Selecting Process Piping - 1

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Selecting process

piping materials

These guidelines and referencedcodes and articles aid selection ofpiping for most HPI processes

R.B. Setterlund, Houston

SELECTION OF PIPING MATERIALS for refineryand petrochemical plants requires collaboration between thecorrosion piping and process engineers, and usually involvesmore than determining if a material is compatible with a givenenvironment. Many questions must be answered before a pipeand valve specification can be written. Is the alloy available inthe size and thickness required? Is it the most economicalchoice? Should it be specified as seamless or welded? Is itsuitable for the maximum anticipated operating temperature orwill long-term exposure to these temperatures cause itsmechanical properties to deteriorate? Will it require specialwelding or heat treatment requirements?

It should be noted at the outset that the best approachto corrosion control may not involve the use of corrosion-resistant alloy materials. Often adequate life can be obtainedin corrosion services with carbon steel piping in conjunctionwith control of process and operating variables. In other cases,in particular those piping systems handling corrosive fluids atelevated temperatures, there is no alternative to corrosion-re-sistant materials. Also, low or elevated temperature service

conditions can dictate the use of special materials.

General guidelines. Corrosion can be classified into threegeneral forms based on the type of damage that results. Sometypes of damage can be tolerated, others cannot and it isimportant to be aware of these distinctions. The three generalforms are: 1. uniform corrosion, 2. localized corrosion and 3.stress corrosion cracking.

Uniform corrosion, in which metal is removed moreor less uniformly, is the most common form of corrosion andthe least dangerous. It is generally agreed that the maximumacceptable loss of metal due to uniform corrosion isapproximately 20 mils per year (mpy).1 This rate of corrosionis not usually desirable since high corrosion rates not only

reduce the thickness of piping but also can lead to plugging ofheat exchanger bundles and reactor screens by corrosiondeposits. Iron sulfide scale occupies a volume about seventimes the volume of metal that is removed, thus a ten in. pipecorroding at 20 mpy would produce about three cubic feet ofloose scale per year per 100 feet of length.

Except where equipment becomes plugged,contamination of process streams by corrosion products is notusually as serious a problem in hydrocarbon processing plantsas in most chemical plants. One exception is equipment lubeand seal oil lines which must be kept absolutely free from

Fig. 1—Cross section of a failed carbon steel piping weld carrying

caustic contaminated vacuum gas oil.

TABLE 1 – Controlling stress corrosion cracking

Metal Environment Common control measureCarbon and alloy steels Caustic solutions at stress relief of welds and

Temperatures over 120°F cold bendsTo over 108°F dependingOn concentration

1(Control of stress)

Heat treated alloys with Sulfide solutions at Control of hardness orHardnesses over HRC 22 ambient or elevated selection of moreto HRC 30 depending temperatures resistant alloys

2

on alloy group3

(Control of materials)

Austenitic stainless Chloride solution at Flushing, neutralizing,steels with temperatures over 110°F avoidance of crevices,susceptibility decreasing to 180°F depending on coatingwith the more highly chloride concentrationalloyed grades

4 and alloy susceptibility (Control of environment)

corrosion products. Type 304 stainless steel is often specifiedfor this service to avoid acid cleaning and to prevent rustformation when the lines are drained.

Localized corrosion involves selective removal of

metal from part of the exposed metal surface. Pittingcorrosion, crevice corrosion, galvanic corrosion and selective

weld attack all fall under this category. These types ofdamage are difficult to inspect for and, unlike uniform attack,

increased corrosion allowances are seldom an effective control

measure.

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Pipe and valve specifications. In most major projects,Fig. 2—Valve stem that failed fromsulfide stress cracking. the preparation of the pipe and valve specifications starts in

the piping department of an engineering contractor. Theseengineering firms have standardized specifications which are

usually coded to: 1. materials of construction, 2. primary

flange pressure classification and 3. minimum allowances forcorrosion. The codes are often subgrouped to provide for

variations in valve trim material, types of small fittings,

screwed or socket welded, or special heat treatment ormaterial requirements. An example of a code system is shown

below.

