
o se
riou
s co
rro
sio
nN
on
eX
X60
gpm
4%0
.23
ZH
CU
I &
OA
lloy
825
No
ne
XX
n.a
n.a
n.a
AA
HTU
OC
SE
rosi
on-
corr
osio
n of
pi
ping
Allo
y 80
0 to
82
5 la
ter
due
to
PT
A c
rack
ing
XX
n.a
.14
% Ð
15%
18 Ð
34
EH
TUO
CS
Ero
sion
-co
rros
ion
of
elbo
ws
(fire
)
Allo
y 82
5X
170
gpm
(ta
rget
)6%
Ð 7
%9
Ð 26
n.a
.
UH
TUI
CS
No
corr
osio
nN
one
XX
16 g
pm4.
6% a
vera
ge21
0.4
Ð 1
OX
No
tes:
Wat
er in
ject
ion
po
int
c V
eloc
ities
> 2
0 ft
/s c
ause
d er
osio
n-co
rros
ion
requ
irin
g w
eld
over
lay
b A
dded
inhi
bitio
n af
ter
early
exp
erie
nce
a C
urre
nt m
easu
red
rate
Ñsu
spec
t ox
ygen
and
chl
orid
es
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
21
Tabl
e11
—W
ash
Wat
er D
etai
ls
So
urc
e o
f W
ash
Wat
er
Pla
nt
Ori
gin
al
Cap
acit
y (b
bls
/d)
Pre
sen
t C
apac
ity
(bb
ls/d
)S
team
C
on
den
sate
Str
ipp
ed
So
ur
Wat
er
Bo
ile
r F
eed
W
ater
Oxy
gen
(p
pb
)O
ther
Rat
e g
pm
(o
rig
ina
l)%
V
apo
riza
tio
n
gp
m P
er
Co
ole
r B
un
dle
Sin
gle
In
ject
ion
P
t.
Mu
ltip
le
Inje
ctio
n
Pts
.In
let
Pip
ing
Ou
tlet
P
ipin
g
B35
,000
5200
0X
X<
20
a,b
,c12
07
.5X
UU
Q2
2,0
00
40
,00
0X
Inh
ibite
d21
XU
U
OX
< 1
001
0 p
pm
Cl
6851
X
X<
100
< 5
0 p
pm
Cld
RX
< 1
005
0 p
pm
Cl
156
< 5
01
9.5
XU
U
X<
100
< 3
0 p
pm
Cld
CX
100
5 p
pm
Cl
3851
6 (
min
.)X
X0
80
pp
m C
l
W4
0,0
00
50
,00
0X
< 1
55
0 p
pm
Cl
12
Ð 3
225
XB
U
Xp
rese
nt
Fe
ad
just
ab
le
Inh
ibite
d
X10
%90
%33
0<
60
XB
B
I2
5,0
00
X60
10X
U
EE
45 T
DB
55 T
DB
Xde
-aer
ated
2766
XU
U
ZX
< 7
5X
UU
Y1
1,5
00
20%
24%
56%
10
0b
6 p
pm
Ð 1
0 p
pm
Cld
35<
75
XU
U
AA
45
,00
06
5,0
00
XX
50 p
pba,
bS
ign
ifica
nt
100
8.3
Xe
BB
CC
36
,00
0X
< 5
0 p
pm
Cl
105
n.a
.n
.an
.a.
E3
0,0
00
XX
low
20
pp
m Ð
50
pp
m C
l17
020
21X
BU
U1
4,0
00
XX
> 4
01
0 p
pm
Cld
16>
50
4X
BU
No
tes:
a R
ed
uce
d f
rom
1 p
pm
Ð 4
pp
mb
Use
an
oxy
ge
n s
cave
ng
er
an
d n
itro
ge
n b
lan
ket
c
Elim
ina
ted
pu
mp
se
al
lea
kag
ed T
race
NH
4H
Se
No
in
div
idu
al
flow
in
dic
ato
rs o
r m
on
itors
Ñu
nb
ala
nce
d w
ate
r d
istr
ibu
tion
W
ate
r lin
e p
lug
s fr
om
co
nta
min
ate
d p
roce
ss w
ate
r
B =
bal
ance
d
U =
unb
alan
ced
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22 API P
UBLICATION
932-A
800 elbows allowed the continued use of carbon steel pipinguntil the entire piping was replaced with Alloy 825. In anotherplant (Plant W), the piping was upgraded to 12 Cr.
Plant Q also reported that the inlet piping system wasunbalanced, the velocities were high (43 ft/s) and that thewater injection rate was too low. However, this was not thecase with Plant W where the piping was balanced and veloci-ties were under 20 ft/s. The amount of wash water appearedadequate and yet corrosion was severe.
5.4.2 Outlet Piping
Similar problems to those reported in the inlet piping werealso reported in the outlet piping and in some cases appearedin both locations. In the two systems discussed above, Q andW, the REAC tube bundles also corroded. This indicates thatthe corrosivity of the process fluid is sustained throughout thesystem and the corrosive is not necessarily depleted. It hasbeen reported that pipe thinning is localized and usually takesthe form of grooving. This is descriptive of a continuouschannel cut into the pipe wall following the liquid flow pathof the corrosive water phase. The groove may be at the bot-tom of the pipe but often follows a spiral, or swirl pattern.These patterns are seen going into vertical nozzles or emerg-ing from elbows on the horizontal pipe run. Grooving inelbows tends to follow the outer radius of the bend asexpected but can be offset and hence escape detection by spotultrasonic inspection.
The most prevalent problem in the outlet piping was ero-sion-corrosion in turbulent areas. This commonly occurs inelbows and in some cases protecting the elbows is sufficientto extend the life of the piping system. For example, Plant Qused three 800 elbows with carbon steel pipe runs until thecarbon steel life was exhausted and Alloy 825 was substitutedfor both components. Plant W utilized stainless steel weldoverlay on the elbows only, but their experience with respectto the carbon steel pipe is tempered by the use of inhibitor.Note also the experience of Plant C, where the lining wasextended downstream during successive turnarounds but fail-ure occurred in the last remaining segment of carbon steel,where the swirl pattern of attack was missed by pulse-echoultrasonic inspection. In another plant (Plant W2), impinge-ment attack of the air cooler outlet header piping resulted inperforation of the pipe and a fire ensued. In this case, the subheaders were connected to the headers by vertical nozzles,with no elbows such that the flow impinged directly on thehorizontal pipe under the nozzle. Severe metal loss occurreddirectly under the nozzle.
Unbalanced piping configurations have been implicatedwith piping system corrosion, as illustrated in the data plotsfrom the UOP survey. While it is logical to deduce that anunbalanced system will produce velocity differences in theheader system, and, therefore, some parts of the system maybe subjected to higher risk of erosion-corrosion, not all cases
clearly follow this pattern. For example, Plants I and U havenot experienced any significant corrosion. This is evidencethat velocity must be linked to other factors, such as the corro-sivity of the process, and is not a stand alone parameter. It isalso evident that compliance with the guidelines for linearvelocity does not ensure freedom from high localized turbu-lence or impingement and consequential damage (Plant W2).
It should also be noted that imbalance in the flow patternsthrough the headers may also be caused by differences in therate of cooling through the various cells of the REAC. Oneoperator reported an air cooler design where reduced coolingwas obtained by shutting down or reducing speed of the fanson the middle group of cells while maintaining higher fanspeeds on the outer cells. This clearly created a thermalimbalance over the REAC.
A number of different alloys have been used in pipingreplacements with varying degrees of success. Austeniticstainless steels apparently have satisfactory general corrosionresistance but are prone to pitting attack and stress corrosioncracking where significant chlorides are present. There is noclear definition of a limiting concentration of chlorides so thatmany operators are unwilling to take the risk and opt for thestress cracking resistance of other alloys.
