Technical Manual - Section 3 (Safety Hazards)

OR-OSHA TECHNICAL MANUAL OR-OSHA TECHNICAL MANUAL OR-OSHA TECHNICAL MANUAL 

Section III 

SAFETY HAZARDS 

CHAPTER 1: 

CHAPTER 2: 

CHAPTER 3: 

CHAPTER 4: 

OILWELL DERRICK 

STABILITY: GUYWIRE 

ANCHOR SYSTEMS 

PETROLEUM REFINING 

PROCESSES 

PRESSURE VESSEL 

GUIDELINES 

INDUSTRIAL ROBOTS AND 

ROBOT SYSTEM SAFETY 

III

III

SECTION III: CHAPTER 1 

OIL WELL DERRICK STABILITY: GUYWIRE 

ANCHOR SYSTEMS 

A. INTRODUCTION 

Work-over Rigs are mast type devices that vary significantly 

from crane or other boom (mast) type equipment. Work-over 

Rigs experience constant and varying dynamic loading 

conditions. They are subjected to various compression 

forces, along with jarring and wind loading. Other forces 

induced by pipe, tubing, etc. being stacked in the derrick and 

workers aloft on the derrick platform, as well as an 

ever-changing number of lateral and vertical forces are also 

present. Because of a work-over rig's dynamic environment, 

the health and safety of the operation is dependent upon the 

stability of the rig and its guy anchor system. 

according to the type of soil and its holding capacity, methods 

of installing guywire anchors, integrity of the system, and 

acceptable parameters in lieu of actual pull testing should be 

established. 

Investigation into each fatal incident has determined that the 

cause of the upset was component failure rather than total 

system failure. This clearly illustrates the fact that the 

integrity of the system is no sounder than its weakest 

component. 

CAUSAL FACTORS 

There is no specific OSHA standard that addresses the 

stability of derricks in the oilwell drilling and servicing 

industry, see Figure III:1-1. But because of the fatality record 

there is a need for a guideline detailing the type of temporary 

stability systems 

A. Introduction.......................................III:1-1 

B. Types of Guywire Anchors...............III:1-2 

C. Stability Considerations...................III:1-3 

D. Observations, directions, and 

Conclusions................................III:1-5 

E. Bibliography.......................................III:1-6 

gure III:1-1. Oilwell Servicing Derrick 

Fi 

III:1-1

INDUSTRY RECOMMENDATIONS 

The American Petroleum Institute (API) in its Specification 

4E "Specification for Drilling and Well Servicing Structures" 

sets forth a "Recommended Guying Pattern General 

Conditions." 

The Association of Oilwell Servicing Contractors. (AOSC) in 

its publication "Recommended Safe Procedures and 

Guidelines for Oil and Gas Well Servicing" recommends the 

same guying patterns as are set forth in API Specification 4E. 

Though not present in the AOSC publication the API 

Specification 4E provides a Recommended Guyline Anchor 

Spacing and Load Chart. This is discussed in detail in the 

Guidelines on the Stability of Well Servicing Derricks. 

There has been considerable progress within the industry to 

design procedures to assure the integrity of the stability 

system without the necessity of conducting individual pull 

tests on each of the anchors. 

APPLICATION 

This chapter is intended to form the basis of a minimum 

safety guideline, for the use of Temporary Guywire Anchor 

Systems on derricks, in the oil well drilling and servicing 

industry. 

Recommended procedures, practices, equipment, and 

requirements have been developed based on availability, 

capability, adaptability, dependability, and reliability of the 

various types of systems. 

B. TYPES OF GUYWIRE ANCHORS 

MANUFACTURED ANCHORS 

There are four basic types of manufactured anchors. The 

screw or helix anchor, expanding plate anchor, flat plate 

anchor, and the pivoting anchor. Holding capacity of these 

anchors varies; detailed information on holding capacity, 

comparison charts with illustrations, and characteristics 

specific to each design may be found in Section 2 of the 

support manual. 

When installed in conformance with manufacturer 

specifications and evidence thereof is provided, this would 

satisfy the requirement for individual pull testing. 

CAUTION: It should continually be emphasized that the 

anchor is only one component of the Rig Stability 

System(RSS) 

Screw- (helix-) type anchors have a direct correlation between 

anchor capacity and the torque required to install the anchor. 

Following the manufacturer's specific recommendations as to 

torquing, with proof thereof, is a valid method of determining 

anchor holding capacity. Torquing according to 

manufacturer's 

specifications is an acceptable nonpull-test method of 

determining anchor capacity. 

SHOP-MADE (IN-HOUSE FABRICATED) 

ANCHORS 

These anchors should be designed by a registered engineer 

and conform to accepted engineering practices. Written 

procedures shall be established for installation. 

These manufactured anchors should be proof tested for 

structural integrity and holding capacity. Records shall be 

maintained of test protocols and holding capacity based on 

soil type. 

Individual pull testing will not be required if anchors are 

installed in accordance with written procedures. Proof thereof 

will be required of installation protocols and proof-tested 

holding capacities. 

III:1-2

C. STABILITY CONSIDERATIONS 

FOUNDATION 

The area should be graded, leveled and maintained so that oil, 

water, drilling fluid, and other fluids will drain away from the 

working area. 

Safe Bearing Capacity shall be determined from the use of an 

appropriate table, soil core test, penetrometer test, flat-plate 

test, or other suitable soil test. When surface conditions are 

used to determine bearing capacity, care must be exercised to 

insure that the soil is homogeneous to a depth of at least twice 

the width of supplemental footing used to support the 

concentrated load. 

Supplemental footing shall be provided to distribute the 

concentrated loads from the mast and rig support points. The 

manufacturer's load distribution diagram will indicate these 

locations. In the absence of a manufacturer's diagram, the 

supplemental footing shall be designed to carry the maximum 

anticipated hook load, the gross weight of the mast, the mast 

mount, the traveling equipment, and the vertical component 

of guywire tension under operational loading conditions. 

These footings must also support the mast and mast weight 

during mast erection. 

GUYWIRES 

All guywires, as indicated by the manufacturer's diagram, 

should be in position and properly tensioned prior to 

commencing any work. 

In the absence of manufacturer recommendations, or where 

mast manufacturer's recommendations cannot be 

implemented, the diagram in Figure III:1-2 may be used. 

Other guying patterns may be used; however, they must be 

based on sound engineering principles as determined by a 

qualified person. These recommendations should be posted 

on the mast in a weatherproof container and should state the 

loading conditions for which they were prepared. Guywires 

should be 6x19 or 6x37 class, regular lay, made of improved 

plow steel (IPS) or better with independent wire-rope core 

(IWRC) and not previously used for any other application. 

Double saddle clips should be used, and wire rope should be 

installed in accordance with the manufacturer's 

Wellhead cellars present special foundation considerations. 

In addition to the obvious of collecting water and fluids that 

can seep into the ground, cellars also require unique mast 

support considerations. These should be analyzed by a 

qualified person to insure that an adequate mast foundation is 

provided. 

Small settlements (soil subsidence) at the beginning of rig-up 

is considered normal. External guywires should never be 

used for plumbing the mast. Rig foundations, guywire 

anchors and guywire tension should be checked at each tower 

(shift) change. 

Figure III:1-2. Anchor Location Diagram 

III:1-3

ecommendations. In the absence of manufacturer 

recommendations, API RP 9B shall be followed. 

GUYWIRE ANCHORS 

The mast manufacturer's recommendations shall be followed. 

In the absence of manufacturer recommenda-tions the 

location diagram, Figure III:1-3, may be used. 

Each zone requires an anchor of different holding capacity. 

If anchors are located in more than one zone, then all anchors 

should be of the capacity required for the greater capacity 

zone. For example, if one anchor is located in "ZONE C" and 

the remaining anchors are located in "ZONE D," all anchors 

shall meet the holding capacity specified in the chart for 

"ZONE C." See Figure III:1-4. 

Figure III:1-3. Reccommended Anchor Locations 

Figure III:1-4. Anchor Capacity Requirements for Each Zone 

III:1-4

D. OBSERVATIONS, DIRECTIONS, AND 

CONCLUSIONS 

VISUAL OBSERVATIONS 

There are characteristic visual observations that can serve as 

indicators of rig stability. They include, but are not limited 

to, the following: 

@ 

@ 

@ 

@ 

@ 

The foundation supports the rig, substructure, and all 

applied loads while in an operational mode, without 

excessive movement. Basically in a level and plumb 

configuration. 

No large movement is observable between the mast 

support structure and the rotary/setback support 

structure when the slips are set and the load is 

removed from the mast, or vice versa. 

The empty travel block hangs plumb with the 

centerline of the wellbore and the mast support 

structure remains level. 

The mast support structure and/or substructure does 

not lean to one side more than the other when the 

load is applied. The guywire on one side becomes 

noticeably taut while the guywire on the opposite 

side becomes slack. 

The guywire anchor(s) show(s) no visible signs of 

movement during the loading and unloading of the 

system while in operational mode. 

The chart presented in Figure III:1-5 may be used as a guide 

to the pretensioning of guywires. This method is commonly 

referred to as the Catenary Method (guywire sag method). 

SUPPORT MANUAL 

The support manual, entitled Guideline on the Stability of 

Well Servicing Derricks, is divided into work sections and 

intended 

to supplement this chapter. It provides a detailed analysis of 

existing guides and standards along with state-of-the-art 

developments. 

Section 3 provides the direction and guidance necessary to 

evaluate and select the proper system to assure rig stability. 

Section 4 discusses the installation of guywire anchor 

systems. It is extremely important to point out that stability 

is dependent on the entire system, and not on a single 

component. 

In the absence of support documentation or manufacturer 

specifications, Section 6 sets forth the criteria for performing 

effective pull testing. It further identifies what would be 

acceptable in lieu of actual pull testing. 

CONCLUSION 

No set of observations or recommendations should be so 

restrictive or subjective as to preclude the use of innovative 

approaches to derrick stability systems. Properly designed 

substructures and base beams have been used effectively and 

safely as anchorages for guywires. 

Engineering calculations based on sound engineering 

principals may also be used as evidence of an acceptable 

alternative to pull testing. Dead weight of equipment, 

fabricated components (i.e., padeyes) and other 

appurtenances are all considerations in determining rig 

stability. 

The derrick manufacturer's specifications and 

recom-mendations should be the preferred and primary means 

of determining derrick stability. 

Guywire anchors, newly installed according to the 

manufacturer's specifications, may be used without the 

III:1-5

Figure III:1-5. Catenary Method 

requirement for actual pull testing (This would qualify as 

meeting the criteria as an acceptable alternative to pull 

testing). If, however, there is a change in conditions, e.g., 

frozen ground 

to thawed ground, or if use of the anchor has been 

interrupted, the anchor shall be pull tested, with 

documentation thereof, prior to being placed back in service. 

E. BIBLIOGRAPHY 

American Petroleum Institute (API). 1988. Specification 4E: 

Specification for Drilling and Well Servicing Structures. 

API: Washington, D.C. 

Association of Oilwell Servicing Contractors (AOSC). 1988. 

Recommended Safe Procedures and Guidelines for Oil 

and Gas Well Servicing. AOSC: Dallas. 

International Association of Drilling Contractors (IADC). 

1990. Accident Prevention Manual. IADC: Houston. 

International Association of Drilling Contractors. 1979. 

Drilling Manual. IADC: Houston. 

Scardino, A. J. 1990. Guidelines on the Stability of Well 

Servicing Derricks. Sigma Associates Ltd.: Pass 

Christian, MS 

III:1-6


PETROLEUM REFINING PROCESSES 


The petroleum industry began with the successful drilling of 

the first commercial oil well in 1859, and the opening of the 

first refinery two years later to process the crude into 

kerosene. The evolution of petroleum refining from simple 

distillation to today's sophisticated processes has created a 

need for health and safety management procedures and safe 

work practices. To those unfamiliar with the industry, 

petroleum refineries may appear to be complex and confusing 

places. Refining is the processing of one complex mixture of 

hydrocarbons into a number of other complex mixtures of 

hydrocarbons. The safe and orderly processing of crude oil 

into flammable gases and liquids at high temperatures and 

pressures using vessels, equipment, and piping subjected to 

stress and corrosion requires considerable knowledge, 

control, and expertise. 

Safety and health professionals, working with process, 

chemical, instrumentation, and metallurgical engineers, assure 

that potential physical, mechanical, chemical, and health 

hazards are recognized and provisions are made for safe 

operating practices and appropriate protective measures. 

These 

A. Introduction. . . . . . . . . . . . . . . . . . . . . . . . III:2-1 

B. Overview of the Petroleum Industry. . . . . III:2-2 

C. Petroleum Refining Operations . . . . . . . III:2-11 

D. Description of Petroleum Refining 

Processes and Related Health and 

Safety Considerations. . . . . . . . . . . . . . III:2-15 

E. Other Refinery Operations. . . . . . . . . . . III:2-49 

F. Bibliography. . . . . . . . . . . . . . . . . . . . . . III:2-58 

Appendix III:2-1. Glossary. . . . . . . . . . . . . .III:2-59 

measures may include hard hats, safety glasses and goggles, 

safety shoes, hearing protection, respiratory protection, and 

protective clothing such as fire resistant clothing where 

required. In addition, procedures should be established to 

assure compliance with applicable regulations and standards 

such as hazard communications, confined space entry, and 

process safety management. 

This chapter of the technical manual covers the history of 

refinery processing, characteristics of crude oil, hydrocarbon 

types and chemistry, and major refinery products and 

by-products. It presents information on technology as 

normally practiced in present operations. It describes the 

more common refinery processes and includes relevant safety 

and health information. Additional information covers 

refinery utilities and miscellaneous supporting activities 

related to hydrocarbon processing. Field personnel will learn 

what to expect in various facilities regarding typical materials 

and process methods, equipment, potential hazards, and 

exposures. 

The information presented refers to fire prevention, industrial 

hygiene, and safe work practices, and is not intended to 

provide comprehensive guidelines for protective measures 

and/or compliance with regulatory requirements. As some of 

the terminology is industry-specific, a glossary is provided as 

an appendix. This chapter does not cover petrochemical 

processing. 

III:2-1

B. OVERVIEW OF THE PETROLEUM INDUSTRY 

BASIC REFINERY PROCESS -- 

DESCRIPTION AND HISTORY 

Petroleum refining has evolved continuously in response to 

changing consumer demand for better and different products. 

The original requirement was to produce kerosene as a 

cheaper and better source of light than whale oil. The 

development of the internal combustion engine led to the 

production of gasoline and diesel fuels. The evolution of the 

airplane created a need first for high-octane aviation gasoline 

and then for jet fuel, a sophisticated form of the original 

product, kerosene. Present-day refineries produce a variety of 

products including many required as feedstocks for the 

petrochemical industry. 

DISTILLATION PROCESSES 

The first refinery, opened in 1861, produced kerosene by 

simple atmospheric distillation. Its by-products included tar 

and naphtha. It was soon discovered that high- quality 

lubricating oils could be produced by distilling petroleum 

under vacuum. However, for the next 30 years kerosene was 

the product consumers wanted. Two significant events 

changed this situation: (1) invention of the electric light 

decreased the demand for kerosene, and (2) invention of the 

internal combustion engine created a demand for diesel fuel 

and gasoline (naphtha). 

THERMAL CRACKING PROCESSES 

With the advent of mass production and World War I, the 

number of gasoline-powered vehicles increased dramatically 

and the demand for gasoline grew accordingly. However, 

distillation processes produced only a certain amount of 

gasoline from crude oil. In 1913, the thermal cracking process 

was developed, which subjected heavy fuels to both pressure 

and intense heat, physically breaking the large molecules into 

smaller ones to produce additional gasoline and distillate 

fuels. Visbreaking, another form of thermal cracking, was 

developed in the late 1930s to produce more desirable and 

valuable products. 

CATALYTIC PROCESSES 

Higher-compression gasoline engines required higher-octane 

gasoline with better antiknock characteristics. The 

introduction of catalytic cracking and polymerization 

processes in the mid- to late 1930s met the demand by 

providing improved gasoline yields and higher octane 

numbers. 

Alkylation, another catalytic process developed in the early 

1940s, produced more high-octane aviation gasoline and 

petrochemical feedstocks for explosives and synthetic rubber. 

Subsequently, catalytic isomerization was developed to 

convert hydrocarbons to produce increased quantities of 

alkylation feedstocks. Improved catalysts and process 

methods such as hydrocracking and reforming were 

developed throughout the 1960s to increase gasoline yields 

and improve antiknock characteristics. These catalytic 

processes also produced hydrocarbon molecules with a 

double bond (alkenes) and formed the basis of the modern 

petrochemical industry. 

TREATMENT PROCESSES 

Throughout the history of refining, various treatment methods 

have been used to remove nonhydrocarbons, impurities, and 

other constituents that adversely affect the properties of 

finished products or reduce the efficiency of the conversion 

processes. Treating can involve chemical reaction and/or 

physical separation. Typical examples of treating are chemical 

sweetening, acid treating, clay contacting, caustic washing, 

hydrotreating, drying, solvent extraction, and solvent 

dewaxing. Sweetening compounds and acids desulfurize 

crude oil before processing and treat products during and 

after processing. 

Following the Second World War, various reforming 

processes improved gasoline quality and yield and produced 

higher-quality products. Some of these involved the use of 

catalysts and/or hydrogen to change molecules and remove 

sulfur. A number of 

Table III:2-1 HISTORY OF REFINING 

III:2-2

Year Process name Purpose By-products, etc. 

1862 Atmospheric distillation Produce kerosene Naphtha, tar, etc. 

1870 Vacuum distillation Lubricants (original) Asphalt, residual 

Cracking feedstocks (1930s) 

coker feedstocks 

1913 Thermal cracking Increase gasoline Residual, bunker fuel 

1916 Sweetening Reduce sulfur & odor Sulfur 

1930 Thermal reforming Improve octane number Residual 

1932 Hydrogenation Remove sulfur Sulfur 

1932 Coking Produce gasoline basestocks Coke 

1933 Solvent extraction Improve lubricant viscosity index Aromatics 

1935 Solvent dewaxing Improve pour point Waxes 

1935 Cat. polymerization Improve gasoline yield & octane number Petrochemical feedstocks 

1937 Catalytic cracking Higher octane gasoline Petrochemical feedstocks 

1939 Visbreaking Reduce viscosity Increased distillate, tar 

1940 Alkylation Increase gasoline octane & yield High-octane aviation 

gasoline 

1940 Isomerization Produce alkylation feedstock Naphtha 

1942 Fluid catalytic cracking Increase gasoline yield & octane Petrochemical feedstocks 

1950 Deasphalting Increase cracking feedstock Asphalt 

1952 Catalytic reforming Convert low-quality naphtha Aromatics 

1954 Hydrodesulfurization Remove sulfur Sulfur 

1956 Inhibitor sweetening Remove mercaptan Disulfides 

1957 Catalytic isomerization Convert to molecules with high Alkylation feedstocks 

octane number 

1960 Hydrocracking Improve quality and reduce sulfur Alkylation feedstocks 

1974 Catalytic dewaxing Improve pour point Wax 

1975 Residual hydrocracking Increase gasoline yield from residual Heavy residuals 

III:2-3

the more commonly used treating and reforming processes are 

described in this chapter of the manual. 

BASICS OF CRUDE OIL 

Crude oils are complex mixtures containing many different 

hydrocarbon compounds that vary in appearance and 

composition from one oil field to another. Crude oils range in 

consistency from water to tar-like solids, and in color from 

clear to black. An "average" crude oil contains about 84% 

carbon, 14% hydrogen, 1-3% sulfur, and less than 1% each of 

nitrogen, oxygen, metals, and salts. Crude oils are generally 

classified as paraffinic, naphthenic, or aromatic, based on the 

predominant proportion of similar hydrocarbon molecules. 

Mixed-base 

crudes have varying amounts of each type of hydrocarbon. 

Refinery crude base stocks usually consist of mixtures of two 

or more different crude oils. 

Relatively simple crude-oil assays are used to classify crude 

oils as paraffinic, naphthenic, aromatic, or mixed. One assay 

method (United States Bureau of Mines) is based on 

distillation, and another method (UOP "K" factor) is based on 

gravity and boiling points. More comprehensive crude assays 

determine the value of the crude (i.e., its yield and quality of 

useful products) and processing parameters. Crude oils are 

usually grouped according to yield structure. 

Table III:2-2. TYPICAL APPROXIMATE CHARACTERISTICS AND PROPERTIES AND GASOLINE 

POTENTIAL OF VARIOUS CRUDES (Representative average numbers) 

Naph. Octane 

Paraffins Aromatics Naphthenes Sulfur API gravity yield number 

Crude source (% vol) (% vol) (% vol) (% wt) (approx.) (% vol) (typical) 

Nigerian 37 9 54 0.2 36 28 60 

-Light 

Saudi 63 19 18 2 34 22 40 

-Light 

Saudi 60 15 25 2.1 28 23 35 

-Heavy 

Venezuela 35 12 53 2.3 30 2 60 

-Heavy 

Venezuela 52 14 34 1.5 24 18 50 

-Light 

USA - - - 0.4 40 - - 

-Midcont. Sweet 

USA 46 22 32 1.9 32 33 55 

-W. Texas Sour 

North Sea 50 16 34 0.4 37 31 50 

-Brent 

III:2-4

Crude oils are also defined in terms of API (American 

Petroleum Institute) gravity. The higher the API gravity, the 

lighter the crude. For example, light crude oils have high API 

gravities and low specific gravities. Crude oils with low 

carbon, high hydrogen, and high API gravity are usually rich 

in paraffins and tend to yield greater proportions of gasoline 

and light petroleum products; those with high carbon, low 

hydrogen, and low API gravities are usually rich in aromatics. 

Crude oils that contain appreciable quantities of hydrogen 

sulfide or other reactive sulfur compounds are called "sour." 

Those with less sulfur are called "sweet." Some exceptions to 

this rule are West Texas crudes, which are always considered 

"sour" regardless of their H2S content, and Arabian 

high-sulfur crudes, which are not considered "sour" because 

their sulfur compounds are not highly reactive. 

BASICS OF HYDROCARBON CHEMISTRY 

Crude oil is a mixture of hydrocarbon molecules, which are 

organic compounds of carbon and hydrogen atoms that may 

include from one to 60 carbon atoms. The properties of 

hydrocarbons depend on the number and arrangement of the 

carbon and hydrogen atoms in the molecules. The simplest 

hydrocarbon molecule is one carbon atom linked with four 

hydrogen atoms: methane. All other variations of petroleum 

hydrocarbons evolve from this molecule. 

Hydrocarbons containing up to four carbon atoms are usually 

gases; those with five to 19 carbon atoms are usually liquids; 

and those with 20 or more are solids. The refining process 

uses chemicals, catalysts, heat, and pressure to separate and 

combine the basic types of hydrocarbon molecules naturally 

found in crude oil into groups of similar molecules. The 

refining process also rearranges their structures and bonding 

patterns into different hydrocarbon molecules and 

compounds. Therefore it is the type of hydrocarbon, 

(paraffinic, naphthenic, or aromatic) rather than its specific 

chemical compounds that is significant in the refining 

process. 

Figure III:2-1 Typical Paraffins 

THREE PRINCIPAL GROUPS OR SERIES 

OF HYDROCARBON COMPOUNDS THAT 

OCCUR NATURALLY IN CRUDE OIL 

PARAFFINS 

The paraffinic series of hydrocarbon compounds found in 

crude oil have the general formula C n H 2n+2 and can be either 

straight chains (normal) or branched chains (isomers) of 

III:2-5

carbon atoms. The lighter, straight-chain paraffin molecules 

are found in gases and paraffin waxes. Examples of 

straight-chain molecules are methane, ethane, propane, and 

butane (gases containing from one to four carbon atoms), and 

pentane and hexane (liquids with five to six carbon atoms). 

The branched-chain (isomer) paraffins are usually found in 

heavier fractions of crude oil and have higher octane numbers 

than normal paraffins. These compounds are saturated 

hydrocarbons, with all carbon bonds satisfied, that is, the 

hydrocarbon chain carries the full complement of hydrogen 

atoms. 

AROMATICS 

Aromatics are unsaturated ring-type (cyclic) compounds 

which react readily because they have carbon atoms that are 

deficient in hydrogen. All aromatics have at least one benzene 

ring (a single-ring compound characterized by three double 

bonds alternating with three single bonds between six carbon 

atoms) as part of their molecular structure. Naphthalenes are 

fused double-ring aromatic compounds. The most complex 

aromatics, polynuclears (three or more fused aromatic rings), 

are found in heavier fractions of crude oil. 

NAPHTHENES 

Figure III:2-2 Typical Aromatics 

Naphthenes are saturated hydrocarbon groupings with the 

general formula C n H 2n , arranged in the form of closed rings 

(cyclic) and found in all fractions of crude oil except the very 

lightest. Single-ring naphthenes (monocycloparaffins) with 

five and six carbon atoms predominate, with two-ring 

naphthenes 

III:2-6

(dicycloparaffins) found in the heavier ends of naphtha. 

OTHER HYDROCARBONS 

ALKENES 

Alkenes are mono-olefins with the general formula C n H 2n and 

contain only one carbon-carbon double bond in the chain. 

The simplest alkene is ethylene, with two carbon atoms joined 

by a double bond and four hydrogen atoms. Olefins are 

usually formed by thermal and catalytic cracking and rarely 

occur naturally in unprocessed crude oil. 

DIENES AND ALKYNES 

Dienes, also known as diolefins, have two carbon-carbon 

double bonds. The alkynes, another class of unsaturated 

hydrocarbons, have a carbon-carbon triple bond within the 

molecule. Both these series of hydrocarbons have the general 

formula C n H 2n-2 . Diolefins such as 1,2-butadiene and 

1,3-butadiene, and alkynes 

such as acetylene occur in C 5 and lighter fractions from 

cracking. The olefins, diolefins, and alkynes are said to be 

unsaturated because they contain less than the amount of 

hydrogen necessary to saturate all the valences of the carbon 

atoms. These compounds are more reactive than paraffins or 

naphthenes and readily combine with other elements such as 

hydrogen, chlorine, and bromine. 

NONHYDROCARBONS 

SULFUR COMPOUNDS 

Sulfur may be present in crude oil as hydrogen sulfide (H 2 S), 

as compounds (e.g., mercaptans, sulfides, disulfides, 

thiophenes, etc.), or as elemental sulfur. Each crude oil has 

different amounts and types of sulfur compounds, but as a 

rule the proportion, stability, and complexity of the 

compounds are greater in heavier crude-oil fractions. 

Hydrogen sulfide is a primary contributor to corrosion in 

refinery processing units. Other corrosive substances are 

elemental sulfur and mercaptans. Moreover, the corrosive 

sulfur compounds have an obnoxious odor. 

Figure III:2-3 Typical Napthenes 

III:2-7

Figure III:2-4 Typical Alkenes 

Pyrophoric iron sulfide results from the corrosive action of 

sulfur compounds on the iron and steel used in refinery 

process equipment, piping, and tanks. The combustion of 

petroleum products containing sulfur compounds produces 

undesirables such as sulfuric acid and sulfur dioxide. 