Stress corrosion cracking

involves cracking of metal withoutsignificant loss of metal and should

be evaluated when selectingmaterials. Stress corrosion crackingoccurs when certain metals are

exposed under a tensile stress to

specific environments and failurescan occur rap- idly without

warning, thus it is important that

the risk be minimized. Stresscorrosion cracking can be

prevented by 1: selecting metals

which are immune to failure (whichis usually the preferred method), 2.

removal or reduction of stress or 3.

control of the environment (whichis the most risky method). Table 1

illustrates how these three methods

are used to control metal-environment combinations likely to

result in stress cracking failures.

Some stress corrosion cracking failures are difficult

to foresee. Fig. 1 shows a cross section of a steel pipe weldthat cracked in caustic-contaminated hydrocarbon at 475°F.

This failure resulted from the use of contaminated stripping

steam and was overcome by operational changes. Had this not been possible, it would have been necessary to stress relieve

all of the welds in the piping system.

The pipe and valve specifications needed for a

particular project are taken from the standard specificationand, by use of a computer, are modified to meet the

requirements of the operating company for whom the plant is

being built. If necessary, a new pipe and valve specificationmay be developed to cover specific service conditions or

special requirements. As the project proceeds, these

specifications are reviewed and revised. New specificationsare added and some specifications are dropped. Often

specifications are discarded or combined to simplify the job bystandardization.

C C 4

Pipe material (C indicates carbon steelpipe without special requirements)

Subgroup (C indicates carbon steelvalves with standard 12 chromestainless steel trim and socket weldfittings)

Corrosion allowance (4 indicatesminimum corrosion allowance in1/32s or 1/8-in. min)

Most stress corrosion cracking failures, however,

could have been prevented using information available at thetime of design. Fig. 2 shows a stem from a new valve that

failed during startup of a hydrocracking unit. The valve stemfailed during short-term exposure to 2,000 ppm H2S during

catalyst presulfiding operations. The stem was UNS S45000

precipitation hardening stainless steel and failed due to a formof stress corrosion cracking referred to as sulfide stress

cracking (SSC). The valve stem was in the H950 condition

with a hardness of Rockwell C40 making it highly susceptibleto an SSC failure. For resistance to SSC, the S45000 valve

stem should have been in the Hl150 condition with a hardness

no greater than Rockwell C 31 or, alternatively, the stem couldhave been of another SSC resistant alloy.2 Since failure can

take place under short-term upset or transient conditions, achange to a more resistant alloy or heat treatment is usually

the only reliable means to ensure freedom from SSC in

refinery process units.

It is usually desirable to employ the fewest possible

different piping materials. This reduces construction costs andis of particular interest to the maintenance departments or the

operating company. For example, assume that one

specification calls for AISI 304 stainless steel pipe and anothercalls for AISI 304L stainless steel pipe. If the quantity of 304

stainless steel is small, it would be preferable to use only AISI

304L stainless for both services. This eliminates the need tokeep the two grades separated and reduces the chance of type

304 piping being used where the lower carbon grade is needed

to prevent weld zone attack. If, on the other hand, the projectinvolves the use of a large quantity of stainless steel in

services where ordinary type 304 has proven to be

satisfactory, then the cost of using both specifications may be justified.The material selection,

General hydrocarbons. The term "general

hydrocarbons" refers to those hydrocarbon services wherecorrosion would not be expected and special requirements are

not needed. Hydrocarbons, by themselves, are not corrosive at

the temperatures at which they are normally processed.Corrosion results from impurities in the hydrocarbon such as

chloride salts, organic acids, water and sulfur compounds or

produced by marking a processflow diagram, shows the

composition, temperature andpressure of each process stream

along with its appropriatematerial of construction.

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by- products formed from breakdown of these impurities.

Also, chemicals added to hydrocarbons during processing,such as NaOH and H2SO4, may require the use of special

metals and/or certain precautions.5

The piping and valve specifications for generalhydrocarbon service are most often written around ASTM A