Among those that have been used are Alloy 800, Alloy825, Alloy 625, Alloy 400 and duplex Alloy 2205. Untilrecently, Alloy 800 has been very popular, but several opera-tors have encountered polythionic acid stress corrosion crack-ing as a result of sensitization of the alloy during fieldwelding. Inadvertent use of Alloy 800H, a higher carbon ver-sion, has exacerbated the problem. Reports of pitting in Alloy800 REAC tubing have also dampened enthusiasm for thealloy in piping replacements. Current upgrades favor Alloy825, which so far has not experienced any of the problemsassociated with Alloy 800.
5.5 WATER WASH TECHNOLOGY
Table 11 is a compilation of all the data made availablethrough this survey on factors influencing the role of washwater in corrosion control. This does not address the eco-nomic issues nor does it discuss the various operational diffi-culties experienced with the injection systems including thespecific hardware requirements. The purpose is to provide abasis of comparison of the quantities and qualities of thewash water used in each of the various units.
There are three aspects to be considered:
1. A quantity of water sufficient to solubilize the salts anddilute the aqueous phase sufficiently that it is not overlyaggressive.
2. A quality of water that does not introduce contami-nants into the process stream that aggravate corrosion.
3. Adequate water/vapor contact at the point of injectionto ensure removal of acidic components from the vapor.
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
23
Discussion of the problem with the various respondentsindicated that process restraints and economics often dictatethe availability and quality of water and the freedom ofchoice is limited. Some uncertainty exists as to how to estab-lish the required amount and what level of contaminants areacceptable.
An early rule of thumb for determining the amount of washwater to be injected was 1 gallon per minute of water for every1000 barrels of feed processed. This survey did not find anyconsistency with this guideline. Injection rates from 1 gpm/1000 bbls – 6 gpm/1000 bbls were reported and it is possiblethat other rules have been used. (See Turner [Reference 8].)The amount provided to each air cooler bundle varied from 4gpm – 21 gpm. It is likely that operators adjust the rates untileach finds a rate that is economical and provides satisfactoryresults. This trial and error approach has been costly in somecases where severe corrosion has been attributed to insuffi-cient wash water. Several respondents claimed improved cor-rosion performance after the wash water had been increased.Examination of the data in Table 11 shows a wide variation inthe amount of wash water relative to the capacity of the unit.For example, for Plant Q, based on a unit capacity of 22,000bbls/d, a water injection rate of 22 gpm would be required bythe above rule. The reported amount of 21 gpm is, therefore,consistent with the rule. However, for Plant B the amount ofwater per 1000 bbls/d is almost four times higher than the rulerequires and yet this unit experienced severe corrosion of car-bon steel REAC tubes and Alloy 800 tubes were substituted.
According to this survey, there is no consensus withrespect to wash water requirements, either as total quantityinjected or the amount distributed to each air cooler bundle.This may in part be due to the variations in nitrogen contentof the feed from unit to unit as discussed later. The surveyshows, however, that all operators introduce enough waterthat at least 25% remains unvaporized after flashing.
Another issue with respect to water injection is single-ver-sus-multiple injection points. With single injection points, anumber of operators have experienced localized corrosion atthe injection point. This has been successfully countered bythe use of alloy protection of the pipe in the vicinity of thewater entry and atomization of the spray to prevent impinge-ment attack and increase scrubbing efficiency. Static in-linemixers are sometimes used to give good water/vapor contact(scrubbing) after the injection point.
Multiple injection points are useful when the inlet headersystem is unbalanced. This design ensures that the water isevenly distributed to each cell in the REACs provided the sys-tem is properly monitored and maintained. Water is injectedjust ahead of the air cooler bundles, usually in the inlet noz-zles. Each injection point requires a flow monitoring deviceand a flow controller, usually a manually operated valve. Astrainer is often used in the water supply piping to preventinjector plugging. The proper flow of water to each pointmust be checked daily to prevent a potential buildup of
deposits. The best systems employ a control house indicatoron the process control board.
All the surveyed units with single injection points andunbalanced inlet piping experienced severe corrosion of theREACs. On the other hand, two units with balanced pipingsystems have not experienced corrosion even with single injec-tion points. There is no clear improvement from using multipleinjection points. Severe corrosion has been reported in unitswith both balanced and unbalanced inlet and outlet piping.
It was desired to include in Table 11 a measure of theseverity of corrosion for each of the units so that the influenceof the wash water conditions on corrosion might be assessed.Unfortunately, a suitable system for conveniently expressingthe corrosion experience for each unit as a simple index wasnot realized.
5.6 WATER SOURCES
Several sources of water are used and, depending on avail-ability, are used separately or mixed. These are boiler feedwater, steam condensate, the stripped bottoms from a sourwater stripper and recycle sour water from the downstreamcold separator. Each of these sources varies in purity and maycontain one or several of the following contaminants; oxygen,carbon dioxide, ammonia, chlorides, cyanides and iron.Boiler feed water is a very good source of water since it hasbeen de-oxygenated but may still contain chlorides. Steamcondensate is most likely to contain oxygen and carbon diox-ide and for this reason should be degassed and de-oxygenatedand stored under a nitrogen blanket before introducing intothe process. Not all respondents admitted to using these pro-cedures. Stripped sour water may contain all of the abovelisted contaminants in varying degrees and is often the pri-mary source of wash water with steam condensate or boilerfeed water being used as back up.
Although the role of oxygen in the corrosion process hasnot been clearly resolved, most operators take steps to mini-mize the amount of oxygen introduced with the wash water.Most units target the oxygen level at 100 ppb maximum but anumber try to maintain oxygen between 20 ppb – 50 ppb. Inone unit where corrosion inhibition is used, an oxygen levelof 330 ppb was tolerated. One operator reported that oxygenwas being admitted to the process from air drawn into leakingpump seals. The seals were, therefore, boxed in and an oxy-gen free purge provided.
Because cyanides, when present, are below the limits ofdetection, none of the operators consider them a controllablefactor and have no knowledge whether or not they are harmful.
5.7 INSPECTION
The importance of proper inspection of these units islinked to the inconsistent nature of the corrosion experience.The corrosion experience in REAC systems is usually unpre-dictable and often highly localized. This means that the num-
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24 API P
UBLICATION
932-A
ber of thickness measurement locations (TMLs) must begreater than for a system where the corrosion is more generaland predictable. The two types of equipment of prime inter-est—air coolers and the associated piping—both have theirown particular set of difficulties with respect to inspection.
The purpose of the survey was to determine the extentand frequency of inspections used by the individual opera-tors interviewed. At the same time, the inspection method-ology was explored to detect any correlation between thequality of inspection and the unit performance from amaterials standpoint.
The information gathered with respect to inspection proce-dures and frequencies is summarized in Table 12. It is appar-ent from the interviews that an internal rotating inspectionsystem (IRIS) is preferred by operators for inspection of aircooler tubing. This consists of traversing the bore of eachtube with a special probe that measures the wall thicknessultrasonically. The method requires the unit to be shut downand the tube surfaces to be well cleaned, usually by high pres-sure water jetting. The inspection frequency depends on theturnaround interval for the unit and in most cases a 2- to 3-year interval is used. The maximum interval between inspec-tions is 5 years. One operator had access to his unit every yearand conducted tube inspections annually.
Piping is especially difficult to inspect because of theextensive surface area that is often difficult to access. The his-
tory of erratic flow patterns in the form of spiraling groovesintroduces a problem of ensuring adequate coverage byselecting a sufficient number of TMLs. Random-spot UT isclearly unreliable and continuous scan techniques are pre-ferred. There is a considerable effort required to conduct100% scans of all the piping. Most operators conduct pipinginspections on a 2
1
/
2-
to 3-year interval but more frequentinspections (6 – 12 months) may be carried out at water injec-tion points or other known problem areas. The relatively lowprocess temperatures allow on-line inspection of piping butnot air coolers. Where experience justifies it, the inspectionperiod can be extended to 5-year intervals. Several plantswith little or no corrosion are able to do this.