Catalytic hydrotreating processes such as 

hydrodesulfurization remove sulfur compounds from refinery 

product streams. Sweetening processes either remove the 

obnoxious sulfur compounds or convert them to odorless 

disulfides, as in the case of mercaptans. 

OXYGEN COMPOUNDS 

Oxygen compounds such as phenols, ketones, and carboxylic 

acids occur in crude oils in varying amounts. 

NITROGEN COMPOUNDS 

Nitrogen is found in lighter fractions of crude oil as basic 

compounds, and more often in heavier fractions of crude oil 

as nonbasic compounds that may also include trace metals 

such as copper, vanadium, and/or nickel. Nitrogen oxides can 

form in process furnaces. The decomposition of nitrogen 

compounds in catalytic cracking and hydrocracking processes 

forms ammonia and cyanides that can cause corrosion . 

TRACE METALS 

Metals including nickel, iron, and vanadium are often found 

in crude oils in small quantities and are removed during the 

refining process. Burning heavy fuel oils in refinery furnaces 

Figure III:2-5. Typcial Diolefins and Alkynes 

III:2-8

and boilers can leave deposits of vanadium oxide and nickel 

oxide in furnace boxes, ducts, and tubes. It is also desirable 

to remove trace amounts of arsenic, vanadium, and nickel 

prior to processing as they can poison certain catalysts. 

SALTS 

Crude oils often contain inorganic salts such as sodium 

chloride, magnesium chloride, and calcium chloride in 

suspension or dissolved in entrained water (brine). These salts 

must be removed or neutralized before processing to prevent 

catalyst poisoning, equipment corrosion, and fouling. Salt 

corrosion is caused by the hydrolysis of some metal chlorides 

to hydrogen chloride (HCl) and the subsequent formation of 

hydrochloric acid when crude is heated. Hydrogen chloride 

may also combine with ammonia to form ammonium chloride 

(NH 4 Cl), which causes fouling and corrosion. 

CARBON DIOXIDE 

Carbon dioxide may result from the decomposition of 

bicarbonates present in or added to crude, or from steam used 

in the distillation process. 

NAPHTHENIC ACIDS 

Some crude oils contain naphthenic (organic) acids, which 

may become corrosive at temperatures above 450 o F when the 

acid value of the crude is above a certain level. 

MAJOR REFINERY PRODUCTS 

GASOLINE 

The most important refinery product is motor gasoline, a 

blend of hydrocarbons with boiling ranges from ambient 

temperatures to about 400 o F. The important qualities for 

gasoline are octane number (antiknock), volatility (starting 

and vapor lock), and vapor pressure (environmental control). 

Additives are often used to enhance performance and provide 

protection against oxidation and rust formation. 

KERSONE 

Kerosene is a refined middle-distillate petroleum product that 

finds considerable use as a jet fuel and around the world in 

cooking and space heating. When used as a jet fuel, some of 

the critical qualities are freeze point, flash point, and smoke 

point. Commercial jet fuel has a boiling range of about 

375-525º F, and military jet fuel 130-550º F. Kerosene, with 

less-critical specifications, is used for lighting, heating, 

solvents, and blending into diesel fuel. 

LIQUEFIED PETROLEUM GAS (LPG) 

LPG, which consists principally of propane and butane, is 

produced for use as fuel and is an intermediate material in the 

manufacture of petrochemicals. The important specifications 

for proper performance include vapor pressure and control of 

contaminants. 

DISTILLATE FUELS 

Diesel fuels and domestic heating oils have boiling ranges of 

about 400-700º F. The desirable qualities required for 

distillate fuels include controlled flash and pour points, clean 

burning, no deposit formation in storage tanks, and a proper 

diesel fuel cetane rating for good starting and combustion. 

RESIDUAL FUELS 

Many marine vessels, power plants, commercial buildings 

and industrial facilities use residual fuels or combinations of 

residual and distillate fuels for heating and processing. The 

two most critical specifications of residual fuels are viscosity 

and low sulfur content for environmental control. 

COKE AND ASPHALT 

Coke is almost pure carbon with a variety of uses from 

electrodes to charcoal briquets. Asphalt, used for roads and 

roofing materials, must be inert to most chemicals and 

weather conditions. 

III:2-9

SOLVENTS 

A variety of products, whose boiling points and hydrocarbon 

composition are closely controlled, are produced for use as 

solvents. These include benzene, toluene, and xylene. 

PETROCHEMICALS 

Many products derived from crude oil refining such as 

ethylene, propylene, butylene, and isobutylene are primarily 

intended for use as petrochemical feedstocks in the 

production of plastics, synthetic fibers, synthetic rubbers, and 

other products. 

LUBRICANTS 

Special refining processes produce lubricating oil base stocks. 

Additives such as demulsifiers, antioxidants, and viscosity 

improvers are blended into the base stocks to provide the 

characteristics required for motor oils, industrial greases, 

lubricants, and cutting oils. The most critical quality for 

lubricating-oil base stock is a high viscosity index, which 

provides for greater consistency under varying temperatures. 

COMMON REFINERY CHEMICALS 

LEADED GASOLINE ADDITIVES 

Tetraethyl lead (TEL) and tetramethyl lead (TML) are 

additives formerly used to improve gasoline octane ratings 

but are no longer in common use except in aviation gasoline. 

OXYGENATES 

Ethyl tertiary butyl ether (ETBE), methyl tertiary butyl ether 

(MTBE), tertiary amyl methyl ether (TAME), and other 

oxygenates improve gasoline octane ratings and reduce 

carbon monoxide emissions. 

CAUSTICS 

Caustics are added to desalting water to neutralize acids and 

reduce corrosion. They are also added to desalted crude in 

order to reduce the amount of corrosive chlorides in the tower 

overheads. They are used in some refinery treating processes 

to remove contaminants from hydrocarbon streams. 

SULFURIC ACID AND HYDROFLUORIC ACID 

Sulfuric acid and hydrofluoric acid are used primarily as 

catalysts in alkylation processes. Sulfuric acid is also used in 

some treatment processes. 

III:2-10

C. PETROLEUM REFINING OPERATIONS 

INTRODUCTION 

Petroleum refining begins with the distillation, or 

fractionation, of crude oils into separate hydrocarbon groups. 

The resultant products are directly related to the 

characteristics of the crude processed. Most distillation 

products are further converted into more usable products by 

changing the size and structure of the hydrocarbon molecules 

through cracking, reforming, and other conversion processes 

as discussed in this chapter. These converted products are 

then subjected to various treatment and separation processes 

such as extraction, hydrotreat-ing, and sweetening to remove 

undesirable constituents and improve product quality. 

Integrated refineries incorporate fractionation, conversion, 

treatment, and blending operations and may also include 

petrochemical processing. 

REFINING OPERATIONS 

Petroleum refining processes and operations can be separated 

into five basic areas: 

FRACTIONATION 

Fractionation (distillation) is the separation of crude oil in 

atmospheric and vacuum distillation towers into groups of 

hydrocarbon compounds of differing boiling-point ranges 

called "fractions" or "cuts." 

Conversion 

Conversion processes change the size and/or structure of 

hydrocarbon molecules. These processes include: 

@ 

decomposition (dividing) by thermal and 

catalytic cracking, 

@ unification (combining) through 

alkylation and polymerization, and 

TREATMENT 

@ alteration (rearranging) with 

isomerization and catalytic reforming . 

Treatment processes are intended to prepare hydrocarbon 

streams for additional processing and to prepare finished 

products. Treatment may include the removal or separation of 

aromatics and naphthenes as well as impurities and 

undesirable contaminants. Treatment may involve chemical 

or physical separation such as dissolving, absorption, or 

precipitation using a variety and combination of processes 

including desalting, drying, hydrodesulfurizing, solvent 

refining, sweetening, solvent extraction, and solvent 

dewaxing. 

FORMULATING AND BLENDING 

Formulating and blending is the process of mixing and 

combining hydrocarbon fractions, additives, and other 

components to produce finished products with specific 

performance properties. 

OTHER REFINING OPERATIONS 

Other refinery operations include light-ends recovery, 

sour-water stripping, solid waste and wastewater treatment, 

process-water treatment and cooling, storage, and handling, 

product movement, hydrogen production, acid and tail-gas 

treatment, and sulfur recovery. 

Auxiliary operations and facilities include steam and power 

generation; process and fire water systems; flares and relief 

systems; furnaces and heaters; pumps and valves; supply of 

steam, air, nitrogen, and other plant gases; alarms and 

sensors; noise and pollution controls; sampling, testing, and 

inspecting; and laboratory, control room, maintenance, and 

administrative facilities. 

III:2-11

III:2-12

Table III:2-3 OVERVIEW OF PETROLEUM REFINING PROCESSES 

Process name Action Method Purpose Feedstock(s) Product(s) 

FRACTIONATION PROCESSES 

Atmospheric Separation Thermal Separate Desalted crude Gas, gas oil, 

distillation fractions oil distillate,residu 

Vacuum distillation Separation Thermal Separate w/o Atmospheric Gas oil, lube 

cracking tower residual stock, residual 

CONVERSION PROCESSES ------- DECOMPOSITION 

Catalytic cracking Alteration Catalytic Upgrade Gas oil, coke Gasoline,petrogasoline 

distillate chemical 

feedstock 

Coking Polymerize Thermal Convert vacu- Residual,heavy Naphtha, gas 

um residuals oil, tar oil, coke 

Hydrocracking Hydrogenate Catalytic Convert to Gas oil, cracked Lighter, higherlighter 

HCs oil, residual qualityproducts 

*Hydrogen Steam Decompose Thermal/cat. Produce Desulfurized Hydrogen, CO, 

Reforming hydrogen gas, O 2 , steam CO 2 

*Steam Cracking Decompose Thermal Crack large Atm tower hvy Cracked 

molecules fuel/distillate naphtha, 

coke,residual 

Visbreaking Decompose Thermal Reduce Atmospheric Distillate, tar 

viscosity tower residual 

CONVERSION PROCESSES ------- UNIFICATION 

Alkylation Combining Catalytic Unite olefins Tower isobu- Iso-octane 

& isoparaffins tane/crckr olefin (alkylate) 

Grease com- Combining Thermal Combine soaps Lube oil, fatty Lubricating 

pounding & oils acid, alkymetal grease 

Polymerization Polymerize Catalytic Unite 2 or Cracker olefins High-octane 

more olefins 

naphtha, 

petrochemical 

stocks 

CONVERSION PROCESSES ----- ALTERATION or REARRANGEMENT 

Catalytic reforming Alteration/ Catalytic Upgrade low- Coker/hydro- High oct. 

dehydration octane naphtha cracker naphtha reformate/aromatic 

Isomerization Rearrange Catalytic Convert strght Butane, pentane, Isobutane/penchain 

to branch hexane tane/hexane 

III:2-13

TREATMENT PROCESSES 

*Amine Treating Treatment Absorption Remove acidic Sour gas, HCs Acid free 

contaminants w/CO 2 & H 2 S gases & 

liquid HCs 

Desalting Dehydration Absorption Remove Crude oil Desalted 

contaminants 

crude 

oil 

Drying & Sweeten- Treatment Abspt/therm Remove H 2 O Liq HCs, LPG, Sweet & 

ing & sulfur cmpds alky. feedstk dry hydrocarbons 

*Furfural Extrac- Solvent extr. Absorption Upgrade mid Cycle oils & High tion 

distillate & lube feedstocks quality dielubes 

sel & lube 

oil 

Hydrodesulfur- Treatment Catalytic Remove sulfur, High-sulfur Deization 

contaminants residual/gas oil sulfurized 

olefins 

Hydrotreating Hydrogenation Catalytic Remv impurities Residuals, Cracker 

saturate Hcs cracked HCs feed, 

distillate, 

lube 

*Phenol extraction Solvent extr. Abspt/therm Improve visc. Lube oil base High 

index, color stocks quality lube 

oils 

Solvent deasphalting Treatment Absorption Remove asphalt Vac. tower resi- Heavy lube 

dual, propane oil, asphalt 

Solvent dewaxing Treatment Cool/filter Remve wax Vac. tower lube Dewaxed 

from lube stocks oils lube 

basestock 

Solvent Extraction Solvent extr. Abspt/precip. Separate unsat. Gas oil, reform- Highoils 

ate, distillate octane 

gasoline 

Sweetening Treatment Catalytic Remv H2S,con- Untreated distil- Highvert 

mercaptan late/gasoline quality 

distilate/ 

gasoline 

*NOTE: These processes are not depicted in the refinery process flow chart. 

III:2-14

D. DESCRIPTION OF PETROLEUM REFINING 

PROCESSES AND RELATED HEALTH AND SAFETY 

CONSIDERATIONS 

CRUDE OIL PRETREATMENT 

(DESALTING) 

Crude oil often contains water, inorganic salts, suspended 

solids, and water-soluble trace metals. As a first step in the 

refining process, to reduce corrosion, plugging, and fouling 

of equipment and to prevent poisoning the catalysts in 

processing units, these contaminants must be removed by 

desalting (dehydration). 

The two most typical methods of crude-oil desalting, 

chemical and electrostatic separation, use hot water as the 

extraction agent. In chemical desalting, water and chemical 

surfactant (demulsifiers) are added to the crude, heated so that 

salts and other impurities dissolve into the water or attach to 

the water, and then held in a tank where they settle out. 

Electrical desalting is the application of high-voltage 

electrostatic charges to concentrate suspended water globules 

in the bottom of the settling tank. Surfactants are added only 

when the crude has a large amount of suspended solids. Both 

methods of desalting are continuous. A third and 

less-common process involves filtering heated crude using 

diatomaceous earth. 

The feedstock crude oil is heated to between 150 o and 350 o F 

to reduce viscosity and surface tension for easier mixing and 

separation of the water. The temperature is limited by the 

vapor pressure of the crude-oil feedstock. 

In both methods other chemicals may be added. Ammonia is 

often used to reduce corrosion. Caustic or acid may be added 

to adjust the pH of the water wash. 

Wastewater and contaminants are discharged from the bottom 

of the settling tank to the wastewater treatment facility. The 

desalted crude is continuously drawn from the top of the 

settling tanks and sent to the crude distillation (fractionating) 

tower. 

HEALTH AND SAFETY CONSIDERATIONS 

Fire Prevention and Protection 

The potential exists for a fire due to a leak or release of crude 

from heaters in the crude desalting unit. Low boiling point 

components of crude may also be released if a leak occurs. 

Safety 

Inadequate desalting can cause fouling of heater tubes and 

heat exchangers throughout the refinery. Fouling restricts 

product flow and heat transfer and leads to failures due to 

increased pressures and temperatures. Corrosion, which 

occurs due to the presence of hydrogen sulfide, hydrogen 

chloride, naphthenic (organic) acids, and other contaminants 

in the crude oil, also causes equipment failure. Neutralized 

salts (ammonium chlorides and sulfides), when moistened by 

Table III:2-4: DESALTING PROCESS 

Feedstocks From Process Typical products............ To 

Crude Storage Treating Desalted crude..........Atmospheric distillation tower 

Waste water..........................Treatment 

III:2-15

Figure II:2-7 Electrostatic Desalting 

condensed water, can cause corrosion. Overpressuring the 

unit is another potential hazard that causes failures. 

Health 

Because this is a closed process, there is little potential for 

exposure to crude oil unless a leak or release occurs. Where 

elevated operating temperatures are used when desalting sour 

crudes, hydrogen sulfide will be present. There is the 

possibility of exposure to ammonia, dry chemical 

demulsifiers, caustics, and/or acids during this operation. Safe 

work practices and/or the use of appropriate personal 

protective equipment may be needed for exposures to 

chemicals and other hazards such as heat, and during process 

sampling, inspection, maintenance, and turnaround activities. 

Depending on the crude feedstock and the treatment 

chemicals used, the wastewater will contain varying amounts 

of chlorides, sulfides, bicarbonates, ammonia, hydrocarbons, 

phenol, and suspended solids. If diatomaceous earth is used 

in filtration, exposures should be minimized or controlled. 

Diatomaceous earth can contain silica in very fine particle 

size, making this a potential respiratory hazard. 

III:2-16

CRUDE OIL DISTILLATION 

(FRACTIONATION) 

The first step in the refining process is the separation of crude 

oil into various fractions or straight-run cuts by distillation in 

atmospheric and vacuum towers. The main fractions or 

"cuts" obtained have specific boiling-point ranges and can be 

classified in order of decreasing volatility into gases, light 

distillates, middle distillates, gas oils, and residuum. 

ATMOSPHERIC DISTILLATION TOWER 

At the refinery, the desalted crude feedstock is preheated 

using recovered process heat. The feedstock then flows to a 

direct-fired crude charge heater where it is fed into the 

vertical distillation column just above the bottom, at pressures 

slightly above atmospheric and at temperatures ranging from 

650º to 700º F (heating crude oil above these temperatures 

may cause undesirable thermal cracking). All but the heaviest 

fractions flash into vapor. As the hot vapor rises in the tower, 

its temperature is reduced. Heavy fuel oil or asphalt residue 

is taken from the bottom. At successively higher points on 

the tower, the various major products 

including lubricating oil, heating oil, kerosene, gasoline, and 

uncondensed gases (which condense at lower temperatures) 

are drawn off. 

The fractionating tower, a steel cylinder about 120 feet high, 

contains horizontal steel trays for separating and collecting 

the liquids. At each tray, vapors from below enter 

perforations and bubble caps. They permit the vapors to 

bubble through the liquid on the tray, causing some 

condensation at the temperature of that tray. An overflow 

pipe drains the condensed liquids from each tray back to the 

tray below, where the higher temperature causes 

re-evaporation. The evaporation, condensing, and scrubbing 

operation is repeated many times until the desired degree of 

product purity is reached. Then side streams from certain 

trays are taken off to obtain the desired fractions. Products 

ranging from uncondensed fixed gases at the top to heavy fuel 

oils at the bottom can be taken continuously from a 

fractionating tower. Steam is often used in towers to lower 

the vapor pressure and create a partial vacuum. The 

distillation process separates the major constituents of crude 

oil into so-called straight-run products. Sometimes crude oil 

is "topped" by distilling off only the lighter fractions, leaving 

a heavy residue that is often distilled further under high 

vacuum. 

Table III:2-5. ATMOSPHERIC DISTILLATION PROCESSES 

Feedstocks From Process Typical products................. To 

Crude Desalting Separation Gases.................................. Fuel or gas recovery 

Naphthas............................ Reforming or treating 

Kero or distillates.............. Treating 

Gas oil............................... Catalytic cracking 

Residual............................ Vacuum tower or visbreaker 

III:2-17

Figure III:2-8 Atmospheric Distillation 

VACUUM DISTILLATION TOWER 

In order further to distill the residuum or topped crude from 

the atmospheric tower at higher temperatures, reduced 

pressure is required to prevent thermal cracking. The process 

takes place in one or more vacuum distillation towers. The 

principles of vacuum distillation resemble those of fractional 

distillation and, except that larger-diameter columns are used 

to maintain comparable vapor velocities at the reduced 

pressures, the equipment is also similar. The internal designs 

of some vacuum towers are different from atmospheric towers 

in that random packing and demister pads are used instead of 

trays. A typical first-phase vacuum tower may produce gas 

oils, lubricating-oil base stocks, and heavy residual for 

propane deasphalting. A second-phase tower operating at 

lower vacuum may distill surplus residuum from the 

atmospheric tower, which is not used for lube-stock 

processing, and surplus residuum from the first vacuum tower 

not used for deasphalting. Vacuum towers are typically used 

to separate catalytic cracking feedstocks from surplus 

residuum. 

OTHER DISTILLATION TOWERS (COLUMNS) 

Within refineries there are numerous other, smaller 

distillation towers called columns, designed to separate 

specific and unique products. Columns all work on the same 

principles as the towers described above. For example, a 

depropanizer is a small column designed to separate propane 

and lighter gases from butane and heavier components. 

Another larger column is used to separate ethyl benzene and 

xylene. Small "bubble" towers called strippers use steam to 

remove trace amounts of light products from heavier product 

streams. 



III:2-18

Even though these are closed processes, heaters and 

exchangers in the atmospheric and vacuum distillation units 

could provide a source of ignition, and the potential for a fire 

exists should a leak or release occur. 


An excursion in pressure, temperature, or liquid levels may 

occur if automatic control devices fail. Control of 

temperature, pressure, and reflux within operating parameters 

is needed to prevent thermal cracking within the distillation 

towers. Relief systems should be provided for overpressure 

and operations monitored to prevent crude from entering the 

reformer charge. 

The sections of the process susceptible to corrosion include 

(but may not be limited to) preheat exchanger (HCl and H 2 S), 

preheat furnace and bottoms exchanger (H 2 S and sulfur 

compounds), atmospheric tower and vacuum furnace (H 2 S, 

sulfur compounds, and organic acids), vacuum tower (H 2 S 

and organic acids), and overhead (H 2 S, HCl, and water). 

Where sour crudes are processed, severe corrosion can occur 

in furnace tubing and in both atmospheric and vacuum towers 

where metal temperatures exceed 450º F. Wet H 2 S also will 

cause cracks in steel. When processing high-nitrogen crudes, 

nitrogen oxides can form in the flue gases of furnaces. 

Nitrogen oxides are corrosive to steel when cooled to low 

temperatures in the presence of water. 

Chemicals are used to control corrosion by hydrochloric acid 

produced in distillation units. Ammonia may be injected into 

the overhead stream prior to initial condensation and/or an 

alkaline solution may be carefully injected into the hot 

crude-oil feed. If sufficient wash-water is not injected, 

deposits of ammonium chloride can form and cause serious 

corrosion. Crude feedstocks may contain appreciable 

amounts of water in suspension which can separate during 

startup and, along with water remaining in the tower from 

steam purging, settle in the bottom of the tower. This water 

can be heated to the boiling point and create an instantaneous 

vaporization explosion upon contact with the oil in the unit. 

Health 

Atmospheric and vacuum distillation are closed processes and 

exposures are expected to be minimal. When sour 

(high-sulfur) crudes are processed, there is potential for 

exposure to hydrogen sulfide in the preheat exchanger and 

furnace, tower flash zone and overhead system, vacuum 

furnace and tower, and bottoms exchanger. Hydrogen 

chloride may be present in the preheat exchanger, tower top 

zones, and overheads. Wastewater may contain water-soluble 

sulfides in high concentrations and other water-soluble 

compounds such as ammonia, chlorides, phenol, mercaptans, 

etc., depending upon the crude feedstock and the treatment 

chemicals. Safe work practices and/or the use of appropriate 

personal protective equipment may be needed for exposures 

to chemicals and other hazards such as heat and noise, and 

during sampling, inspection, maintenance, and turnaround 

activities. 

Table III:2-6 VACUUM DISTILLATION PROCESS 

Feedstocks From Process Typical products................... To 

Residuals Atmospheric Separation Gas oils................................. Catalytic cracker 

tower Lubricants............................. Hydrotreating or solvent extraction 

Residual................................ Deasphalter, visbreaker, or coker 

III:2-19

Figure III:2-9 Vacuum Distillation 

SOLVENT EXTRACTION AND 

DEWAXING 

Solvent treating is a widely used method of refining 

lubricating oils as well as a host of other refinery stocks. 

Since distillation (fractionation) separates petroleum products 

into groups only by their boiling-point ranges, impurities may 

remain. These include organic compounds containing sulfur, 

nitrogen, and oxygen; inorganic salts and dissolved metals; 

and soluble salts that were present in the crude feedstock. In 

addition, kerosene and distillates may have trace amounts of 

aromatics and naphthenes, and lubricating oil base-stocks 

may contain wax. Solvent refining processes including 

solvent extraction and solvent dewaxing usually remove these 

undesirables at intermediate refining stages or just before 

sending the product to storage. 

SOLVENT EXTRACTION 

The purpose of solvent extraction is to prevent corrosion, 

protect catalyst in subsequent processes, and improve finished 

products by removing unsaturated, aromatic hydrocarbons 

from lubricant and grease stocks. The solvent extraction 

process separates aromatics, naphthenes, and impurities from 

the product stream by dissolving or precipitation. The 

feedstock is first dried and then treated using a continuous 

countercurrent solvent treatment operation. In one type of 

process, the feedstock is washed with a liquid in which the 

substances to be removed are more soluble than in the desired 

resultant product. In another process, selected solvents are 

added to cause impurities to precipitate out of the product. In 

the adsorption process, highly porous solid materials collect 

liquid molecules on their surfaces. 

III:2-20

The solvent is separated from the product stream by heating, 

evaporation, or fractionation, and residual trace amounts are 

subsequently removed from the raffinate by steam stripping 

or vacuum flashing. Electric precipitation may be used for 

separation of inorganic compounds. The solvent is then 

regenerated to be used again in the process. 

The most widely used extraction solvents are phenol, furfural, 

and cresylic acid. Other solvents less frequently used are 

liquid sulfur dioxide, nitrobenzene, and 2,2' dichloroethyl 

ether. The selection of specific processes and chemical 

agents depends on the nature of the feedstock being treated, 

the contaminants present, and the finished product 

requirements. 

Table III:2-7. SOLVENT EXTRACTION PROCESS 

Feedstocks From Process Typical products.................... To 

Naphthas Atm. tower Treating High octane gasoline............... Treating or blending 

Distillates Refined Fuels.......................... Treating or blending 

Kerosene Spent agents............................ Treatment or recycle 

Figure III:2-10 Aromatics Extraction 

Diagrams in Figures II:2-10, 11, 12, 13, 15, and 20 

reproduced with the permission of Shell International 

Petroleum Company Limited. 

III:2-21

Table III:2-8 SOLVENT DEWAXING PROCESS 

Feedstocks From Process Typical products................To 

Lube basestock Vacuum tower Treating Dewaxed lubes or wax....... Hydrotreating 

Spent agents....................... Treatment or recycle 

SOLVENT DEWAXING 

Solvent dewaxing is used to remove wax from either distillate 

or residual basestocks at any stage in the refining process. 

There are several processes in use for solvent dewaxing, but 

all have the same general steps, which are: (1) mixing the 

feedstock with a solvent, (2) precipitating the wax from the 

mixture by chilling, and (3) recovering the solvent from the 

wax and dewaxed oil for recycling by distillation and steam 

stripping. Usually two solvents are used: toluene, which 

dissolves the oil and maintains fluidity at low temperatures, 

and methyl ethyl ketone (MEK), which dissolves little wax at 

low temperatures and acts as a wax precipitating agent. Other 

solvents that are sometimes used include benzene, methyl 

isobutyl ketone, propane, petroleum naphtha, ethylene 

dichloride, methylene chloride, and 

sulfur dioxide. In addition, there is a catalytic process used 

as an alternate to solvent dewaxing. 



Solvent treatment is essentially a closed process and, 

although operating pressures are relatively low, the potential 

exists for fire from a leak or spill contacting a source of 

ignition such as the drier or extraction heater. In solvent 

dewaxing, disruption of the vacuum will create a potential 

fire hazard by allowing air to enter the unit. 

Health 

Because solvent extraction is a closed process, exposures are 

expected to be minimal under normal operating conditions. 

However, there is a potential for 

exposure to extraction solvents 

such as phenol, furfural, glycols, 

methyl ethyl ketone, amines, and 

other process chemicals. Safe work 

practices and/or the use of 

appropriate personal protective 

equipment may be needed for 

exposures to chemicals and other 

hazards such as noise and heat, and 

during repair, inspection, 

maintenance, and turnaround 

activities. 