53 Grade B or A 106 Grade B seamless pipe, more familiar to

pipefitters as "black iron" pipe. The basic specification for petroleum refinery service will require that valves have cast

steel bodies with stainless steel trim, usually 12% chromium

stainless steel.Specifications for less severe service may allow cast

iron flanged valves under the limits for ductile cast iron andfor gray cast iron shown in ASME B 31.3, "Chemical Plant

and Petroleum Refinery Piping Code." Standard A 53 Grade B

pipe is widely available and low in cost, can be bent hot andcold, and cut and welded using simple methods and minimal

precautions. Carbon steel pipe has relatively high strength and

ductility, adequate toughness for most applications, and fair

resistance to corrosion in a wide range of environments.Changes from basic pipe specifications should be carefully

considered since any material substitution made to obtain animprovement in either strength, toughness or corrosion

resistance, will usually involve increased cost and decreased

availability. Some hydrocarbon services, however, requirealternative materials. One example is piping to handle hydro-

carbon at temperatures below ambient.Low temperature service. The fracture toughness of

carbon steel and ferritic alloys decreases with decreasing

metal temperature.6 This phenomenon is the basis for the 20°F minimum temperature limit in Appendix A of the

ANSI B 31.3 piping code. Some ferritic materials such as

structural grade steels without chemistry limits and ductile andmalleable iron cannot be used below this temperature, but

most ferritic steels can be used to a lower temperature

provided they are stress relieved and qualified by impacttesting.

The B 31.3 code has an important exclusion to the

impact test requirement based on the fact that brittle fractureinitiation is related to the level of applied stress. Impact testing

is not required for temperatures between -20°F and -50°F

provided the actual stress is less than 25% of the allowablestress above -20°F. This exclusion should be applied with care

and post weld stress relief is advised as a precautionary

measure even though it is not mandated by the B 31.3 code.Austenitic grades of stainless steel, provided they are

in the solution treated condition and contain less than 0.10%

carbon, can be used to temperatures down to -325°F without being impact tested. Liquefied natural gas as well as other

refrigerated hydrocarbons are often handled in austenitic

stainless steel pipe. Since austenitic stainless steel can betaken "off the shelf" and applied directly to low temperature

service without special tests, there is a temptation to employ itautomatically for temperatures under -20°F. This may lead to

unexpected problems, as illustrated by chloride stress-

corrosion cracking failures which recently occurred shortlyafter the startup of a chemical plant. Three similar plants had

been constructed using A 53 B pipe to handle solutions

containing organic chlorides without problems. This plant,however, required that the minimum design temperature be

reduced from -20°F to -40°F.

The stainless steel piping was replaced in a matter ofdays using pipe from stock. Since the pressure in the failed

line was sufficiently low, ordinary A 53 Grade B pipe could

be used without changing the -40°F design temperature. Hadimpact tested material been required, the replacement may

have taken weeks or months.Hydrocarbon-sulfur. At elevated temperature, iron

reacts chemically with elemental sulfur and/or sulfur

compounds to form iron sulfide. The corrosiveness of the

sulfur bearing hydrocarbons, unlike chemical mixtures, is not proportional to the weight percent sulfur. The reason for this is

that the sulfur may be present in various forms such as

elemental sulfur, hydrogen sulfide, aliphatic sulfides, aromaticsulfides, polysulfides, mercaptans and disulfides, all with

different potentials for causing corrosion. At elevated

temperatures many organic sulfides break down to form

hydrogen sulfide or sulfur which reacts with metal surfaces.Lighter molecules tend to promote corrosion more readily than

heavier sulfur compounds, some of which, because of theirstability, are essentially noncorrosive.

7

Sulfide corrosion is strongly temperature dependent.The sulfidation rate decreases in proportion to the amount ofchromium in the steel (Fig. 3).10 These curves have beendrawn based on modified data from a 1963 AmericanPetroleum Institute paper, "High Temperature SulfidicCorrosion in Hydrogen-Free Environment."11 In crudefractionation units, carbon steel is relatively unaffected bycorrosion at temperatures below 500°F to 550°F and marginalin performance at temperatures between 550°F and 650°F. 8

The most common carbon- to-alloy steel break temperature is

550°F, but some refiners will require the use of alloy steel attemperatures as low as 500°F, while others have used carbonsteel up to 600°F. When carbon steel is used in contact withsulfur over 500°F it is common to specify silicon-killed gradessuch as ASTM A 106 pipe and A 105 fittings. Steels with0.15% to 0.30% silicon have been shown to be greatlysuperior to steels with under 0.1% silicon in someenvironments.9

Fig. 3—Effect of chromium content of steel on high temperaturecorrosion rate in a hydrogen free environment