Ultrasonic inspection is most frequently used, but manyplants employ radiography to look for localized corrosion orspiral grooving that may have been missed by close intervalUT. Radiography has also been used on fittings, especiallyelbows, to detect localized corrosion. Radiography of largediameter thick wall piping requires a cobalt source whichresults in a grainy image and less reliable interpretation.
Inspection intervals are set by annual turnaround schedulesand the thoroughness of inspection during the turnaround is afunction of available manpower and time restraints. Severalrespondents indicated that upgrading to alloy extended theinspection interval for the items where alloy was employed.
Table 12—Inspection Summary
Plant Equipment Item Inspection Interval (years)
Type of Inspection Operating Factor
B, Q Piping 2.5 (5 max.) UT 98%one time only RT
A/C tubes 2.5 (5 max.) IRIS, RFECR, O, C Wash water injection point 3 UT/B-scan
HP separator; LP separator 3 Ð 6 WFMPT, T-scanA/C tubes 3 Ð 6 IRIS
Piping 3 UT, RT6 B-scan
W All 2A/C tubes 100% IRIS
Piping ells; headers 1 close interval UTX Air coolers 5
Piping 3 Ð 5Y Air coolers 2 100% IRIS
Piping 2 UTWash water injection point 2 RT
CC All 2.5 91%AA, BB All 3 UT, RT
Selected items 0.5 Ð 1 100% B-scan, RTU A/C tubes 1 VT, UT (IRIS)
Feed/effluent exchangers 5 VT, UTSeparators 5 VT, UT, WFMPT
E All 4 VT, UT, RTVessels API 510Piping 1 API 570
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A S
TUDY
OF
C
ORROSION
IN
H
YDROPROCESS
R
EACTOR
E
FFLUENT
A
IR
C
OOLER
S
YSTEMS
25
Wherever possible, on-line inspection should be employedto provide closer monitoring of potential problem areas.Operators have reported avoiding serious consequences byfinding a problem area before a leak occurred. It is expectedthat hydroprocess units will receive a high priority from riskbased inspection planning. These survey results show thatthere is a relatively low incidence of failure but a very seriousconsequence when failure occurs.
5.8 CORROSION
It is generally recognized that corrosion in hydroprocess-ing REAC systems can occur at any place between the pointof water injection and the point of water separation. However,this survey also reveals that carryover and entrainment ofwater in the hydrocarbon streams beyond the separators hasbeen a persistent and worrisome problem for some operators.Corrosion has also occurred in bypass piping (deadlegs)around feed/effluent exchangers when the piping is config-ured such that deposited salts can accumulate and becomecorrosive in the presence of water.
The general locations where the survey showed most oper-ators to have experienced problems have been summarized inTable 13. The list of locations is familiar and has been wellcovered in previous surveys. Table 13 shows that most of theunits surveyed have experienced either REAC or piping cor-rosion in their early history. Also listed in Table 13 are thetypes of attack associated with the corrosion experience.These fall into three categories, salt deposit attack, aqueoussalt corrosion and velocity influenced corrosion. These prob-lems have been countered by either carefully implementedprocess controls or by the use of corrosion resistant alloys.
The primary corrosive in the majority of cases was believedby respondents to be ammonium bisulfide, and the severity ofattack dependent on concentration and velocity. However, it isbelieved that oxygen can be an accelerant of the corrosionprocess and is an undesirable component. The majority ofoperators take care to minimize or control the amount ofoxygen entering the system. One unit reported improvement intheir corrosion experience when the oxygen in the water washwas reduced from 1 ppm – 4 ppm to 50 ppb. Some operatorsbelieve that oxygen should be kept below 50 ppb, or even aslow as 20 ppb, in the water injected into the system. There arehowever many units that allow up to 100 ppb oxygen. It isinteresting to note that some of the units that have a relativelybenign corrosion history take no special steps to minimizeoxygen. The role of oxygen and other oxidants in the corrosionprocess is not clearly understood by the corrosion communitybut the effort to control them to low levels appears to bejustified by the experiences reported. Plants that employdeaerated steam condensate, for example (EE) and (I), havereported a relatively good corrosion performance (see Table 7).Plant B maintains low oxygen and was able to use carbon steelREAC outlet piping for 24 years. During a period when the
oxygen levels were higher than usual, corrosion rates of 50mpy on the CS pipe were experienced.
The potential harm of chlorides was recognized in two ways:1. Deposition of ammonium chloride in the effluent cool-ing train with serious corrosion consequences, (see PlantsC, O and R, Table 7); and2. Potential effects on alloy materials performance suchas pitting and stress corrosion cracking (see Plants Q, W,BB and E).
One operator believed that chlorides were always involvedwith bisulfide corrosion and had evidence of a differencebetween 1 ppm and 5 ppm on the severity of attack. Chloridesenter the system with the feed, from the reactor catalyst, withmake-up hydrogen, especially if unscrubbed reformer gas isused, and with the wash water. One or two plants do not havea crude desalter so that the chloride levels are inherently high.Steps to control the ingress of chlorides from all sourcesseems prudent. Unfortunately, insufficient data was availablefrom this survey to correlate any distinctive influence of chlo-rides on the severity of corrosion experienced by any particu-lar unit other than clear cases of NH
4
Cl deposition.The survey was unable to determine the importance of cya-
nides in the corrosion process. Most units reported undetect-able levels of cyanides and, therefore, were unable to determinewhether or not the minute quantities present had any effect ornot; however, the presence of cyanides was reported by severalrespondents who either observed the Prussian blue color of cor-rosion deposits on piping or found it by analysis of the depos-its. One operator reported no apparent problems with cyanidesin the REAC system but a very definite influence on corrosionof a downstream coker unit.
5.9 ALLOY SUBSTITUTION TO PREVENT CORROSION
The alloy solution is costly. A recent study
10
concluded thatto upgrade REAC exchanger and piping materials from carbonsteel to Alloy 825 would cost $1 million for a hydrocrackerunit with 6,160 ft
2
of air cooler surface. Alternative solutions,however, carry more risk. This is because the parametersaffecting corrosion are not quantitatively well defined andthere often is great difficulty predicting the sites where theprocess parameters may fall outside of the guidelines.
Some of the alternative materials selections to replace orupgrade from carbon steel have been discussed by Singh etal.
11
,
and Shargay and Lewis
12
. A few additional items have
10
C. A. Shargay and K. R. Lewis, “Cost Comparison of MaterialsOptions for Hydroprocessing Effluent Equipment and Piping,”NACE, Corrosion 96, Paper 600.
11
A. Singh, C. Harvey and R. L. Piehl, “Corrosion of Reactor Efflu-ent Air Coolers,” Paper 490, Corrosion 97.
12
C. A. Shargay and K. R. Lewis, “Cost Comparison of MaterialsOptions for Hydroprocessing Effluent Equipment and Piping,”NACE, Corrosion 96, Paper 600.
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been picked up by this survey. Austenitic stainless steels areavoided by most operators because of the potential for stresscorrosion cracking and pitting corrosion. Some units usethem in the form of linings for pipe or as weld overlay wherethe integrity of the pressure boundary is less threatened andthe risk of catastrophic failure is greatly reduced. Experiencewith pitting of Alloy 800 tubes and polythionic acid cracking
of Alloy 800 piping has introduced concerns about the use ofthis alloy. There is a preference for using Alloy 825, whichhas a higher alloy content and stabilizing elements to combatboth these modes of attack.