III:2-22

Table III:2-9 VISBREAKING PROCESS 

Feedstocks From Process Typical products................ To 

Residual Atmospheric tower Decompose Gasoline or distillate...........Treating or blending 

Vacuum tower 

Vapor.............................Hydrotreater 

Residue...........................Stripper or recycle 

Gases..............................Gas plant 

THERMAL CRACKING 

Because the simple distillation of crude oil produces amounts 

and types of products that are not consistent with those 

required by the marketplace, subsequent refinery processes 

change the product mix by altering the molecular structure of 

the hydrocarbons. One of the ways of accomplishing this 

change is through "cracking," a process that breaks or cracks 

heavier, higher boiling-point petroleum fractions into more 

valuable products such as gasoline, fuel oil, and gas oils. The 

two basic types of cracking are thermal cracking, using heat 

and pressure, and catalytic cracking. 

The first thermal cracking process was developed around 

1913. Distillate fuels and heavy oils were heated under 

pressure in large drums until they cracked into smaller 

molecules with better antiknock characteristics. However, 

this method produced large amounts of solid, unwanted coke. 

This early process has evolved into the following applications 

of thermal cracking: visbreaking, steam cracking, and coking. 

VISBREAKING PROCESS 

Visbreaking, a mild form of thermal cracking, significantly 

lowers the viscosity of heavy crude-oil residue without 

affecting the boiling point range. Residual from the 

atmospheric distillation tower is heated (800-950º F) at 

atmospheric pressure and mildly cracked in a heater. It is then 

quenched with cool gas oil to control overcracking, and 

flashed in a distillation tower. Visbreaking is used to reduce 

the pour point of waxy residues and reduce the viscosity of 

residues used for blending with lighter fuel oils. Middle 

distillates may also be produced, depending on product 

demand. The thermally cracked residue tar, which 

accumulates in the bottom of the fractionation tower, is 

vacuum flashed in a stripper and the distillate recycled. 

the 

Figure III:2-12 Visbreaking 

III:2-23

STEAM CRACKING PROCESS 

Steam cracking is a petrochemical process sometimes used 

in refineries to produce olefinic raw materials (e.g., ethylene) 

from various feedstocks for petrochemicals manufacture. The 

feedstocks range from ethane to vacuum gas oil, with heavier 

feeds giving higher yields of by-products such as naphtha. 

The most common feeds are ethane, butane, and naphtha. 

Steam cracking is carried out at temperatures of 1,500-1,600º 

F, and at pressures slightly above atmospheric. Naphtha 

produced from steam cracking contains benzene, which is 

extracted prior to hydrotreating. Residual from steam 

cracking is sometimes blended into heavy fuels. 

COKING PROCESSES 

Coking is a severe method of thermal cracking used to 

upgrade heavy residuals into lighter products or distillates. 

Coking produces straight-run gasoline (coker naphtha) and 

various middle-distillate fractions used as catalytic cracking 

feedstocks. The process so completely reduces hydrogen that 

the residue is a form of carbon called "coke." The two most 

common processes are delayed coking and continuous 

(contact or fluid) coking. Three typical types of coke are 

obtained (sponge coke, honeycomb coke, and needle coke) 

depending upon the reaction mechanism, time, temperature, 

and the crude feedstock. 

Delayed Coking 

In delayed coking the heated charge (typically residuum from 

atmospheric distillation towers) is transferred to large coke 

drums which provide the long residence time needed to allow 

the cracking reactions to proceed to completion. Initially the 

heavy feedstock is fed to a furnace which heats the residuum 

to high temperatures (900-950º F) at low pressures (25-30 

psi) and is designed and controlled to prevent premature 

coking in the heater tubes. The mixture is passed from the 

heater to one or more coker drums where the hot material is 

held approximately 24 hours (delayed) at pressures of 25-75 

psi, until it cracks into lighter products. Vapors from the 

drums are returned to a fractionator where gas, naphtha, and 

gas oils are separated out. The heavier hydrocarbons 

produced in the fractionator are recycled through the furnace. 

After the coke reaches a predetermined level in one drum, the 

flow is diverted to another drum to maintain continuous 

operation. The full drum is steamed to strip out uncracked 

hydrocarbons, cooled by water injection, and decoked by 

mechanical or hydraulic methods. The coke is mechanically 

removed by an auger rising from the bottom of the drum. 

Hydraulic decoking consists of fracturing the coke bed with 

high-pressure water ejected from a rotating cutter. 

Table III:2-10 COKING PROCESSES 

Feedstocks From Process Typical products............ To 

Residual Atmospheric & vac- Decomposition Naphtha, gasoline...........Distillation column, 

uum catalytic cracker 

blending 

Clarified oil Catalytic cracker Coke........................... Shipping, recycle 

Tars Various units Gas oil........................ Catalytic cracking 

Wastewater Treatment 

(sour) 

Gases 

Gas plant 

III:2-24


Fire Protection and Prevention 

Because thermal cracking is a closed process, the primary 

potential for fire is from leaks or releases of liquids, gases, or 

vapors reaching an ignition source such as a heater. The 

potential for fire is present in coking operations due to vapor 

or product leaks. Should coking temperatures get out of 

control, an exothermic reaction could occur within the coker. 


In thermal cracking when sour crudes are processed, 

corrosion can occur where metal temperatures are between 

450º and 900º F. Above 900º F coke forms a protective layer 

on the metal. The furnace, soaking drums, lower part of the 

tower, and high-temperature exchangers are usually subject 

to corrosion. Hydrogen sulfide corrosion in coking can also 

occur when temperatures are not properly controlled above 

900º F. 

Continuous Coking 

Continuous (contact or fluid) coking is a moving-bed process 

that operates at temperatures higher than delayed coking. In 

continuous coking, thermal cracking occurs by using heat 

transferred from hot, recycled coke particles to feedstock in 

a radial mixer, called a reactor, at a pressure of 50 psi. Gases 

and vapors are taken from the reactor, quenched to stop any 

further reaction, and fractionated. The reacted coke enters a 

surge drum and is lifted to a feeder and classifier where the 

larger coke particles are removed as product. The remaining 

coke is dropped into the preheater for recycling with 

feedstock. Coking occurs both in the reactor and in the surge 

drum. The process is automatic in that there is a continuous 

flow of coke and feedstock. 

Continuous thermal changes can lead to bulging and cracking 

of coke drum shells. In coking, temperature control must 

often be held within a 10-20º F range, as high temperatures 

will produce coke that is too hard to cut out of the drum. 

Conversely, temperatures that are too low will result in a high 

asphaltic-content slurry. Water or steam injection may be 

used to prevent buildup of coke in delayed coker furnace 

tubes. Water must be completely drained from the coker, so 

as not to cause an explosion upon recharging with hot coke. 

Provisions for alternate means of egress from the working 

platform on top of coke drums are important in the event of 

an emergency. 

Health 

The potential exists for exposure to hazardous gases such as 

hydrogen sulfide and carbon monoxide, and trace polynuclear 

aromatics (PNAs) associated with coking operations. When 

coke is moved as a slurry, oxygen depletion may occur within 

confined spaces such as storage silos, since wet carbon will 

adsorb oxygen. Wastewater may be highly alkaline and 

contain 

III:2-25

oil, sulfides, ammonia, and/or phenol. The potential exists in 

the coking process for exposure to burns when handling hot 

coke or in the event of a steam-line leak, or from steam, hot 

water, hot coke, or hot slurry that may be expelled when 

opening cokers. Safe work practices and/or the use of 

appropriate personal protective equipment may be needed for 

exposures to chemicals and other hazards such as heat and 

noise, and during process sampling, inspection, maintenance, 

and turnaround activities. (Note: coke produced from 

petroleum is a different product from that generated in the 

steel-industry coking process.) 

CATALYTIC CRACKING 

Catalytic cracking breaks complex hydrocarbons into simpler 

molecules in order to increase the quality and quantity of 

lighter, more desirable products and decrease the amount of 

residuals. This process rearranges the molecular structure of 

hydrocarbon compounds to convert heavy hydrocarbon 

feedstocks into lighter fractions such as kerosene, gasoline, 

LPG, heating oil, and petrochemical feedstocks. 

Catalytic cracking is similar to thermal cracking except that 

catalysts facilitate the conversion of the heavier molecules 

into lighter products. Use of a catalyst (a material that assists 

a chemical reaction but does not take part in it) in the 

cracking reaction increases the yield of improved-quality 

products under much less severe operating conditions than in 

thermal cracking. Typical temperatures are from 850-950º F 

at much lower 

pressures of 10-20 psi. The catalysts used in refinery 

cracking units are typically solid materials (zeolite, aluminum 

hydrosilicate, treated bentonite clay, fuller's earth, bauxite, 

and silica-alumina) that come in the form of powders, beads, 

pellets or shaped materials called extrudites. 

There are three basic functions in the catalytic cracking 

process: 

Reaction: Feedstock reacts with catalyst and cracks into 

different hydrocarbons. 

Regeneration: Catalyst is reactivated by burning off coke. 

Fractionation: Cracked hydrocarbon stream is separated into 

various products. 

The three types of catalytic cracking processes are fluid 

catalytic cracking (FCC), moving-bed catalytic cracking, and 

Thermofor catalytic cracking (TCC). The catalytic cracking 

process is very flexible, and operating parameters can be 

adjusted to meet changing product demand. In addition to 

cracking, catalytic activities include dehydrogenation, 

hydrogenation, and isomerization. 

FLUID CATALYTIC CRACKING 

The most common process is FCC, in which the oil is cracked 

in the presence of a finely divided catalyst which is 

maintained in an aerated or fluidized state by the oil vapors. 

The fluid 

Table III:2-11 CATALYTIC CRACKING PROCESS 

Feedstock From Process Typical products............................... To 

Gas oils Towers, coker Decomposition, Gasoline............................................Treater or blend 

Visbreaker alteration Gases................................................Gas plant 

Deasphalted Deasphalter Middle distillates...............................Hydrotreat, blend, or 

recycle 

oils 

Petrochem feedstocks.......................Petrochem or other 

Residue..............................................Residual fuel blend 

III:2-26

Figure III:2-14 Fluid Catalytic Cracking 

cracker consists of a catalyst section and a fractionating 

section that operate together as an integrated processing unit. 

The catalyst section contains the reactor and regenerator, 

which with the standpipe and riser forms the catalyst 

circulation unit. The fluid catalyst is continuously circulated 

between the reactor and the regenerator using air, oil vapors, 

and steam as the conveying media. 

A typical FCC process involves mixing a preheated 

hydrocarbon charge with hot, regenerated catalyst as it enters 

the riser leading to the reactor. The charge is combined with 

a recycle stream within the riser, vaporized, and raised to 

reactor temperature (900-1,000º F) by the hot catalyst. As the 

mixture travels up the riser, the charge is cracked at 10-30 

psi. 

In the more modern FCC units, all cracking takes place in the 

riser. The "reactor" no longer functions as a reactor; it merely 

serves as a holding vessel for the cyclones. This cracking 

continues until the oil vapors are separated from the catalyst 

in the reactor cyclones. The resultant product stream 

(cracked 

product) is then charged to a fractionating column where it is 

separated into fractions, and some of the heavy oil is recycled 

to the riser. 

Spent catalyst is regenerated to get rid of coke that collects on 

the catalyst during the process. Spent catalyst flows through 

the catalyst stripper to the regenerator, where most of the 

coke deposits burn off at the bottom where preheated air and 

spent catalyst are mixed. Fresh catalyst is added and worn-out 

catalyst removed to optimize the cracking process. 

MOVING BED CATALYTIC CRACKING 

The moving-bed catalytic cracking process is similar to the 

FCC process. The catalyst is in the form of pellets that are 

moved continuously to the top of the unit by conveyor or 

pneumatic lift tubes to a storage hopper, then flow downward 

by gravity through the reactor, and finally to a regenerator. 

The regenerator and hopper are isolated from the reactor by 

steam seals. The cracked product is separated into recycle gas, 

oil, clarified oil, distillate, naphtha, and wet gas. 

III:2-27

THERMOFOR CATALYTIC CRACKING 

In a typical thermofor catalytic cracking unit, the preheated 

feedstock flows by gravity through the catalytic reactor bed. 

The vapors are separated from the catalyst and sent to a 

fractionating tower. The spent catalyst is regenerated, cooled, 

and recycled. The flue gas from regeneration is sent to a 

carbon-monoxide boiler for heat recovery. 



Liquid hydrocarbons in the catalyst or entering the heated 

combustion air stream should be controlled to avoid 

exothermic reactions. Because of the presence of heaters in 

catalytic cracking units, the possibility exists for fire due to 

a leak or vapor release. Fire protection including concrete or 

other insulation on columns and supports, or fixed water 

spray or fog systems where insulation is not feasible and in 

areas where firewater hose streams cannot reach, should be 

considered. In some processes, caution must be taken to 

assure prevent explosive concentrations of catalyst dust 

during recharge or disposal. When unloading any coked 

catalyst, the possibility exists for iron sulfide fires. Iron 

sulfide will ignite spontaneously when exposed to air and 

therefore mus be wetted with water to prevent it from igniting 

vapors. Coked catalyst may be either cooled below 120º F 

before they are dumped from the reactor, or dumped into 

containers that have been purged and inerted with nitrogen 

and then cooled before further handling. 


Regular sampling and testing of the feedstock, product, and 

recycle streams should be performed to assure that the 

cracking process is working as intended and that no 

contaminants have entered the process stream. Corrosives or 

deposits in the feedstock can foul gas compressors. 

Inspections of critical equipment including pumps, 

compressors, furnaces, and heat exchangers should be 

conducted as needed. When processing sour crude, corrosion 

may be expected where temperatures are 

below 900 o F. Corrosion takes place where both liquid and 

vapor phases exist, and at areas subject to local cooling such 

as nozzles and platform supports. 

When processing high-nitrogen feedstocks, exposure to 

ammonia and cyanide may occur, subjecting carbon steel 

equipment in the FCC overhead system to corrosion, 

cracking, or hydrogen blistering. These effects may be 

minimized by water wash or corrosion inhibitors. Water wash 

may also be used to protect overhead condensers in the main 

column subjected to fouling from ammonium hydrosulfide. 

Inspections should include checking for leaks due to erosion 

or other malfunctions such as catalyst buildup on the 

expanders, coking in the overhead feeder lines from feedstock 

residues, and other unusual operating conditions. 

Health 

Because the catalytic cracker is a closed system, there is 

normally little opportunity for exposure to hazardous 

substances during normal operations. The possibility exists of 

exposure to extremely hot (700º F) hydrocarbon liquids or 

vapors during process sampling or if a leak or release occurs. 

In addition, exposure to hydrogen sulfide and/or carbon 

monoxide gas may occur during a release of product or vapor. 

Catalyst regeneration involves steam stripping and decoking, 

and produces fluid waste streams that may contain varying 

amounts of hydrocarbon, phenol, ammonia, hydrogen sulfide, 

mercaptan, and other materials depending upon the 

feedstocks, crudes, and processes. Inadvertent formation of 

nickel carbonyl may occur in cracking processes using nickel 

catalysts, with resultant potential for hazardous exposures. 

Safe work practices and/or the use of appropriate personal 


chemicals and other hazards such as noise and heat; during 

process sampling, inspection, maintenance and turnaround 

activities; and when handling spent catalyst, recharging 

catalyst, or if leaks or releases occur. 

III:2-28

HYDROCRACKING 

Hydrocracking is a two-stage process combining catalytic 

cracking and hydrogenation, wherein heavier feedstocks are 

cracked in the presence of hydrogen to produce more 

desirable products. The process employs high pressure, high 

temperature, a catalyst, and hydrogen. Hydrocracking is used 

for feedstocks that are difficult to process by either catalytic 

cracking or reforming, since these feedstocks are 

characterized usually by a high polycyclic aromatic content 

and/or high concentrations of the two principal catalyst 

poisons, sulfur and nitrogen compounds. 

The hydrocracking process largely depends on the nature of 

the feedstock and the relative rates of the two competing 

reactions, hydrogenation and cracking. Heavy aromatic 

feedstock is converted into lighter products under a wide 

range of very high pressures (1,000-2,000 psi) and fairly high 

temperatures (750-1,500º F), in the presence of hydrogen and 

special catalysts. When the feedstock has a high paraffinic 

content, the primary function of hydrogen is to prevent the 

formation of polycyclic aromatic compounds. Another 

important role of hydrogen in the hydrocracking process is to 

reduce tar formation and prevent buildup of coke on the 

catalyst. Hydrogenation also serves to convert sulfur and 

nitrogen compounds present in the feedstock to hydrogen 

sulfide and ammonia. 

Hydrocracking produces relatively large amounts of isobutane 

for alkylation feedstocks. Hydrocracking also performs 

isomerization for pour-point control and smoke-point control, 

both of which are important in high-quality jet fuel. 

HYDROCRACKING PROCESS 

In the first stage, preheated feedstock is mixed with recycled 

hydrogen and sent to the first-stage reactor, where catalysts 

convert sulfur and nitrogen compounds to hydrogen sulfide 

and ammonia. Limited hydrocracking also occurs. 

After the hydrocarbon leaves the first stage, it is cooled and 

liquefied and run through a hydrocarbon separator. The 

hydrogen is recycled to the feedstock. The liquid is charged 

to a fractionator. Depending on the products desired 

(gasoline components, jet fuel, and gas oil), the fractionator 

is run to cut out some portion of the first stage reactor 

outturn. Kerosene-range material can be taken as a separate 

side-draw product or included in the fractionator bottoms 

with the gas oil. 

The fractionator bottoms are again mixed with a hydro-gen 

stream and charged to the second stage. Since this material 

has already been subjected to some hydrogen-ation, cracking, 

and reforming in the first stage, the operations of the second 

stage are more severe (higher temperatures and pressures). 

Like the outturn of the first stage, the second stage product is 

separated from the hydrogen and charged to the fractionator. 



Because this unit operates at very high pressures and 

temperatures, control of both hydrocarbon leaks and 

hydrogen releases is important to prevent fires. In some 

processes, care is 

Table III:2-12 HYDROCRACKING PROCESS 

Feedstocks From Process Typical products..................... To 

High pour point Catalytic cracker Decomposition Kerosene, jet fuel......................Blending 

residuals Atmospheric, vac. tower Hydrogenation Gasoline, distillates....................Blending 

Gas oil Vacuum tower, coker Heavy naphthas Recycle, reformer 

Hydrogen Reformer Gas.............................................Gas 

plant 

III:2-29

Figure III-2:15 Two-Stage Hydrocracking 

needed to ensure that explosive concentrations of catalytic 

dust do not form during recharging. 


Inspection and testing of safety relief devices are important 

due to the very high pressures in this unit. Proper process 

control is needed to protect against plugging reactor beds. 

Unloading coked catalyst requires special precautions to 

prevent iron sulfide-induced fires. The coked catalyst should 

either be cooled to below 120º F before dumping, or be 

placed in nitrogen-inerted containers until cooled. 

Because of the operating temperatures and presence of 

hydrogen, the hydrogen-sulfide content of the feedstock must 

be strictly controlled to a minimum to reduce the possibility 

of severe corrosion. Corrosion by wet carbon dioxide in areas 

of condensation also must be considered. When processing 

high-nitrogen feedstocks, the ammonia and hydrogen sulfide 

form ammonium hydrosulfide, which causes serious 

corrosion at temperatures below the water dew point. 

Ammonium hydrosulfide is also present in sour water 

stripping. 

Health 

Because this is a closed process, exposures are expected to be 

minimal under normal operating conditions. There is a 

potential for exposure to hydrocarbon gas and vapor 

emissions, hydrogen and hydrogen sulfide gas due to 

high-pressure leaks. Large quantities of carbon monoxide 

may be released during catalyst 

III:2-30

egeneration and changeover. Catalyst steam stripping and 

regeneration create waste streams containing sour water and 

ammonia. Safe work practices and/or the use of appropriate 

personal protective equipment may be needed for exposure to 

chemicals and other hazards such as noise and heat, during 

process sampling, inspection, maintenance, and turnaround 

activities, and when handling spent catalyst. 

CATALYTIC REFORMING 

Catalytic reforming is an important process used to convert 

low-octane naphthas into high-octane gasoline blending 

components called reformate. Reforming represents the total 

effect of numerous reactions such as cracking, 

polymerization, dehydrogenation, and isomerization taking 

place simultaneously. Depending on the properties of the 

naphtha feedstock (as measured by the paraffin, olefin, 

naphthene, and aromatic content) and catalysts used, 

reformates can be produced with very high concentrations of 

toluene, benzene, xylene, and other aromatics useful in 

gasoline blending and petrochemical processing. Hydrogen, 

a significant by-product, is separated from the reformate for 

recycling and use in other processes. 

A catalytic reformer comprises a reactor section and a 

product-recovery section. More or less standard is a feed 

preparation section in which, by combination of 

hydrotreatment and distillation, the feedstock is prepared to 

specification. Most processes use platinum as the active 

catalyst. Sometimes platinum is combined with a second 

catalyst (bimetallic catalyst) such as rhenium or another noble 

metal. 

There are many different commercial catalytic reforming 

processes including platforming, powerforming, ultraforming, 

and Thermofor catalytic reforming. In the platforming 

process, the first step is preparation of the naphtha feed to 

remove impurities from the naphtha and reduce catalyst 

degradation. The naphtha feedstock is then mixed with 

hydrogen, vaporized, and passed through a series of 

alternating furnace and fixed-bed 

reactors containing a platinum catalyst. The effluent from the 

last reactor is cooled and sent to a separator to permit removal 

of the hydrogen-rich gas stream from the top of the separator 

for recycling. The liquid product from the bottom of the 

separator is sent to a fractionator called a stabilizer 

(butanizer). It makes a bottom product called reformate; 

butanes and lighter go overhead and are sent to the saturated 

gas plant. 

Some catalytic reformers operate at low pressure (50-200 

psi), and others operate at high pressures (up to 1,000 psi). 

Some catalytic reforming systems continuously regenerate the 

catalyst in other systems. One reactor at a time is taken 

off-stream for catalyst regeneration, and some facilities 

regenerate all of the reactors during turnarounds. 



This is a closed system; however, the potential for fire exists 

should a leak or release of reformate gas or hydrogen occur. 


Operating procedures should be developed to ensure control 

of hot spots during start-up. Safe catalyst handling is very 

important. Care must be taken not to break or crush the 

catalyst when loading the beds, as the small fines will plug up 

the reformer screens. Precautions against dust when 

regenerating or replacing catalyst should also be considered. 

Also, water wash should be considered where stabilizer 

fouling has occurred due to the formation of ammonium 

chloride and iron salts. Ammonium chloride may form in 

pretreater exchangers and cause corrosion and fouling. 

Hydrogen chloride from the hydrogenation of chlorine 

compounds may form acid or ammonium chloride salt. 

Health 


minimal under normal operating conditions. There is 

potential 

III:2-31

for exposure to hydrogen sulfide and benzene should a leak 

or release occur. 

Small emissions of carbon monoxide and hydrogen sulfide 

may occur during regeneration of catalyst. Safe work 

practices and/or 


exposures to chemicals and other hazards such as noise and 

heat; during testing, inspecting, maintenance and turnaround 

activities; and when handling regenerated or spent catalyst. 

Table III:2-13 CATALYTIC REFORMING PROCESS 

Feedstocks From Process Typical products...................... To 

Desulfurized naphtha Coker Rearrange, High octane gasoline................Blending 

Naphthene-rich Hydrocracker dehydrogenate Aromatics.................................Petrochemical 

fractions Hydrodesulfur Hydrogen.................................Recycle, hydrotreat, etc. 

Straight-run naphtha Atmospheric Gas...........................................Gas plant 

fractionator 

Figure III:2-16 Platforming Process 

III:2-32

CATALYTIC HYDROTREATING 

Catalytic hydrotreating is a hydrogenation process used to 

remove about 90% of contaminants such as nitrogen, sulfur, 

oxygen, and metals from liquid petroleum fractions. These 

contaminants, if not removed from the petroleum fractions as 

they travel through the refinery processing units, can have 

detrimental effects on the equipment, the catalysts, and the 

quality of the finished product. Typically, hydrotreating is 

done prior to processes such as catalytic reforming so that the 

catalyst is not contaminated by untreated feedstock. 

Hydrotreating is also used prior to catalytic cracking to 

reduce sulfur and improve product yields, and to upgrade 

middle-distillate petroleum fractions into finished kerosene, 

diesel fuel, and heating fuel oils. In addition, hydrotreating 

converts olefins and aromatics to saturated compounds. 

CATALYTIC HYDRODESULFURIZATION PROCESS 

Hydrotreating for sulfur removal is called 

hydrodesulfur-ization. In a typical catalytic 

hydrodesulfurization unit, the feedstock is deaerated and 

mixed with hydrogen, preheated in a fired heater (600-800º 

F) and then charged under pressure (up to 1,000 psi) through 

a fixed-bed catalytic reactor. In the reactor, the sulfur and 

nitrogen compounds in the feedstock are converted into H2S 

and NH3. The reaction products leave the reactor and after 

cooling to a low temperature enter a liquid/gas separator. The 

hydrogen-rich gas from the high-pressure separation is 

recycled to combine with the feedstock, and the low-pressure 

gas stream rich in H2S is sent to a gas treating unit where 

H2S is removed. The clean gas is then suitable as fuel for the 

refinery furnaces. The liquid stream is the product from 

hydrotreating and is normally sent to a stripping column for 

removal of H2S and other undesirable components. In cases 

where steam is used for stripping, the product is sent to a 

vacuum drier for removal of water. Hydrodesulfurized 

products are blended or used as catalytic reforming feedstock. 

OTHER HYDROTREATING PROCESSES 

Hydrotreating processes differ depending upon the feedstocks 

available and catalysts used. Hydrotreating can be used to 

improve the burning characteristics of distillates such as 

kerosene. Hydrotreatment of a kerosene fraction can convert 

aromatics into naphthenes, which are cleaner-burning 

compounds. 

Lube-oil hydrotreating uses catalytic treatment of the oil with 

hydrogen to improve product quality. The objectives in mild 

lube hydrotreating include saturation of olefins and 

improvements in color, odor, and acid nature of the oil. Mild 

lube hydrotreating also may be used following solvent 

processing. Operating temperatures are usually below 600º 

F and operating pressures below 800 psi. Severe lube 

hydrotreating, at temperatures in the 600-750º F range and 

hydrogen pressures up to 3,000 psi, is capable of saturating 

aromatic rings, along with sulfur and nitrogen removal, to 

impart specific properties not achieved at mild conditions. 

Hydrotreating also can be employed to improve the quality of 

pyrolysis gasoline (pygas), a by-product from the manufacture 

of ethylene. Traditionally, the outlet for pygas has been 

motor gasoline blending, a suitable route in view of its high 

octane number. However, only small portions can be blended 

untreated owing to the unacceptable odor, color, and 

gum-forming tendencies of this material. The quality of 

pygas, which is high in diolefin content, can be satisfactorily 

improved by hydro-treating, whereby conversion of diolefins 

into mono-olefins provides an acceptable product for motor 

gas blending. 