. 10

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Standard A 53 Grade B pipe has no silicon requirements

and can be furnished with or without silicon which resulted in

a 1986 failure having tragic consequences. A short section of

standard weight NPS 4 ASTM A 53 Grade B pipe was added

in the field to correct an interference problem. The added pipehad only 0.016% silicon while the remaining shop spooled

pipe had 0.17% silicon or higher. The line carried hydrocarbon

with 0.06% sulfur at a temperature of 610°F. A large number

of wall thickness readings had shown adequate wall thickness,

however, no thickness readings had been made on the field-added splice section. After many years of operation the shortsection was thinned (Fig. 4), and failed due to fluid pressure

resulting in a fire with fatalities.

The workhorse alloy in petroleum refining is one

containing 5% chromium and 0.5% molybdenum. This alloy,

often called simply "5 chrome," has a sulfidation rate of aboutone-third that of carbon steel, allowing it to be used in the

important 525°F to 675°F temperature range. Alloy steels.

with lower chromium contents such as 1-1/4 Cr-0.5 Mo and 2-1/4 Cr-l Mo steels are seldom employed for their corrosionresistance in hydrocarbon plus sulfur environments. These

alloys are primarily used either for very high temperature,noncorrosive services or for service in high temperature, high

pressure hydrogen environments, as discussed later.

In applications where corrosion rates are too severe for 5

Cr-0.5 Mo steel, either 7 Cr-0.5 Mo or 9 Cr-1 Mo alloy steelsmay be used. At present 7 chrome steel is rarely produced and,

when it is used either 9 chrome (A 217 Grade C12) or 12

chrome (A 217 Grade CA15) castings must be specified for

valve bodies.

Hydrocarbon-organic acids. In crude distillation units, thecorrosion rate may be greatly affected by various organic acids

present in petroleum stocks. These acids, referred to as

napthenic acid, can cause severe corrosion to refinery piping

and equipment operating at temperatures between 400°F and

700°F.12

At higher temperatures, naphthenic acids are decomposed

and do not contribute to corrosion of units downstream of the

crude unit. Type 316 stainless steel is widely used to resist

naphthenic acid corrosion, however, under some conditions

lower priced alloys may be suitable. A recent paper by Piehlgives current information on this complex subject and should

be reviewed prior to making decisions on materials for

handling naphthenic acid crude.13

Water-hydrogen sulfide. Another service conditiop

calling for a separate specification is piping for either water or

wet gas containing hydrogen sulfide. While carbon steel withextra corrosion allowance is usually suitable on the basis of

metal loss, consideration must be made for the hydrogen that

is charged into the steel due to corrosion in the presence of sulfide ions.

The primary consideration for sour service should be

avoidance of hard valve components to avoid sulfide stresscracking as illustrated by the broken stem shown in Fig. 2.

Sulfide stress cracking of valve components can have serious

consequences especially when it involves the valve stem. Not

only is there a chance of leakage but an open gate valve canfail closed and shut off a line. For this reason it is good

practice to make all process valves inherently SSC resistant.

This can be done by referencing NACE Standard MR0175-90

on the valve purchase order, however, a more direct and less

time consuming method is to list approved valves by

manufacturer and model numbers and to review proposedsubstitutions on an item-by-item basis.

Another NACE standard that in the writer's opinionshould be used for all applications, sour or not, is NACE

Standard RP0472-87, "Methods and Controls to Prevent In-

Service Cracking of Carbon Steel Welds in P-1 Materials inCorrosive Petroleum Refining Environments." This standard

recommends that welds not exceed 200 Brinell hardness (HE)

and further, that postweld heat treatment (PWHT) of

weldments be considered.

It has been established over the past several years thateven welds of normal hardness are not immune to cracking in

wet sulfide environments.14 While considerable attention has

been given to cracking of pressure vessel welds in wet sulfideenvironments, failures of piping welds have been rare. A

possible explanation is the symmetry of piping welds which

produce a more even residual stress pattern than in pressurevessel welds. One of the rare failures, shown in Fig. 5, took

place in a fitting-to-pipe weld and was largely attributable to

bending stresses. This weld had a hardness under 200 Brinell

but had not been postweld heat treated. No cracks were

detected in pipe-to-pipe welds which had similar hardnesses but lower applied stress. Despite the rarity of problems, it is

common practice to stress relieve piping for wet sulfide

environments.