Another approach to avoiding these problems was toemploy duplex alloys which have inherent resistance to bothphenomena. 3RE60 has been used successfully (Plant CC)
Table 13—Corrosion Experience
Corrosion Description Plants Matching DescriptionAir cooler tube thinning from bisulfide corrosion Underdeposit attack B, R Flow corrosion C, Z Inlet end erosion-corrosion Y Outlet end erosion-corrosion W, Y Other Q, R Reasons Insufficient wash water B,R High bisulfide concentration at separator C, Z Too high velocity C, W, Y Unbalanced header system Z,R Ammonium fluoride RWater injection point corrosion R, Y No with alloy protection C, RAir cooler inlet piping corrosion Q, R, W, BB Elbows Q Headers W, Y Header boxes Y Reasons Insufficient wash water R, W, Y High bisulfide concentration at separator Too high velocity Q, W, Y Suspect O2 and Cl R, BBAir cooler outlet piping corrosion Q, C Thinning B, C, W, CC, AA Headers Y Header boxes Y Elbows C, AA, E Dead leg C, O Reasons Insufficient wash water Y, AA, E High bisulfide concentration at separator AA, C Too high velocity Q, W, Y, AA, CC Unbalanced header system W, Y Suspect Cl and O2 B, WFeed/effluent exchanger corrosion Bisulfide corrosion B, Q, CC Suspect O2 B Chlorides O, AA, E, BB Insufficient wash water O, AATrim cooler corrosion Bisulfide corrosion B, Q U-bend corrosion B Reasons Insufficient wash water High bisulfide concentration at separator Too high velocity Unbalanced header system Suspect O2 QDownstream of separator C, Y, AA High bisulfide C, AA High velocity C, Y, R O2
By-pass dead legs AA
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A S
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downstream of the water injection point for more than 18years with no plans to replace it. Alloy 2205 has been used forboth air cooler tubes and piping with varying success. Prob-lems can arise if the material is not properly specified andfabricated
13
. High residual hardness after welding can lead tosulfide stress cracking and must be avoided. In addition onerespondent reported selective leaching of the ferrite phase byammonium chloride.
Alloy 400 has been used successfully for tubes in watercooled exchangers for more than 20 years but this survey didnot reveal any air cooler applications.
5.10 INHIBITION
Only two units surveyed used chemical inhibition to con-trol corrosion. One unit employs a filming amine type ofinhibitor and the other uses a proprietary chemical. Bothunits, however, continue to exercise control over some of thecritical parameters such as bisulfide concentrations, velocitiesand contaminants. It appears that the application of the inhib-itors does permit the use of carbon steel where it might other-wise have to be substituted. The decision to use an inhibitoris, therefore, an economic choice versus an alloy upgrade.
6 Discussion and Analysis of Survey Responses
The following section is an interpretation of the informa-tion supplied by the respondents from a more generalizedviewpoint. These interpretations include ideas and opinionsexpressed by the engineers interviewed that were not neces-sarily substantiated with actual scientific or engineering data.
6.1 GENERAL EQUIPMENT CONSIDERATIONS
This study has been broadly directed at hydroprocess reac-tor effluent streams. This includes the products of reactionfrom both hydrotreating and hydrocracking processes. Withinthose processes are differences in the equipment arrange-ments that affect where corrosion might most be expected.Hydrocracking may involve two stages of catalytic reactions,the first is essentially a hydrotreating step in which sulfur,nitrogen and chloride contaminants are converted to H
2
S,NH
3
and HCl respectively. These corrosive compounds arenormally removed before the hydrocarbon stream enters thesecond stage so that the second stage effluent would beexpected to be less aggressive than the first stage effluent.This does not preclude the requirement for alloy in these sys-tems, as reported for Plant CC.
Downstream of the reactor there are two flow schemes thatinfluence the amount of equipment to be protected and the
wash water flow scheme. In one scheme, the total reactoreffluent is sent to a single bank of air coolers and the to a highpressure low temperature (HPLT) separator. In the secondscheme, a high pressure high temperature (HPHT) separatoris employed and only its vapor stream is water washed. TheHPHT separator liquid hydrocarbon is unwashed and carriesdissolved H
2
S, NH
3
and HCl to the downstream productstripper tower. This can result in corrosion problems in thestripper.
Clearly, each of the above process schemes has economictrade-offs, which also include the number of equipment itemsto be monitored and inspected, the amount of alloy employed,and the distribution of wash water. The corrosion processesare the same since the reactants are unchanged but the sever-ity may be affected by the distribution in terms of concentra-tions and flows.
Many operators have reported problems in equipmentdownstream of the separators. This includes the separatorvessels, piping and strippers. These items have experiencedvarious modes of attack from general bisulfide and chloridepromoted corrosion to hydrogen related cracking. It is beyondthe scope of this study to detail these incidences but the expe-rience serves to emphasize the aggressive nature of aqueoussolutions of the ammonium salts wherever they occur. Opera-tors should be aware that poor separation or entrainment ofthe aqueous phase can result in the same problems that haveplagued REAC systems. The penalty for allowing the aque-ous phase to carry through the separators is increased corro-sion requiring an increased scope of inspection andmaintenance activities.
6.2 NITROGEN CONTENT OF THE FEED
A number of respondents have reported observing anincrease in corrosion severity when the nitrogen content ofthe feed has been increased, or the throughput increased forthe same size equipment. The relationship between nitrogenin the feedstock and the severity of corrosion is simply thatincreased nitrogen will increase the amount of ammonia afterhydrogenation and since the number of moles of bisulfide isessentially equal to number of moles of ammonia, this willresult in an increase in bisulfide. The bisulfide content inmols/hr is determined by the difference between the lbs/hrnitrogen in the feed and the lbs/hr nitrogen in the productdivided by the molecular weight of 14. To determine thebisulfide concentration in condensed water, the followingrelationships are used;
For wt% H
2
S < 2
×
wt% NH
3
, then wt% NH
4
HS = 1.5
×
wt% H
2
S
For wt% H
2
S > 2
×
wt% NH
3
, then wt% NH
4
HS = 3
×
wt% NH
3
.
The amount of ammonia produced for any given amount ofnitrogen in the feed is a function of both the process and the
13
A. K. Singh, R. J. Gaugler and A. J. Bagdasarian, “Duplex Stain-less Steel in Refinery Hydroprocessing Units, Success and FailureStories,” “Proceedings of 4th International Conference on DuplexStainless Steels,” Paper no.16, Glasgow, Scotland, Nov. 1994.
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efficiency of conversion within the process. In the first case,for example, naphtha hydrotreaters are usually low in nitro-gen and may not require continuous water wash, whereas die-sel hydrotreaters will require a water wash. In addition, thecatalytic efficiency of the process will vary from unit to unitfor the same amount of nitrogen. Some units process feed-stocks with varying nitrogen contents, resulting in fluctuatingammonia concentrations in the reactor effluent. Add to thatthe changes in catalyst activity during its normal cycle and itis clear that ammonia contents of the effluent may vary con-siderably over a period of time. This in turn influences theamount of wash water needed at any one time. It is for thisreason that some operators use adjustable wash water ratesthat are determined by the amount of nitrogen in the feed.
Superficially, the data from this survey appear to indicatethat units that experience severe corrosion are dealing withnitrogen contents in the feed of 1200 ppm or greater, andthose units not experiencing significant corrosion have feed-stocks of less than 600 ppm nitrogen. However, from the fore-going it is clear that such inferences can be grosslyinaccurate.
Careful examination of the UOP survey data showed anon-linear relationship between the nitrogen in the feed andthe ammonia in the air cooler inlet gas. The amount of ammo-nia increased with the increase in nitrogen level as expected.However, the ammonia contents reported for a given nitrogenlevel covered a range of values. Consequently, with such ascatter of data, the correlation between the ammonia contentand the severity of corrosion is weak and at best indicates atrend rather than a specific relationship.