The potential exists for fire in the event of a leak or release of 

product or hydrogen gas. 

III:2-33

Table III:2-14 HYDRODESULFURIZATION PROCESS 

Feedstocks From Process Typical products......................To 

Naphthas, distillates Atmospheric & Treating, Naphtha....................................Catalytic reformer 

Sour gas oil, vacuum tower hydrogenation Hydrogen..................................Recycle 

Residuals Catalytic & Distillates..................................Blending 

thermal cracker 

H 2 S, ammonia...........................Sulfur plant, treater 

Gas.............................................Gas plant 


Many processes require hydrogen generation to provide for 

a continuous supply. Because of the operating temperatures 

and presence of hydrogen, the hydrogen sulfide content of the 

feedstock must be strictly controlled to a minimum to reduce 

corrosion. Hydrogen chloride may form and condense as 

hydrochloric acid in the lower-temperature parts of the unit. 

Ammonium hydrosulfide may form in high-temperature, 

high-pressure units. Excessive contact time and/or 

temperature will create coking. Precautions need to be taken 

when unloading coked catalyst from the unit to prevent iron 

sulfide fires. The coked catalyst should be cooled to below 

120 o F before removal, 

or dumped into nitrogen-inerted bins where it can be cooled 

before further handling. Special antifoam additives may be 

used to prevent catalyst poisoning from silicone carryover in 

the coker feedstock. 

Health 



potential for exposure to hydrogen sulfide or hydrogen gas in 

the event of a release, or to ammonia should a sour-water leak 

or spill occur. Phenol also may be present if high 

boiling-point feedstocks are processed. Safe work practices 

and/or appropriate personal protective equipment may be 

needed for exposures to 

Figure III:2-17 Distillate Hydrodesulffurization 

III:2-34

chemicals and other hazards such as noise and heat; during 

process sampling, inspection, maintenance, and turnaround 

activities; and when handling amine or exposed to catalyst. 

ISOMERIZATION 

Isomerization converts n-butane, n-pentane and n-hexane into 

their respective isoparaffins of substantially higher octane 

number. The straight-chain paraffins are converted to their 

branched-chain counterparts whose component atoms are the 

same but are arranged in a different geometric structure. 

Isomerization is important for the conversion of n-butane into 

isobutane, to provide additional feedstock for alkylation units, 

and the conversion of normal pentanes and hexanes into 

higher branched isomers for gasoline blending. Isomerization 

is similar to catalytic reforming in that the hydrocarbon 

molecules are rearranged, but unlike catalytic reforming, 

isomerization just converts normal paraffins to isoparaffins. 

There are two distinct isomerization processes, butane (C 4 ) 

and pentane/hexane (C 5 /C 6 ). Butane isomerization produces 

feedstock for alkylation. Aluminum chloride catalyst plus 

hydrogen chloride are universally used for the 

low-temperature processes. Platinum or another metal 

catalyst is used for the higher-temperature processes. In a 

typical low-temperature process, the feed to the isomerization 

plant is n-butane or mixed butanes mixed with hydrogen (to 

inhibit olefin formation) and passed to the reactor at 230-340º 

F and 200-300 psi. Hydrogen is flashed off in a 

high-pressure separator and the hydrogen chloride removed 

in a stripper column. The resultant butane 

mixture is sent to a fractionator (deisobutanizer) to separate 

n-butane from the isobutane product. 

Pentane/hexane isomerization increases the octane number 

of the light gasoline components n-pentane and n-hexane, 

which are found in abundance in straight-run gasoline. In a 

typical C5/C6 isomerization process, dried and desulfurized 

feedstock is mixed with a small amount of organic chloride 

and recycled hydrogen, and then heated to reactor 

temperature. It is then passed over supported-metal catalyst 

in the first reactor where benzene and olefins are 

hydrogenated. The feed next goes to the isomerization reactor 

where the paraffins are catalytically isomerized to 

isoparaffins. The reactor effluent is then cooled and 

subsequently separated in the product separator into two 

streams: a liquid product (isomerate) and a recycle 

hydrogen-gas stream. The isomerate is washed (caustic and 

water), acid stripped, and stabilized before going to storage. 

SAFETY AND HEALTH CONSIDERATIONS 


Although this is a closed process, the potential for a fire 

exists should a release or leak contact a source of ignition 

such as the heater. 


If the feedstock is not completely dried and desulfurized, the 

potential exists for acid formation leading to catalyst 

poisoning and metal corrosion. Water or steam must not be 

allowed to enter areas where hydrogen chloride is present. 

Precautions are 

Table III:2-15 ISOMERIZATION PROCESSES 

Feedstock From Process Typical products................To 

n-Butane Various Rearrangement Isobutane.........................Alkylation 

n-Pentane processes Isopentane........................Blending 

n-Hexane Isohexane.........................Blending 

Gas.................................Gas Plant 

III:2-35

Figure III:2-18 C 4 Isomerization 

Figure II:2-19 C 5 and C 6 Isomerization 

III:2-36

needed to prevent HCl from entering sewers and drains. 

Health 


minimal during normal operating conditions. There is a 

potential for exposure to hydrogen gas, hydrochloric acid, 

and hydrogen chloride and to dust when solid catalyst is used. 

Safe work practices and/or appropriate personal protective 

equipment may be needed for exposures to chemicals and 

other hazards such as heat and noise, and during process 


POLYMERIZATION 

Polymerization in the petroleum industry is the process of 

converting light olefin gases including ethylene, propylene, 

and butylene into hydrocarbons of higher molecular weight 

and higher octane number that can be used as gasoline 

blending stocks. Polymerization combines two or more 

identical olefin molecules to form a single molecule with the 

same elements in the same proportions as the original 

molecules. Polymerization may be accomplished thermally 

or in the presence of a catalyst at lower temperatures. 

The olefin feedstock is pretreated to remove sulfur and other 

undesirable compounds. In the catalytic process the 

feedstock is either passed over a solid phosphoric acid 

catalyst or comes in contact with liquid phosphoric acid, 

where an exothermic polymeric reaction occurs. This reaction 

requires cooling water and the injection of cold feedstock into 

the reactor to control 

temperatures between 300º and 450º F at pressures from 200 

psi to 1,200 psi. The reaction products leaving the reactor are 

sent to stabilization and/or fractionator systems to separate 

saturated and unreacted gases from the polymer gasoline 

product. 

NOTE: In the petroleum industry, polymerization is used to 

indicate the production of gasoline components, hence the 

term "polymer" gasoline. Furthermore, it is not essential that 

only one type of monomer be involved. If unlike olefin 

molecules are combined, the process is referred to as 

"copolymerization." Polymerization in the true sense of the 

word is normally prevented, and all attempts are made to 

terminate the reaction at the dimer or trimer (three monomers 

joined together) stage. However, in the petrochemical section 

of a refinery, polymerization, which results in the production 

of, for instance, polyethylene, is allowed to proceed until 

materials of the required high molecular weight have been 

produced. 



Polymerization is a closed process where the potential for a 

fire could occur due to leaks or releases reaching a source of 

ignition. 


The potential for an uncontrolled exothermic reaction exists 

should loss of cooling water occur. Severe corrosion leading 

to equipment failure will occur should water make contact 

with the phosphoric acid, such as during water washing at 

shutdowns. Corrosion may also occur in piping manifolds, 

Table III:2-16 POLYMERIZATION PROCESS 

Feedstocks From Process Typical products................ To 

Olefins Cracking Unification High octane naphtha...........Gasoline blending 

processes 

Petrochem. feedstocks.........Petrochemical 

Liquefied petro. gas............Storage 

III:2-37

eboilers, exchangers, and other locations where acid may 

settle out. 

Health 

Because this is a closed system, exposures are expected to be 


potential for exposure to caustic wash (sodium hydroxide), to 

phosphoric 

acid used in the process or washed out during turnarounds, 

and to catalyst dust. Safe work practices and/or appropriate 


to chemicals and other hazards such as noise and heat, and 

during process sampling, inspection, maintenance, and 

turnaround activities. 

Figure III:2-20 Polymerization Process 

III:2-38

ALKYLATION 

Alkylation combines low-molecular-weight olefins (primarily 

a mixture of propylene and butylene) with isobutene in the 

presence of a catalyst, either sulfuric acid or hydrofluoric 

acid. The product is called alkylate and is composed of a 

mixture of high-octane, branched-chain paraffinic 

hydrocarbons. Alkylate is a premium blending stock because 

it has exceptional antiknock properties and is clean burning. 

The octane number of the alkylate depends mainly upon the 

kind of olefins used and upon operating conditions. 

SULFURIC ACID ALKYLATION PROCESS 

In cascade type sulfuric acid (H2SO4) alkylation units, the 

feedstock (propylene, butylene, amylene, and fresh isobutane) 

enters the reactor and contacts the concentrated sulfuric acid 

catalyst (in concentrations of 85% to 95% for good operation 

and to minimize corrosion). The reactor is divided into zones, 

with olefins fed through distributors to each zone, and the 

sulfuric acid and isobutanes flowing over baffles from zone 

to zone. 

The reactor effluent is separated into hydrocarbon and acid 

phases in a settler, and the acid is returned to the reactor. The 

hydrocarbon phase is hot-water washed with caustic for pH 

control before being successively depropanized, 

deisobutanized, and debutanized. The alkylate obtained from 

the deisobutanizer can then go directly to motor-fuel blending 

or be rerun to produce aviation-grade blending stock. The 

isobutane is recycled to the feed. 

HYDROFLUORIC ACID ALKYLATION PROCESS 

Phillips and UOP are the two common types of hydro-fluoric 

acid alkylation processes in use. In the Phillips process, olefin 

and isobutane feedstock are dried and fed to a combination 

reactor/settler system. Upon leaving the reaction zone, the 

reactor effluent flows to a settler (separating vessel) where the 

acid separates from the hydrocarbons. The acid layer at the 

bottom of the separating vessel is recycled. The top layer of 

hydrocarbons (hydrocarbon phase), consisting of propane, 

normal butane, alkylate, and excess (recycle) isobutane, is 

charged to the main fractionator, the bottom product of which 

is motor alkylate. The main fractionator overhead, consisting 

mainly of propane, isobutane, and HF, goes to a 

depropanizer. Propane with trace amount of HF goes to an 

HF stripper for HF removal and is then catalytically 

defluorinated, treated, and sent to storage. Isobutane is 

withdrawn from the main fractionator and recycled to the 

reactor/settler, and alkylate from the bottom of the main 

fractionator is sent to product blending. 

The UOP process uses two reactors with separate settlers. 

Half of the dried feedstock is charged to the first reactor, 

along with recycle and makeup isobutane. The reactor 

effluent then goes to its settler, where the acid is recycled and 

the hydrocarbon charged to the second reactor. The other 

half of the feedstock also goes to the second reactor, with the 

settler acid being recycled and the hydrocarbons charged to 

the main fractionator. Subsequent processing is similar to the 

Phillips process. Overhead from the main fractionator goes to 

a depropanizer. Isobutane is recycled to the reaction zone 

and alkylate is sent to product blending. 

Table II:2-17 ALKYLATION PROCESS 

Feedstocks From Process Typical products............... To 

Petroleum gas Distillation or cracking Unification High octane gasoline..........Blending 

Olefins Cat. or hydro cracking n-Butane & propane...........Stripper or blender 

Isobutane Isomerization 

III:2-39

Figure III:2-21 Sulfuric Acid Alkaylation 

Figure III:2-22 Hydrogen Fluoride Alkylation 

III:2-40



Alkylation units are closed processes; however, the potential 

exists for fire should a leak or release occur that allows 

product or vapor to reach a source of ignition. 


Sulfuric acid and hydrofluoric acid are potentially hazardous 

chemicals. Loss of coolant water, which is needed to 

maintain process temperatures, could result in an upset. 

Precautions are necessary to ensure that equipment and 

materials that have been in contact with acid are handled 

carefully and are thoroughly cleaned before they leave the 

process area or refinery. Immersion wash vats are often 

provided for neutralization of equipment that has come into 

contact with hydrofluoric acid. Hydrofluoric acid units should 

be thoroughly drained and chemically cleaned prior to 

turnarounds and entry to remove all traces of iron fluoride 

and hydro-fluoric acid. Following shutdown, where water has 

been used the unit should be thoroughly dried before 

hydrofluoric acid is introduced. 

Leaks, spills, or releases involving hydrofluoric acid or 

hydrocarbons containing hydrofluoric acid can be extremely 

hazardous. Care during delivery and unloading of acid is 

essential. Process unit containment by curbs and drainage and 

isolation so that effluent can be neutralized before release to 

the sewer system should be considered. Vents can be routed 

to soda-ash scrubbers to neutralize hydrogen fluoride gas or 

hydrofluoric acid vapors before release. Pressure on the 

cooling water and steam side of exchangers should be kept 

below the minimum pressure on the acid service side to 

prevent water contamination. 

Some corrosion and fouling in sulfuric acid units may occur 

from the breakdown of sulfuric acid esters or where caustic is 

added for neutralization. These esters can be removed by 

fresh acid treating and hot-water washing. To prevent 

corrosion from 

hydrofluoric acid, the acid concentration inside the process 

unit should be maintained above 65% and moisture below 

4%. 

Health 


minimal during normal operations. There is a potential for 

exposure should leaks, spills, or releases occur. Sulfuric acid 

and (particularly) hydrofluoric acid are potentially hazardous 

chemicals. Special precautionary emergency preparedness 

measures and protection appropriate to the potential hazard 

and areas possibly affected need to be provided. Safe work 

practices and appropriate skin and respiratory personal 

protective equipment are needed for potential exposures to 

hydro-fluoric and sulfuric acids during normal operations 

such as reading gauges, inspecting, and process sampling, as 

well as during emergency response, maintenance, and 

turnaround activities. Procedures should be in place to ensure 

that protective equipment and clothing worn in hydrofluoric 

acid activities are decontaminated and inspected before 

reissue. Appropriate personal protection for exposure to heat 

and noise also may be required. 

SWEETENING AND TREATING 

PROCESSES 

Treating is a means by which contaminants such as organic 

compounds containing sulfur, nitrogen, and oxygen; 

dissolved metals and inorganic salts; and soluble salts 

dissolved in emulsified water are removed from petroleum 

fractions or streams. Petroleum refiners have a choice of 

several different treating processes, but the primary purpose 

of the majority of them is the elimination of unwanted sulfur 

compounds. A variety of intermediate and finished products, 

including middle distillates, gasoline, kerosene, jet fuel and 

sour gases are dried and sweetened. Sweetening, a major 

refinery treatment of gasoline, treats sulfur compounds 

(hydrogen sulfide, thiophene and mercaptan) to improve 

color, odor and oxidation stability. Sweetening also reduces 

concentrations of carbon dioxide. 

III:2-41

Treating can be accomplished at an intermediate stage in the 

refining process, or just before sending the finished product 

to storage. Choices of a treating method depend on the nature 

of the petroleum fractions, amount and type of impurities in 

the fractions to be treated, the extent to which the process 

removes the impurities, and end-product specifications. 

Treating materials include acids, solvents, alkalis, oxidizing, 

and adsorption agents. 

ACID, CAUSTIC, OR CLAY TREATING 

Sulfuric acid is the most commonly used acid treating 

process. Sulfuric acid treating results in partial or complete 

removal of unsaturated hydrocarbons, sulfur, nitrogen, and 

oxygen compounds, and resinous and asphaltic compounds. 

It is used to improve the odor, color, stability, carbon residue, 

and other properties of the oil. Clay/lime treatment of 

acid-refined oil removes traces of asphaltic materials and 

other compounds improving product color, odor, and 

stability. Caustic treating with sodium (or potassium) 

hydroxide is used to improve odor and color by removing 

organic acids (naphthenic acids, phenols) and sulfur 

compounds (mercaptans, H2S) by a caustic wash. By 

combining caustic soda solution with various solubility 

promoters (e.g., methyl alcohol and cresols), up to 99% of all 

mercaptans as well as oxygen and nitrogen compounds can be 

dissolved from petroleum fractions. 

DRYING AND SWEETENING 

Feedstocks from various refinery units are sent to gas treating 

plants where butanes and butenes are removed for use as 

alkylation feedstock, heavier components are sent to gasoline 

blending, propane is recovered for LPG, and propylene is 

removed for use in petrochemicals. Some mercaptans are 

removed by water-soluble chemicals that react with the 

mercaptans. Caustic liquid (sodium hydroxide), amine 

compounds (diethanolamine) or fixed-bed catalyst sweetening 

also may be used. Drying is accomplished by the use of water 

absorption or adsorption agents to remove water from the 

products. Some processes simultaneously dry and sweeten by 

adsorption on molecular sieves. 

SULFUR RECOVERY 

Sulfur recovery converts hydrogen sulfide in sour gases and 

hydrocarbon streams to elemental sulfur. The most widely 

used recovery system is the Claus process, which uses both 

thermal and catalytic-conversion reactions. A typical process 

produces elemental sulfur by burning hydrogen sulfide under 

controlled conditions. Knockout pots are used to remove 

water and hydrocarbons from feed gas streams. The gases are 

then exposed to a catalyst to recover additional sulfur. Sulfur 

vapor from burning and conversion is condensed and 

recovered. 

HYDROGEN SULFIDE SCRUBBING 

Hydrogen sulfide scrubbing is a common treating process in 

which the hydrocarbon feedstock is first scrubbed to prevent 

catalyst poisoning. Depending on the feedstock and the 

nature of contaminants, desulfurization methods vary from 

ambient temperature-activated charcoal absorption to 

high-temperature catalytic hydrogenation followed by zinc 

oxide treating. 

Table III:2-18 SWEETENING AND TREATING PROCESSES 

Feedstocks From Process Products........................To 

Gases Various Treatment Butane & butene..............Alkylation 

Finished products 

Propane, distillates...........Storage 

Intermediates 

Gasoline........................Blending 

Propylene......................Petrochemical 

III:2-42

Figure III:2-23 Molecular Sieve Drying and Sweetening 



The potential exists for fire from a leak or release of feedstock 

or product. Sweetening processes use air or oxygen. If excess 

oxygen enters these processes, it is possible for a fire to occur 

in the settler due to the generation of static electricity, which 

acts as the ignition source. 

Health 

Because these are closed processes, exposures are expected 

to be minimal under normal operating conditions. There is a 

potential for exposure to hydrogen sulfide, caustic (sodium 

hydroxide), spent caustic, spent catalyst (Merox), catalyst 

dust and sweetening agents (sodium carbonate and sodium 

bicarbonate). Safe work practices and/or appropriate personal 


chemicals 

and other hazards such as noise and heat, and during process 


UNSATURATED GAS PLANTS 

Unsaturated (unsat) gas plants recover light hydrocarbons (C 3 

and C 4 olefins) from wet gas streams from the FCC, TCC, and 

delayed coker overhead accumulators or fractionation 

receivers. In a typical unsat gas plant, the gases are 

compressed and treated with amine to remove hydrogen 

sulfide either before or after they are sent to a fractionating 

absorber where they are mixed into a concurrent flow of 

debutanized gasoline. The light fractions are separated by 

heat in a reboiler, the offgas is sent to a sponge absorber, and 

the bottoms are sent to a debutanizer. A portion of the 

debutanized hydrocarbon is recycled, with the balance sent to 

the splitter for separation. The overhead gases go to a 

depropanizer for use as alkylation unit feedstock. 

III:2-43

Table III:2-19 UNSAT GAS PLANT PROCESS 

Feedstock From Process Typical products.................. To 

Gas Oils FCC,TCC, Treatment Gasoline................................ Recycle or treating 

Delayed coker 

Gases..................................... Alkylation 



The potential of a fire exists should spills, releases, or vapors 

reach a source of ignition. 


In unsat gas plants handling FCC feedstocks, the potential 

exists for corrosion from moist hydrogen sulfide and 

cyanides. When feedstocks are from the delayed coker or the 

TCC, corrosion from hydrogen sulfide and deposits in the 

high pressure sections of gas compressors from ammonium 

compounds is possible. 

Health 


to be minimal under normal operating conditions. There is a 

potential for exposures to amine compounds such as 

monoethanolamine (MEA), diethanolamine (DEA) and 

methyldiethanolamine (MDEA) and hydrocarbons. Safe work 

practices and/or appropriate personal protective equipment 

may be needed for exposures to chemicals and other hazards 

such as noise and heat, and during process sampling, 

inspection, maintenance, and turnaround activities. 

AMINE PLANTS 

Amine plants remove acid contaminants from sour gas and 

hydrocarbon streams. In amine plants, gas and liquid 

hydrocarbon streams containing carbon dioxide and/or 

hydrogen sulfide are charged to a gas absorption tower or 

liquid contactor where the acid contaminants are absorbed by 

counterflowing amine solutions (i.e., MEA, DEA, MDEA). 

The stripped gas or liquid is removed overhead, and the 

amine is sent to a regenerator. In the regenerator, the acidic 

components are stripped by heat and reboiling action and 

disposed of, and the amine is recycled. 



The potential for fire exists where a spill or leak could reach 

a source of ignition. 


To minimize corrosion, proper operating practices should be 

established and regenerator bottom and reboiler temperatures 

controlled. Oxygen should be kept out of the system to 

prevent amine oxidation. 

Health 


minimal during normal operations. There is potential for 

exposure to amine compounds (i.e., monoethanolamine, 

diethanolamine, methyldiethanol-amine), hydrogen sulfide 

and carbon dioxide. Safe work practices and/or appropriate 


to chemicals and other hazards such as noise and heat, and 

during process sampling, inspection, maintenance and 


III:2-44

SATURATE GAS PLANTS 

Saturate gas plants separate refinery gas components 

including butanes for alkylation, pentanes for gasoline 

blending, LPGs for fuel, and ethane for petrochemicals. 

Because sat gas processes depend on the feedstock and 

product demand, each refinery uses different systems, usually 

absorption-fractionation or straight fractionation. In 

absorption-fractionation, gases and liquids from various 

refinery units are fed to an absorber-deethanizer where C 2 and 

lighter fractions are separated from heavier fractions by lean 

oil absorption and removed for use as fuel gas or 

petrochemical feed. The heavier fractions are stripped and 

sent to a debutanizer, and the lean oil is recycled back to the 

absorber-deethanizer. C 3 /C 4 is separated from pentanes in the 

debutanizer, scrubbed to remove hydrogen sulfide, and fed to 

a splitter where propane and butane are separated. In 

fractionation sat-gas plants, the absorption stage is 

eliminated. 



There is potential for fire if a leak or release reaches a source 

of ignition such as the unit reboiler. 


Corrosion could occur from the presence of hydrogen sulfide, 

carbon dioxide, and other compounds as a result of prior 

treating. Streams containing ammonia should be dried before 

processing. Antifouling additives may be used in absorption 

oil to protect heat exchangers. Corrosion inhibitors may be 

used to control corrosion in overhead systems. 

Health 


minimal during normal operations. There is potential for 

exposure to hydrogen sulfide, carbon dioxide, and other 

products such as diethanolamine or sodium hydroxide carried 

over from prior treating. Safe work practices and/or 


exposures to chemicals and other hazards such as noise and 

heat, and during process sampling, inspection, maintenance, 

and turnaround activities. 

ASPHALT PRODUCTION 

Asphalt is a portion of the residual fraction that remains after 

primary distillation operations. It is further processed to 

impart characteristics required by its final use. In vacuum 

distillation, generally used to produce road-tar asphalt, the 

residual is heated to about 750º F and charged to a column 

where vacuum is applied to prevent cracking. 

Asphalt for roofing materials is produced by air blowing. 

Residual is heated in a pipe still almost to its flash point and 

charged to a blowing tower where hot air is injected for a 

predetermined time. The dehydrogen-ization of the asphalt 

forms hydrogen sulfide, and the oxidation creates sulfur 

dioxide. Steam, used to blanket the top of the tower to entrain 

the various contaminants, is then passed through a scrubber 

to condense the hydrocarbons. 

A third process used to produce asphalt is solvent 

deasphalting. In this extraction process, which uses propane 

(or hexane) as a solvent, heavy oil fractions are separated to 

produce heavy lubricating oil, catalytic cracking feedstock, 

and asphalt. Feedstock and liquid propane are pumped to an 

extraction tower at precisely controlled mixtures, 

temperatures (150-250º F), and pressures of 350-600 psi. 

Separation occurs in a rotating disc contactor, based on 

differences in solubility. The products are then evaporated 

and steam stripped to recover the propane, which is recycled. 

Deasphalting also removes some sulfur and nitrogen 

compounds, metals, carbon residues, and paraffins from the 

feedstock. 

III:2-45

Table III:2-20. SOLVENT DEASPHALTING PROCESS 

Feedstock From Process Typical products.....................To 

Residual Vacuum tower Treatment Heavy lube oil..........................Treating or lube blending 

Atmospheric tower 

Asphalt.....................................Storage or shipping 

Reduced crude 

Deasphalted oil.........................Hydrotreat & catalytic cracker 

Propane.....................................Recycle 



The potential for a fire exists if a product leak or release 

contacts a source of ignition such as the process heater. 

Condensed steam from the various asphalt and deasphalting 

processes will contain trace amounts of hydrocarbons. Any 

disruption of the vacuum can result in the entry of 

atmospheric air and subsequent fire. In addition, raising the 

temperature of the vacuum tower bottom to improve 

efficiency can generate methane by thermal cracking. This 

can create vapors in asphalt storage tanks that are not 

detectable by flash testing but are high enough to be 

flammable. 


Deasphalting requires exact temperature and pressure control. 

In addition, moisture, excess solvent, or a drop in operating 

temperature may cause foaming, which affects the product 

temperature control and may create an upset. 

Health 


to be minimal during normal operations. Should a spill or 

release occur, there is a potential for exposure to residuals 

and asphalt. Air blowing can create some polynuclear 

aromatics. Condensed steam from the air-blowing asphalt 

process may also contain contaminants. The potential for 

exposure to hydrogen sulfide and sulfur dioxide exists in the 

production of asphalt. Safe work 

practices and/or appropriate personal protective equipment 

may be needed for exposures to chemicals and other hazards 

such as noise and heat, and during process sampling, 


HYDROGEN PRODUCTION 

High-purity hydrogen (95-99%) is required for 

hydro-desulfurization, hydrogenation, hydrocracking, and 

petrochemical processes. Hydrogen, produced as a by-product 

of refinery processes (principally hydrogen recovery from 

catalytic reformer product gases), often is not enough to meet 

the total refinery requirements, necessitating the 

manufacturing of additional hydrogen or obtaining supply 

from external sources. 

In steam-methane reforming, desulfurized gases are mixed 

with superheated steam (1,100-1,600º F) and reformed in 

tubes containing a nickel base catalyst. The reformed gas, 

which consists of steam, hydrogen, carbon monoxide, and 

carbon dioxide, is cooled and passed through converters 

containing an iron catalyst where the carbon monoxide reacts 

with steam to form carbon dioxide and more hydrogen. The 

carbon dioxide is removed by amine washing. Any remaining 

carbon monoxide in the product stream is converted to 

methane. 