Fig. 4 –Cross section of a failed carbon steel piping weld carryingnaptha with 0.06% sulfur.

Fig. 5—Cross section of a failed carbon steel piping weld carryingwet sour hydrocarbon.

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Hydrocarbon-hydrogen. Hydrogen at high temperatureand high pressure can permeate steel, and when the conditions

are severe enough, react with metal carbides in the

microstructure. Two types of damage are possible: 1. surface

decarburization, which may not be serious, and 2. subsurface

decarburization, which results in internal fissures that makethe steel unsuitable for safe operation.

Alloy steels containing chromium and/or molybdenum

contain carbides more resistant to reduction by hydrogen. The

limits for various alloys in terms of metal temperature and

hydrogen partial pressure are contained in API Publication941, "Steels for Hydrogen Service at Elevated Temperaturesand Pressures in Petroleum Refineries and Petrochemical

Plants." The operating limit chart contained in API Publication

941, referred to as the Nelson curve, was developed over the

past 30 years and finds application not only in petroleum

refinery units but also in plants that manufacture ammonia,methanol, edible oils and higher alcohols.

The Nelson curve is based on the partial pressure of

hydrogen in the vapor phase and the maximum anticipatedmetal temperature. The user should ensure that the correct

process information and the latest revision are used. Thecarbon-l/2% molybdenum limit was lowered in 1977 and

because of subsequent problems at temperatures below this

limit, the current revision contains a warning against the use of

carbon-l/2% molybdenum steel in high temperature re-former

units.15

When alloy steels are required by API 941 it is not only

necessary to specify chromium-molybdenum alloy pipe but

also to ensure that all components and welds are of the correct

composition. In the example shown in Fig. 6, a section of

carbon steel pipe had been welded into a 2-1/4 Cr-l Mo steel

line. The carbon steel failed by high temperature hydrogenattack after 10 years.

Hydrocarbon-hydrogen-hydrogen sulfide. Hydro-

treating reactor inlet-outlet piping involves exposure of steels

to H2S in the presence of hydrogen. There are various types ofhydrotreaters, which is a general term to describe the catalytic

desulfurization, treating or cracking of hydrocarbons with

hydrogen. All the processes are similar and operate with

reaction temperatures of around 700°F to 850°F. The

operating pressures vary from 400 psig for units designed to

desulfurize light hydrocarbon streams to over 2,500 psig inhydrocrackers designed to break heavy hydrocarbons into

more valuable, lighter hydrocarbons. The piping for these twounits may contain similar amounts of hydrogen sulfide but the

pipe materials may differ.

The solid lines in Fig. 7 illustrate the relative corrosion ratesof steels with varying chromium contents in naphtha

desulfurizer piping.16 As shown by the shape of the curves,

chromium is not nearly as effective in reducing corrosion as in

hydrogen-free atmospheres. Nevertheless, 9Cr-1 Mo alloy

steel is often used for reactor effluent piping. Another materialsometimes used is 12% chromium ferritic stainless steel (type

410), however, type 410 stainless steel will undergo a loss of

room temperature ductility and toughness on long-term expo-sure to temperatures over 700°F through an aging process

called "885 embrittlement." The 831.3 code contains a

warning but does not prohibit its use over this temperature.One major refiner has made extensive use of centrifugally cast

type 410 stainless steel piping. Extruded type 410 stainless

steel pipe had operated for over 25 years at temperatures over

700°F in units used to desulfurize synthetic crude oil from tar

sands.The most frequently used material for high

temperature hydrotreater piping is austenitic stainless steel,

usually the titanium-stabilized type 321 grade. Austenitic

stainless steels are not susceptible to 885 embrittlement andFig.6—Cross section of a failed piping weld carrying hydrogen at800 to 880°F.

Fig. 7 –Effect of chromium content of steel on the hightemperature corrosion rate in hydrogen-hydrogen sulfide.