Note: Both parameters in this relationship are variable. This is analo-gous to the relationship between
K
p
factor and corrosion severity.Therefore it appears that the use of nitrogen content as a guide topotential corrosion severity is no more reliable than the
K
p
factor.
Although the severity of corrosion due to increased quan-tity of nitrogen in the feedstock is not predictable, the experi-ence shows a trend towards increased problems. The practiceof changing feed stocks or increasing unit throughput withoutregard for the corrosion consequences has penalized someoperators.
6.3 SALT DEPOSITION AND TEMPERATURE
Corrosion can be caused by deposition of either ammo-nium chlorides or ammonium bisulfides or both (excludingplants where fluorides may be present). The deposition tem-peratures of the two salts are considerably different. Ammo-nium chloride usually deposits at 350°F – 400°F, whereasbisulfides deposit in the range of 80°F – 150°F. Depositiontemperatures increase with the amount of chloride or nitrogenin the feed. The prediction of the precise deposition tempera-tures for any particular set of process conditions has beenstudied extensively. Yiing-Mei Wu
14
has used a thermody-namic approach to predict the temperature at which saltdeposits, the kind of salt that deposits and an approximation
of the amount. Turner
15
and others
16
make use of depositioncharts to predict salt crystallization temperatures.
The temperature at the point of water injection is anothercritical process parameter. When the unit is being designed tomeet a 25% unvaporized water criterion, the amount of washwater can vary by 1.5 – 2.5 times for a 100°F difference. Thisis directly tied to heat exchanger design and performance.
It is clear that there is an important relationship betweenprocess design and operation and control of corrosion. Theinformation needed to provide the best system of corrosioncontrol requires computational understanding and skills nor-mally out of the range of traditional metallurgists and corro-sion engineers. Few respondents to this survey volunteered anunderstanding of the process aspects in this area, althoughseveral indicated awareness of the influence of the processconditions on the corrosion performance of their units.
6.4 MANAGEMENT OF CORROSION
Successful management of corrosion in these units requiresintegrated team effort involving process, mechanical, inspec-tion and corrosion engineers. This is not only for design orexpansion but for day-to-day operating decisions. As dis-cussed below, the effect of the process conditions on washwater management is an important aspect of corrosion con-trol; in addition, a joint effort is needed to resolve the effec-tiveness of changes in ammonia levels and bulk fluid flowvelocities. Some units have been successful in persuadingtheir management to recognize the importance of observingthe process parameter guidelines and keeping the corrosionengineer informed of any changes in operating conditionsthat could affect those parameters. The advent of federalrequirements for process safety management has introducedprocedures that several respondents rely on, namely the man-agement of change. This requires that when a process changeis introduced, all affected disciplines are notified and aregiven the opportunity to discuss the consequences and to pro-pose any necessary remedial action.
6.5 FACTORS INFLUENCING CORROSION
The key factors influencing corrosion in REAC systems areunanimously recognized as bisulfide concentration and veloc-ity. It is also realized that these two parameters interact in theeffect on corrosion severity.
A widely observed influence of velocity has been thesevere, localized metal loss experienced at changes of flowdirection, such as in piping elbows, the u-bends on exchangertubes, or the spiral gouging that occurs in straight piping. It is
14
Y. M. Wu, “Calculations Estimate Process Stream Depositions,”
Oil & Gas Journal
, January 1994, p. 38.
15
J. Turner, “Design of Hydroprocessing Effluent Water Wash Sys-tems,” Paper 593, Corrosion 98.
16
E. F. Ehmke, “Corrosion Correlations with Ammonia and Hydro-gen Sulfide in Air Coolers,”
Materials Performance
, July 1975.
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this writer’s opinion that the mechanism is more properlydescribed as erosion-corrosion. The difference between ero-sion-corrosion and mechanical erosion is that in the first eventit is the susceptibility of the corrosion product film tomechanical disruption that is the controlling factor. In thecase of mechanical erosion, both the corrosion product filmand the underlying metal are removed mechanically. In ero-sion-corrosion, the accelerated loss of metal is caused by highcorrosion rates of the metal surface by constant removal ofthe partially protective corrosion product film as it is formedand re-formed. The importance of this distinction is that it isthe quality of the corrosion product film that is most influen-tial in the resistance of the material to the effect of velocity.Thus, factors that affect the chemical and mechanical proper-ties of the corrosion product film may have a significant effecton its ability to resist breakdown caused by increased veloc-ity. It is for this reason that the presence of contaminants isimportant where they are perceived to affect the protective-ness of the surface film. It is beyond the scope of this study topursue this complex subject further.
Discussion of this subject with corrosion engineers indi-cated that the effects of contaminants, such as oxygen, chlo-rides and cyanides, on the corrosion film properties were notsufficiently understood to allow customized control of theoutcome. However, through empirical experience, many engi-neers have strong convictions regarding the influence ofsome, if not all the contaminants, and use their own guide-lines based on their experience. This study could haverevealed some consistent correlation between differences incontaminant levels and the severity of corrosion experienced.The variability of the aggressiveness from unit to unit and thelack of precision in the measurement of the contaminantsmade this an extremely difficult task.
6.6 CORROSION CONTROL
The history of corrosion in REAC systems has been a suc-cession of surprise events. Among the first problems encoun-tered were tube end erosion-corrosion and tube thinning inthe air coolers. This was followed by corrosion of the REACinlet piping and subsequently outlet piping. These problemslacked universal consistency. Some units had problems, andthe location of each problem varied. Differences in bisulfideconcentration and velocity accounted for much of the vari-ability and the broad guidelines developed encompassedmany of the variations. Problems persist because the condi-tions at the locations where corrosion occurs cannot beobserved and monitored and are difficult to forecast. Oneexample is plugging occurs in air cooler tubes, causingincreased flow and subsequent attack on unplugged tubes.Monitoring such an event requires frequent on-line inspec-tion, which is costly and runs the risk of being unsuccessful.In addition to limits on bisulfide concentration and velocity,the crux of corrosion control has been to make the system as
balanced as possible with respect to stream compositions andflow distribution. Thus, balanced flow paths into, through andout of the air coolers, sufficient quantity and uniform distribu-tion of the wash water have been an essential part of the cor-rosion control strategy.
6.7 WATER WASHING
Water washing is an essential control measure but requiressufficient water to be effective. It is important that water beintroduced into the system in such a way that it does not cre-ate additional problems. Liquid water must be available at alllocations where salts condense from the effluent stream insufficient quantity, to dissolve the solids and move themthrough the system. A sufficient quantity of water is needed tomaintain a mildly corrosive solution throughout its passage tothe separators. This survey did not find any consistency in theamount of water used by the various units, some units usingas much as six times as much as others in proportion to thefeed rate.
A detailed discussion of the subject has been presented byJ. Turner
17
, who indicated two guidelines that are commonlyused for determining the amount of wash water to be injected.
1. The maximum bisulfide concentration in the cold sepa-rator, and
2. The amount of washwater required to ensure that 25%water remains in the aqueous phase at the point ofinjection.
The two guidelines differ greatly in their influence on thedesign requirements to achieve each goal. The amount ofammonia that goes into solution at the point of injection is afunction of temperature, and it is assumed that almost totalsolubility is achieved below 150°F – 200°F. The concentra-tion of the bisulfide solution depends then on the ammoniaproduced by de-nitrification. Simulation analyses have shownthat the bisulfide concentration at the point of injection is lessthan in the downstream separator water. It is likely that corro-sion will be worse downstream of the air coolers and bisulfideconcentrations will be higher. In this case, it does not seem asimportant to maintain 25% unvaporized at the point of injec-tion. There is in fact an advantage to distributing the water asvapor rather than liquid to the point of condensation withinthe air cooler tubes. Insufficient water, however, could pro-duce high concentrations of salts at the point of condensationdownstream, especially chlorides. For this reason, it is pru-dent to maintain a minimum of 25% unvaporized water, aspracticed unanimously by the respondents to this survey.