Steam-naphtha reforming is a continuous process for the 

production of hydrogen from liquid hydrocarbons and is, in 

fact, similar to steam-methane reforming. A variety of 

naphthas in the gasoline boiling range may be employed, 

including fuel containing up to 35% aromatics. Following 

pretreatment to 

III:2-46

Table III:2-21. STEAM REFORMING PROCESS 

Feedstock From Process Typical products.....................To 

Desulfurized Various Decomposition Hydrogen.................................Processing 

refinery gas treatment Carbon dioxide........................Atmosphere 

units 

Carbon monoxide....................Methane 

remove sulfur compounds, the feedstock is mixed with steam 

and taken to the reforming furnace (1,250-1,500º F) where 

hydrogen is produced. 



The possibility of fire exists should a leak or release occur 

and reach an ignition source. 


The potential exists for burns from hot gases and superheated 

steam should a release occur. Inspections and testing should 

be considered where the possibility exists for valve failure 

due to contaminants in the hydrogen. Carryover from caustic 

scrubbers should be controlled to prevent corrosion in 

preheaters. Chlorides from the feedstock or steam system 

should be prevented from entering reformer tubes and 

contaminating the catalyst. 

Health 


to be minimal during normal operating conditions. There is a 

potential for exposure to excess hydrogen, carbon monoxide, 

and/or carbon dioxide. Condensate can be contaminated by 

process materials such as caustics and amine compounds, 

with resultant exposures. Depending on the specific process 

used, safe work practices and/or appropriate personal 


chemicals and other 

hazards such as noise and heat, and during process sampling, 


BLENDING 

Blending is the physical mixture of a number of different 

liquid hydrocarbons to produce a finished product with 

certain desired characteristics. Products can be blended 

in-line through a manifold system, or batch blended in tanks 

and vessels. In-line blending of gasoline, distillates, jet fuel, 

and kerosene is accomplished by injecting proportionate 

amounts of each component into the main stream where 

turbulence promotes thorough mixing. Additives including 

octane enhancers, metal deactivators, anti-oxidants, 

anti-knock agents, gum and rust inhibitors, detergents, etc. are 

added during and/or after blending to provide specific 

properties not inherent in hydrocarbons. 



Ignition sources in the area need to be controlled in the event 

of a leak or release. 

Health 



other hazards such as noise and heat; when handling 

additives; and during inspection, maintenance, and 


III:2-47

LUBRICANT, WAX, AND GREASE 

MANUFACTURING PROCESSES 

Lubricating oils and waxes are refined from the residual 

fractions of atmospheric and vacuum distillation. The primary 

objective of the various lubricating oil refinery processes is to 

remove asphalts, sulfonated aromatics, and paraffinic and 

isoparaffinic waxes from residual fractions. Reduced crude 

from the vacuum unit is deasphalted and combined with 

straight-run lubricating oil feedstock, preheated, and 

solvent-extracted (usually with phenol or furfural) to produce 

raffinate. 

WAX MANUFACTURING PROCESS 

Raffinate from the extraction unit contains a considerable 

amount of wax that must be removed by solvent extraction 

and crystallization. The raffinate is mixed with a solvent 

(propane) and precooled in heat exchangers. The 

crystallization temperature is attained by the evaporation of 

propane in the chiller and filter feed tanks. The wax is 

continuously removed by filters and cold solvent-washed to 

recover retained oil. The solvent is recovered from the oil by 

flashing and steam stripping. The wax is then heated with hot 

solvent, chilled, filtered, and given a final wash to remove all 

oil. 

LUBRICATING OIL PROCESS 

The dewaxed raffinate is blended with other distillate 

fractions and further treated for viscosity index, color, 

stability, carbon residue, sulfur, additive response, and 

oxidation stability in extremely selective extraction processes 

using solvents (furfural, 

phenol, etc.). In a typical phenol unit, the raffinate is mixed 

with phenol in the treating section at temperatures below 400º 

F. Phenol is then separated from the treated oil and recycled. 

The treated lube-oil base stocks are then mixed and/or 

compounded with additives to meet the required physical and 

chemical characteristics of motor oils, industrial lubricants, 

and metal working oils. 

GREASE COMPOUNDING 

Grease is made by blending metallic soaps (salts of 

long-chained fatty acids) and additives into a lubricating oil 

medium at temperatures of 400-600º F. Grease may be either 

batch-produced or continuously compounded. The 

characteristics of the grease depend to a great extent on the 

metallic element (calcium, sodium, aluminum, lithium, etc.) 

in the soap and the additives used. 



The potential for fire exists if a product or vapor leak or 

release in the lube blending and wax processing areas reaches 

a source of ignition. Storage of finished products, both bulk 

and packaged, should be in accordance with recognized 

practices. 

While the potential for fire is reduced in lube oil blending, 

care must be taken when making metal-working oils and 

compounding greases due to the use of higher blending and 

compounding temperatures and lower flash point products. 

Table III:2-22 LUBRICATING OIL AND WAX MANUFACTURING PROCESSES 

Feedstock From Process Typical products................To 

Lube Vacuum tower, solvent Treatment Dewaxed raffinate............. Lube blend or 

compound 

feedstock dewaxing, hydrotreating Grease compounding 

and solvent extraction, etc. Wax............................... Storage or shipping 

additives 

III:2-48


Control of treater temperature is important as phenol can 

cause corrosion above 400º F. Batch and in-line blending 

operations require strict controls to maintain desired product 

quality. Spills should be cleaned and leaks repaired to avoid 

slips and falls. Additives in drums and bags need to be 

handled properly to avoid strain. Wax can clog sewer or oil 

drainage systems and interfere with wastewater treatment. 

Health 

When blending, sampling, and compounding, personal 

protection from steam, dusts, mists, vapors, metallic salts, and 

other additives is appropriate. Skin contact with any 

formulated grease or lubricant should be avoided. Safe work 

practices and/or appropriate personal protection may be 

needed for exposures to chemicals and other hazards such as 

noise and heat; during inspection, maintenance, and 

turnaround activities; and while sampling and handling 

hydrocarbons and chemicals during the production of 

lubricating oil and wax. 

E. OTHER REFINERY OPERATIONS 

HEAT EXCHANGERS, COOLERS, AND 

PROCESS HEATERS 

HEATING OPERATIONS 

Process heaters and heat exchangers preheat feedstocks in 

distillation towers and in refinery processes to reaction 

temperatures. Heat exchangers use either steam or hot 

hydrocarbon transferred from some other section of the 

process for heat input. The heaters are usually designed for 

specific process operations, and most are of cylindrical 

vertical or box-type designs. The major portion of heat 

provided to process units comes from fired heaters fueled by 

refinery or natural gas, distillate, and residual oils. Fired 

heaters are found on crude and reformer preheaters, coker 

heaters, and large-column reboilers. 

COOLING OPERATIONS 

Heat also may be removed from some processes by air and 

water exchangers, fin fans, gas and liquid coolers, and 

overhead condensers, or by transferring heat to other systems. 

The basic mechanical vapor-compression refrigeration 

system, which may serve one or more process units, includes 

an evaporator, compressor, condenser, controls, and piping. 

Common coolants 

are water, alcohol/water mixtures, or various glycol solutions. 



A means of providing adequate draft or steam purging is 

required to reduce the chance of explosions when lighting 

fires in heater furnaces. Specific start-up and emergency 

procedures are required for each type of unit. If fire impinges 

on fin fans, failure could occur due to overheating. If 

flammable product escapes from a heat exchanger or cooler 

due to a leak, fire could occur. 


Care must be taken to ensure that all pressure is removed 

from heater tubes before removing header or fitting plugs. 

Consideration should be given to providing for pressure relief 

in heat-exchanger piping systems in the event they are 

blocked off while full of liquid. If controls fail, variations of 

temperature and pressure could occur on either side of the 

heat exchanger. If heat exchanger tubes fail and process 

pressure is greater than heater pressure, product could enter 

the heater with downstream consequences. If the process 

pressure is less than heater 

III:2-49

pressure, the heater stream could enter into the process fluid. 

If loss of circulation occurs in liquid or gas coolers, increased 

product temperature could affect downstream operations and 

require pressure relief. 

Health 

Because these are closed systems, exposures under normal 

operating conditions are expected to be minimal. Depending 

on the fuel, process operation, and unit design, there is a 

potential for exposure to hydrogen sulfide, carbon monoxide, 

hydrocarbons, steam boiler feed-water sludge, and 

water-treatment chemicals. Skin contact should be avoided 

with boiler blowdown, which may contain phenolic 

compounds. Safe work practices and/or appropriate personal 

protective equipment against hazards may be needed during 

process maintenance, inspection, and turnaround activities 

and for protection from radiant heat, superheated steam, hot 

hydrocarbon, and noise exposures. 

STEAM GENERATION 

HEATER AND BOILER OPERATIONS 

Steam is generated in main generation plants, and/or at 

various process units using heat from flue gas or other 

sources. Heaters (furnaces) include burners and a combustion 

air system, the boiler enclosure in which heat transfer takes 

place, a draft or pressure system to remove flue gas from the 

furnace, soot blowers, and compressed-air systems that seal 

openings to prevent the escape of flue gas. Boilers consist of 

a number of tubes that carry the water-steam mixture through 

the furnace for maximum heat transfer. These tubes run 

between steam-distribution drums at the top of the boiler and 

water-collecting drums at the bottom of the boiler. Steam 

flows from the steam drum to the superheater before entering 

the steam distribution system. 

HEATER FUEL 

Heaters may use any one or combination of fuels including 

refinery gas, natural gas, fuel oil, and powdered coal. 

Refinery 

off-gas is collected from process units and combined with 

natural gas and LPG in a fuel-gas balance drum. The balance 

drum provides constant system pressure, fairly stable 

Btu-content fuel, and automatic separation of suspended 

liquids in gas vapors, and it prevents carryover of large slugs 

of condensate into the distribution system. Fuel oil is 

typically a mix of refinery crude oil with straight-run and 

cracked residues and other products. The fuel-oil system 

delivers fuel to process-unit heaters and steam generators at 

required temperatures and pressures. The fuel oil is heated to 

pumping temperature, sucked through a coarse suction 

strainer, pumped to a temperature-control heater, and then 

pumped through a fine-mesh strainer before being burned. 

In one example of process-unit heat generation, carbon 

monoxide boilers recover heat in catalytic cracking units as 

carbon monoxide in flue gas is burned to complete 

combustion. In other processes, waste-heat recovery units 

use heat from the flue gas to make steam. 

STEAM DISTRIBUTION 

The distribution system consists of valves, fittings, piping, 

and connections suitable for the pressure of the steam 

transported. Steam leaves the boilers at the highest pressure 

required by the process units or electrical generation. The 

steam pressure is then reduced in turbines that drive process 

pumps and compressors. Most steam used in the refinery is 

condensed to water in various types of heat exchangers. The 

condensate is reused as boiler feedwater or discharged to 

wastewater treatment. When refinery steam is also used to 

drive steam turbine generators to produce electricity, the 

steam must be produced at much higher pressure than 

required for process steam. Steam typically is generated by 

heaters (furnaces) and boilers combined in one unit. 

FEEDWATER 

Feedwater supply is an important part of steam generation. 

There must always be as many pounds of water entering the 

system as there are pounds of steam leaving it. Water used in 

steam generation must be free of contaminants including 

III:2-50

minerals and dissolved impurities that can damage the system 

or affect its operation. Suspended materials such as silt, 

sewage, and oil, which form scale and sludge, must be 

coagulated or filtered out of the water. Dissolved gases, 

particularly carbon dioxide and oxygen, cause boiler 

corrosion and are removed by deaeration and treatment. 

Dissolved minerals including metallic salts, calcium, 

carbonates, etc., that cause scale, corrosion, and turbine blade 

deposits are treated with lime or soda ash to precipitate them 

from the water. Recirculated cooling water must also be 

treated for hydrocarbons and other contaminants. 

Depending on the characteristics of raw boiler feedwater, 

some or all of the following six stages of treatment will be 

applicable: 

(1) Clarification 

(2) Sedimentation 

(3) Filtration 

(4) Ion exchange 

(5) Deaeration 

(6) Internal treatment 



The most potentially hazardous operation in steam generation 

is heater startup. A flammable mixture of gas and air can 

build up as a result of loss of flame at one or more burners 

during light-off. Each type of unit requires specific startup 

and emergency procedures including purging before lightoff 

and in the event of misfire or loss of burner flame. 


If feedwater runs low and boilers are dry, the tubes will 

overheat and fail. Conversely, excess water will be carried 

over into the steam distribution system and damage the 

turbines. Feedwater must be free of contaminants that could 

affect operations. Boilers should have continuous or 

intermittent blowdown systems to remove water from steam 

drums and limit buildup of 

scale on turbine blades and superheater tubes. Care must be 

taken not to overheat the superheater during startup and 

shut-down. Alternate fuel sources should be provided in the 

event of loss of gas due to refinery unit shutdown or 

emergency. Knockout pots provided at process units remove 

liquids from fuel gas before burning. 

Health 


equipment may be needed for potential exposures to 

feedwater chemicals, steam, hot water, radiant heat, and 

noise, and during process sampling, inspection, maintenance, 

and turnaround activities. 

PRESSURE-RELIEF AND FLARE SYSTEMS 

PRESSURE-RELIEF SYSTEMS 

Pressure-relief systems control vapors and liquids that are 

released by pressure-relieving devices and blow-downs. 

Pressure relief is an automatic, planned release when 

operating pressure reaches a predetermined level. Blowdown 

normally refers to the intentional release of material, such as 

blowdowns from process unit startups, furnace blowdowns, 

shutdowns, and emergencies. Vapor depressuring is the rapid 

removal of vapors from pressure vessels in case of fire. This 

may be accom-plished by the use of a rupture disc, usually set 

at a higher pressure than the relief valve. 

SAFETY RELIEF VALVE OPERATIONS 

Safety relief valves, used for air, steam, and gas as well as for 

vapor and liquid, allow the valve to open in proportion to the 

increase in pressure over the normal operating pressure. 

Safety valves designed primarily to release high volumes of 

steam usually pop open to full capacity. The overpressure 

needed to open liquid-relief valves where large-volume 

discharge is not required increases as the valve lifts due to 

increased spring resistance. Pilot-operated safety relief valves, 

with up to six times the capacity of normal relief valves, are 

used where tighter 

III:2-51

sealing and larger volume discharges are required. 

Nonvolatile liquids are usually pumped to oil-water 

separation and recovery systems, and volatile liquids are sent 

to units operating at a lower pressure. 

FLARE SYSTEMS 

A typical closed pressure release and flare system includes 

relief valves and lines from process units for collection of 

discharges, knockout drums to separate vapors and liquids, 

seals, and/or purge gas for flashback protection, and a flare 

and igniter system which combusts vapors when discharging 

directly to the atmosphere is not permitted. Steam may be 

injected into the flare tip to reduce visible smoke. 

PRESSURE RELIEF HEALTH AND SAFETY 

CONSIDERATIONS 


Vapors and gases must not discharge where sources of 

ignition could be present. 


Liquids should not be discharged directly to a vapor disposal 

system. Flare knockout drums and flares need to be large 

enough to handle emergency blowdowns. Drums should be 

provided with relief in the event of over pressure. 

Pressure relief valves must be provided where the potential 

exists for overpressure in refinery processes due to the 

following causes: 

(1) Loss of cooling water, which may greatly 

reduce pressure in condensers and 

increase the pressure in the process unit. 

(2) Loss of reflux volume, which may cause 

a pressure drop in condensers and a 

pressure rise in distillation towers 

because the quantity of reflux affects the 

volume of vapors leaving the distillation 

tower. 

(3) Rapid vaporization and pressure 

increase from injection of a lower 

boiling-point liquid including water into 

a process vessel operating at higher 

temperatures. 

(4) Expansion of vapor and resultant 

over-pressure due to overheated process 

steam, malfunctioning heaters, or fire. 

(5) Failure of automatic controls, closed 

outlets, heat exchanger failure, etc. 

(6) Internal explosion, chemical reaction, 

thermal expansion, or accumulated 

gases. 

Maintenance is important because valves are required to 

function properly. The most common operating problems are 

listed below. 

Health 

(1) Failure to open at set pressure, because 

of plugging of the valve inlet or outlet, 

or because corrosion prevents proper 

operation of the disc holder and guides. 

(2) Failure to reseat after popping open due 

to fouling, corrosion, or deposits on the 

seat or moving parts, or because solids in 

the gas stream have cut the valve disc. 

(3) Chattering and premature opening, 

because operating pressure is too close to 

the set point. 


equipment may be needed to protect against hazards during 


WASTEWATER TREATMENT 

Wastewater treatment is used for process, runoff, and 

sewerage water prior to discharge or recycling. Wastewater 

typically contains hydrocarbons, dissolved materials, 

suspended solids, 

III:2-52

phenols, ammonia, sulfides, and other compounds. 

Wastewater includes condensed steam, stripping water, spent 

caustic solutions, cooling tower and boiler blowdown, wash 

water, alkaline and acid waste neutralization water, and other 

process-associated water. 

PRETREATMENT OPERATIONS 

Pretreatment is the separation of hydrocarbons and solids 

from wastewater. API separators, interceptor plates, and 

settling ponds remove suspended hydrocarbons, oily sludge, 

and solids by gravity separation, skimming, and filtration. 

Some oil-in-water emulsions must be heated first to assist in 

separating the oil and the water. Gravity separation depends 

on the specific gravity differences between water and 

immiscible oil globules, which allows free oil to be skimmed 

off the surface of the wastewater. Acidic wastewater is 

neutralized using ammonia, lime, or soda ash. Alkaline 

wastewater is treated with sulfuric acid, hydrochloric acid, 

carbon dioxide-rich flue gas, or sulfur. 

SECONDARY TREATMENT OPERATIONS 

After pretreatment, suspended solids are removed by 

sedimentation or air flotation. Wastewater with low levels of 

solids may be screened or filtered. Flocculation agents are 

sometimes added to help separation. Secondary treatment 

processes biologically degrade and oxidize soluble organic 

matter by the use of activated sludge, unaerated or aerated 

lagoons, trickling filter methods, or anaerobic treatments. 

Materials with high adsorption characteristics are used in 

fixed-bed filters or added to the wastewater to form a slurry 

which is removed by sedimentation or filtration. Additional 

treatment methods are used to remove oils and chemicals 

from wastewater. Stripping is used on wastewater containing 

sulfides and/or ammonia, and solvent extraction is used to 

remove phenols. 

activated carbon adsorption, etc. Compressed oxygen is 

diffused into wastewater streams to oxidize certain chemicals 

or to satisfy regulatory oxygen-content requirements. 

Wastewater that is to be recycled may require cooling to 

remove heat and/or oxidation by spraying or air stripping to 

remove any remaining phenols, nitrates, and ammonia. 



The potential for fire exists if vapors from wastewater 

containing hydrocarbons reach a source of ignition during 

treatment. 

Health 



waste products during process sampling, inspection, 

maintenance, and turnaround activities as well as to noise, 

gases, and heat. 

COOLING TOWERS 

Cooling towers remove heat from process water by 

evaporation and latent heat transfer between hot water and 

air. The two types of towers are crossflow and counterflow. 

Crossflow towers introduce the airflow at right angles to the 

water flow throughout the structure. In counterflow cooling 

towers, hot process water is pumped to the uppermost plenum 

and allowed to fall through the tower. Numerous slats or 

spray nozzles located throughout the length of the tower 

disperse the water and help in cooling. Air enters at the tower 

bottom and flows upward against the water. When the fans or 

blowers are at the air inlet, the air is considered to be forced 

draft. Induced draft is when the fans are at the air outlet. 

TERTIARY TREATMENT OPERATIONS 

Tertiary treatments remove specific pollutants to meet 

regulatory discharge requirements. These treatments include 

chlorination, ozonation, ion exchange, reverse osmosis, 

III:2-53

COOLING WATER 

Recirculated cooling water must be treated to remove 

impurities and dissolved hydrocarbons. Because the water is 

saturated with oxygen from being cooled with air, the chances 

for corrosion are increased. One means of corrosion 

prevention is the addition of a material to the cooling water 

that forms a protective film on pipes and other metal surfaces. 



When cooling water is contaminated by hydrocarbons, 

flammable vapors can be evaporated into the discharge air. 

If a source of ignition is present, or if lightning occurs, a fire 

may start. A potential fire hazard also exists where there are 

relatively dry areas in induced-draft cooling towers of 

combustible construction. 


Loss of power to cooling tower fans or water pumps could 

have serious consequences in the operation of the refinery. 

Impurities in cooling water can corrode and foul pipes and 

heat exchangers, scale from dissolved salts can deposit on 

pipes, and wooden cooling towers can be damaged by 

microorganisms. 

Health 

Cooling-tower water can be contaminated by process 

materials and by-products including sulfur dioxide, hydrogen 

sulfide, and carbon dioxide, with resultant exposures. Safe 

work practices and/or appropriate personal protective 

equipment may be needed during process sampling, 

inspection, maintenance, and turnaround activities; and for 

exposure to hazards such as those related to noise, 

water-treatment chemicals, and hydrogen sulfide when 

wastewater is treated in conjunction with cooling towers. 

ELECTRIC POWER 

Refineries may receive electricity from outside sources or 

produce their own power with generators driven by steam 

turbines or gas engines. Electrical substations receive power 

from the utility or power plant for distribution throughout the 

facility. They are usually located in nonclassified areas, away 

from sources of vapor or cooling-tower water spray. 

Transformers, circuit breakers, and feed-circuit switches are 

usually located in substations. Substations feed power to 

distribution stations within the process unit areas. 

Distribution stations can be located in classified areas, 

providing that classification requirements are met. 

Distribution stations usually have a liquid-filled transformer 

and an oil-filled or air-break disconnect device. 



Generators that are not properly classified and are located too 

close to process units may be a source of ignition should a 

spill or release occur. 


Normal electrical safety precautions including dry footing, 

high-voltage warning signs, and guarding must be taken to 

protect against electrocution. Lockout/tagout and other 

appropriate safe work practices must be established to prevent 

energization while work is being performed on high-voltage 

electrical equipment. 

Health 

Safe work practices and/or the use of appropriate personal 

protective equipment may be needed for exposures to noise, 

for exposure to hazards during inspection and maintenance 

activities, and when working around transformers and 

switches that may contain a dielectric fluid which requires 

special handling precautions. 

III:2-54

GAS AND AIR COMPRESSORS 

Both reciprocating and centrifugal compressors are used 

throughout the refinery for gas and compressed air. Air 

compressor systems include compressors, coolers, air 

receivers, air dryers, controls, and distribution piping. 

Blowers are used to provide air to certain processes. Plant air 

is provided for the operation of air-powered tools, catalyst 

regeneration, process heaters, steam-air decoking, sour-water 

oxidation, gasoline sweetening, asphalt blowing, and other 

uses. Instrument air is provided for use in pneumatic 

instruments and controls, air motors and purge connections. 



Air compressors should be located so that the suction does 

not take in flammable vapors or corrosive gases. There is a 

potential for fire should a leak occur in gas compressors. 


Knockout drums are needed to prevent liquid surges from 

entering gas compressors. If gases are contaminated with 

solid materials, strainers are needed. Failure of automatic 

compressor controls will affect processes. If maximum 

pressure could potentially be greater than compressor or 

process-equipment design pressure, pressure relief should be 

provided. Guarding is needed for exposed moving parts on 

compressors. Compressor buildings should be properly 

electrically classified, and provisions should be made for 

proper ventilation. 

Where plant air is used to back up instrument air, 

interconnections must be upstream of the instrument air 

drying system to prevent contamination of instruments with 

moisture. Alternate sources of instrument air supply, such as 

use of nitrogen, may be needed in the event of power outages 

or compressor failure. 

Health 


equipment may be needed for exposure to hazards such as 

noise and during inspection and maintenance activities. The 

use of appropriate safeguards must be considered so that plant 

and instrument air is not used for breathing or pressuring 

potable water systems. 

MARINE, TANK CAR, AND TANK TRUCK 

LOADING and UNLOADING 

Facilities for loading liquid hydrocarbons into tank cars, tank 

trucks, and marine vessels and barges are usually part of the 

refinery operations. Product characteristics, distribution 

needs, shipping requirements, and operating criteria are 

important when designing loading facilities. Tank trucks and 

rail tank cars are either top- or bottom-loaded, and 

vapor-recovery systems may be provided where required. 

Loading and unloading liquefied petroleum gas (LPG) require 

special considerations in addition to those for liquid 

hydrocarbons. 



The potential for fire exists where flammable vapors from 

spills or releases can reach a source of ignition. Where 

switch-loading is permitted, safe practices need to be 

established and followed. Bonding is used to equalize the 

electrical charge between the loading rack and the tank truck 

or tank car. Grounding is used at truck and rail loading 

facilities to prevent flow of stray currents. Insulating flanges 

are used on marine dock piping connections to prevent static 

electricity buildup and discharge. Flame arrestors should be 

installed in loading rack and marine vapor-recovery lines to 

prevent flashback. 

III:2-55


Automatic or manual shutoff systems at supply headers are 

needed for top and bottom loading in the event of leaks or 

overfills. Fall protection such as railings are needed for 

top-loading racks where employees are exposed to falls. 

Drainage and recovery systems may be provided for storm 

drainage and to handle spills and leaks. Precautions must be 

taken at LPG loading facilities not to overload or 

overpressurize tank cars and trucks. 

Health 

The nature of the health hazards at loading and unloading 

facilities depends upon the products being loaded and the 

products previously transported in the tank cars, tank trucks, 

or marine vessels. Safe work practices and/or appropriate 

personal protective equipment may be needed to protect 

against hazardous exposures when loading or unloading, 

cleaning up spills or leaks, or when gauging, inspecting, 

sampling, or performing maintenance activities on loading 

facilities or vapor-recovery systems. 

TURBINES 

Turbines are usually gas- or steam-powered and are typically 

used to drive pumps, compressors, blowers, and other refinery 

process equipment. Steam enters turbines at high 

temperatures and pressures, expands across and drives 

rotating blades while directed by fixed blades. 



Steam turbines used for exhaust operating under vacuum 

should have safety relief valves on the discharge side, both 

for protection and to maintain steam in the event of vacuum 

failure. Where maximum operating pressure could be greater 

than design pressure, steam turbines should be provided with 

relief 

devices. Consideration should be given to providing 

governors and overspeed control devices on turbines. 

Health 


equipment may be needed for noise, steam and heat 

exposures, and during inspection and maintenance activities. 

PUMPS, PIPING AND VALVES 

Centrifugal and positive-displacement (i.e., reciprocating) 

pumps are used to move hydrocarbons, process water, fire 

water, and wastewater through piping within the refinery. 

Pumps are driven by electric motors, steam turbines, or 

internal combustion engines. The pump type, capacity, and 

construction materials depend on the service for which it is 

used. 

Process and utility piping distribute hydrocarbons, steam, 

water, and other products throughout the facility. Their size 

and construction depend on the type of service, pressure, 

temperature, and nature of the products. Vent, drain, and 

sample connections are provided on piping, as well as 

provisions for blanking. 

Different types of valves are used depending on their 

operating purpose. These include gate valves, bypass valves, 

globe and ball valves, plug valves, block and bleed valves, 

and check valves. Valves can be manually or automatically 

operated. 



The potential for fire exists should hydrocarbon pumps, 

valves, or lines develop leaks that could allow vapors to reach 

sources of ignition. Remote sensors, control valves, fire 

valves, and isolation valves should be used to limit the release 

of hydrocarbons at pump suction lines in the event of leakage 

and /or fire. 