16

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have excellent ductility and toughness even after long-termservice. Austenitic stainless steels are susceptible to stress

corrosion cracking when exposed to chloride environments

and Appendix F of the 831.3 code contains a precautionary

warning against their use when chlorides are known to be

present.Hydrocrackers and heavy gas oil desulfurizers

present a more limited choice of piping materials than naphtha

desulfurizers, as shown by the dashed lines in Fig. 7. Nine

chrome steel is not acceptable and while 12 chrome stainless

steel has an acceptably low corrosion rate, its low code stressvalues make it less attractive than austenitic grades of stainlesssteel. Also, its low toughness becomes more significant as the

thickness of the pipe increases.

For hydrocrackers, where costs may exceed several

thou- sand dollars per linear foot of pipe, a more economical

alternative to extruded heavy wall type 321 stainless steel pipeis centrifugally cast " HF modified" piping. Type HF modified

is a casting alloy developed for this application.17 It contains

more carbon than wrought 18-8 grades of austenitic stainlesssteel which makes the metal more fluid at casting temperatures

and improves quality. Also, it is chemically balanced to produce a two-phase ferritic-austenitic microstructure whichensures the production of sound, crack-free castings. The high

chromium content gives the alloy very high resistance to high

temperature sulfide corrosion, however, it causes the alloy to

lose toughness after elevated temperature service. The loss of

toughness is kept to within acceptable levels by controlling theferrite level to under 15%. The usual composition of HF

modified is:

Chromium 21% to 25%

Nickel 6.5% to 11%Carbon 0.15% to 0.20%

Ferrite 5% to 15%

Due to its high chromium content and two-phase

microstructure, type HF modified stainless steel is highlyresistant to chloride stress cracking. It has lower ductility than

wrought type 321 stainless steel and cannot be formed into

bends. Straight lengths of pipe as well as flanges and other

shapes can be produced by centrifugal casting, but other

shapes such as elbows may have to be statically cast withsome resultant sacrifice in properties.

Material selection diagram. An effective means to expressthe consensus among the corrosion engineer, the piping

engineer and the process engineer is the material selection

diagram. The material selection, produced by marking a process flow diagram, shows the composition, temperature

and pressure of each process stream along with its appropriate

material of construction. The drawing can be extended to

show the code number of the appropriate piping and valve

specifications. Corrosion allowances are usually shown alongwith inhibitor and water wash injection points and locations

for corrosion-indicating instruments. To illustrate, Fig. 8

shows a simplified material selection diagram for the high

pressure loop of a gas oil desulfurizer designed to operate at a

pressure of approximately 800 psig. The feed is assumed tocontain 6,000 ppm of sulfur. Some of the factors involved inselecting materials for the various operating conditions

indicated by the numbered locations on the diagram are

discussed in the following paragraphs.

1. Five-chrome alloy steel with a 1/8-in. corrosionallowance is the minimum requirement for pipe transporting

hot charge oil from the shell of the feed effluent heatexchanger to the hydrogen-rich recycle gas mixing point. The

gas oil is free from hydrogen but contains hydrogen sulfide.

Fig. 3 indicates a corrosion rate of 10 to 12 mpy for 5 chrome

steel at the 663°F operating temperature. If the temperaturehad been significantly higher, either a higher corrosion

allowance or the use of 9 Cr-l Mo steel would have been

required. This is the only area where 5 chrome steel is called

for, therefore, if the line was very short it may be preferable to

employ type 321 stainless steel to reduce the number of alloysinvolved.

2. Type 321 austenitic stainless steel with 1/16-in.corrosion allowance is shown for the reactor inlet and outlet

piping. The predicted corrosion rate at the 747°F outlet

temperature is approximately 2 mpy for 18-8 stainless steel,

however, the rate for 5 chrome steel would be over 50 mpy(Fig. 7). This selection assumes that appreciable chlorides are

not present. The flanged valves would be grade CF 8M

stainless steel which is equivalent to type 316 since this is the

product form for which valves are normally supplied.3. Low alloy 1-1/4 Cr-l/2 Mo steel is selected for piping

in and out of the hot high pressure separator. The operating

temperature is not high enough to require protection from

sulfur corrosion, but is high enough to cause hydrogen attack

Fig. 8—Simplified material selection diagram for the high pressureportion of a gas oil desulfurizer.

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in carbon steel. (Maximum rather than average conditionsshould always be used in conjunction with the API 941

hydrogen curves.)