The actual amount of water required for any particular unitis not, therefore, a matter of simple rules of thumb butrequires a careful assessment of the process parameters. It
17
J. Turner, “Design of Hydroprocessing Effluent Water Wash Sys-tems,” Paper 593, Corrosion 98.
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requires knowing the chemical equilibria and the temperatureat the wash water injection point.
The water quality is also important. The contaminants intro-duced with the wash water should not have any significantcontribution to downstream corrosion. A few of the respon-dents mentioned control of iron entering the system with washwater. Insoluble sulfides will quickly form from any iron ionsentering these sour water systems and will lead to deposits.For example, 50 gpm of wash water containing 1 ppm iron candeposit as much as 300 lbs iron sulfide per year in the system.
In an effort to obtain good distribution of the wash water,there has been a progression of improvements in the injectiondevices starting with an open tee, to quills and spray nozzleswith downstream inline mixers. Experience with these differ-ent devices has varied from unit to unit. The use of single ver-sus multiple injection points is controversial. To improveuniformity of distribution through the air coolers, many oper-ators use multiple injection points. This has not worked infal-libly and corrosion of tubes has been experienced in spite ofmultiple injections showing that corrosion may not depend onwash water distribution alone, assuming each injection pointis working properly.
6.8 CORROSION ASSESSMENT
A major difficulty in assessing the performance of individ-ual process units is the problem of quantifying corrosionexperience. A unit that performs generally well can suffer alocal failure that is disastrous. This unit is then classified as a“serious” corrosion case and the process and engineeringparameters used for comparison with “moderate” or “mild”cases. Attempts to correlate individual process parameterswith severity of corrosion are inherently flawed by the inclu-sion of extreme behavior for the stated process conditions,whereas the conditions at the point of failure are probablyquite different. Plotting corrosion severity against anothergeneral parameter, such as
K
p
factor or nitrogen content in thefeed, only compounds the error and the resulting plots areextremely scattered.
The precise conditions prevailing at the location of corro-sion may be difficult, if not impossible, to quantify and con-trol. The options available to rectify the problem ofteninclude a lesser but continued risk. The distinct trend towardsuse of expensive alloys to replace carbon steel probablyreflects the desire to minimize the risk. There are definitetrends toward the use of higher alloys such as 2205, 800 and825 for air coolers and related piping especially for replace-ments and expansions. At the same time, alloy substitutionallows more process flexibility, including higher nitrogenfeedstocks and higher conversion efficiencies, reducedinspection and reduced maintenance. As an example, unitsthat employ carbon steel air cooler tubes strive to maintain4% – 8% bisulfide in the separator water but allow increasing
amounts of bisulfide depending on the alloy used. Typically,for 8% – 15% bisulfide, Alloy 800 would be employed.
6.9 FLOW EFFECTS
Velocity limits also depend on the alloy being used. Withcarbon steel tubes an upper velocity limit of 20 ft/s is generallyobserved, whereas with alloy tubes, higher velocities are per-mitted. For example, velocities up to 40 ft/s have been usedwith Alloy 800 tubes. Another aspect of flow through the sys-tem is the importance of maintaining high enough velocities tominimize phase separation between the vapor, water andhydrocarbon phases. The importance of flow regime has beendiscussed by Ehmke
18
, whose experience indicated that leastcorrosion was experienced in a stratified or annular flow pat-tern where the liquid was in laminar flow at the wall. Thepresent survey showed that most operators try to maintainannular flow in the air cooler tubes to avoid possible problems.
7 ConclusionsThe cause of corrosion in reactor effluent air cooler systems
is reasonably well understood and has been attributed to theformation of ammonium chloride and ammonium bisulfidesalts. To prevent plugging of the flow paths by condensed soliddeposits, water is injected into the process to solubilize thesalts. The aqueous solutions thus formed may be extremelyaggressive to carbon steel and even cause problems for somealloys. Experience has shown that the problem can be con-trolled by strict limitations on aqueous salt concentration andvelocity. This simple strategy, however, is complicated bynumerous factors such as the even distribution of flow throughthe equipment and the complexity of controlling the flow pat-terns to avoid high velocity turbulent conditions. Maintaininguniform concentration of the salt solutions throughout theequipment by avoiding deposit build-ups or evaporative condi-tions is another complication. The corrosion history of theseunits has been characterized by highly localized failures.Severe thinning has occurred over relatively small areas wherelocal conditions have been very aggressive. This has made thetask of inspection of the equipment more difficult. The inspec-tion intervals have been shortened and the coverage increased.But in spite of this, serious failures have occurred.
The extent to which these factors can be manipulated forthe best control is often dictated by economic considerations.There is evidence that a hydraulically balanced piping systemaround the air coolers alleviates corrosion in some but not allsystems. For that reason, there has been a trend toward theuse of Alloy 825 for air cooler tubes and related air coolerpiping. This alloy has been used successfully under some pro-cess conditions for up to 15 years with no adverse experience.Currently, users allow up to 40 ft/s velocity. There is no
18E. F. Ehmke, “Corrosion Correlations with Ammonia and Hydro-gen Sulfide in Air Coolers,” Materials Performance, July 1975.
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A STUDY OF CORROSION IN HYDROPROCESS REACTOR EFFLUENT AIR COOLER SYSTEMS 31
known limit with respect to bisulfide concentrations, but labo-ratory research has indicated low corrosion up to 45% bisul-fide under very low flow conditions. No pitting corrosion orcracking problems have been reported. The prospects of pro-viding trouble-free equipment with minimal risk of a cata-strophic failure, that allows flexibility in operating conditions,is to some companies worth the considerable investment.
The design and control of the water wash addition to theprocess is one of the most critical factors in controlling thecorrosion problem, especially with carbon steel equipment.The proper amount of water needed to keep the systemflushed of salt deposits and to control its distribution throughsplit flow paths to ensure uniform washing of all the equip-ment. The water quality is also important and is suspected toaffect details of the corrosion process such that the corrosionproduct films can vary in their degree of protectiveness. Thisin turn affects the tolerance to bisulfide concentration andvelocity. For this reason, care is exercised by limiting oxygenand chloride contents of the wash water, though the maxi-mum permissible levels of both these elements are notknown. Other contaminants, such as mineral salts and heavymetal ions, can cause plugging problems in the water systemand contribute to fouling in the process equipment.
The most critical task is to determine the amount of waterneeded at the point of injection. One criterion is to maintain atleast 25% water in the liquid state after injection. The amount ofvaporization is a function of the temperature and pressure. Theamount of water injected also depends on the ammonia concen-tration which is a function of the nitrogen content of the feedand the efficiency of de-nitrification. The amount of ammoniathat goes into solution depends on the temperature at the washwater injection point and may be calculated using thermody-namic modelling. Many operators base the quantity of injectionwater on the concentration of bisulfide in the low pressure sepa-rator. Typically, they try to maintain a level of 4% – 8% bisulfidein the sour water. This apparently has been a successful strategyfor those who use it according to the reported performance oftheir units. It is not clear whether the target concentration isachieved simply by adjusting the water addition or whether themore sophisticated analyses just discussed are employed. It isrecommended that a proper process evaluation be used, takinginto account conditions at the point of water injection to main-tain 25% unvaporized water, as well as the bisulfide concentra-tion at the separator.