III:2-56


Depending on the product and service, backflow prevention 

from the discharge line may be needed. The failure of 

automatic pump controls could cause a deviation in process 

pressure and temperature. Pumps operated with reduced or no 

flow can overheat and rupture. Pressure relief in the discharge 

piping should be provided where pumps can be 

overpressured. Provisions may be made for pipeline 

expansion, movement, and temperature changes to avoid 

rupture. Valves and instruments that require servicing or 

other work should be accessible at grade level or from an 

operating platform. Operating vent and drain connections 

should be provided with double-block valves, a block valve 

and plug, or blind flange for protection against releases. 

Health 

Safe work practices and/or appropriate personal pro-tective 

equipment may be needed for exposure to haz-ards such as 

those related to liquids and vapors when opening or draining 

pumps, valves, and/or lines, and during product sampling, 

inspection, and maintenance activities. 

TANK STORAGE 

Atmospheric storage tanks and pressure storage tanks are 

used throughout the refinery for storage of crudes, 

intermediate 

hydrocarbons (during the process), and finished products. 

Tanks are also provided for fire water, process and treatment 

water, acids, additives, and other chemicals. The type, 

construction, capacity and location of tanks depends on their 

use and materials stored. 



The potential for fire exists should hydrocarbon storage tanks 

be overfilled or develop leaks that allow vapors to escape and 

reach sources of ignition. Remote sensors,control valves, 

isolation valves, and fire valves may be provided at tanks for 

pump-out or closure in the event of a fire in the tank, or in the 

tank dike or storage area. 


Tanks may be provided with automatic overflow control and 

alarm systems, or manual gauging and checking procedures 

may be established to control overfills. 

Health 


equipment may be needed for exposure to hazards related to 

product sampling, manual gauging, inspection, and 

maintenance activities including confined-space entry where 

applicable. 

III:2-57

F. BIBLIOGRAPHY 

American Petroleum Institute. 1971. Chemistry and 

Petroleum for Classroom Use in Chemistry 

Courses. Washington, D.C.: American Petroleum 

Institute. 

__________. 1973. Industrial Hygiene Monitoring Manual 

for Petroleum Refineries and Selected 

Petrochemical Operations. Manual 

2700-1/79-1M. Washington, D.C.: American 

Petroleum Institute. 

__________. 1980. Facts About Oil. Manual 

4200-10/80-25M. Washington, D.C.: American 


__________. 1990. Management of Process Hazards. RP 

750. Washington, D.C.: American Petroleum 

Institute. 

__________. 1990. Inspection of Piping, Tubing, Valves 

and 

Fittings. RP 574. Washington, D.C.: American 


__________. 1991. Inspection of Fired Boilers and Heaters. 

RP 573. Washington, D.C.: American Petroleum 

Institute. 

__________. 1992. Inspection of Pressure Vessels. RP 572. 

Washington, D.C.: American Petroleum Institute. 

__________. 1992. Inspection of Pressure Relieving 

Devices 

RP 576. Washington, D.C.: American Petroleum 

Institute. 

__________. 1994. Fire Protection in Refineries. Sixth 

Edition. RP 2001. Washington, D.C.: American 


Exxon Company, USA. 1987. Encyclopedia for the User of 

Petroleum Products. Lubetext D400. Houston: 

Exxon Company, USA. 

Hydrocarbon Processing. 1988. Refining Handbook. 

Houston: Gulf Publishing Co. 

__________. 1992. Refining Handbook. Houston: Gulf 

Publishing Co. 

IARC. [No date given.] Occupational Exposures in 

Petroleum 

Refining. IARC Monographs, Volume 45. 

Kutler, A. A. 1969. "Crude distillation." Petro/Chem 

Engineering. New York: John G. Simmonds & 

Co., Inc. 

Mobil Oil Corporation. 1972. Light Products Refining, 

Fuels 

Manufacture. Mobil Technical Bulletin, 1972. 

Fairfax, Virginia: Mobil Oil Corporation. 

Parmeggiani, Luigi, Technical Editor. 1983. Encyclopaedia 

of 

Occupational Health and Safety. Third Edition. 

Geneva: International Labour Organization. 

Shell International Petroleum Company Limited. 1983. The 

Petroleum Handbook. Sixth Edition. Amsterdam: 

Elsevier Science Publishers B.V. 

Speight, James G. 1980. The Chemistry and Terminology of 

Petroleum. New York: Marcel Dekker, Inc. 

Vervalin, Charles H., Editor. 1985. Fire Protection Manual 

for Hydrocarbon Processing Plants. Volume 1, 

Third edition. Houston: Gulf Publishing Co. 

Armistead, George, Jr. 1950. Safety in Petroleum Refining 

and Related Industries. New York: John G. 

Simmons & Co., Inc. 

III:2-58

APPENDIX III:2-1. GLOSSARY 

ABSORPTION The disappearance of one substance into 

another so that the absorbed substance loses its identifying 

characteristics, while the absorbing substance retains most of 

its original physical aspects. Used in refining to selectively 

remove specific components from process streams. 

ACID TREATMENT A process in which unfinished 

petroleum products such as gasoline, kerosene, and 

lubricating oil stocks are treated with sulfuric acid to improve 

color, odor, and other properties. 

ADDITIVE Chemicals added to petroleum products in small 

amounts to improve quality or add special characteristics. 

ADSORPTION Adhesion of the molecules of gases or 

liquids to the surface of solid materials. 

AIR FIN COOLERS A radiator-like device used to cool or 

condense hot hydrocarbons; also called fin fans. 

ALICYCLIC HYDROCARBONS Cyclic (ringed) 

hydrocarbons in which the rings are made up only of carbon 

atoms. 

ALIPHATIC HYDROCARBONS Hydrocarbons 

characterized by open-chain structures: ethane, butane, 

butene, acetylene, etc. 

ALKYLATION A process using sulfuric or hydro-fluoric 

acid as a catalyst to combine olefins (usually butylene) and 

isobutane to produce a high-octane product known as 

alkylate. 

API GRAVITY An arbitrary scale expressing the density of 

petroleum products. 

AROMATIC Organic compounds with one or more benzene 

rings. 

ASPHALTENES The asphalt compounds soluble in carbon 

disulfide but insoluble in paraffin naphthas. 

ATMOSPHERIC TOWER A distillation unit operated at 

atmospheric pressure. 

BENZENE An unsaturated, six-carbon ring, basic aromatic 

compound. 

BLEEDER VALVE A small-flow valve connected to a fluid 

process vessel or line for the purpose of bleeding off small 

quantities of contained fluid. It is installed with a block valve 

to determine if the block valve is closed tightly. 

BLENDING The process of mixing two or more petroleum 

products with different properties to produce a finished 

product with desired characteristics. 

BLOCK VALVE A valve used to isolate equipment. 

BLOWDOWN The removal of hydrocarbons from a process 

unit, vessel, or line on a scheduled or emergency basis by the 

use of pressure through special piping and drums provided for 

this purpose. 

BLOWER Equipment for moving large volumes of gas 

against low-pressure heads. 

BOILING RANGE The range of temperature (usually at 

atmospheric pressure) at which the boiling (or distillation) of 

a hydrocarbon liquid commences, proceeds, and finishes. 

BOTTOMS Tower bottoms are residue remaining in a 

distillation unit after the highest boiling-point material to be 

distilled has been removed. Tank bottoms are the heavy 

materials that accumulate in the bottom of storage tanks, 

usually comprised of oil, water, and foreign matter. 

III:2-59

BUBBLE TOWER A fractionating (distillation) tower in 

which the rising vapors pass through layers of condensate, 

bubbling under caps on a series of plates. 

CATALYST A material that aids or promotes a chemical 

reaction between other substances but does not react itself. 

Catalysts increase reaction speeds and can provide control by 

increasing desirable reactions and decreasing undesirable 

reactions. 

CATALYTIC CRACKING The process of breaking up 

heavier hydrocarbon molecules into lighter hydrocarbon 

fractions by use of heat and catalysts. 

CAUSTIC WASH A process in which distillate is treated 

with sodium hydroxide to remove acidic contaminants that 

contribute to poor odor and stability. 

CHD UNIT See Hydrodesulfurization. 

COKE A high carbon-content residue remaining from the 

destructive distillation of petroleum residue. 

COKING A process for thermally converting and upgrading 

heavy residual into lighter products and by-product petroleum 

coke. Coking also is the removal of all lighter distillable 

hydrocarbons that leaves a residue of carbon in the bottom of 

units or as buildup or deposits on equipment and catalysts. 

CONDENSATE The liquid hydrocarbon resulting from 

cooling vapors. 

CONDENSER A heat-transfer device that cools and 

condenses vapor by removing heat via a cooler medium such 

as water or lower-temperature hydrocarbon streams. 

CONDENSER REFLUX Condensate that is returned to the 

original unit to assist in giving increased conversion or 

recovery. 

COOLER A heat exchanger in which hot liquid 

hydrocarbon is passed through pipes immersed in cool water 

to lower its temperature. 

CRACKING The breaking up of heavy molecular-weight 

hydrocarbons into lighter hydrocarbon molecules by the 

application of heat and pressure, with or without the use of 

catalysts. 

CRUDE ASSAY A procedure for determining the general 

distillation and quality characteristics of crude oil. 

CRUDE OIL A naturally occurring mixture of hydrocarbons 

that usually includes small quantities of sulfur, nitrogen, and 

oxygen derivatives of hydrocarbons as well as trace metals. 

CYCLE GAS OIL Cracked gas oil returned to a cracking 

unit. 

DEASPHALTING Process of removing asphaltic materials 

from reduced crude using liquid propane to dissolve 

nonasphaltic compounds. 

DEBUTANIZER A fractionating column used to remove 

butane and lighter components from liquid streams. 

DE-ETHANIZER A fractionating column designed to 

remove ethane and gases from heavier hydrocarbons. 

DEHYDROGENATION A reaction in which hydro-gen 

atoms are eliminated from a molecule. Dehydro-genation is 

used to convert ethane, propane, and butane into olefins 

(ethylene, propylene, and butenes). 

DEPENTANIZER A fractionating column used to remove 

pentane and lighter fractions from hydrocarbon streams. 

DEPROPANIZER A fractionating column for removing 

propane and lighter components from liquid streams. 

DESALTING Removal of mineral salts (most chlorides, 

e.g., magnesium chloride and sodium chloride) from crude 

oil. 

DESULFURIZATION A chemical treatment to remove 

sulfur or sulfur compounds from hydrocarbons. 

III:2-60

DEWAXING The removal of wax from petroleum products 

(usually lubricating oils and distillate fuels) by solvent 

absorption, chilling, and filtering. 

DIETHANOLAMINE A chemical (C4H11O2N) used to 

remove H2S from gas streams. 

DISTILLATE The products of distillation formed by 

condensing vapors. 

DOWNFLOW Process in which the hydrocarbon stream 

flows from top to bottom. 

DRY GAS Natural gas with so little natural gas liquids that 

it is nearly all methane with some ethane. 

FEEDSTOCK Stock from which material is taken to be fed 

(charged) into a processing unit. 

FLASHING The process in which a heated oil under 

pressure is suddenly vaporized in a tower by reducing 

pressure. 

FLASH POINT Lowest temperature at which a petroleum 

product will give off sufficient vapor so that the vapor-air 

mixture above the surface of the liquid will propagate a flame 

away from the source of ignition. 

FLUX Lighter petroleum used to fluidize heavier residual so 

that it can be pumped. 

FOULING Accumulation of deposits in condensers, 

exchangers, etc. 

FRACTION One of the portions of fractional distillation 

having a restricted boiling range. 

FRACTIONATING COLUMN Process unit that separates 

various fractions of petroleum by simple distillation, with the 

column tapped at various levels to separate and remove 

fractions according to their boiling ranges. 

FUEL GAS Refinery gas used for heating. 

GAS OIL Middle-distillate petroleum fraction with a boiling 

range of about 350-750º F, usually includes diesel fuel, 

kerosene, heating oil, and light fuel oil. 

GASOLINE A blend of naphthas and other refinery 

products with sufficiently high octane and other desirable 

characteristics to be suitable for use as fuel in internal 

combustion engines. 

HEADER A manifold that distributes fluid from a series of 

smaller pipes or conduits. 

HEAT As used in the Health Considerations sections of this 

document, heat refers to thermal burns for contact with hot 

surfaces, hot liquids and vapors, steam, etc. 

HEAT EXCHANGER Equipment to transfer heat between 

two flowing streams of different temperatures. Heat is 

transferred between liquids or liquids and gases through a 

tubular wall. 

HIGH-LINE OR HIGH-PRESSURE GAS High-pressure 

(100 psi) gas from cracking unit distillate drums that is 

compressed and combined with low-line gas as gas 

absorption feedstock. 

HYDROCRACKING A process used to convert heavier 

feedstocks into lower-boiling, higher-value products. The 

process employs high pressure, high temperature, a catalyst, 

and hydrogen. 

HYDRODESULFURIZATION A catalytic process in 

which the principal purpose is to remove sulfur from 

petroleum fractions in the presence of hydrogen. 

HYDROFINISHING A catalytic treating process carried 

out in the presence of hydrogen to improve the properties of 

low viscosity-index naphthenic and medium viscosity-index 

naphthenic oils. It is also applied to paraffin waxes and 

microcrystalline waxes for the removal of undesirable 

components. This process consumes hydrogen and is used in 

lieu of acid treating. 

III:2-61

HYDROFORMING Catalytic reforming of naphtha at 

elevated temperatures and moderate pressures in the presence 

of hydrogen to form high-octane BTX aromatics for motor 

fuel or chemical manufacture. This process results in a net 

production of hydrogen and has rendered thermal reforming 

somewhat obsolete. It represents the total effect of numerous 

simultaneous reactions such as cracking, polymerization, 

dehydrogenation, and isomerization. 

HYDROGENATION The chemical addition of hydrogen to 

a material in the presence of a catalyst. 

INHIBITOR Additive used to prevent or retard undesirable 

changes in the quality of the product, or in the condition of 

the equipment in which the product is used. 

ISOMERIZATION A reaction that catalytically converts 

straight-chain hydrocarbon molecules into branched-chain 

molecules of substantially higher octane number. The 

reaction rearranges the carbon skeleton of a molecule without 

adding or removing anything from the original material. 

ISO-OCTANE A hydrocarbon molecule 

(2,2,4-trimethylpentane) with excellent antiknock 

characteristics on which the octane number of 100 is based. 

KNOCKOUT DRUM A vessel wherein suspended liquid is 

separated from gas or vapor. 

LEAN OIL Absorbent oil fed to absorption towers in which 

gas is to be stripped. After absorbing the heavy ends from the 

gas, it becomes fat oil. When the heavy ends are subsequently 

stripped, the solvent again becomes lean oil. 

LOW-LINE or LOW-PRESSURE GAS Low-pressure (5 

psi) gas from atmospheric and vacuum distillation recovery 

systems that is collected in the gas plant for compression to 

higher pressures. 

NAPHTHENES Hydrocarbons (cycloalkanes) with the 

general formula CnH2n, in which the carbon atoms are 

arranged to form a ring. 

OCTANE NUMBER A number indicating the relative 

antiknock characteristics of gasoline. 

OLEFINS A family of unsaturated hydrocarbons with one 

carbon-carbon double bond and the general formula CnH2n. 

PARAFFINS A family of saturated aliphatic hydrocarbons 

(alkanes) with the general formula CnH2n+2. 

POLYFORMING The thermal conversion of naphtha and 

gas oils into high-quality gasoline at high temperatures and 

pressure in the presence of recirculated hydrocarbon gases. 

POLYMERIZATION The process of combining two or 

more unsaturated organic molecules to form a single (heavier) 

molecule with the same elements in the same proportions as 

in the original molecule. 

PREHEATER Exchanger used to heat hydrocarbons before 

they are fed to a unit. 

PRESSURE-REGULATING VALVE A valve that releases 

or holds process-system pressure (that is, opens or closes) 

either by preset spring tension or by actuation by a valve 

controller to assume any desired position between fully open 

and fully closed. 

PYROLYSIS GASOLINE A by-product from the 

manufacture of ethylene by steam cracking of hydrocarbon 

fractions such as naphtha or gas oil. 

PYROPHORIC IRON SULFIDE A substance typically 

formed inside tanks and processing units by the corrosive 

NAPHTHA A general term used for low boiling 

hydrocarbon fractions that are a major component of 

gasoline. Aliphatic naphtha refers to those naphthas 

containing less than 0.1% benzene and with carbon numbers 

from C3 through C16. Aromatic naphthas have carbon 

numbers from C6 through C16 and contain significant 

quantities of aromatic hydrocarbons such as benzene 

(>0.1%), toluene, and xylene. 

III:2-62

interaction of sulfur compounds in the hydrocarbons and the 

iron and steel in the equipment. On exposure to air (oxygen) 

it ignites spontaneously. 

QUENCH OIL Oil injected into a product leaving a 

cracking or reforming heater to lower the temperature and 

stop the cracking process. 

RAFFINATE The product resulting from a solvent 

extraction process and consisting mainly of those components 

that are least soluble in the solvents. The product recovered 

from an extraction process is relatively free of aromatics, 

naphthenes, and other constituents that adversely affects 

physical parameters. 

REACTOR The vessel in which chemical reactions take 

place during a chemical conversion type of process. 

REBOILER An auxiliary unit of a fractionating tower 

designed to supply additional heat to the lower portion of the 

tower. 

RECYCLE GAS High hydrogen-content gas returned to a 

unit for reprocessing. 

REDUCED CRUDE A residual product remaining after the 

removal by distillation of an appreciable quantity of the more 

volatile components of crude oil. 

REFLUX The portion of the distillate returned to the 

fractionating column to assist in attaining better separation 

into desired fractions. 

REFORMATE An upgraded naphtha resulting from 

catalytic or thermal reforming. 

REFORMING The thermal or catalytic conversion of 

petroleum naphtha into more volatile products of higher 

octane number. It represents the total effect of numerous 

simultaneous reactions such as cracking, polymerization, 

dehydrogenation, and isomerization. 

under carefully controlled conditions of temperature and 

oxygen content of the regeneration gas stream. 

SCRUBBING Purification of a gas or liquid by washing it 

in a tower. 

SOLVENT EXTRACTION The separation of materials of 

different chemical types and solubilities by selective solvent 

action. 

SOUR GAS Natural gas that contains corrosive, 

sulfur-bearing compounds such as hydrogen sulfide and 

mercaptans. 

STABILIZATION A process for separating the gaseous and 

more volatile liquid hydrocarbons from crude petroleum or 

gasoline and leaving a stable (less-volatile) liquid so that it 

can be handled or stored with less change in composition. 

STRAIGHT-RUN GASOLINE Gasoline produced by the 

primary distillation of crude oil. It contains no cracked, 

polymerized, alkylated, reformed, or visbroken stock. 

STRIPPING The removal (by steam-induced vaporization 

or flash evaporation) of the more volatile components from a 

cut or fraction. 

SULFURIC ACID TREATING A refining process in 

which unfinished petroleum products such as gasoline, 

kerosene, and lubricating oil stocks are treated with sulfuric 

acid to improve their color, odor, and other characteristics. 

SULFURIZATION Combining sulfur compounds with 

petroleum lubricants. 

SWEETENING Processes that either remove obnoxious 

sulfur compounds (primarily hydrogen sulfide, mercaptans, 

and thiophens) from petroleum fractions or streams, or 

convert them, as in the case of mercaptans, to odorless 

disulfides to improve odor, color, and oxidation stability. 

REGENERATION In a catalytic process the reactivation of 

the catalyst, sometimes done by burning off the coke deposits 

III:2-63

SWITCH LOADING The loading of a high static-charge 

retaining hydrocarbon (i.e., diesel fuel) into a tank truck, tank 

car, or other vessel that has previously contained a low-flash 

hydrocarbon (gasoline) and may contain a flammable mixture 

of vapor and air. 

TAIL GAS The lightest hydrocarbon gas released from a 

refining process. 

THERMAL CRACKING The breaking up of heavy oil 

molecules into lighter fractions by the use of high temperature 

without the aid of catalysts. 

TURNAROUND A planned complete shutdown of an entire 

process or section of a refinery, or of an entire refinery to 

perform major maintenance, overhaul, and repair operations 

and to inspect, test, and replace process materials and 

equipment. 

VACUUM DISTILLATION The distillation of petroleum 

under vacuum which reduces the boiling temperature 

sufficiently to prevent cracking or decomposition of the 

feedstock. 

VAPOR The gaseous phase of a substance that is a liquid at 

normal temperature and pressure. 

VISBREAKING Viscosity breaking is a low-temperature 

cracking process used to reduce the viscosity or pour point of 

straight-run residuum. 

WET GAS A gas containing a relatively high proportion of 

hydrocarbons that are recoverable as liquids. 

III:2-64


PRESSURE VESSEL GUIDELINES 


Recent inspection programs for metallic pressure containment 

vessels and tanks have revealed cracking and damage in a 

considerable number of the vessels inspected. 

Safety and hazard evaluations of pressure vessels, as also 

presented in PUB 8-1.5, need to consider the consequences 

of a leakage or a rupture failure of a vessel. 

Two consequences result from a complete rupture: 

For a leakage failure, the hazard consequences can range from 

no effect to very serious effects: 

@ 

@ 

Suffocation or poisoning, depending on the nature of 

the contained fluid, if the leakage occurs into a closed 

space; 

Fire and explosion for a flammable fluid are 

included as a physical hazard; and 

@ 

Blast effects due to sudden expansion of the 

pressurized fluid; and 

@ 

Chemical and thermal burns from contact with 

process liquids. 

@ 

Fragmentation damage and injury, if vessel rupture 

occurs. 

A. Introduction.........................................III:3-1 

B. Recent Cracking Experience in 

Pressure Vessels..........................III:3-2 

C. Nondestructive Examiniation 

Methods.......................................III:3-6 

D. Information for Safety 

Assessment..................................III:3-9 

E. Bibliography........................................III:3-9 

Appendix II:3-1. Recordkeeping Data 

for Steel Vessels and Low- 

Pressure Storage Tanks..........III:3-10 

Only pressure vessels and low pressure storage tanks widely 

used in process, pulp and paper, petroleum refining, and 

petrochemical industries and for water treatment systems of 

boilers and steam generation equipment are covered in this 

chapter. Excluded are vessels and tanks used in many other 

applications and also excludes other parts of a pressure 

containment system such as piping and valves. 

The types and applications of pressure vessels included and 

excluded in this chapter are summarized in Table III:3-1. An 

illustration of a schematic pressure vessel is presented in 

Figure III:3-1. 

NOTE: Though this review of pressure vessels excludes 

inspection or evaluation of safety release valves, the 

compliance officer should be aware that NO valves or 

T-fittings should be present between the vessel and the 

safety relief valve. 

III:3-1

Pressure Vessel Design Codes. Most of the pressure or 

storage vessels in service in the United States will have been 

designed and constructed in accordance with one of the 

following two design codes: 

In addition, some vessels designed and constructed between 

1934 to 1956 may have used the rules in the "API-ASME 

Code for Unfired Pressure Vessels for Petroleum Liquids and 

Gases." This code was discontinued in 1956. 

@ 

@ 

The ASME Code, or Section VIII of the ASME 

(American Society of Mechanical Engineers) Boiler 

and Pressure Vessel Code; or 

The API Standard 620 or the American Petroleum 

Institute Code which provides rules for lower 

pressure vessels not covered by the ASME Code. 

Vessels certification can only be performed by trained 

inspectors qualified for each code. Written tests and 

practical experience are required for certification. Usually, 

the compliance office is not equipped for this task, but is able 

to obtain the necessary contract services. 

TABLE III:3-1. VESSEL TYPES 

Vessels included: 

Stationary and unfired 

Used for pressure containment of 

gases and liquids 

Constructed of carbon steel or 

low alloy steel 

Vessel types specifically excluded: 

Vessels used as fired boilers 

Vessels used in high-temperature processes 

(above 315C, 600F) or at very low and cryogenic temperatures 

Vessels and containers used in transportable systems 

Operated at temperatures between 

Storage tanks that operate at nominally atmospheric 

-75 and 315C (-100 and 600F) pressure 

Piping and pipelines 

Safety and pressure-relief valves 

Special-purpose vessels, such as those for human occupancy. 

B. RECENT CRACKING EXPERIENCE IN PRESSURE VESSELS 

DEAERATOR SERVICE 

Deaeration refers to the removal of noncondensible gases, 

primarily oxygen, from the water used in a steam generation 

system. 

Deaerators are widely used in many industrial applications 

including power generation, pulp and paper, chemical, and 

petroleum refining and in many public facilities such as 

hospitals and schools where steam generation is required. In 

actual practice, the deaerator vessel can be separate from the 

III:3-2

Figure III:3-1. Some Major Parts of a Pressure Vessel 

storage vessel or combined with a storage vessel into one 

unit. 

Typical operational conditions for deaerator vessels range up 

to about 300 psi and up to about 150 C (300 F). Nearly all 

of the vessels are designed to ASME Code resulting in vessel 

wall thicknesses up to but generally less than 25 mm (1 in). 

The vessel material is almost universally one of the carbon 

steel grades. 

Analysis of incident survey data and other investigations has 

determined the following features about the deaerator vessel 

cracking. 

The failures and the survey results have prompted TAPPI 

(Technical Association of Pulp and Paper Industry), the 

National Board of Boiler and Pressure Vessel Inspectors, and 

NACE (National Association of Corrosion Engineers) to 

prepare inspection, operation and repair recommendations. 

For inspection, all recommendations suggest: 

@ 

@ 

Special attention to the internal surface of all welds 

and heat-affected zones (HAZ); and 

Use of the wet fluorescent magnetic particle (WFMT) 

method for inspection. 

@ 

@ 

@ 

Water hammer is the only design or operational 

factor that correlates with cracking. 

Cracking is generally limited to weld regions of 

vessels that had not been postweld heat treated. 

Corrosion fatigue appears to be the predominant 

mechanism of crack formation and growth. 

The TAPPI and the NACE recommendations also contain 

additional items, such as: 

@ 

Inspection by personnel certified to American Society 

for Nondestructive Testing's SNT-TC-1A minimum 

Level I and interpretation of the results by minimum 

Level II; and 

@ Reinspection within one year for repaired vessels, 1-2 

years for vessels with discontinuities but unrepaired, 

III:3-3

and 3-5 years for vessels found free of discontinuities. 

AMINE SERVICE 

The amine process is used to remove hydrogen sulfide (H 2 S) 

from petroleum gases such as propane and butane. It is also 

used for carbon dioxide (CO 2 ) removal in some processes. 

Amine is a generic term and includes monoethanolamine 

(MEA), diethanolamine (DEA) and others in the amine 

group. These units are used in petroleum refinery, gas 

treatment and chemical plants. 

The operating temperatures of the amine process are generally 

in the 38 to 93C (100 to 200F) range and therefore the 

plant equipment is usually constructed from one of the 

carbon steel grades. The wall thickness of the pressure 

vessels in amine plants is typically about 25 mm (1 in). 