4. The piping carrying liquid out of the bottom of the

hot high pressure separator is carbon steel because of the

lowered hydrogen content. The pressure letdown valve in thisline as well as downstream piping are specified to be stainless

steel to guard against corrosion/erosion by hot flashing H2S

liquids. Sulfide corrosion is velocity dependent and the use of

carbon or low alloy steel is questionable. In this example, the

letdown valve would be located to minimize the footage of expensive stainless steel piping.

5. The mixture of sulfides, ammonia compounds and

water in the downstream piping can produce serious

corrosion.17 In this case, it was determined that carbon steel

with a high corrosion allowance could be employed provided

the fluid velocity was limited. In addition, injection facilitieswere installed for wash water and for inhibitors to control

fouling and corrosion.

6. The hydrogen partial pressure in the recycle gas wasunder 700 psig and the use of alloys was not required at the

maximum operating temperature of the recycle gas piping. To prevent hydrogen attack resulting from the recycle gas beingfurther heated, the break point between carbon and stainless

steel was specified to be located well back from the mixing

point.

Precautions. It is hoped that the information in this brief paper will aid the engineer concerned with the selection and

specification of piping for refinery and petrochemical service.

The charts and examples in this article have been simplified

and are intended only to illustrate concepts. Engineers

involved in specifying materials should refer to the datacontained in the original articles and standards before actually

selecting material for process piping.

LITERATURE CITED

1. Corrosion Data Surry, 5th edition. National Association of CorrosionEngineers, Houston, Texas, 1974

2. "Sulfide Stress Cracking Resistant Metallic Material for Oil Field

Equipment," NACE Standard MR0175-90, National Association ofCorrosion Engineers, Houston, Texas, 1990.

3. Fraser, J P and Treseder, R S.. "Cracking of High Strength Steels in

Hydrogen Sulfide Solutions," Corrosion, Vol. 8, 1952

4. Couper, A. S. and McConomy, H. F., "Stress Corrosion Cracking ofAustenitic Stainless Steels in Refineries," Proceedings of API Division

of Refining, 1966

5. Gutzeit, J., "Corrosion in Petroleum Refineries," Process IndustriesCorrosion, NACE, 1988

6. Metals Handbook, Volume I, Ninth Edition, American Society forMetals, Metals Park, Ohio,1978.

7. "'High Temperature Crude Oil Corrosivity Studies," API Publication

943, American Petroleum Institute, Washington, D.C., 1974.8. Humphries, M. J. and Sorel, G., "Corrosion Control in Crude Oil

Distillation Units," Materials Performance, Vol. 15, No.2, 1976.

9. Minutes of the Refining Industry Corrosion Group Committee T-8, National Association of Corrosion Engineers, 22nd Annual Conference,April 20, 1966.

10. Gutzeit, J., "High Temperature Sulfide Corrosion of Steels," Process Industries Corrosion, NACE, 1988.

11. McConomy, H F., "High Temperature Sulfidic Corrosion in Hydrogen-

Free Environment," Proceedings of API Division of Refining, May 1963

12. "Corrosion of Refinery Equipment by Naphthenic Acid,"Materials Protection, Vol. 2, No 9, 1963.

13. Piehl, R. L., "Naphthenic Acid Corrosion in Crude Distillation Units,"Materials Performance, Vol. 27, No 1, 1988.

14. Merrick, R D, "Refinery Experiences with Cracking in Wet H2SEnvironments," ibid.

15. "Steels for Hydrogen Service at Elevated Temperatures and Pressures in

Petroleum Refineries and Petrochemical Plants," API Publication 941,Third Edition, American Petroleum Institute, Washington, D.C., 1983.

16. Couper, A.S., and Gorman, J.W., "New Computer Correlations to

Estimate Corrosion of Steels by Refinery Streams Containing HydrogenSulfide," Paper 67, National Association of Corrosion Engineers, 26thAnnual Conference, March 2, 1970.

17. Prescott, G.R. and Heller, J.J., "Application of a Modified HF Alloy forHydrocracker Service," Materials Protection, Vol. 7, No.3, 1968.

18. Piehl, R.L., "Survey of Corrosion in Hydrocracker Effluent Air

Coolers," Materials Performance, Vol. 15, No.1, 1976

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Selecting Process Piping - 1