It is clear that chemical engineering techniques are neededto determine the water wash requirements and also to predictthe deposition temperature of the ammonia salts and theamount of salt depositing. These factors bring into play theheat balance of the process and affect equipment perfor-mance. This is especially true during the design of the unit butshould also apply to any process changes that are subse-quently made. For this reason, cost-effective corrosion con-
trol of these units requires a continuous team effort byoperating engineers and those responsible for corrosion per-formance, to monitor and control the process parameters andto implement effective change management procedures whensignificant adjustments are made.
8 Future Research
The survey/interview approach used in this study and inprevious studies has clearly exhausted the possibility ofuncovering new or unique information leading to resolutionof some of the unanswered questions. It is evident that thereis a need for a new approach, such as the generation of reli-able laboratory data that serves as a baseline to predict mate-rials performance under the various conditions encountered inthese processes.
The referenced literature used in this report includes sev-eral laboratory studies 5,6,9 that cover different aspects of theproblem. The tests by Damin and McCoy5 were conductedunder essentially stagnant conditions while those of Scherreret al.6 utilized a simulated process flow scheme. Bonner etal.9 studied the effects of oxidants and explored the effect ofpH. A combination of the latter two studies might be mostuseful in providing realistic corrosion rate data and providinginsight into the mechanisms of the corrosion processes. Twotypes of study are suggested, possibly in sequence.
The first study would consist of a series of tests under simu-lated process conditions reproducing the natural process con-ditions as closely as possible. The objective would be togenerate corrosion on various alloys including carbon steelthat matched the mode and severity of that observed in plantequipment under the same conditions. Assuming that thiscould be achieved, the studies would then be broadened tointroduce the effects of different variables, especially velocityand oxygen, chlorides and cyanides. The objective would be toprovide a clearer picture of the influence of velocity on corro-sion and determine the effect of contaminants on both corro-sion and erosion-corrosion performance of the various alloys.
In a second series of studies the more fundamental aspectscould be explored. The following is a suggested list of topics.
1. The corrosion product film needs to be characterized interms of chemical composition and properties and differ-ences in protective and nonprotective films determined.This could include studies of alloys as well as carbon steel.
2. The effect of process contaminants, such as oxygen,chlorides and cyanides, should be studied with respect tothe films characterized in item 1 above. Studies of filmformation under truly anaerobic conditions are needed asa baseline for comparison with the presence of oxidants.
3. Determine the desirable film properties that provideresistance to the effects of flow velocity, and how best toachieve those properties.
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33
APPENDIX A—PLOTS OF CORROSION SEVERITY VERSUS VARIOUS PARAMETERS FROM THE UOP SURVEY DATA FOR
ALL COOLER TUBES (REFERENCE 7)
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34 API PUBLICATION 932-A
Figure A-1—Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s) on Corrosion Severity
Figure A-2—Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentrationin the Downstream Separator and Calculated Maximum Tube Velocity (ft/s)
on Corrosion Severity for Balanced and Unbalanced Headers
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum tube velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum tube velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
BalancedHeaders
No corrosion
Severe
Medium
Low
Balanced InUnbalanced Out
No corrosion
Severe
Medium
Low
UnbalancedHeaders
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A STUDY OF CORROSION IN HYDROPROCESS REACTOR EFFLUENT AIR COOLER SYSTEMS 35
Figure A-3—Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s)
on Corrosion Severity for Balanced Header Systems
Figure A-4—Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s) on Corrosion Severity
for Balanced Inlet and Unbalanced Outlet Header Systems
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum tube velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
BalancedHeaders
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum tube velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
Balanced InUnbalanced Out
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36 API PUBLICATION 932-A
Figure A-5—Corrosion of Air Cooler Tubes—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Tube Velocity (ft/s)
on Corrosion Severity for Unbalanced Header Systems
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum tube velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
UnbalancedHeaders
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37
APPENDIX B—PLOTS OF CORROSION SEVERITY VERSUS VARIOUS PARAMETERS FROM THE UOP SURVEY DATA FOR
REAC PIPING (REFERENCE 7)
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38 API PUBLICATION 932-A
Figure B-1—Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum
Outlet Header Velocity (ft/s) on Corrosion Severity
Figure B-2—Corrosion of REAC Outlet Header or Piping—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum
Velocity (ft/s) in the Outlet Header or Piping on Corrosion Severity
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header or piping velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
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A STUDY OF CORROSION IN HYDROPROCESS REACTOR EFFLUENT AIR COOLER SYSTEMS 39
Figure B-3—Corrosion of REAC Outlet Piping—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum
Outlet Piping Velocity (ft/s) on Corrosion Severity
Figure B-4—Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s)
on Corrosion Severity for Balanced and Unbalanced Header Systems
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet piping velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
BalancedHeaders
No corrosion
Severe
Medium
Low
Balanced InUnbalanced Out
No corrosion
Severe
Medium
Low
UnbalancedHeaders
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40 API PUBLICATION 932-A
Figure B-5—Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s)
on Corrosion Severity for Balanced Header Systems
Figure B-6—Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s)
on Corrosion Severity for Balanced Inlet and Unbalanced Outlet Header Systems
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
BalancedHeaders
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
Balanced InUnbalanced Out
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A STUDY OF CORROSION IN HYDROPROCESS REACTOR EFFLUENT AIR COOLER SYSTEMS 41
Figure B-7—Corrosion of REAC Outlet Header—The Combined Effect of Calculated Ammonium Bisulfide Concentration in the Downstream Separator and Calculated Maximum Outlet Header Velocity (ft/s)
on Corrosion Severity for Unbalanced Header Systems
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40 45 50
Calculated maximum outlet header velocity (ft/s)
Calc
ula
ted b
isulfid
e c
oncentr
ation (
wt%
)
No corrosion
Severe
Medium
Low
UnbalancedHeaders
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43
APPENDIX C—QUESTIONNAIRE
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44
SURVEY OF HYDROPROCESS REACTOR EFFLUENT SYSTEM CORROSION
To: All selected recipientsThank you for your participation in this important task to determine recommended practices to minimize corrosion through
design, operation and maintenance of hydroprocess effluent systems. From your response to the preliminary questionnaire itappears that your experience will be of great value to this effort and we would like to obtain more detailed information. We wouldlike to follow up with a visit to your office or refinery to conduct personal interviews and discussions with the people most knowl-edgeable about corrosion in the hydroprocess unit(s) you have identified.
We ask that the following information be available at the time of the visit as a minimum basis for the discussions. As much aspossible should be available as hard copies to turn over to the consultant for subsequent analysis. Any or all of the documents fur-nished can be returned to the engineers at the conclusion of the project.
SECTION 1—SCHEMATIC DRAWINGS
Please provide the following schematic drawings. Single page (11'' × 17'' max.) reductions of process flow diagrams areacceptable provided, they are legible. Mechanical flow sheets and piping layout drawings should not be submitted at this time butmay be requested later.
a. Process flow schematic from the reactor to low pressure separator (show design pressures and temperatures and major controlinstruments).b. Overhead air cooler piping arrangement with location of water injection points.
Comments (use a separate page if necessary):____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
SECTION 2—OPERATING CONDITIONS
(a) Temperature and Pressure
Normal RangeMaximum Upset
High/Low
TemperaturesReactor effluentAir cooler inletAir cooler outletHot high pressure separatorCold high pressure separatorHot low pressure separatorCold low pressure separator
PressuresReactor effluentAir cooler inlet Air cooler outletHot high pressure separatorCold high pressure separatorHot low pressure separatorCold low pressure separator
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Annual operating cycle—scheduled annual operating hours__________actual operating hours (history) ___________scheduled outage ______________________
Comments (use a separate page if necessary):____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
(b) Process Conditions
It is desirable to know as much as possible about the chemical composition of the process streams from the outlet of the reactorto the discharge of the low-pressure, low-temperature separator. It is generally recognized that compounds of H
2
S, NH
3
, halo-gens, cyanides and oxidants such as oxygen are the principal contributors to corrosion. We need to identify the presence and con-centration of each salt to match with the corrosion experience for each of the units reported.