Although the possibility of cracking of carbon steels in an 

amine environment has been known for some years, real 

concern about safety implications was highlighted by a 1984 

failure of the amine process pressure vessel. Overall, the 

survey found about 40% cracking incidence in a total of 294 

plants. Cracking had occurred in the absorber/contactor, the 

regenerator and the heat exchanger vessels, and in the piping 

and other auxiliary equipment. Several of the significant 

findings of the survey were: 

@ 

@ 

@ 

All cracks were in or near welds. 

Cracking occurred predominantly in stressed or 

unrelieved (not PWHT) welds. 

Cracking occurred in all amine vessel processes but 

was most prevalent in MEA units. 

Information from laboratory studies indicate that pure amine 

does not cause cracking of carbon steels but amine with 

carbon dioxide in the gas phase causes severe cracking. The 

presence or absence of chlorides, cyanides, or hydrogen 

sulfide may also be factors but their full role in the cracking 

mechanism are not completely known at present. 

WET HYDROGEN SULFIDE 

Wet Hydrogen Sulfide refers to any fluid containing water 

and hydrogen sulfide (H 2 S). Hydrogen is generated when 

steel is exposed to this mixture and the hydrogen can enter 

into the steel. Dissolved hydrogen can cause cracking, 

blistering, and embrittlement. 

The harmful effects of hydrogen generating environments on 

steel have been known and recognized for a long time in the 

petroleum and petrochemical industries. In particular, 

sensitivity to damage by hydrogen increases with the hardness 

and strength of the steel and damage and cracking are more 

apt to occur in high strength steels. 

@ 

@ 

@ 

@ 

Significant cracks can start from very small hard 

zones associated with welds; these hard zones are not 

detected by conventional hardness tests. 

Initially small cracks can grow by a stepwise form of 

hydrogen blistering to form through thickness cracks. 

NACE/API limits on weld hardness may not be 

completely effective in preventing cracking. 

Thermal stress relief (postweld heat treatment, 

PWHT) appears to reduce the sensitivity to and the 

severity of cracking. 

@ 

WFMT and UT (ultrasonic test) were the 

predominant detection methods for cracks; internal 

examination by WFMT is the preferred method. 

Wet hydrogen sulfide has also been found to cause service 

cracking in liquified petroleum gas (LPG) storage vessels. 

The service cracking in the LPG vessels occurs 

predominantly in the weld heat affected zone (HAZ). The 

vessels are usually 

III:3-4

spherical with wall thickness in the 20 mm to 75 mm (0.8 in 

to 3 in) range. 

Recommendations for new and existing wet hydrogen- sulfide 

vessels to minimize the risk of a major failure include: 

@ 

@ 

@ 

@ 

Use lower-strength steels for new vessels; 

Schedule an early inspection for vessels more than 

five years in service; 

Improve monitoring to minimize breakthrough of 

hydrogen sulfide; and 

Replace unsafe vessels or downgrade to less- severe, 

usually lower-pressure, service. 

AMMONIA SERVICE 

Commercial refrigeration systems, certain chemical processes, 

and formulators of agricultural chemicals will be sites of 

ammonia service tanks. 

PULP DIGESTER SERVICE 

The kraft pulping process is used in the pulp and paper 

industry to digest the pulp in the papermaking process. The 

operation is done in a relatively weak (a few percent) water 

solution of sodium hydroxide and sodium sulfide typically in 

the 110 to 140 C (230 to 285 F) temperature range. 

Since the early 1950s, a continuous version of this process 

has been widely used. Nearly all of the vessels are ASME 

Code vessels made using one of the carbon steel grades with 

typical design conditions of 175 to 180C (350 to 360F) 

and 150 psig. 

These vessels had a very good service record with only 

isolated reports of cracking problems until the occurrence of 

a sudden rupture failure in 1980. The inspection survey has 

revealed that about 65% of the properly inspected vessels had 

some cracking. Some of the cracks were fabrication flaws 

revealed by the use of more sensitive inspection techniques 

but most of the cracking was service-induced. The inspection 

survey and analysis indicates the following features about the 

cracking. 

Careful inspections of vessels used for storage of ammonia 

(in either vapor or liquid form) in recent years have resulted 

in evidence of serious stress corrosion cracking problems. 

The vessels for this service are usually constructed as spheres 

from one of the carbon steel grades, and they operate in the 

ambient temperature range. 

The water and oxygen content in the ammonia has a strong 

influence on the propensity of carbon steels to crack in this 

environment. 

@ 

@ 

@ 

@ 

All cracking was associated with welds. 

Wet fluorescent magnetic particle (WFMT) testing 

with proper surface preparation was the most 

effective method of detecting the cracking. 

Fully stress-relieved vessels were less susceptible. 

No clear correlation of cracking and noncrack-ing 

could be found with vessel age and manufacture or 

with process variables and practices. 

Cracks have a tendency to be found to be in or near the welds 

in as-welded vessels. Cracks occur both transverse and 

parallel to the weld direction. Thermal stress relieving seems 

to be a mitigating procedure for new vessels, but its efficacy 

for older vessels after a period of operation is dubious partly 

because small, undetected cracks may be present. 

@ 

Analysis and research indicate that the cracking is 

due to a caustic stress corrosion cracking mechanism 

although its occurrence at the relatively low caustic 

concentrations of the digester process was 

unexpected. 

Currently, preventive measures such as weld cladding, spray 

coatings, and anodic protection are being studied, and 

III:3-5

considerable information has been obtained. In the 

meantime, the recommended guideline is to perform an 

annual examination. 

SUMMARY OF SERVICE CRACKING 

EXPERIENCE 

The preceding discussion shows a strong influence of 

chemical environment on cracking incidence. This is a 

factor that is not explicitly treated in most design codes. 

Service experience is the best and often the only guide to 

in-service safety assessment. 

For vessels and tanks within the scope of this document, the 

service experience indicates that the emphasis of the 

inspection and safety assessment should be on: 

@ 

@ 

@ 

Welds and adjacent regions; 

Vessels that have not been thermally stress relieved 

(no PWHT of fabrication welds); and 

Repaired vessels, especially those without PWHT 

after repair. 

The evaluation of the severity of the detected cracks can be 

done by fracture mechanics methods. This requires specific 

information about stresses, material properties, and flaw 

indications. Generalized assessment guidelines are not easy 

to formulate. However, fortunately, many vessels in the 

susceptible applications listed above operate at relatively low 

stresses, and therefore, cracks have a relatively smaller effect 

on structural integrity and continued safe operation. 

@ 

Vessels in deaerator, amine, wet H2S, ammonia and 

pulp digesting service; 

C. NONDESTRUCTIVE EXAMINATION METHODS 

Of the various conventional and advanced nondestructive 

examination (NDE) methods, five are widely used for the 

examination of pressure vessels and tanks by certified 

pressure vessel inspectors. The names and acronyms of these 

common five methods are: 

referred to as "surface" examination methods and the last two 

as "volumetric" methods. Table II of PUB 8-1.5 summarizes 

the main features of these five methods. 

VISUAL EXAMINATION (VT) 

@ 

@ 

@ 

@ 

@ 

VT Visual Examination, 

PT Liquid Penetrant Test, 

MT Magnetic Particle Test, 

RT Gamma and X-ray Radiography, and 

UT Ultrasonic Test. 

A visual examination is easy to conduct and can cover a large 

area in a short time. 

It is very useful for assessing the general condition of the 

equipment and for detecting some specific problems such as 

severe instances of corrosion, erosion, and hydrogen 

blistering. The obvious requirements for a meaningful visual 

examination are a clean surface and good illumination. 

VT, PT and MT can detect only those discontinuities and 

defects that are open to the surface or are very near the 

surface. In contrast, RT and UT can detect conditions that are 

located within the part. For these reasons, the first three are 

often 

III:3-6

LIQUID PENETRANT TEST (PT) 

This method depends on allowing a specially formulated 

liquid (penetrant) to seep into an open discontinuity and then 

detecting the entrapped liquid by a developing agent. When 

the penetrant is removed from the surface, some of it remains 

entrapped in the discontinuities. Application of a developer 

draws out the entrapped penetrant and magnifies the 

discontinuity. Chemicals which fluoresce under black 

(ultraviolet) light can be added to the penetrant to aid the 

detectability and visibility of the developed indications. The 

essential feature of PT is that the discontinuity must be 

"open," which means a clean, undisturbed surface. 

The PT method is independent of the type and composition 

of the metal alloy so it can be used for the examination of 

austenitic stainless steels and nonferrous alloys where the 

magnetic particle test is not applicable. 

MAGNETIC PARTICLE TEST (MT) 

This method depends on the fact that discontinuities in or 

near the surface perturb magnetic flux lines induced into a 

ferromagnetic material. For a component such as a pressure 

vessel where access is generally limited to one surface at a 

time, the "prod" technique is widely used. The magnetic field 

is produced in the region around and between the prods 

(contact probes) by an electric current (either AC or DC) 

flowing between the prods. The ferromagnetic material 

requirement basically limits the applicability of MT to carbon 

and low- alloy steels. 

The perturbations of the magnetic lines are revealed by 

applying fine particles of a ferromagnetic material to the 

surface. The particles can be either a dry powder or a wet 

suspension in a liquid. The particles can also be treated to 

fluoresce under black light. These options lead to variations 

such as the "wet fluorescent magnetic particle test" (WFMT). 

MT has some capability for detecting subsurface defects. 

However, there is no easy way to determine the limiting depth 

of sensitivity since it is highly dependent on magnetizing 

current, material, and geometry and size of the defect. A very 

crude approximation would be a depth no more than 1.5 mm 

to 3 mm (1/16 in to 1/8 in). 

A very important precaution in performing MT is that corners 

and surface irregularities also perturb the magnetic field. 

Therefore, examining for defects in corners and near or in 

welds must be performed with extra care. Another precaution 

is that MT is most sensitive to discontinuities which are 

oriented transverse to the magnetic flux lines and this 

characteristic needs to be taken into account in determining 

the procedure for inducing the magnetic field. 

RADIOGRAPHY (RT) 

The basic principle of radiographic examination of metallic 

objects is the same as in any other form of radiography such 

as medical radiography. Holes, voids, and discontinuities 

decrease the attenuation of the X-ray and produce greater 

exposure on the film (darker areas on the negative film). 

Because RT depends on density differences, cracks with 

tightly closed surfaces are much more difficult to detect than 

open voids. Also, defects located in an area of a abrupt 

dimensional change are difficult to detect due to the 

superimposed density difference. RT is effective in showing 

defect dimensions on a plane normal to the beam direction 

but determination of the depth dimension and location 

requires specialized techniques. 

Since ionizing radiation is involved, field application of RT 

requires careful implementation to prevent health hazards. 

ULTRASONIC TESTING (UT) 

The fundamental principles of ultrasonic testing of metallic 

materials are similar to radar and related methods of using 

electromagnetic and acoustic waves for detection of foreign 

objects. The distinctive aspect of UT for the inspection of 

III:3-7

metallic parts is that the waves are mechanical, so the test 

equipment requires three basic components. 

@ 

@ 

@ 

Electronic system for generating electrical signal. 

Transducer system to convert the electrical signal 

into mechanical vibrations and vice versa and to 

inject the vibrations into and extract them from the 

material. 

Electronic system for amplifying, processing and 

displaying the return signal. 

Very short signal pulses are induced into the material and 

waves reflected back from discontinuities are detected during 

the "receive" mode. The transmitting and detection can be 

done with one transducer or with two separate transducers 

(the tandem technique). 

Unlike radiography, UT in its basic form does not produce a 

permanent record of the examination. However, more recent 

versions of UT equipment include automated operation and 

electronic recording of the signals. 

Ultrasonic techniques can also be used for the detection and 

measurement of general material loss such as by corrosion 

and erosion. Since wave velocity is constant for a specific 

material, the transit time between the initial pulse and the 

back reflection is a measure of the travel distance and the 

thickness. 

DETECTION PROBABILITIES AND FLAW 

SIZING 

The implementation of NDE (nondestructive examination) 

results for structural integrity and safety assessment involves 

a detailed consideration of two separate but interrelated 

factors. 

@ 

@ 

Detecting the discontinuity. 

Identifying the nature of the discontinuity and 

determining its size. 

Much of the available information on detection and sizing 

capabilities has been developed for aircraft and nuclear power 

applications. This kind of information is very specific to the 

nature of the flaw, the material, and the details of the test 

technique, and direct transference to other situations is not 

always warranted. 

The overall reliability of NDE is obviously an important 

factor in a safety and hazard assessment. Failing to detect or 

undersizing existing discontinuities reduces the safety margin 

while oversizing errors can result in unnecessary and 

expensive outages. High reliability results from a 

combination of factors. 

@ 

@ 

Validated procedures, equipment and test personnel. 

Utilization of diverse methods and techniques. 

@ 

Application of redundancy by repetitive and 

independent tests. 

Finally, it is useful to note that safety assessment depends on 

evaluating the "largest flaw that may be missed, not the 

smallest one that can be found." 

III:3-8

D. INFORMATION FOR SAFETY ASSESSMENT 

This chapter and PUB 8-1.5 has a large amount of 

information on the design rules, inspection requirements, and 

service experience, relevant to pressure vessels and low 

pressure storage tanks used in general industrial applications. 

Though the compliance officer is not usually qualified as a 

pressure vessel inspector, as a summary and a reminder, 

Appendix III:3-1 

outlines the information, data, and recordkeeping that are 

necessary, useful, or indicative of safe management of 

operating vessels and tanks. 

These records, besides the construction and maintenance logs 

usually are kept by the plant engineer, maintenance 

supervisor, or facility manager, will be indicative of the 

surveillance activities around safe operation of pressure 

vessels. 

E. BIBLIOGRAPHY 

Chuse, R. 1984. Pressure Vessels: The ASME Code 

Simplified. 6th ed. McGraw-Hill: New York. 

Forman, B. Fred. 1981. Local Stresses in Pressure 

Vessels. Pressure Vessel Handbook Publishing, Inc.: Tulsa. 

Hammer, W. 1981. Pressure Hazards in Occupational 


Management and Engineering. 2nd ed. Prentice-Hall: 

New York. 

McMaster, R. C. and McIntire, P. (eds.) 1982-1987. 

Nondestructive Testing Hand-book. 2nd ed., Vols. 1-3. 

American Society for Metals/American Society of 

Nondestructive Testing: Columbus. 

Megyesy, E. F. 1986. Pressure Vessel Handbook. 7th ed. 

Pressure Vessel Handbook Publishing Inc.: Tulsa. 

OSHA Instruction Pub 8-1.5. 1989. Guidelines for Pressure 

Vessel Safety Assessment. Occupational Safety and 

Health Administration: Washington, D.C. 

Thielsch, H. 1975. Defects and Failures in Pressure 

Vessels and Piping. 2nd ed., Chaps. 16 and 17. Reinhold: 

New York. 

Yokell, S. 1986. Understanding the Pressure Vessel Code. 

Chemical Engineering 93(9):75-85. 

III:3-9

APPENDIX III:3-1. RECORDKEEPING DATA FOR STEEL 

VESSELS AND LOW PRESSURE STORAGE 

TANKS 

INTRODUCTION AND SCOPE 

@ 

Date vessel was placed in service 

This outline summarizes information and data that will be 

helpful in assessing the safety of steel pressure vessels and 

low pressure storage tanks that operate at temperatures 

between -75 and 315 C (-100 and 600 F). 

VESSEL IDENTIFICATION AND 

DOCUMENTATION 

Information that identifies the specific vessel being assessed 

and provides general information about it include the 

following items: 

@ 

Current owner of the vessel 

@ 

Interruption dates if not in continuous service. 

DESIGN AND CONSTRUCTION 

INFORMATION 

Information that will identify the code or standard used for 

the design and construction of the vessel or tank and the 

specific design values, materials, fabrication methods, and 

inspection methods used include the following items: 

@ 

Design code 

-- ASME Code Section and Division, API 

Standard or other design code used 

@ 

Vessel location 

-- Original location and current location if it 

has been moved 

@ 

Type of construction 

-- Shop or field fabricated or other fabrication 

method 

@ Vessel identification 

-- Manufacturer's serial number 

-- National Board number if registered with NB 

@ 

@ 

@ 

Manufacturer identification 

-- Name and address of manufacturer 

-- Authorization or identification number of the 

manufacturer 

Date of manufacture of the vessel 

Data report for the vessel 

-- ASME U-1 or U-2, API 620 form or other 

applicable report 

@ 

@ 

@ 

VIII, division 1 or 2 vessels 

-- Maximum allowable pressure and 

temperature 

-- Minimum design temperature 

API 620 vessels 

-- Design pressure at top and maximum fill 

Additional requirements included such as 

-- Appendix Q (Low-Pressure Storage Tanks 

For Liquified Hydrocarbon Gases) and 

-- Appendix R (Low-Pressure Storage Tanks 

for Refrigerated Products) 

III:3-10

@ 

Other design code vessels 

-- Maximum design and allowable pressures 

-- Maximum and minimum operating 

temperatures 

@ 

Vessel history 

-- Alterations, reratings, and repairs performed 

-- Date(s) of changes or repairs 

@ 

@ 

Vessel materials 

-- ASME, ASTM, or other specification names 

and numbers for the major parts 

Design corrosion allowance 

IN-SERVICE INSPECTION 

Information about inspections performed on the vessel or tank 

and the results obtained that will assist in the safety 

assessment include the following items: 

@ 

@ 

Thermal stress relief (PWHT, postweld heat 

treatment) 

-- Design code requirements 

-- Type, extent, and conditions of PWHT 

performed 

Nondestructive examination (NDE) of welds 

-- Type and extent of examination performed 

-- Time when NDE was performed (before or 

after PWHT or hydrotest) 

SERVICE HISTORY 

Information on the conditions of operating history of the 

vessel or tank that will be helpful in safety assessment include 

the following items: 

@ 

Fluids handled 

-- Type and composition, temperature and 

pressures 

@ 

@ 

@ 

@ 

Inspection(s) performed 

-- Type, extent, and dates 

Examination methods 

-- Preparation of surfaces and welds 

-- Techniques used (visual, magnetic particle, 

penetrant test, radiography, ultrasonic) 

Qualifications of personnel 

-- ASNT (American Society for Nondestructive 

Testing) levels or equivalent of examining 

and supervisory personnel 

Inspection results and report 

-- Report form used (NBIC NB-7, API 510 or 

other) 

-- Summary of type and extent of damage or 

cracking 

-- Disposition (no action, delayed action or 

repaired) 

@ 

@ 

Type of service 

-- Continuous, intermittent or irregular 

Significant changes in service conditions 

-- Changes in pressures, temperatures, and fluid 

compositions and the dates of the changes 

SPECIFIC APPLICATIONS 

Survey results indicate that a relatively high proportion of 

vessels in operations in several specific applications have 

experienced inservice related damage and cracking. 

Information on the following items can assist in assessing the 

safety of vessels in these applications: 

III:3-11

@ 

@ 

@ 

@ 

Service application 

-- Deaerator, amine, wet hydrogen sulfide, 

ammonia, or pulp digesting 

Industry bulletins and guidelines for this application 

-- Owner/operator awareness of information 

Type, extent, and results of examinations 

-- Procedures, guidelines and recommendations 

used 

-- Amount of damage and cracking 

-- Next examination schedule 

Participation in industry survey for this application 

@ 

Problem mitigation 

-- Written plans and actions 

EVALUATION OF INFORMATION 

The information acquired for the above items is not adaptable 

to any kind of numerical ranking for quantitative safety 

assessment purposes. However, the information can reveal 

the owner or user's apparent attention to good practice, 

careful operation, regular maintenance, and adherence to the 

recommendations and guidelines developed for susceptible 

applications. If the assessment indicated cracking and other 

serious damage problems, it is important that the inspector 

obtain qualified technical advice and opinion. 

III:3-12


INDUSTRIAL ROBOTS AND ROBOT SYSTEM 

SAFETY 


Industrial robots are programmable multifunctional 

mechanical devices designed to move material, parts, tools, 

or specialized devices through variable programmed motions 

to perform a variety of tasks. An industrial robot system 

includes not only industrial robots but also any devices and/or 

sensors required for the robot to perform its tasks as well as 

sequencing or monitoring communication interfaces. 

A. Introduction........................................III:4-1 

B. Types and Classification 

of Robots.....................................III:4-2 

C. Hazards................................................III:4-7 

D. Investigation Guidelines..................III:4-10 

E. Control and Safeguarding 

Personnel..................................III:4-10 

F. Bibliography.....................................III:4-13 

Appendix III:4-1. Glossary for 

Robotics and Robotic 

System.......................................III:4-14 

Appendix III:4-2. Other Robotic 

Systems.....................................III:4-18 

Robots are generally used to perform unsafe, hazardous, 

highly repetitive, and unpleasant tasks. They have many 

different functions such as material handling, assembly, arc 

welding, resistance welding, machine tool load and unload 

functions, painting, spraying, etc. See Appendix III:4-1 for 

common definitions. 

Most robots are set up for an operation by the 

teach-and-repeat technique. In this mode, a trained operator 

(programmer) typically uses a portable control device (a teach 

pendant) to teach a robot its task manually. Robot speeds 

during these programming sessions are slow. 

This instruction includes safety considerations necessary to 

operate the robot properly and use it automatically in 

conjunction with other peripheral equipment. This 

instruction applies to fixed industrial robots and robot 

systems only. See Appendix III:4-2 for the systems that are 

excluded. 

ACCIDENTS: PAST STUDIES 

Studies in Sweden and Japan indicate that many robot 

accidents do not occur under normal operating conditions but, 

instead during programming, program touch-up or 

refinement, maintenance, repair, testing, setup, or adjustment. 

During many of these operations the operator, programmer, 

or corrective maintenance worker may temporarily be within 

the robot's working envelope where unintended operations 

could result in injuries. 

III:4-1

Typical accidents have included the following: 

@ 

@ 

@ 

A robot's arm functioned erratically during a 

programming sequence and struck the operator. 

A materials handling robot operator entered a robot's 

work envelope during operations and was pinned 

between the back end of the robot and a safety pole. 

A fellow employee accidentally tripped the power 

switch while a maintenance worker was servicing an 

assembly robot. The robot's arm struck the 

maintenance worker's hand. 

ROBOT SAFEGUARDING 

The proper selection of an effective robotic safeguarding 

system should be based upon a hazard analysis of the robot 

system's 

use, programming, and maintenance operations. Among the 

factors to be considered are the tasks a robot will be 

programmed to perform, start-up and command or 

programming procedures, environmental conditions, location 

and installation requirements, possible human errors, 

scheduled and unscheduled maintenance, possible robot and 

system malfunctions, normal mode of operation, and all 

personnel functions and duties. 

An effective safeguarding system protects not only operators 

but also engineers, programmers, maintenance personnel, and 

any others who work on or with robot systems and could be 

exposed to hazards associated with a robot's operation. A 

combination of safeguarding methods may be used. 

Redundancy and backup systems are especially 

recommended, particularly if a robot or robot system is 

operating in hazardous conditions or handling hazardous 

materials. The safeguarding devices employed should not 

themselves constitute or act as a hazard or curtail necessary 

vision or viewing by attending human operators. 

B. TYPES AND CLASSIFICATION OF ROBOTS 

Industrial robots are available commercially in a wide range 

of sizes, shapes, and configurations. They are designed and 

fabricated with different design configurations and a different 

number of axes or degrees of freedom. These factors of a 

robot's design influence its working envelope (the volume of 

working or reaching space). Diagrams of the different robot 

design configurations are shown in Figure III:4-1. 

SERVO AND NONSERVO 

All industrial robots are either servo or nonservo controlled. 

Servo robots are controlled through the use of sensors that 

continually monitor the robot's axes and associated 

components for position and velocity. This feedback is 

compared to pretaught information which has been 

programmed and stored in the robot's memory. 

Nonservo robots do not have the feedback capability, and 

their axes are controlled through a system of mechanical stops 

and limit switches. 

TYPE OF PATH GENERATED 

Industrial robots can be programmed from a distance to 

perform their required and preprogrammed operations with 

different types of paths generated through different control 

techniques. The three different types of paths generated are 

Point-to-Point Path, Controlled Path, and Continuous Path. 

POINT-TO-POINT PATH 

Robots programmed and controlled in this manner are 

programmed to move from one discrete point to another 

within 

III:4-2

Regulator Coordinate Robot 

Cylindrical Roordinate Robot 

Spherical Coordinate Robot 

Arituclated Arm Robot 

Gantry Robot SCARA Robot 

Figure III:4-1. Robot Arm Design Configurations. 

III:4-3

the robot's working envelope. In the automatic mode of 

operation, the exact path taken by the robot will vary slightly 

due to variations in velocity, joint geometries, and point 

spatial locations. This difference in paths is difficult to 

predict and therefore can create a potential safety hazard to 

personnel and equipment. 

CONTROLLED PATH 

The path or mode of movement ensures that the end of the 

robot's arm will follow a predictable (controlled) path and 

orientation as the robot travels from point to point. The 

coordinate transformations required for this hardware 

management are calculated by the robot's control system 

computer. Observations that result from this type of 

programming are less likely to present a hazard to personnel 

and equipment. 

CONTINUOUS PATH 

A robot whose path is controlled by storing a large number or 

close succession of spatial points in memory during a 

teaching sequence is a continuous path controlled robot. 

During this time, and while the robot is being moved, the 

coordinate points in space of each axis are continually 

monitored on a fixed time base, e.g., 60 or more times per 

second, and placed into the control system's computer 

memory. When the robot is placed in the automatic mode of 

operation, the program is replayed from memory and a 

duplicate path is generated. 

ROBOT COMPONENTS 

Industrial robots have four major components: the 

mechanical unit, power source, control system, and tooling 

(Figure III:4-2): 

MECHANICAL UNIT 

The robot's manipulative arm is the mechanical unit. This 

mechanical unit is also comprised of a fabricated structural 

frame with provisions for supporting mechanical linkage and 

joints, guides, actuators (linear or rotary), control valves, and 

sensors. The physical dimensions, design, and 

weight-carrying ability depend on application requirements. 

POWER SOURCES 

Energy is provided to various robot actuators and their 

controllers as pneumatic, hydraulic, or electrical power. The 

robot's drives are usually mechanical combinations powered 

by these types of energy, and the selection is usually based 

upon application requirements. For example, pneumatic 

power (low-pressure air) is used generally for low weight 

carrying robots. 

Hydraulic power transmission (high-pressure oil) is usually 

used for medium to high force or weight applications, or 

where smoother motion control can be achieved than with 

pneumatics. Consideration should be given to potential 

hazards of fires from leaks if petroleum-based oils are used. 

Electrically powered robots are the most prevalent in 

industry. Either AC or DC electrical power is used to supply 

energy to electromechanical motor-driven actuating 

mechanisms and their respective control systems. Motion 

control is much better, and in an emergency an electrically 

powered robot can be stopped or powered down more safely 

and faster than those with either pneumatic or hydraulic 

power. 

CONTROL SYSTEMS 

Either auxiliary computers or embedded microprocessors are 

used for practically all control of industrial robots today. 

These perform all of the required computational functions as 

well as interface with and control associated sensors, 

grippers, tooling, and other associated peripheral equipment. 

The control system performs the necessary sequencing and 

memory functions for on-line sensing, branching, and 

integration of other equipment. Programming of the 

controllers can be done on-line or at remote off-line control 

stations with electronic data transfer of programs by cassette, 

floppy disc, or telephone modem. 

III:4-4

Figure III:4-2. Industrial Robots: Major Components 

Self-diagnostic capability for troubleshooting and 

maintenance greatly reduces robot system downtime. 

Some robot controllers have sufficient capacity, in terms of 

computational ability, memory capacity, and input-output 

capability to serve also as system controllers and handle many 

other machines and processes. 

Programming of robot controllers and systems has not been 

standardized by the robotics industry; therefore, the different 

manufacturers use their own proprietary programming 

languages which require special training of personnel. 

ROBOT PROGRAMMING BY TEACHING 

METHODS 

A program consists of individual command steps which state 

either the position or function to be performed, along with 

other informational data such as speed, dwell or delay times, 

sample input device, activate output device, execute, etc. 

When establishing a robot program, it is necessary to 

establish a physical or geometrical relationship between the 

robot and other equipment or work to be serviced by the 

robot. To establish these coordinate points precisely within 

the robot's 

III:4-5

working envelope, it is necessary to control the robot 

manually and physically teach the coordinate points. To do 

this as well as determine other functional programming 

information, three different teaching or programming 

techniques are used: lead-through, walk-through, and 

off-line. 

LEAD-THROUGH PROGRAMMING OR TEACHING 

This method of teaching uses a proprietary teach pendant (the 

robot's control is placed in a "teach" mode), which allows 

trained personnel physically to lead the robot through the 

desired sequence of events by activating the appropriate 

pendant button or switch. Position data and functional 

information are "taught" to the robot, and a new program is 

written (Figure III:4-3). The teach pendant can be the sole 

source by which a program is established, or it may be used 

in conjunction with an additional programming console 

and/or the robot's controller. When using this technique of 

teaching or programming, the person performing the teach 

function can be within the robots working envelope with 

operational safeguarding devices deactivated or inoperative. 

WALK-THROUGH PROGRAMMING OR 

TEACHING 

A person doing the teaching has physical contact with the 

robot arm and actually gains control and walks the robot's 

arm through the desired positions within the working 

envelope (Figure III:4-4). 

During this time, the robot's controller is scanning and storing 

coordinate values on a fixed time basis. When the robot is 

later placed in the automatic mode of operation, these values 

and other functional information are replayed and the 

program run as it was taught. With the walk-through method 

of programming, the person doing the teaching is in a 

potentially hazardous position because the operational 

safeguarding devices are deacti-vated or inoperative. 

OFF-LINE PROGRAMMING 

The programming establishing the required sequence of 

functional and required positional steps is written on a remote 

computer console (Figure III:4-5). Since the console is 

distant from the robot and its controller, the written program 

has to be transferred to the robot's controller and precise 

positional data established to achieve the actual coordinate 

information for the robot and other equipment. The program 

can be transferred directly or by cassette or floppy discs. 

After the program has been completely transferred to the 

robot's controller, either the lead-through or walk-through 

technique can be used for obtaining actual positional 

coordinate information for the robot's axes. 

When programming robots with any of the three techniques 

discussed above, it is generally required that the program be 

verified and slight modifications in positional information 

made. This procedure is called program touch-up and is 

normally carried out in the teach mode of operation. The 

teacher manually leads or walks the robot through the 

programmed steps. Again, there are potential hazards if 

safeguarding devices are deactivated or inoperative. 

Figure III:4-3. Robot Lead-Through 

Programming or Teaching. 

III:4-6

DEGREES OF FREEDOM 

Regardless of the configuration of a robot, movement along 

each axis will result in either a rotational or a translational 

movement. The number of axes of movement (degrees of 

freedom) and their arrangement, along with their sequence of 

operation and structure, will permit movement of the robot to 

any point within its envelope. Robots have three arm 

movements (up-down, in-out, side-to-side). In addition, they 

can have as many as three additional wrist movements on the 

end of the robot's arm: yaw (side to side), pitch (up and 

down), and rotational (clockwise and counterclockwise). 

C. HAZARDS 

The operational characteristics of robots can be significantly 

different from other machines and equipment. Robots are 

capable of high-energy (fast or powerful) movements through 

a large volume of space even beyond the base dimensions of 

the robot (see Figure II:4-6). The pattern and initiation of 

movement of the robot is predictable if the item being 

"worked" and the environment are held constant. Any change 

to the object being worked (i.e., a physical model change) or 

environmental changes can affect the programmed 

movements. 

Thus, a worker can be hit by one robot while working on 

another, trapped between them or peripheral equipment, or hit 

by flying objects released by the gripper. 

A robot with two or more resident programs can find the 

current operating program erroneously calling another 

existing program with different operating parameters such as 

velocity, acceleration, or deceleration, or position within the 

robot's 

Some maintenance and programming personnel may be 

required to be within the restricted envelope while power is 

available to actuators. The restricted envelope of the robot 

can overlap a portion of the restricted envelope of other 

robots or work zones of other industrial machines and related 

equipment. 

Figure III:4-4. Walk-through Programming and 

Teacher. 

Figure III:4-5. Off-line Programming or Teaching 

III:4-7

Figure III:4-6. A Robot’s Work Envelope. 

restricted envelope. The occurrence of this might not be 

predictable by maintenance or programming personnel 

working with the robot. A component malfunction could also 

cause an unpredictable movement and/or robot arm velocity. 

Additional hazards can also result from the malfunction of, or 

errors in, interfacing or programming of other process or 

peripheral equipment. The operating changes with the 

process being performed or the breakdown of conveyors, 

clamping mechanisms, or process sensors could cause the 

robot to react in a different manner. 

TYPES OF ACCIDENTS 

Robotic incidents can be grouped into four categories: a 

robotic arm or controlled tool causes the accident, places an 

individual in a risk circumstance, an accessory of the robot's 

mechanical parts fails, or the power supplies to the robot are 

uncontrolled. 

IMPACT OR COLLISION ACCIDENTS 

Unpredicted movements, component malfunctions, or 

unpredicted program changes with the robot's arm or 

peripheral equipment can result in contact accidents. 

CRUSHING AND TRAPPING ACCIDENTS 

A worker's limb or other body part can be trapped between a 

robot's arm and other peripheral equipment, or the individual 

may be physically driven into and crushed by other peripheral 

equipment. 

MECHANICAL PART ACCIDENTS 

The breakdown of the robot's drive components, tooling or 

end-effector, peripheral equipment, or its power source is a 

mechanical accident. The release of parts, failure of gripper 

mechanism, or the failure of end-effector power tools (e.g., 

grinding wheels, buffing wheels, deburring tools, power 

screwdrivers, and nut runners) are a few types of mechanical 

failures. 

III:4-8

OTHER ACCIDENTS 

Other accidents can result from working with robots. 

Equipment that supplies robot power and control represents 

potential electrical and pressurized fluid hazards. Ruptured 

hydraulic lines could create dangerous high-pressure cutting 

streams or whipping hose hazards. Environmental accidents 

from arc flash, metal spatter, dust, electromagnetic, or 

radio-frequency interference can also occur. In addition, 

equipment and power cables on the floor present tripping 

hazards. 

SOURCES OF HAZARDS 

The expected hazards of machine to man can be expected 

with several additional variations. 

HUMAN ERRORS 

Inherent prior programming, interfacing activated peripheral 

equipment, or connecting live input-output sensors to the 

microprocessor or a peripheral can cause dangerous, 

unpredicted movement or action by the robot from human 

error. The incorrect activation of the "teach pendant" or 

control panel is a frequent human error. The greatest 

problem, however, is overfamiliarity with the robot's 

redundant motions so that an individual places himself in a 

hazardous position while programming the robot or 

performing maintenance on it. 

CONTROL ERRORS 

Intrinsic faults within the control system of the robot, errors 

in software, electromagnetic interference, and radio frequency 

interference are control errors. In addition, these errors can 

occur from faults in the hydraulic, pneumatic, or electrical 

subcontrols associated with the robot or robot system. 

UNAUTHORIZED ACCESS 

Entry into a robot's safeguarded area is hazardous because the 

person involved may not be familiar with the safeguards in 

place or their activation status. 

MECHANICAL FAILURES 

Operating programs may not account for cumulative 

mechanical part failure, and faulty or unexpected operation 

may occur. 

ENVIRONMENTAL SOURCES 

Electromagnetic or radio-frequency interference (transient 

signals) should be considered to exert an undesirable 

influence on robotic operation and increase the potential for 

injury to any person working in the area. Solutions to 

environmental hazards should be documented prior to 

equipment start-up. 

POWER SYSTEMS 

Pneumatic, hydraulic, or electrical power sources that have 

malfunctioning control or transmission elements in the robot 

power system can disrupt electrical signals to the control 

and/or power-supply lines. Fire risks are increased by 

electrical overloads or by use of flammable hydraulic oil. 

Electrical shock and release of stored energy from 

accumulating devices also can be hazardous to personnel. 

IMPROPER INSTALLATION 

The design, requirements, and layout of equipment, utilities, 

and facilities of a robot or robot system, if inadequately done, 

can lead to inherent hazards. 

III:4-9

D. INVESTIGATION GUIDELINES 

MANUFACTURED, REMANUFACTURED, 

AND REBUILT ROBOTS 

All robots should meet minimum design requirements to 

insure safe operation by the user. Consideration needs to be 

given to a number of factors in designing and building the 

robots to industry standards. If older or obsolete robots are 

rebuilt or remanufactured, they should be upgraded to 

conform to current industry standards. 

INSTALLATION 

A robot or robot system should be installed by the users in 

accordance with the manufacturer's recommendations and in 

conformance to acceptable industry standards. Temporary 

safeguarding devices and practices should be used to 

minimize the hazards associated with the installation of new 

equipment. The facilities, peripheral equipment, and 

operating conditions which should be considered are: 

Every robot should be designed, manufactured, 

remanufactured, or rebuilt with safe design and 

manufacturing considerations. Improper design and 

manufacture can result in hazards to personnel if minimum 

industry standards are not conformed to on mechanical 

components, controls, methods of operation, and other 

required information necessary to insure safe and proper 

operating procedures. 

@ 

@ 

@ 

@ 

@ 

@ 

@ 

Installation specifications, 

Physical facilities, 

Electrical facilities, 

Action of peripheral equipment integrated with the 

robot, 

Identification requirements, 

Control and emergency stop requirements, and 

Special robot operating procedures or conditions. 

To insure that robots are designed, manufactured, 

remanufactured, and rebuilt to insure safe operation, it is 

recommended that they comply with Section 4 of the 

ANSI/RIA R15.06-1992 standard for Manufacturing, 

Remanufacture, and Rebuild of Robots. 

To insure safe operating practices and safe installation of 

robots and robot systems, it is recommended that the 

minimum requirements of Section 5 of the ANSI/RIA 

R15.06-1992, Installation of Robots and Robot Systems be 

followed. In addition, OSHA's Lockout/ Tagout standards 

(29 CFR 1910.147 and 1910.333) must be be followed for 

servicing and maintenance. 

E. CONTROL AND SAFEGUARDING PERSONNEL 

For the planning stage, installation, and subsequent operation 

of a robot or robot system, one should consider the following. 

RISK ASSESSMENT 

At each stage of development of the robot and robot system 

a risk assessment should be performed. 

There are different system and personnel safeguarding 

requirements at each stage. The appropriate level of 

safeguarding determined by the risk assessment should be 

applied. In addition, the risk assessments for each stage of 

development should be documented for future reference. 

III:4-10

SAFEGUARDING DEVICES 

Personnel should be safeguarded from hazards associated 

with the restricted envelope (space) through the use of one or 

more safeguarding devices: 

@ 

@ 

@ 

@ 

@ 

Mechanical limiting devices, 

Nonmechanical limiting devices, 

Presence sensing safeguarding devices, 

Fixed barriers (which prevent contact with moving 

parts), and 

Interlocked barrier guards. 

AWARENESS DEVICES 

Typical awareness devices include chain or rope barriers with 

supporting stanchions or flashing lights, signs, whistles, and 

horns . They are usually used in conjunction with other 

safeguarding devices. 

SAFEGUARDING THE TEACHER 

Special consideration must be given the teacher or person 

who is programming the robot. During the teach mode of 

operation, the person performing the teaching has control of 

the robot and associated equipment and should be familiar 

with the operations to be programmed, system interfacing, 

and control functions of the robot and other equipment. 

When systems are large and complex, it can be easy to 

activate improper functions or sequence functions improperly. 

Since the person doing the training can be within the robot's 

restricted envelope, such mistakes can result in accidents. 

Mistakes in programming can result in unintended movement 

or actions with similar results. For this reason, a restricted 

speed of 250 mm/sec. or 10 in/sec. should be placed on any 

part of the robot during training to minimize potential injuries 

to teaching personnel. 

Several other safeguards are suggested in the ANSI/RIA 

R15.06-1992 standard to reduce the hazards associated with 

teaching a robotic system. 

OPERATOR SAFEGUARDS 

The system operator should be protected from all hazards 

during operations performed by the robot. When the robot is 

operating automatically, all safeguarding devices should be 

activated, and at no time should any part of the operator's 

body be within the robot's safeguarded area. 

For additional operator safeguarding suggestions, see the 

ANSI/RIA R15.06-1992 standard, Section 6.6. 

ATTENDED CONTINUOUS OPERATION 

When a person is permitted to be in or near the robots 

restricted envelope to evaluate or check the robots motion or 

other operations, all continuous operation safeguards must be 

in force. During this operation, the robot should be at slow 

speed, and the operator would have the robot in the teach 

mode and be fully in control of all operations. 

Other safeguarding requirements are suggested in the 

ANSI/RIA R15.06-1992 standard, Section 6.7. 

MAINTENANCE & REPAIR PERSONNEL 

Safeguarding maintenance and repair personnel is very 

difficult because their job functions are so varied. 

Troubleshooting faults or problems with the robot, controller, 

tooling, or other associated equipment is just part of their job. 

Program touchup is another of their jobs as is scheduled 

maintenance, and adjustments of tooling, gages, recalibration, 

and many other types of functions. 

While maintenance and repair is being performed, the robot 

should be placed in the manual or teach mode, and the 

maintenance personnel perform their work within the 

safeguarded area and within the robots restricted envelope. 

Additional hazards are present during this mode of operation 

III:4-11

ecause the robot system safeguards are not operative. 

To protect maintenance and repair personnel, safeguarding 

techniques and procedures as stated in the ANSI/RIA 

R15.06-1992 standard, Section 6.8, are recommended. 

MAINTENANCE 

Maintenance should occur during the regular and periodic 

inspection program for a robot or robot system. An 

inspection program should include, but not be limited to, the 

recommendations of the robot manufacturer and manufacturer 

of other associated robot system equipment such as conveyor 

mechanisms, parts feeders, tooling, gages, sensors, and the 

like. 

SAFETY TRAINING 

Personnel who program, operate, maintain, or repair robots or 

robot systems should receive adequate safety training, and 

they should be able to demonstrate their competence to 

perform their jobs safely. Employers can refer to OSHA's 

publication 2254 (Revised), "Training Requirements in 

OSHA Standards and Training Guidelines." 

GENERAL REQUIREMENTS 

To ensure minimum safe operating practices and safeguards 

for robots and robot systems covered by this instruction, the 

following sections of the ANSI/RIA R15.06-1992 must also 

be considered: 

These recommended inspection and maintenance programs 

are essential for minimizing the hazards from component 

malfunction, breakage, and unpredicted movements or actions 

by the robot or other system equipment. 

To insure proper maintenance, it is recommended that 

periodic maintenance and inspections be documented along 

with the identity of personnel performing these tasks. 

@ 

@ 

@ 

@ 

Section 6 - Safeguarding Personnel 

Section 7 - Maintenance of Robots and Robot 

Systems 

Section 8 - Testing and Start-up of Robots and Robot 

Systems 

Section 9 - Safety Training of Personnel 

Robots or robotic systems must comply with the following 

regulations: 

Occupational Safety and Health Administration, OSHA 29 

CFR 1910.333 and OSHA 29 CFR Part 1910.147, "Control 

of Hazardous Energy Source (Lockout/Tagout); Final Rule." 

III:4-12

F. BIBLIOGRAPHY 

American National Standards Institute (ANSI) American 

National Safety Standard ANSI/ RIA R15.06-1992. 

Industrial Robots and Robot Systems - Safety 

Requirements. American National Standards Institute, 

Inc., 1430 Broadway, New York, New York 10018 

National Institute for Occupational Safety and Health 

(NIOSH) 

Alert Publication No. 85103. Request for Assistance in 

Preventing the Injury of Workers by Robots. National 

Institute for Occupational Safety and Health, Division of 

Safety Research, 944 Chestnut Ridge Road, Morgantown, 

West Virginia 26505 

Occupational Safety and Health Administration Publication 

No. 3067. Concepts and Techniques of Machine 

Safeguarding. U.S. Department of Labor, 1980 

(reprinted 1983). Superintendent of Documents, U.S. 

Government Printing Office, Washington, D.C. 20210 

Robotic Industries Association, 900 Victors Way, P.O. Box 

3724, Ann Arbor, Michigan 48106 

Occupational Safety and Health Administration Publication 

No. 

2254 (Revised). Training Requirements in OSHA 

Standards and Training Guidelines. Superintendent of 

Documents, U.S. Government Printing Office, 

Washington, D.C. 20210 

National Safety Council Data Sheet 1-717-85. Robots. 

National 

Safety Council, 444 N. Michigan Avenue, Chicago, 

Illinois 60611 

National Institute for Occupational Safety and Health 

(NIOSH) 

Technical Report Publication No. 880108. Safe 

Maintenance Guidelines for Robotic Workstations. 

National Institute for Occupational Safety and Health, 

Division of Safety Research, 944 Chestnut Ridge Road, 

Morgantown, West Virginia 26505 

OSHA Instruction Publication No. 8-1.3. 1987. Guideline 

for 

Robotics Safety. Occupational Safety and Health 

Administration, Washington, DC 

III:4-13

APPENDIX III:4-1. 

GLOSSARY FOR ROBOTICS AND ROBOTIC 

SYSTEMS 

Actuator 

A power mechanism used to effect motion of the robot; a 

device that converts electrical, hydraulic, or pneumatic energy 

into robot motion. 

Application Program 

The set of instructions that defines the specific intended tasks 

of robots and robot systems. This program may be originated 

and modified by the robot user. 

Attended Continuous Operation 

The time when robots are performing (production) tasks at a 

speed no greater than slow speed through attended program 

execution. 

Attended Program Verification 

The time when a person within the restricted envelope (space) 

verifies the robot's programmed tasks at programmed speed. 

Automatic Mode 

The robot state in which automatic operation can be initiated. 

Automatic Operation 

The time during which robots are performing programmed 

tasks through unattended program execution. 

Awareness Barrier 

Physical and/or visual means that warns a person of an 

approaching or present hazard. 

Awareness Signal 

A device that warns a person of an approaching or present 

hazard by means of audible sound or visible light. 

Barrier 

A physical means of separating persons from the restricted 

envelope (space). 

Control Device 

Any piece of control hardware providing a means for human 

intervention in the control of a robot or robot system, such as 

an emergency-stop button, a start button, or a selector switch. 

Control Program 

The inherent set of control instructions that defines the 

capabilities, actions and responses of the robot system. This 

program is usually not intended to be modified by the user. 

Coordinated Straight Line Motion 

Control wherein the axes of the robot arrive at their respective 

end points simultaneously, giving a smooth appearance to the 

motion. Control wherein the motions of the axes are such 

that the Tool Center Point (TCP) moves along a prespecified 

type of path (line, circle, etc.) 

Device 

Any piece of control hardware such as an emergency-stop 

button, selector switch, control pendant, relay, solenoid valve, 

sensor, etc. 

Drive Power 

The energy source or sources for the robot actuators. 

Emergency Stop 

The operation of a circuit using hardware-based components 

that overrides all other robot controls, removes drive power 

from the robot actuators, and causes all moving parts to stop. 

Axis 

The line about which a rotating body such as tool turns. 

III:4-14

Enabling Device 

A manually operated device that permits motion when 

continuously activated. Releasing the device stops robot 

motion and motion of associated equipment that may present 

a hazard. 

End-effector 

An accessory device or tool specifically designed for 

attachment to the robot wrist or tool mounting plate to enable 

the robot to perform its intended task. (Examples may 

include gripper, spot-weld gun, arc-weld gun, spray- paint 

gun, or any other application tools.) 

Energy Source 

Any electrical, mechanical, hydraulic, pneumatic, chemical, 

thermal, or other source. 

Envelope (Space), Maximum 

The volume of space encompassing the maximum designed 

movements of all robot parts including the end-effector, 

workpiece, and attachments. 

Restricted Envelope (Space) 

That portion of the maximum envelope to which a robot is 

restricted by limiting devices. The maximum distance that 

the robot can travel after the limiting device is actuated 

defines the boundaries of the restricted envelope (space) of 

the robot. 

NOTE: The safeguarding interlocking logic and robot 

program may redefine the restricted envelope (space) as the 

robot performs its application program. 

(See Appendix D of the ANSI/RIA R15.06-1992 

Specification). 

Operating Envelope (Space) 

That portion of the restricted envelope (space) that is actually 

used by the robot while performing its programmed motions. 

Hazardous Motion 

Any motion that is likely to cause personal physical harm. 

Industrial Equipment 

Physical apparatus used to perform industrial tasks, such as 

welders, conveyors, machine tools, fork trucks, turn tables, 

positioning tables, or robots. 

Industrial Robot 

A reprogrammable, multifunctional manipulator designed to 

move material, parts, tools, or specialized devices through 

variable programmed motions for the performance of a 

variety of tasks. 

Industrial Robot System 

A system that includes industrial robots, the end-effectors, 

and the devices and sensors required for the robots to be 

taught or programmed, or for the robots to perform the 

intended automatic operations, as well as the communication 

interfaces required for interlocking, sequencing, or 

monitoring the robots. 

Interlock 

An arrangement whereby the operation of one control or 

mechanism brings about or prevents the operation of another. 

Joint Motion 

A method for coordinating the movement of the joints such 

that all joints arrive at the desired location simultaneously. 

Limiting Device 

A device that restricts the maximum envelope (space) by 

stopping or causing to stop all robot motion and is 

independent of the control program and the application 

programs. 

Maintenance 

The act of keeping the robots and robot systems in their 

proper operating condition. 

Hazard 

A situation that is likely to cause physical harm. 

III:4-15

Mobile Robot 

A self-propelled and self-contained robot that is capable of 

moving over a mechanically unconstrained course. 

Muting 

The deactivation of a presence-sensing safeguarding device 

during a portion of the robot cycle. 

Operator 

The person designated to start, monitor, and stop the intended 

productive operation of a robot or robot system. An operator 

may also interface with a robot for productive purposes. 

Pendant 

Any portable control device, including teach pendants, that 

permits an operator to control the robot from within the 

restricted envelope (space) of the robot. 

Presence-Sensing Safeguarding Device 

A device designed, constructed, and installed to create a 

sensing field or area to detect an intrusion into the field or 

area by personnel, robots, or other objects. 

Program 

1. (noun) A sequence of instructions to be executed by the 

computer or robot controller to control a robot or robot 

system; 

2. (verb) to furnish (a computer) with a code of instruction; 

3. (verb) to teach a robot system a specific set of movements 

and instructions to accomplish a task. 

Rebuild 

To restore the robot to the original specifications of the 

manufacturer, to the extent possible. 

Remanufacture 

To upgrade or modify robots to the revised specifications of 

the manufacturer and applicable industry standards. 

Repair 

To restore robots and robot systems to operating condition 

after damage, malfunction, or wear. 

Robot Manufacturer 

A company or business involved in either the design, 

fabrication, or sale of robots, robot tooling, robotic peripheral 

equipment or controls, and associated process ancillary 

equipment. 

Robot System Integrator 

A company or business who either directly or through a 

subcontractor will assume responsibility for the design, 

fabrication, and integration of the required robot, robotic 

peripheral equipment, and other required ancillary equipment 

for a particular robotic application. 

Safeguard 

A barrier guard, device, or safety procedure designed for the 

protection of personnel. 

Safety Procedure 

An instruction designed for the protection of personnel. 

Sensor 

A device that responds to physical stimuli (such as heat, light, 

sound, pressure, magnetism, motion, etc.) and transmits the 

resulting signal or data for providing a measurement, 

operating a control, or both. 

Service 

To adjust, repair, maintain, and make fit for use. 

Single Point of Control 

The ability to operate the robot such that initiation or robot 

motion from one source of control is possible only from that 

source and cannot be overridden from another source. 

Slow Speed Control 

A mode of robot motion control where the velocity of the 

robot is limited to allow persons sufficient time either to 

withdraw the hazardous motion or stop the robot. 

Start-up 

Routine application of drive power to the robot or robot 

system. 

III:4-16

Start-up, Initial 

Initial drive power application to the robot or robot system 

after one of the following events: 

@ 

@ 

@ 

@ 

Manufacture or modification 

Installation or reinstallation 

Programming or program editing 

Maintenance or repair 

Teach 

The generation and storage of a series of positional data 

points effected by moving the robot arm through a path of 

intended motions. 

Teach Mode 

The control state that allows the generation and storage of 

positional data points effected by moving the robot arm 

through a path of intended motions. 

Teacher 

A person who provides the robot with a specific set of 

instructions to perform a task. 

Tool Center Point (TCP) 

The origin of the tool coordinate system. 

User 

A company, business, or person who uses robots and who 

contracts, hires, or is responsible for the personnel associated 

with robot operation. 

III:4-17

APPENDIX III:4-2. 

OTHER ROBOTIC SYSTEMS NOT COVERED 

BY THIS CHAPTER 

Service robots are machines that extend human capabilities. 

Automatic guided-vehicle systems are advanced 

material-handling or conveying systems that involve a 

driverless vehicle which follows a guide-path. 

Undersea and space robots include in addition to the 

manipulator or tool that actually accomplishes a task, the 

vehicles or platforms that transport the tools to the site. 

These vehicles are called remotely operated vehicles (ROVs) 

or autonomous undersea vehicles (AUVs); the feature that 

distinguishes them is, respectively, the presence or absence of 

an electronics tether that connects the vehicle and surface 

control station. 

Automatic storage and retrieval systems are storage racks 

linked through automatically controlled conveyors and an 

automatic storage and retrieval machine or machines that ride 

on floor-mounted guide rails and power-driven wheels. 

Automatic conveyor and shuttle systems are comprised of 

various types of conveying systems linked together with 

various shuttle mechanisms for the prime purpose of 

conveying materials or parts to prepositioned and 

predetermined locations automatically. 

Teleoperators are robotic devices comprised of sensors and 

actuators for mobility and/or manipulation and are controlled 

remotely by a human operator. 

Mobile robots are freely moving automatic programmable 

industrial robots 

Prosthetic robots are programmable manipulators or devices 

for missing human limbs. 

Numerically controlled machine tools are operated by a 

series of coded instructions comprised of numbers, letters of 

the alphabet, and other symbols. These are translated into 

pulses of electrical current or other output signals that 

activate motors and other devices to run the machine. 

III:4-18

Technical Manual - Section 3 (Safety Hazards)

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