Please provide the following flow stream compositions (typically found on the bottom of the PFD). Please give moles/hr orppm, mol wt of component, and total moles in the stream. If available please also provide gals/hr or scfm. Include all componentsin the stream and indicate the phases present (e.g., liquid, vapor).
In addition, please address the following:1. NH
4
HS Concentration in liquid phase________%Location of measurement _____________________Temperature __________ Pressure _____________
K
p
Factor (mol% H
2
S
×
mol% NH
3
) ____________2. Chlorides Concentration ___________ ppm
Location _____________ Temperature _______ Pressure _________3. Fluorides Concentration ___________ ppm
Location _____________ Temperature _______ Pressure _________
(c) Flow Conditions
In addition to the above information on the quantities of vapors and liquids moving through the system, it is desirable to definethe actual flow conditions at certain critical areas. Of particular interest is the dispersion of the injected wash water and distribu-tion to the air cooler tubes, the flow through the air cooler tubes and the flow in the outlet manifolds, especially the elbows. Theinjection and distribution of wash water is explored in a later section. This section will address conditions around the air coolers.
Component
Reactor A/C High Pressure Separator Low Pressure Separator
Inlet Outlet In* In*
Temperature °FPressure psigC
1
– C
7
(total hydrocarbons)HydrogenHydrogen SulfideHydrogen CyanideAmmoniaWaterOxygen
* give both hot & cold
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Please answer the following:
What is the condition of the stream entering the air coolers? Is it all vapor or does it have some liquid? ________________________________________________________________________________________________________________________________________________________________________________________________________________________________ At what point does condensation of a) water and b) hydrocarbon take place in the cooler tubes? _____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________What are the flow characteristics in the cooler tubes? Please indicate the bulk velocity and flow regime (annular, stratified, plug,etc.?). _____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Give the flow characteristics of the outlet piping. __________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Additional Comments:____________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
SECTION 3—METALLURGY
Please provide a Materials Selection Diagram or marked-up flow sheet indicating the principal materials of construction forvessels and piping.
Manufacturers Vessel and Exchanger Data Sheets may be submitted provided the information is up-to-date, including anychanges and the approximate date of the change, and that all items exposed to the operating stream are included.
Inspection Data Sheets and computer graphics may also be used with the same provisions as above. If inspection documentsare submitted in response to Section 4, they need not be duplicated for this section provided they contain all the required informa-tion as indicated next.
• All materials should be properly identified with a) a specification number such as ASTM, ASME or API, b) the materialdescription (e.g., alloy name), c) thickness, and d) corrosion allowance.
• Piping and tubing should be designated as welded or seamless.• Any stress relief heat treatment should be noted.
In general, only materials exposed to the operating environment need be described in detail. The following equipment must beincluded:
Reactor exit piping Reactor feed/effluent exchangers (effluent side only)Piping to the air coolersAir coolers (header boxes and tubes)Trim coolerPiping to the separatorsHot high pressure separatorCold high pressure separatorHot low pressure separatorCold low pressure separator
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SECTION 4—WATER WASH
Source of wash water_____________________________________________________________________________________List all chemical contaminants and their concentrations. The following are suggested as a starter list:Ammonium salts or ammonia; hydrogen sulfide, other sulfides or sulfur compounds, cyanides, chlorides, HCl, fluorides, oxygenand oxidizing agents.________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________pH?__________Quantity of water injected (gals/min) _______________Number of injection points _______________ One for each bundle? _______________Based on number of air cooler bundles, what quantity of water is provided per cooler?_________________________________________________________________________________________________________________________________________If not covered in Section 1, please provide a sketch or describe the air cooler piping arrangement from the inlet line through themanifolds and individual inlets to the cooler headers, as well as the outlet arrangement. _________________________________ ____________________________________________________________________________________________________________________________________________________________________________________________________________What chemical analyses are performed on the air cooler effluent?______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Describe the method of determining ammonium bi-sulfide concentration in the AC effluent. Include the sampling procedure andanalytical method. ___________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
SECTION 5—INSPECTION
To avoid accumulation of a large number of documents, it is preferable that, where possible,
summary
sheets of the inspectionrecords for each equipment item be submitted. The purpose of gathering this information is to determine whether the level andquality of inspection has had a bearing on the performance of the unit. It is also important to learn if any indications of a potentialproblem developed over a long period of time or if they developed suddenly—the time frame can be used to relate to the processconditions in the same time period.
It is suggested that a separate sheet or sheets be provided for each item of equipment discussed. The items listed below are theminimum information required. Name of item (reactor, piping, etc.) ___________________________________________________________________________Frequency of inspection___________________________________________________________________________________Last inspected___________________________________________________________________________________________Type of inspection (visual, UT, eddy current, etc.)______________________________________________________________________________________________________Inspection method—please indicate the extent of inspection for each item, especially piping (i.e., whether it is random, fixed loca-tion or grid readings). Inspection record—year, observations, readings.Please attach Inspection Data Sheets for each item reported.
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SECTION 6—CORROSION
Please provide a summary narrative of the corrosion experience with the unit.This section should include corrosion data acquired by coupons, probes or test pieces, as well as visual observations and
inspection thickness data.In answering the following questions please address each item of equipment separately. Do not be confined by the space pro-
vided, attach additional sheets if needed.
Since the unit was commissioned, has any item experienced severe corrosion requiring it be replaced? If so, describe.____________________________________________________________________________________________________________________________________________________________________________________________________________Has the same item been replaced more than once? ______________________________________________________________Were there any changes made in the metallurgy, such as a different corrosion allowance, or different material?___________________________________________________________________________________________________________________________________________________________________________________________________________________________Have any non-metallurgical changes been made, such as inhibition, or process modification? ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Have the changes been successful in controlling the problem? __________________________________________________________________________________________________________________________________________________________Has the problem diminished without making changes? ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________If so, what was responsible for the improvement? ___________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Were process changes made for reasons other than corrosion control? ____________________________________________________________________________________________________________________________________________________Has corrosion ever led to an unscheduled shutdown? If “yes” describe the incident. ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Has there ever been a catastrophic incident? ________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________What changes have been made to avoid a repetition of the event? ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
SECTION 7—INHIBITION
The following information is requested with respect to the use of chemical inhibitors in the effluent system.
Type of inhibitor (trade name or generic description) _________________________________________________________________________________________________________________________________________________________________Water soluble? __________________ Hydrocarbon soluble? __________________Point of addition________________________________________________________________________________________________________________________________________________________________________________________________Method of injection____________________________________________________________________________________________________________________________________________________________________________________________Continuous? __________________ Intermittent? __________________Dosage? __________________________________________________Number of years in use ______________________________________
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Effectiveness—is corrosion rate reduced or is corrosion essentially eliminated? ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________Have other inhibitors been tried which were unsuccessful? Please describe. ______________________________________________________________________________________________________________________________________________________________________________________________________________________________________________________
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APIAmerican Petroleum Institute
2002 Publications Order Form
C93401 $ 63.00
$ 120.00C93801
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Publ 934, Materials and Fabrication Requirement for 2-1/4Cr-1Mo & 3Cr-1Mo Steel Heavy Wall Pressure Vessels for High Temperature,
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Cracking of 11/4 Cr-1/2 Mo Steel EquipmentPubl 939-A, Research Report on Characterization and Monitoring
of Cracking in Wet H2S Service
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Additional copies are available through Global EngineeringDocuments at (800) 854-7179 or (303) 397-7956
Information about API Publications, Programs and Services isavailable on the World Wide Web at: http://www.api.org
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